10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

            (Mark One)

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

For the fiscal year ended December 31, 2009 or

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

For the transition period from                      to                     

Commission file number 1-32853

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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)

704-594-6200

(Registrant’s telephone number, including area code)

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

	Name of each exchange on which registered
Title of each class
Common Stock, $0.001 par value	New York Stock Exchange, Inc.

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):

Large accelerated filer x	Accelerated filer ¨
Non-accelerated filer ¨	Smaller reporting company ¨
(Do not check if a smaller reporting company)

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

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

TABLE OF CONTENTS

DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2009

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

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:

• 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;

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

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

• Additional competition in electric markets and continued industry consolidation;

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

• 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;

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

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

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

• 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;

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

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

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

• 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;

• 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;

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

• 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.

PART I

Item 1. Business.

GENERAL

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.

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PART I

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.

GLOSSARY OF TERMS

The following terms or acronyms used in this Form 10-K are defined below:

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

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PART I

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

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PART I

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
NOx	Nitrogen oxide
NPNS	Normal purchase/normal sale

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PART I

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

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PART I

Term or Acronym	Definition
WVPA	Wabash Valley Power Association, Inc.

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

Service Area and Customers

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.

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PART I

Energy Capacity and Resources

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.

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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

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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.

Fuel Supply

U.S. Franchised Electric and Gas relies principally on coal and nuclear fuel for its generation of electric energy. The following table lists U.S. Franchised Electric and Gas’ sources of power and fuel costs for the three years ended December 31, 2009.

	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

(a) Statistics related to coal generation and all fuels reflect U.S. Franchised Electric and Gas’ 69% ownership interest in the East Bend Steam Station and 50.05% ownership interest in Unit 5 of the Gibson Steam Station.

(b) Statistics related to nuclear generation and all fuels reflect U.S. Franchised Electric and Gas’ 12.5% interest in the Catawba Nuclear Station through September 30, 2008 and an approximate 19% ownership interest in the Catawba Nuclear Station from October 1, 2008 and thereafter.

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

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

Coal. U.S. Franchised Electric and Gas meets its coal demand 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.

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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

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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.

Inventory

Generation of electricity is capital-intensive. U.S. Franchised Electric and Gas must maintain an adequate stock of fuel, materials and supplies in order to ensure continuous operation of generating facilities and reliable delivery to customers. As of December 31, 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.

Nuclear Insurance and Decommissioning

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

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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.

Asbestos Related Injuries and Damages Claims

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.

Competition

U.S. Franchised Electric and Gas competes in some areas with government-owned power systems, municipally owned electric systems, rural electric cooperatives and other private utilities. By statute, the NCUC and the PSCSC assign service areas outside municipalities in North Carolina and South Carolina, 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.

Regulation

State

The NCUC, the PSCSC, the PUCO, the IURC and the KPSC (collectively, the State Utility Commissions) approve rates for retail electric service within their respective states. In addition, the PUCO and the KPSC approve rates for retail gas distribution service within their respective states. The FERC approves U.S. Franchised Electric and Gas’ cost-based rates for electric sales to certain wholesale customers. 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

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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.”

Federal

Regulations of FERC and the State Utility Commissions govern access to regulated electric and gas customer and other data by non-regulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of non-regulated affiliates with U.S. Franchised Electric and Gas.

The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through 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

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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.

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.

Other

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

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 non-regulated generation in Ohio, acquired from Cinergy in April 2006, which are dedicated under the ESP, and the five Midwestern gas-fired non-regulated generation assets that were a portion of former DENA, which are dispatched into wholesale markets. Commercial Power’s assets, excluding wind energy generation assets, are comprised of approximately 7,550 net MW of power generation primarily located in the Midwestern United States. 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 began operating under an ESP, which expires on December 31, 2011, and is described below. Prior to January 1, 2009, these generation assets were contracted through the RSP, which expired on December 31, 2008.

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.

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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.

The following map shows the location of DEGS generation assets.

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Rates and Regulation

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:

• Annually Adjusted Component (AAC) Rider- This rider is intended to provide cost recovery primarily for certain environmental compliance expenditures. This component is avoidable (or by-passable) by all customers that switch to an alternative electric service provider.

• Fuel and Purchased Power (FPP) Rider – This rider is intended to provide cost recovery for fuel, purchased power and emission allowance expenses (including carbon or energy taxes) incurred to generate or procure electricity for retail ratepayers that are provided service by Duke Energy Ohio. This component is avoidable (or by-passable) by all customers that switch to an alternative electric service provider.

• Capacity Dedication Rider – This rider is intended to provide cost recovery for maintaining the generation fleet to serve the retail rate payers. This component is not avoidable (or non-by-passable) by customers that switch to an alternative electric service provider.

• System Reliability Tracker – This tracker is intended to provide actual cost recovery for capacity purchases made to maintain adequate reserve margin. This component is not avoidable (or non-by-passable) by all customers that switch to an alternative electric service provider.

• Base Generation Charge – This component reflects a market price for retail generation service and is not a cost-based rate. This component is avoidable (or by-passable) by all customers that switch to an alternative electric service provider.

• Transmission Cost Recovery Rider – The generation portion of this rider is designed to permit Duke Energy Ohio to recover certain Midwest ISO charges and all FERC approved transmission costs allocable to retail ratepayers that are provided service by Duke Energy Ohio. This component is avoidable (or by-passable) by all customers that switch to an alternative electric service provider.

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

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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.

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.

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.)

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.

Market Environment and Competition

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.

Fuel Supply

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.

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INTERNATIONAL ENERGY

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.

Competition and Regulation

International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government-owned electric generating companies, 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.)

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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, 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.

Competition and Regulation

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

ENVIRONMENTAL MATTERS

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

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

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

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

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

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

• The North Carolina clean air legislation that froze electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of SO₂ and nitrogen oxide (NO_x) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). However, Duke Energy Carolinas ended its amortization in 2007 as part of its rate case settlement with the NCUC.

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.

GEOGRAPHIC REGIONS

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.

EMPLOYEES

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.

EXECUTIVE OFFICERS OF DUKE ENERGY

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.

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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.

Executive officers serve until their successors are duly elected.

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

Item 1A. Risk Factors.

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.

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PART I

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.

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PART I

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.

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PART I

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:

• weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, and periods of low rainfall that decrease Duke Energy’s ability to operate its facilities in an economical manner;

• supply of and demand for energy commodities;

• illiquid markets including reductions in trading volumes which result in lower revenues and earnings;

• transmission or transportation constraints or inefficiencies which impact Duke Energy’s non-regulated energy operations;

• availability of competitively priced alternative energy sources, which are preferred by some customers over electricity produced from coal, nuclear or gas plants, and of energy-efficient equipment which reduces energy demand;

• natural gas, crude oil and refined products production levels and prices;

• ability to procure satisfactory levels of inventory, such as coal and uranium;

• electric generation capacity surpluses which cause Duke Energy’s non-regulated energy plants to generate and sell less electricity at lower prices and may cause some plants to become non-economical to operate; and

• capacity and transmission service into, or out of, Duke Energy’s markets.

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.

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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.

Item 1B. Unresolved Staff Comments.

None.

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PART I

Item 2. Properties.

U.S. FRANCHISED ELECTRIC AND GAS

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.

Name Total MW
Capacity   Owned MW
Capacity   Fuel                   Location   Ownership
Interest
(percentage)  

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

(a) This generation facility is jointly owned by Duke Energy Carolinas, along with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation and Piedmont Municipal Power Agency.

(b) Duke Energy Indiana owns and operates Gibson Station Units 1-4 and owns 50.05% of Unit 5, but is the operator. Unit 5 is jointly owned by Duke Energy Indiana, Wabash Valley Power Association, Inc. and Indiana Municipal Power Agency.

(c) Includes Cayuga Internal Combustion (IC).

(d) This generation facility is jointly owned by Duke Energy Kentucky and a subsidiary of Dayton Power and Light, Inc.

(e) Includes Wabash River IC.

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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.

COMMERCIAL POWER

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.

Name Total MW
Capacity   Owned MW
Capacity     Plant Type     Primary Fuel     Location   Approximate
Ownership
Interest
(percentage)  

Hanging Rock	1,240	1,240	Combined Cycle	Natural gas	OH	100%
Lee	640	640	Simple Cycle	Natural gas	IL	100
Vermillion(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

(a) This generation facility is jointly owned by Duke Energy Ohio and Wabash Valley Power Association, Inc.

(b) These generation facilities are jointly owned by Duke Energy Ohio and subsidiaries of American Electric Power, Inc. and/or Dayton Power and Light, Inc.

(c) Station is not operated by Duke Energy Ohio.

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.

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INTERNATIONAL ENERGY

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

Name Total
MW
Capacity   Owned
MW
Capacity   Fuel           Location   Approximate
Ownership
Interest
(percentage)  

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

(a) Includes Canoas I and II, which is jointly owned by Duke Energy and Companhia Brasileira de Aluminio.

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.

OTHER

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.

Item 3. Legal Proceedings.

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

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

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

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

Duke Energy’s common stock is listed for trading on the New York Stock Exchange (NYSE) (ticker symbol DUK). As of February 22, 2010, there were approximately 160,575 common stockholders of record.

Common Stock Data by Quarter

	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

(a) Stock prices represent the intra-day high and low stock price.

(b) Dividends paid in September 2009 and December 2009 increased from $0.23 per share to $0.24 per share and dividends paid in September 2008 and December 2008 increased from $0.22 per share to $0.23 per share.

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.

Issuer Purchases of Equity Securities for Fourth Quarter of 2009

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

Stock Performance Graph

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.

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NYSE CEO Certification

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.

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Item 6. Selected Financial Data.^(a)(b)

	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

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	2009		2008		2007		2006		2005
	(in millions, except per-share amounts)
Dividends per share(d)		0.94		0.90		0.86		1.26		1.17
Balance Sheet
Total assets	$	57,040	$	53,077	$	49,686	$	68,700	$	54,723
Long-term debt including capital leases, less current maturities	$	16,113	$	13,250	$	9,498	$	18,118	$	14,547

(a) Significant transactions reflected in the results above include: 2009 impairment of goodwill and other assets (see Note 11 to the Consolidated Financial Statements, “Goodwill and Intangible Assets”), 2007 spin-off of the natural gas businesses (see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”), 2006 merger with Cinergy, 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006, 2005 DENA disposition, 2005 deconsolidation of DCP Midstream effective July 1, 2005, and 2005 Duke Energy Field Services, LLC (DEFS) sale of Texas Eastern Products Pipeline Company, LLC (TEPPCO).

(b) Periods prior to 2009 have been recast to reflect the adoption of the noncontrolling interest presentation provisions of Accounting Standards Codification 810 – Consolidation, which was adopted by Duke Energy effective January 1, 2009.

(c) 2006 increase primarily attributable to issuance of approximately 313 million shares in connection with Duke Energy’s merger with Cinergy.

(d) 2007 decrease due to the spin-off of the natural gas businesses to shareholders on January 2, 2007 as dividends subsequent to the spin-off were split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximated the former total dividend of Duke Energy prior to the spin-off.

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PART II

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

INTRODUCTION

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

EXECUTIVE OVERVIEW

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:

• Obtained favorable rate case outcomes in North Carolina, South Carolina, Ohio and Kentucky which will increase revenues by nearly $460 million upon full implementation.

• Updated/enabled construction work-in-progress (CWIP) recovery for Duke Energy Carolinas’ Cliffside Unit 6 and the Integrated Gasification Combined Cycle (IGCC) plant at Duke Energy Indiana’s Edwardsport Generating Station.

• Received approval for cost recovery mechanisms for save-a-watt programs in North Carolina, South Carolina and Ohio. Approval in Indiana is anticipated in February 2010.

• Began deployment of SmartGrid in Ohio, along with the initiation of a rate rider cost recovery mechanism, which is awaiting approval and a ruling is expected in the first quarter of 2010. Additionally, Duke Energy was awarded a stimulus grant for approximately $200 million to be used for reimbursement of costs related to SmartGrid.

• Received approvals of wind, solar and other renewable energy projects, which will enable innovative renewable energy initiatives and help Duke Energy meet specific renewable energy standards over time.

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.

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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.

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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.”

RESULTS OF OPERATIONS

Consolidated Operating Revenues

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:

• An approximate $726 million decrease at U.S. Franchised Electric and Gas. See Operating Revenue discussion within “Segment Results” for U.S. Franchised Electric and Gas below for further information; and

• An approximate $27 million decrease at International Energy. See Operating Revenue discussion within “Segment Results” for International Energy below for further information.

Partially offsetting these decreases was:

• An approximate $288 million increase at Commercial Power. See Operating Revenue discussion within “Segment Results” for Commercial Power below for further information.

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:

• An approximate $419 million increase at U.S. Franchised Electric and Gas. See Operating Revenue discussion within “Segment Results” for U.S. Franchised Electric and Gas below for further information; and

• An approximate $125 million increase at International Energy. See Operating Revenue discussion within “Segment Results” for International Energy below for further information.

Partially offsetting these increases was:

• An approximate $55 million decrease at Commercial Power. See Operating Revenue discussion within “Segment Results” for Commercial Power below for further information.

Consolidated Operating Expenses

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:

• An approximate $626 million decrease at U.S. Franchised Electric and Gas. See Operating Expense discussion within “Segment Results” for U.S. Franchised Electric and Gas below for further information;

• An approximate $65 million decrease at International Energy. See Operating Expense discussion within “Segment Results” for International Energy below for further information; and

• An approximate $40 million decrease at Other. See Operating Expense discussion within “Segment Results” for Other below for further information.

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Partially offsetting these decreases was:

• An approximate $489 million increase at Commercial Power, which includes approximately $413 million of impairment charges in 2009 primarily related to a goodwill impairment charge associated with the non-regulated generation operations in the Midwest. See Operating Expense discussion within “Segment Results” for Commercial Power below for further information.

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:

• An approximate $401 million increase at U.S. Franchised Electric and Gas. See Operating Expense discussion within “Segment Results” for U.S. Franchised Electric and Gas below for further information;

• An approximate $123 million increase at International Energy. See Operating Expense discussion within “Segment Results” for International Energy below for further information; and

• An approximate $27 million increase at Commercial Power. See Operating Expense discussion within “Segment Results” for Commercial Power below for further information.

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

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.

Consolidated Operating Income

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.

Consolidated Other Income and Expenses

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).

Consolidated Interest Expense

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.

Consolidated Income Tax Expense from Continuing Operations

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.

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

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.

Extraordinary Item, net of tax

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.

Segment Results

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.

EBIT by Business Segment

	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	)

(a) Other within Interest income and other includes foreign currency transaction gains and losses and additional noncontrolling interest amounts not allocated to reportable segment and Other EBIT.

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.

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U.S. Franchised Electric and Gas

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).

	Years Ended December 31,
	2009		2008		Variance 2009 vs. 2008			2007		Variance 2008 vs. 2007
	(in millions, except where noted)
Operating revenues	$	9,433	$	10,159	$	(726	)	$	9,740	$	419
Operating expenses		7,263		7,889		(626	)		7,488		401
Gains (losses) on sales of other assets and other, net		20		6		14			—		6
Operating income		2,190		2,276		(86	)		2,252		24
Other income and expenses, net		131		122		9			53		69
EBIT	$	2,321	$	2,398	$	(77	)	$	2,305	$	93
Duke Energy Carolinas’ GWh sales(a)		79,830		85,476		(5,646	)		86,604		(1,128	)
Duke Energy Midwest GWh sales(a)(b)		56,753		62,523		(5,770	)		64,570		(2,047	)
Net proportional MW capacity in operation(c)		26,957		27,438		(481	)		27,586		(148	)

(a) Gigawatt-hours (GWh).

(b) Duke Energy Ohio (Ohio transmission and distribution only), Duke Energy Indiana and Duke Energy Kentucky collectively referred to as Duke Energy Midwest within this U.S. Franchised Electric and Gas segment discussion.

(c) Megawatt (MW).

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

	2009		2008		2007
Increase (decrease) over prior year
Residential sales(a)	(0.2	)%	(0.5	)%	6.5	%
General service sales(a)	(1.1	)%	(0.5	)%	5.4	%
Industrial sales(a)	(15.2	)%	(5.5	)%	(2.3	)%
Wholesale sales	(31.6	)%	11.9	%	40.9	%
Total Duke Energy Carolinas’ sales(b)	(6.6	)%	(1.3	)%	4.8	%
Average number of customers	0.5	%	1.5	%	2.0	%

(a) Major components of Duke Energy Carolinas’ retail sales.

(b) Consists of all components of Duke Energy Carolinas’ sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

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

	2009		2008		2007
Increase (decrease) over prior year
Residential sales(a)	(4.3	)%	(3.0	)%	6.7	%
General service sales(a)	(3.5	)%	(1.2	)%	6.3	%
Industrial sales(a)	(15.0	)%	(6.5	)%	(0.4	)%
Wholesale sales	(20.8	)%	1.5	%	7.7	%
Total Duke Energy Midwest’s sales(b)	(9.2	)%	(3.2	)%	4.5	%
Average number of customers	(0.3	)%	0.3	%	0.8	%

(a) Major components of Duke Energy Midwest’s retail sales.

(b) Consists of all components of Duke Energy Midwest’s sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

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Year Ended December 31, 2009 as Compared to December 31, 2008

Operating Revenues. The decrease was driven primarily by:

• A $536 million decrease in fuel revenues (including emission allowances) driven primarily by decreased demand from retail and near-term wholesale customers and lower natural gas fuel rates primarily in Ohio and Kentucky, partially offset by higher fuel rates for electric retail customers. Fuel revenues represent sales to both retail and wholesale customers;

• A $117 million decrease due to lower weather normalized sales volumes to retail customers largely reflecting the overall declining economic conditions in 2009, which primarily impacted the industrial sector;

• A $63 million decrease in GWh and thousand cubic feet (Mcf) sales to retail customers due to overall milder weather conditions in 2009 compared to 2008. Weather statistics for heating degree days in 2009 were unfavorable in the Midwest but favorable in the Carolinas compared to 2008. Weather statistics for cooling degree days in 2009 were unfavorable in both the Midwest and Carolinas compared to 2008; and

• A $30 million net decrease in wholesale power revenues, net of sharing, primarily due to decreased sales volumes and lower prices on near-term sales as a result of weak market conditions, partially offset by higher prices and increased sales volumes to customers served under certain long-term contracts.

Partially offsetting these decreases was:

• A $31 million net increase in retail rates and rate riders primarily due to increases in recoveries of Duke Energy Indiana’s environmental compliance costs and the IGCC rider, partially offset by the expiration of the one-time increment rider related to merger savings that was included in North Carolina retail rates in 2008.

Operating Expenses. The decrease was driven primarily by:

• A $541 million decrease in fuel expense (including purchased power and natural gas purchases for resale) primarily due to a lower volume of coal used in electric generation, lower prices and volumes for natural gas purchased for resale and used in electric generation and reduced purchased power, partially offset by higher coal prices;

• A $71 million decrease in operating and maintenance expenses primarily due to lower scheduled outage and maintenance costs at nuclear and fossil generating stations, lower power and gas delivery maintenance and decreased capacity costs due to the expiration of certain drought mitigation contracts in 2008, partially offset by higher benefits costs; and

• A $36 million decrease in depreciation and amortization due primarily to lower depreciation rates in the Carolinas, partially offset by increases in depreciation due primarily to additional capital spending.

Partially offsetting these decreases was:

• A $22 million increase in property and other taxes due primarily to normal increases.

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.

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

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.

Year Ended December 31, 2008 as Compared to December 31, 2007

Operating Revenues. The increase was driven primarily by:

• A $474 million increase in fuel revenues (including emission allowances) driven primarily by higher fuel rates in all regions and legislative changes that allow Duke Energy Carolinas to collect additional purchased power and environmental compliance costs from retail customers. Fuel revenues represent sales to both retail and wholesale customers; and

• A $92 million increase related to substantial completion in 2007 of the sharing of anticipated merger savings through rate decrement riders with regulated customers.

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Partially offsetting these increases were:

• A $73 million decrease in weather adjusted sales volumes to retail customers reflecting the overall declining economic conditions, which are primarily impacting the industrial sector;

• A $53 million decrease in retail rates and rate riders primarily related to the new retail base rates implemented in North Carolina in the first quarter of 2008, net of increases in recoveries of Duke Energy Indiana’s environmental compliance costs from retail customers and higher gas base rates implemented in the second quarter of 2008 for Duke Energy Ohio; and

• A $49 million decrease in GWh and Mcf sales to retail customers due to milder weather in 2008 compared to 2007. While weather statistics for heating degree days in 2008 were favorable compared to 2007, this favorable impact was more than offset by the impact of fewer cooling degree days in 2008 compared to 2007.

Operating Expenses. The increase was driven primarily by:

• A $441 million increase in fuel expense (including purchased power and natural gas purchases for resale) primarily due to higher coal and natural gas prices and increased purchased power. This increase also reflects a $21 million reimbursement in first quarter 2007 of previously incurred fuel expenses resulting from a settlement between Duke Energy Carolinas and U.S. Department of Justice (DOJ) resolving Duke Energy Carolinas’ used nuclear fuel litigation against the Department of Energy (DOE). The settlement between the parties was finalized on March 5, 2007;

• A $67 million increase in depreciation due primarily to additional capital spending; and

• A $66 million increase in operating and maintenance expenses primarily due to higher scheduled outage and maintenance costs at nuclear and fossil generating plants, storm costs primarily in the Midwest related to Hurricane Ike in September 2008 net of deferral of a portion of the Ohio and Kentucky storm costs associated with Hurricane Ike, increased capacity costs due to additional contracts that were entered into in late 2007 to ensure customer electricity needs were met despite ongoing drought conditions and increased power delivery maintenance charges to increase system reliability, partially offset by lower benefit costs including short-term incentives.

Partially offsetting these increases was:

• A $170 million decrease in regulatory amortization expenses, including approximately $187 million for the amortization of compliance costs related to North Carolina clean air legislation, which was completed in 2007. This decrease was partially offset by the write-off in 2007 of a portion of the investment in the GridSouth Regional Transmission Organization (RTO) (approximately $17 million) per a rate order from the NCUC.

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.

Commercial Power

	Years Ended December 31,
	2009			2008		Variance 2009 vs. 2008			2007			Variance 2008 vs. 2007
	(in millions, except where noted)
Operating revenues	$	2,114		$	1,826	$	288		$	1,881		$	(55	)
Operating expenses		2,134			1,645		489			1,618			27
Gains (losses) on sales of other assets and other, net		12			59		(47	)		(7	)		66
Operating income		(8	)		240		(248	)		256			(16	)
Other income and expenses, net		35			24		11			22			2
EBIT	$	27		$	264	$	(237	)	$	278		$	(14	)
Actual plant production, GWh		26,962			20,199		(6,763	)		23,702			(3,503	)
Net proportional megawatt capacity in operation		8,005			7,641		364			8,019			(378	)

Year Ended December 31, 2009 as compared to December 31, 2008

Operating Revenues. The increase was primarily driven by:

• A $98 million increase in retail electric revenues resulting from higher retail pricing principally related to implementation of the ESP in 2009 and the timing of fuel and purchased power rider collections in 2008, net of lower sales volumes driven by the economy and increased customer switching levels;

• A $70 million increase in net mark-to-market revenues on non-qualifying power and capacity hedge contracts, consisting of mark-to-market losses of $2 million in 2009 compared to losses of $72 million in 2008;

• A $68 million increase in revenues due to higher generation volumes and increased PJM capacity revenues from the Midwest gas-fired assets in 2009 compared to 2008;

• A $48 million increase in wholesale electric revenues due to higher generation volumes and hedge realization in 2009 compared to 2008 and margin earned from participation in wholesale auctions in 2009; and

• A $25 million increase in wind generation revenues due to commencement of operations of wind facilities in the third quarter of 2008 and additional wind generation facilities placed in service in 2009.

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Operating Expenses. The increase was primarily driven by:

• A $413 million impairment charge primarily related to goodwill associated with non-regulated generation operations in the Midwest;

• A $55 million increase in fuel expense due to mark-to-market losses on non-qualifying fuel hedge contracts, consisting of mark-to-market losses of $58 million in 2009 compared to losses of $3 million in 2008;

• A $44 million increase in depreciation and administrative expenses associated with wind projects placed in service in the third quarter of 2008 and throughout 2009, as well as the continued development of the renewable business in 2009;

• A $36 million increase in operating expenses resulting from depreciation expense on environmental projects placed in service in the second half of 2008 and higher plant maintenance expenses resulting from increased plant outages in 2009 compared to 2008;

• A $29 million increase in retail and wholesale fuel expense due to higher purchased power expenses and higher long-term contract prices and lower realized gains on fuel hedges in 2009 compared to 2008; and

• A $10 million increase in fuel and operating expenses for the Midwest gas-fired assets primarily due to higher generation volumes in 2009 compared to 2008, partially offset by bad debt reserves recorded in 2008 associated with the Lehman Brothers bankruptcy.

Partially offsetting these increases was:

• An $82 million impairment of emission allowances due to the invalidation of the Clean Air Interstate Rule (CAIR) in July 2008.

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.

Matters Impacting Future Commercial Power Results

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.

Year Ended December 31, 2008 as compared to December 31, 2007

Operating Revenues. The decrease was primarily driven by:

• A $21 million decrease in wholesale electric revenues due to lower hedge realization and lower generation volumes primarily resulting from increased plant outages in 2008 compared to 2007;

• A $20 million decrease in net mark-to-market revenues on non-qualifying power and capacity hedge contracts, consisting of mark-to-market losses of $72 million in 2008 compared to losses of $52 million in 2007; and

• A $17 million decrease in revenues due to lower generation volumes from the Midwest gas-fired assets resulting from milder weather net of increased PJM capacity revenues in 2008 compared to 2007.

Operating Expenses. The increase was primarily driven by:

• An $82 million impairment of emission allowances due to the invalidation of the CAIR in July 2008;

• A $68 million increase in fuel expense due to mark-to-market losses on non-qualifying fuel hedge contracts, consisting of mark-to-market losses of $3 million in 2008 compared to gains of $65 million in 2007; and

• A $14 million increase in plant maintenance expenses resulting from increased plant outages in 2008 compared to 2007.

Partially offsetting these increases were:

• A $63 million decrease in emission allowance expenses due to lower cost basis emission allowances consumed and lower overall emission allowance consumption due to installation of flue gas desulfurization equipment and lower generation volumes due to increased plant outages in 2008 compared to 2007;

• A $46 million decrease in net fuel and purchased power expense for retail load due to realized gains on fuel hedges partially offset by higher purchased power as a result of increased plant outages in 2008 compared to 2007; and

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• A $24 million decrease in fuel and operating expenses for the Midwest gas-fired assets primarily due to lower generation volumes and lower amortization of locked-in hedge losses in 2008 compared to 2007, net of an approximate $15 million bad debt reserve related to the Lehman Bros. bankruptcy and higher plant maintenance expenses.

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.

International Energy

	Years Ended December 31,
	2009		2008		Variance 2009 vs. 2008			2007		Variance 2008 vs. 2007
	(in millions, except where noted)
Operating revenues	$	1,158	$	1,185	$	(27	)	$	1,060	$	125
Operating expenses		834		899		(65	)		776		123
Gains (losses) on sales of other assets and other, net		—		1		(1	)		—		1
Operating income		324		287		37			284		3
Other income and expenses, net		63		146		(83	)		114		32
Expense attributable to noncontrolling interest		22		22		—			10		12
EBIT	$	365	$	411	$	(46	)	$	388	$	23
Sales, GWh		19,978		18,066		1,912			17,127		939
Net proportional megawatt capacity in operation		4,053		4,018		35			3,968		50

Year Ended December 31, 2009 as Compared to December 31, 2008

Operating Revenues. The decrease was driven primarily by:

• A $41 million decrease in Peru due to unfavorable average hydrocarbon and spot prices; and

• A $16 million decrease in Central America due to lower average sales prices and lower dispatch in El Salvador, partially offset by favorable hydrology in Guatemala as a result of drier weather.

Partially offsetting these decreases was:

• A $29 million increase in Ecuador due to higher dispatch as a result of drier weather.

Operating Expenses. The decrease was driven primarily by:

• An $81 million decrease in Peru due to lower purchased power costs, thermal generation and hydrocarbon royalty costs; and

• A $55 million decrease in Central America due to lower fuel costs.

Partially offsetting these decreases was:

• A $31 million increase in Ecuador due to higher fuel consumption and the reversal of a bad debt allowance as a result of collection of an arbitration award in the prior year;

• A $24 million increase in Brazil due to transmission cost adjustments, partially offset by favorable exchange rates; and

• An $8 million increase in general and administrative expenses due to reorganization costs and higher legal costs.

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.

Matters Impacting Future International Energy Results

International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand, 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.

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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.

Year Ended December 31, 2008 as Compared to December 31, 2007

Operating Revenues. The increase was driven primarily by:

• A $60 million increase in Brazil due to higher sales prices, higher demand and favorable exchange rates;

• A $49 million increase in Guatemala and El Salvador due to favorable sales prices partially offset by lower dispatch; and

• A $15 million increase in Argentina due to favorable sales prices as a result of higher demand.

Operating Expenses. The increase was driven primarily by:

• A $70 million increase in Guatemala and El Salvador primarily due to higher fuel prices;

• A $57 million increase in Peru primarily due to higher purchased power, fuel costs, and royalty fees due to unfavorable hydrology and higher oil reference pricing; and

• A $15 million increase in Argentina due to higher gas and power marketing purchases and increased fuel prices.

Partially offsetting these increases was:

• A $24 million decrease in Ecuador due to lower fuel consumption and maintenance costs as a result of lower thermal dispatch and the reversal of a bad debt allowance as a result of collection of an arbitration award; and

• A $5 million decrease in Brazil due to a transmission credit adjustment and reversal of a bad debt allowance as a result of a customer settlement, partially offset by unfavorable exchange rates.

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.

Other

	Years Ended December 31,
	2009			2008			Variance 2009 vs. 2008			2007			Variance 2008 vs. 2007
	(in millions)
Operating revenues	$	128		$	134		$	(6	)	$	167		$	(33	)
Operating expenses		389			429			(40	)		467			(38	)
Gains (losses) on sales of other assets and other, net		4			3			1			2			1
Operating income		(257	)		(292	)		35			(298	)		6
Other income and expenses, net		2			(288	)		290			37			(325	)
Benefit attributable to noncontrolling interest		(4	)		(12	)		(8	)		(1	)		(11	)
EBIT	$	(251	)	$	(568	)	$	317		$	(260	)	$	(308	)

Year Ended December 31, 2009 as Compared to December 31, 2008

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.

Matters Impacting Future Other Results

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

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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.

Year Ended December 31, 2008 as Compared to December 31, 2007

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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

Regulatory Accounting

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

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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.

Goodwill Impairment Assessments

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.

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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.

Revenue Recognition

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

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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.

Accounting for Loss Contingencies

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.”

Accounting for Income Taxes

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

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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.”

Pension and Other Post-Retirement Benefits

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 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:

	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

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	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

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:

	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)

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

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

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:

• $4.2 billion at U.S. Franchised Electric and Gas

• $0.6 billion at Commercial Power

• $0.2 billion at International Energy and

• $0.2 billion at Other

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

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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.

Operating Cash Flows

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:

• Excluding the impacts of non-cash impairment charges, net income increased during the year ended December 31, 2009 compared to the same period in 2008, and

• Changes in traditional working capital amounts due to timing of cash receipts and cash payments, principally a net increase in cash from taxes of approximately $740 million, partially offset by an increase in coal inventory, partially offset by

• An approximate $800 million increase in contributions to company sponsored pension plans.

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:

• An approximate $412 million decrease in contributions to Duke Energy’s pension plan and other post retirement benefit plans, partially offset by

• Net income of $1,362 million in 2008 compared to $1,500 million in 2007.

Investing Cash Flows

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.

Capital, Investment and Acquisition Expenditures by Business Segment

	Years Ended December 31,
	2009		2008		2007
	(in millions)
U.S. Franchised Electric and Gas	$	3,560	$	3,650	$	2,613
Commercial Power		688		870		442
International Energy		128		161		74
Other		181		241		153
Total consolidated	$	4,557	$	4,922	$	3,282

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

• An approximate $365 million decrease in capital, investment and acquisition expenditures, due primarily to 2008 acquisitions discussed below.

This decrease in cash used was partially offset by the following:

• An approximate $125 million decrease in proceeds from available-for-sale securities, net of purchases, due to net purchases of approximately $25 million in 2009 compared to net proceeds of approximately $100 million in 2008,

• An approximate $70 million decrease in net emission allowance activity, reflecting net purchases in 2009 compared to net sales in 2008, and

• An approximate $30 million decrease in proceeds from asset sales.

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

• An approximate $1,640 million increase in capital and investment expenditures, due primarily to capital expansion projects, the acquisition of Catamount (approximately $245 million) and the purchase of a portion of Saluda River Electric Cooperative (Saluda), Inc.’s ownership interest in the Catawba Nuclear Station in 2008 (approximately $150 million),

• An approximate $875 million decrease in proceeds from available-for-sale securities, net of purchases, due to net proceeds of approximately $100 million in 2008 compared to net proceeds of approximately $975 million in 2007, primarily as a result of investing

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excess cash obtained from the issuances of debt during 2008 versus utilizing short-term investments as a source of cash in 2007, and

• An approximate $60 million decrease in proceeds from asset sales.

These increases in cash used were partially offset by the following:

• An approximate $100 million increase in proceeds from the sale of emission allowances, net of purchases.

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Financing Cash Flows and Liquidity

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:

• An approximate $475 million decrease due to the repayment of the Duke Energy Ohio credit facility drawdown and outstanding commercial paper, and

• An approximate $80 million increase in dividends paid in 2009.

These decreases in cash provided were partially offset by:

• An approximate $385 million increase in proceeds from the issuances of common stock primarily related to the DRIP and other internal plans, and

• An approximate $210 million increase in proceeds from issuances of long-term debt, net of redemptions, as a result of net issuances of approximately $2,875 million during 2009 as compared to net issuances of approximately $2,665 million during 2008.

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:

• An approximate $3,090 million increase in proceeds from issuances of long-term debt, net of redemptions, as a result of net issuances of approximately $2,665 million during 2008 as compared to net repayments of approximately $425 million during 2007,

• An approximate $400 million increase due to the distribution of cash in 2007 related to the spin-off of Spectra Energy,

• An approximate $110 million increase due to payments for the redemption of convertible notes in 2007, and

• An approximate $80 million increase in proceeds from the issuances of common stock primarily related to the DRIP and other internal plans.

These increases were partially offset by:

• An approximate $690 million decrease in proceeds from issuances of notes payable and commercial paper, net of repayments, and

• An approximate $50 million increase in dividends paid in 2008.

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

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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

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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.

Master Credit Facility Summary as of December 31, 2009 (in millions)^(a)

	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

(a) This summary excludes certain demand facilities and committed facilities that are insignificant in size or which generally support very specific requirements, which primarily include facilities that backstop various outstanding tax-exempt bonds.

(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower.

(c) Contains sub limits at December 31, 2009 as follows: $1,097 million for Duke Energy, $840 million for Duke Energy Carolinas, $650 million for Duke Energy Ohio, $450 million for Duke Energy Indiana and $100 million for Duke Energy Kentucky.

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.

Senior Unsecured Credit Ratings Summary as of February 1, 2010

	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

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.

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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.

Off-Balance Sheet Arrangements

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include 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.”

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Contractual Obligations

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

Contractual Obligations as of December 31, 2009

	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

(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.” Amount includes interest payments over life of debt. Interest payments on variable rate debt instruments were calculated using interest rates derived from the interpolation of the forecast interest rate curve. In addition, a spread was placed on top of the interest rates to aid in capturing the volatility inherent in projecting future interest rates.

(b) See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”. Amounts in the table above include the interest component of capital leases based on the interest rates explicitly stated in the lease agreements.

(c) Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity, and natural gas transportation contracts.

(d) Includes contractual obligations to purchase physical quantities of electricity, coal, nuclear fuel and limestone. Also, includes contracts that Duke Energy has designated as hedges, undesignated contracts and contracts that qualify as normal purchase/normal sale (NPNS). For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2009. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties.

(e) Includes contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for new generation plants and nuclear plant refurbishments, environmental projects on fossil facilities, major maintenance of certain non-regulated plants, maintenance and day to day contract work at certain wind facilities and commitments to buy wind and combustion turbines (CT). Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase cannot be determined.

(f) Relates to future annual funding obligations to the nuclear decommissioning trust fund (NDTF) (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations”).

(g) The table above excludes certain obligations discussed herein related to amounts recorded within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets due to the uncertainty of the timing and amount of future cash flows necessary to settle these obligations. The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Duke Energy may use internal resources or external resources to perform retirement activities. As a result, cash obligations for asset retirement activities are excluded from the table above. However, the vast majority of asset retirement obligations will be settled beyond 2014. Asset retirement obligations recognized on the Consolidated Balance Sheets total $3,185 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,765 million at December 31, 2009. The table above excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing of when cash payments will be required. Additionally, the table above excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of pension and other post-retirement benefit plans (see Note 20 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory liabilities (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also excluded are Deferred Income Taxes and Investment Tax Credits recorded on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Additionally, amounts related to uncertain tax positions are excluded from the table above due to uncertainty of timing of future payments.

(h) Current liabilities, except for current maturities of long-term debt, and purchase obligations reflected in the Consolidated Balance Sheets, have been excluded from the above table.

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Quantitative and Qualitative Disclosures About Market Risk

Risk Management Policies

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.

Commodity Price Risk

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

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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

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 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.

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.

Interest Rate Risk

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.

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Marketable Securities Price Risk

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:

	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

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.

Foreign Currency Risk

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.

Other Issues

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

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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

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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.”

New Accounting Standards

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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

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

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Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Duke Energy Corporation

Charlotte, North Carolina

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.

/s/ DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 26, 2010

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DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per-share amounts)

	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

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In millions)

	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

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS - (Continued)

(In millions, except per-share amounts)

	December 31,
	2009			2008
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	1,390		$	1,477
Notes payable and commercial paper		-			543
Taxes accrued		428			362
Interest accrued		222			187
Current maturities of long-term debt		902			646
Other		1,146			1,130
Total current liabilities		4,088			4,345
Long-term Debt		16,113			13,250
Deferred Credits and Other Liabilities
Deferred income taxes		5,615			5,117
Investment tax credits		310			148
Asset retirement obligations		3,185			2,567
Other		5,843			6,499
Total deferred credits and other liabilities		14,953			14,331
Commitments and Contingencies
Equity
Common Stock, $0.001 par value, 2 billion shares authorized; 1,309 million and 1,272 million shares outstanding at December 31, 2009 and December 31, 2008, respectively		1			1
Additional paid-in capital		20,661			20,106
Retained earnings		1,460			1,607
Accumulated other comprehensive loss		(372	)		(726	)
Total Duke Energy Corporation shareholders’ equity		21,750			20,988
Noncontrolling Interests		136			163
Total equity		21,886			21,151
Total Liabilities and Equity	$	57,040		$	53,077

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2009		2008		2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,085	$	1,358	$	1,502
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)		1,846		1,834		1,888
Extraordinary items, net of tax		-		(67)		-
(Gains) losses on sales of other assets		(44)		(95)		10
Impairment of goodwill and other impairment charges		449		94		-
Deferred income taxes		941		485		669
Equity in (earnings) loss of unconsolidated affiliates		(70)		102		(157)
Contributions to qualified pension plans		(800)		-		(412)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		4		(33)		-
Receivables		(38)		189		(240)
Inventory		(298)		(209)		(36)
Other current assets		277		(449)		(22)
Increase (decrease) in
Accounts payable		(80)		(136)		(172)
Taxes accrued		52		47		(134)
Other current liabilities		70		(88)		(321)
Other assets		(9)		236		739
Other liabilities		78		60		(106)
Net cash provided by operating activities		3,463		3,328		3,208
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(4,296)		(4,386)		(3,125)
Investment expenditures		(137)		(147)		(91)
Acquisitions, net of cash acquired		(124)		(389)		(66)
Purchases of available-for-sale securities		(3,013)		(7,353)		(23,639)
Proceeds from sales and maturities of available-for-sale securities		2,988		7,454		24,613
Net proceeds from the sales of other assets, and sales of and collections on notes receivable		70		92		154
Settlement of net investment hedges and other investing derivatives		-		-		(10)
Purchases of emission allowances		(93)		(62)		(103)
Sales of emission allowances		67		104		52
Change in restricted cash		58		115		68
Other		(12)		(39)		(4)
Net cash used in investing activities		(4,492)		(4,611)		(2,151)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		4,409		4,794		823
Issuance of common stock related to employee benefit plans		519		133		50
Payments for the redemption of:
Long-term debt		(1,533)		(2,130)		(1,248)
Convertible notes		-		-		(110)
Decrease in cash overdrafts		-		-		(2)
Notes payable and commercial paper		(548)		(73)		617
Distributions to noncontrolling interests		(37)		(2)		(52)
Contributions from noncontrolling interests		-		6		68
Cash distributed to Spectra Energy		-		-		(395)
Dividends paid		(1,222)		(1,143)		(1,089)
Other		(3)		6		11
Net cash provided by (used in) financing activities		1,585		1,591		(1,327)
Net increase (decrease) in cash and cash equivalents		556		308		(270)
Cash and cash equivalents at beginning of period		986		678		948
Cash and cash equivalents at end of period	$	1,542	$	986	$	678
Supplemental Disclosures:
Cash paid for interest, net of amount capitalized	$	689	$	677	$	827
Cash (received) paid for income taxes	$	(419)	$	322	$	367
Significant non-cash transactions:
Distribution of Spectra Energy to shareholders	$	-	$	-	$	5,219
Accrued capital expenditures	$	428	$	378	$	570

See Notes to Consolidated Financial Statements

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CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME

(In millions)

										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

(a) Net unrealized gains (losses) on cash flow hedges, net of $1 tax expense in 2009, $6 tax expense in 2008 and $9 tax benefit in 2007.

(b) Reclassification into earnings from cash flow hedges, net of $10 tax expense in 2009, $2 tax expense in 2008 and zero in 2007.

(c) Net actuarial gain net of $54 tax expense in 2007.

(d) Net of zero tax expense in 2007.

(e) Net actuarial loss net of $12 tax benefit in 2009 and $159 tax benefit in 2008.

(f) Net of $4 tax benefit in 2009 and $18 tax benefit in 2008.

(g) Net of $2 tax expense in 2009 and $5 tax benefit in 2008.

(h) Net of $4 tax expense in 2009 and $8 tax benefit in 2008.

(i) Net of $16 tax expense in 2009.

See Notes to Consolidated Financial Statements

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Notes To Consolidated Financial Statements

For the Years Ended December 31, 2009, 2008 and 2007

1. Summary of Significant Accounting Policies

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.

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. Refer to the following section titled, “Reapplication of Regulatory Accounting Treatment to Portions of Generation in Ohio.”

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

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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.

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.

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.

Components of Inventory

	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

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

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Notes To Consolidated Financial Statements—(Continued)

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.

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 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.

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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.

See Note 16 for further information.

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

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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

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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

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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

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on its consolidated results of operations, cash flows or financial position.

2. Business Segments

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.

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Business Segment Data^(a)

	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		—		—		—

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	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)
Total consolidated	$  12,720	$  —	$  12,720	$  2,236	$  1,746	$  3,282	$	49,686

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

(b) Includes assets held for sale and assets of entities in discontinued operations. See Note 12 for description and carrying value of investments accounted for under the equity method of accounting within each segment.

(c) As discussed further in Note 11, during the year ended December 31, 2009, Commercial Power recorded impairment charges of approximately $413 million, which consists primarily of a goodwill impairment charge associated with its Midwest non-regulated generation assets.

(d) Other within interest income and other includes foreign currency transaction gains and losses and additional noncontrolling interest expense not allocated to the segment results.

(e) As discussed further in Note 12, Duke Energy recorded its proportionate share of impairment charges recorded by Crescent of approximately $238 million during the year ended December 31, 2008.

Geographic Data

	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

(a) Change in amounts of long-lived assets in Latin America is primarily due to foreign currency translation adjustments on property, plant and equipment and other long-lived asset balances.

3. Acquisitions and Dispositions of Businesses and Sales of Other Assets

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 23 ¹/₂ 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.

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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.

4. Regulatory Matters

Regulatory Assets and Liabilities.

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.

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Duke Energy’s Regulatory Assets and Liabilities:

	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

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

(b) Recovery/Refund period varies for these items with some currently unknown.

(c) Included in rate base.

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

(e) Included in Other Current Assets on the Consolidated Balance Sheets.

(f) Included in Accounts Receivable and Other Assets on the Consolidated Balance Sheets.

(g) North Carolina portion of approximately $7 million to be recovered in rates through 2012. South Carolina portion of approximately $9 million to be recovered in retail rates through 2014.

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

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

(j) Duke Energy is required to pay interest on the outstanding balance.

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

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

(m) Included in Accounts Payable and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(n) Included in Other Current Liabilities on the Consolidated Balance Sheets.

(o) Recovery is over the life of the associated asset.

(p) Incurred costs were deferred and are being recovered in rates. U.S. Franchised Electric and Gas is over-recovered for approximately $140 million of these costs in the South Carolina jurisdiction at December 31, 2009. South Carolina over-recovery will be refunded via a rate rider implemented February 2010 that is expected to return these funds over approximately three years, dependent on volume of sales in that jurisdiction.

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

(r) Approximately $75 million and $95 million of the balance at December 31, 2009 and 2008, respectively, relates to mark-to-market deferrals associated with open native load hedge positions at Commercial Power.

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(s) Represents the latest recovery period across all jurisdictions in which Duke Energy operates. Regulatory asset and liability balances may be collected or refunded sooner than the indicated date in certain jurisdictions.

(t) North Carolina has approved earning a return on the outstanding balance. South Carolina will not earn a return during the refund period.

(u) Approximately $88 million and an insignificant amount at December 31, 2009 and 2008, respectively, relates to under collections of Commercial Power’s native load fuel costs.

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.

U.S. Franchised Electric and Gas.

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

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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

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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.

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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.

Capital Expansion Projects.

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

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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 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, 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.

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 and construction is underway.

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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.

Other U.S. Franchised Electric and Gas Matters.

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

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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.

Commercial Power.

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.

5. Joint Ownership of Generating and Transmission Facilities

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.

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

	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	—

(a) Included in U.S. Franchised Electric and Gas segment.

(b) Included in Commercial Power segment.

(c) Station is not operated by Duke Energy Ohio.

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.

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6. Income Taxes

The following details the components of income tax expense:

Income Tax Expense

	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

(a) Included in the “Total current income taxes” line above are uncertain tax benefits relating primarily to certain temporary differences of approximately $91 million for 2009, $46 million for 2008 and $245 million for 2007.

Income from Continuing Operations before Income Taxes

	For the Years Ended December 31,
	2009		2008		2007
	(in millions)
Domestic	$	1,433	$	1,575	$	1,894
Foreign		398		316		342
Total income from continuing operations before income taxes	$	1,831	$	1,891	$	2,236

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

	For the Years Ended December 31,
	2009			2008			2007
	(in millions)
Income tax expense, computed at the statutory rate of 35%	$	641		$	663		$	782
State income tax, net of federal income tax effect		98			43			40
Tax differential on foreign earnings		(16	)		3			(23	)
Goodwill impairment charge		130			—			—
AFUDC equity income		(53	)		(52	)		(24	)
Other items, net		(42	)		(41	)		(63	)
Total income tax expense from continuing operations	$	758		$	616		$	712
Effective tax rate		41.4	%		32.5	%		31.9	%

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.

Net Deferred Income Tax Liability Components

	December 31,
	2009			2008
	(in millions)
Deferred credits and other liabilities	$	591		$	995
Tax Credit Carryforwards(a)		290			—
Other		260			—
Total deferred income tax assets		1,141			995
Valuation allowance		(163	)		(94	)
Net deferred income tax assets		978			901
Investments and other assets		(594	)		(764	)
Accelerated depreciation rates		(4,744	)		(4,125	)
Regulatory assets and deferred debits		(1,184	)		(856	)
Other		—			(30	)
Total deferred income tax liabilities		(6,522	)		(5,775	)
Net deferred income tax liabilities	$	(5,544)		$	(4,874)

(a) Of the tax credit carryforwards, approximately $218 million relate to investment tax credits expiring in 2029 and approximately $72 million relates to alternative minimum tax credits that have no expiration.

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

Deferred Tax Liabilities

	December 31,
	2009		2008
	(in millions)
Current deferred tax assets, included in other current assets	$	3	$	158
Non-current deferred tax assets, included in other investments and other assets		95		97
Current deferred tax liabilities, included in other current liabilities		(27)		(12)
Non-current deferred tax liabilities		(5,615)		(5,117)
Total net deferred income tax liabilities	$	(5,544)	$	(4,874)

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.

Changes to Unrecognized Tax Benefits

	2009				2008				2007
	Increase/   (Decrease)				Increase/ (Decrease)				Increase/ (Decrease)
	(in millions)
Unrecognized Tax Benefits—January 1,		$	572			$	348			$	499
Spin-off of Spectra Energy			—				—				(78	)
Unrecognized Tax Benefits – January 2,			572				348				421
Unrecognized Tax Benefits Changes
Gross increases—tax positions in prior periods			132				294				36
Gross decreases—tax positions in prior periods			(38	)			(65	)			(56	)
Gross increases—current period tax positions			11				5				1
Settlements			(13	)			(7	)			(52	)
Lapse of statute of limitations			—				(3	)			(2	)
Total Changes			92				224				(73	)
Unrecognized Tax Benefits—December 31,		$	664			$	572			$	348

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.

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Duke Energy has the following tax years open.

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

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.

7. Asset Retirement Obligations

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:

	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

(a) As discussed in Note 3, in September 2008, Duke Energy acquired an additional ownership interest in Catawba.

(b) Substantially all of the accretion expense for the years ended December 31, 2009 and 2008 relate to Duke Energy’s regulated electric operations and have been deferred in accordance with regulatory accounting treatment, as discussed above.

(c) As discussed below, Duke Energy updates its nuclear decommissioning costs study every five years as required by the NCUC and PSCSC. The increase in the revisions to estimated cash flows primarily relates to the increase in estimated cost of decommissioning Duke Energy’s nuclear units. Approximately half of the increase in the nuclear decommissioning cost estimates is due to increased labor costs since the completion of the last cost study in 2003. Other assumptions that had changed since the 2003 study that impacted the determination of the asset retirement obligation liability include the inflation rate, market risk premium and credit adjusted risk free rate.

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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.

8. Risk Management, Derivative Instruments and Hedging Activities

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.

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Commodity Price Risk

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 SO₂ emission 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.

Interest Rate Risk

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.

Volumes

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.

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Underlying Notional Amounts for Derivative Instruments Accounted for At Fair Value

	December 31, 2009
Commodity contracts
Electricity-energy (Gigawatt-hours)		3,687
Emission allowances: SO2 (thousands of tons)		9
Emission allowances: NOX (thousands of tons)		2
Natural gas (millions of decatherms)		71
Coal (millions of tons)		2
Financial contracts
Interest rates (dollars in millions)	$	366

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

	December 31, 2009
Balance Sheet Location	Asset Derivatives		Liability Derivatives
	(in millions)
Derivatives Designated as Hedging Instruments
Commodity contracts
Current Assets: Other	$	1	$	—
Interest rate contracts
Current Assets: Other		4		—
Current Liabilities: Other		—		1
Deferred Credits and Other Liabilities: Other		—		6
Total Derivatives Designated as Hedging Instruments	$	5	$	7
Derivatives Not Designated as Hedging Instruments
Commodity contracts
Current Assets: Other	$	59	$	1
Investments and Other Assets: Other		59		2
Current Liabilities: Other		85		232
Deferred Credits and Other Liabilities: Other		44		100
Interest rate contracts
Current Liabilities: Other		—		3
Deferred Credits and Other Liabilities: Other		—		4
Total Derivatives Not Designated as Hedging Instruments	$	247	$	342
Total Derivatives	$	252	$	349

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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

Income

	Year Ended December 31, 2009
	(in millions)
Location of Pre-Tax Losses Reclassified from AOCI into Earnings(a)
Commodity contracts
Revenue, non-regulated electric, natural gas and other	$	(13	)
Fuel used in electric generation and purchased power-non-regulated		(10	)
Interest rate contracts
Interest expense		(5	)
Total Pre-Tax Losses Reclassified from AOCI into Earnings	$	(28	)

(a) Represents the gains and losses on cash flow hedges previously recorded in AOCI during the term of the hedging relationship and reclassified into earnings during the current period.

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

Income or as Regulatory Assets or Liabilities

	Year Ended December 31, 2009
	(in millions)
Location of Pre-Tax Gains Recognized in Earnings
Commodity contracts
Revenue, regulated electric	$	1
Revenue, non-regulated electric, natural gas and other		1
Fuel used in electric generation and purchased power-non-regulated		10
Interest rate contracts
Interest expense		1
Total Pre-Tax Gains Recognized in Earnings	$	13
Location of Pre-Tax Gains (Losses) Recognized as Regulatory Assets or Liabilities
Commodity contracts
Regulatory Asset	$	(48	)
Regulatory Liability		3
Interest rate contracts
Regulatory Asset		1
Total Pre-Tax Losses Recognized as Regulatory Assets or Liabilities	$	(44	)

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Credit Risk

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

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily 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

Features

	December 31, 2009
	(in millions)
Aggregate Fair Value Amounts of Derivative Instruments in a Net Liability Position	$	208
Collateral Already Posted	$	130
Additional Cash Collateral or Letters of Credit in the Event Credit-risk-related Contingent Features were Triggered at the End of the Reporting Period	$	6

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.

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9. Fair Value of Financial Assets and Liabilities

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.

	Total Fair Value Amounts at December 31, 2009			Level 1			Level 2			Level 3
	(in millions)
Description
Investments in available-for-sale auction rate securities(a)(b)		$	198		$	—		$	—		$	198
Nuclear decommissioning trust fund equity securities(b)			1,156			1,156			—			—
Nuclear decommissioning trust fund debt securities(b)			609			36			573			—
Other long-term trading and available-for-sale equity securities(a)(b)			66			60			6			—
Other long-term trading and available-for-sale debt securities(a)(b)			258			32			226			—
Derivative assets(c)			120			1			24			95
Total Assets		$	2,407		$	1,285		$	829		$	293
Derivative liabilities(d)			(217)			(112)			(35)			(70)
Net Assets		$	2,190		$	1,173		$	794		$	223

(a) Included in Other within Investments and Other Assets on the Consolidated Balance Sheets.

(b) See Note 10 for additional information related to investments by major security type.

(c) Included in Other within Current Assets and Other within Investments and Other Assets on the Consolidated Balance Sheets. See Note 8 for additional information regarding derivatives.

(d) Included in Other within Current Liabilities and Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. See Note 8 for additional information regarding derivatives.

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	Total Fair Value Amounts at December 31, 2008				Level 1				Level 2				Level 3
	(in millions)
Description
Investments in available-for-sale auction rate securities(a)(b)		$	224			$	—			$	—			$	224
Nuclear decommissioning trust fund equity securities(b)			831				831				—				—
Nuclear decommissioning trust fund debt securities(b)			605				22				583				—
Other long-term trading and available-for-sale equity securities(b)(c)			80				49				31				—
Other long-term trading and available-for-sale debt securities(b)(c)			234				25				209				—
Derivative assets(d)			251				9				70				172
Total Assets		$	2,225			$	936			$	893			$	396
Derivative liabilities(e)			(341	)			(88	)			(115	)			(138	)
Net Assets		$	1,884			$	848			$	778			$	258

(a) Approximately $173 million of auction rate securities are included in Other within Investments and Other Assets and approximately $51 million are classified as Short-Term Investments within Current Assets on the Consolidated Balance Sheets.

(b) See Note 10 for additional information related to investments by major security type.

(c) Included in Other within Investments and Other Assets on the Consolidated Balance Sheets.

(d) Included in Other within Current Assets and Other within Investments and Other Assets on the Consolidated Balance Sheets.

(e) Included in Other within Current Liabilities and Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

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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):

Rollforward of Level 3 Measurements

	Available-for-Sale Auction Rate Securities				Derivatives (net)				Total
	(in millions)
Year Ended December 31, 2009
Balance at January 1, 2009		$	224			$	34		$	258
Total pre-tax realized or unrealized gains (losses) included in earnings:
Revenue, non-regulated electric, natural gas, and other			—				(5	)		(5	)
Fuel used in electric generation and purchased power-non-regulated			—				16			16
Total pre-tax (losses) gains included in other comprehensive income			(10	)			1			(9	)
Net purchases, sales, issuances and settlements			(16	)			(7	)		(23	)
Total losses included on balance sheet as regulatory asset or liability or as non-current liability			—				(14	)		(14	)
Balance at December 31, 2009		$	198			$	25		$	223
Pre-tax amounts included in the Consolidated Statements of Operations related to Level 3 measurements outstanding at December 31, 2009:
Revenue, non-regulated electric, natural gas, and other		$	—			$	(14	)	$	(14	)
Fuel used in electric generation and purchased power-non-regulated			—				(12	)		(12	)
Total		$	—			$	(26	)	$	(26	)
Year Ended December 31, 2008
Balance at January 1, 2008		$	15			$	8		$	23
Transfers in to Level 3			285				—			285
Total pre-tax realized or unrealized gains (losses) included in earnings:
Revenue, non-regulated electric, natural gas, and other			—				(11	)		(11	)
Fuel used in electric generation and purchased power-non-regulated			—				96			96
Other income and expense, net			(3	)			—			(3	)
Total pre-tax losses included in other comprehensive income			(43	)			(1	)		(44	)
Net purchases, sales, issuances and settlements			(30	)			(84	)		(114	)
Total gains included on balance sheet as regulatory asset or liability or as non-current liability			—				26			26
Balance at December 31, 2008		$	224			$	34		$	258
Pre-tax amounts included in the Consolidated Statements of Operations related to Level 3 measurements outstanding at December 31, 2008:
Revenue, non-regulated electric, natural gas, and other		$	—			$	(3	)	$	(3	)
Fuel used in electric generation and purchased power-non-regulated			—				30			30
Other income and expense, net			(3	)			—			(3	)
Total		$	(3	)		$	27		$	24

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

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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.

	As of December 31,
	2009		2008
	Book Value	Approximate Fair Value	Book Value	Approximate Fair Value
	(in millions)
Long-term debt, including current maturities	$  17,015	$  16,899	$ 13,896	$ 13,981

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.

10. Investments in Debt and Equity Securities

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

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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).

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

	As of December 31,
	2009							2008
	Gross Unrealized Holding Gains(a)		Gross Unrealized Holding Losses(a)			Estimated Fair Value		Gross Unrealized Holding Gains(a)		Gross Unrealized Holding Losses(a)			Estimated Fair Value
Short-term Investments	$	—	$	—		$	—	$	—	$	(4	)	$	51
Total short-term investments	$	—	$	—		$	—	$	—	$	(4	)	$	51
Equity Securities	$	337	$	(30	)	$	1,216	$	161	$	(163	)	$	880
Corporate Debt Securities		14		(2	)		256		5		(7	)		124
Municipal Bonds		2		(8	)		83		2		(10	)		150
U.S. Government Bonds		11		(1	)		290		18		—			292
Auction Rate Securities		—		(53	)		198		—		(42	)		173
Other		18		(18	)		211		3		(31	)		236
Total long-term investments	$	382	$	(112	)	$	2,254	$	189	$	(253	)	$	1,855

(a) The table above includes unrealized gains and losses of approximately $374 million and $56 million, respectively, at December 31, 2009 and unrealized gains and losses of approximately $182 million and $190 million, respectively, at December 31, 2008 associated with investments held in the NDTF. Additionally, the table above includes unrealized gains of approximately $1 million and an insignificant amount of unrealized losses at December 31, 2009 and unrealized gains and losses of approximately $1 million and $14 million, respectively, at December 31, 2008 associated with investments held in the Duke Energy Indiana Grantor Trust. As discussed above, unrealized losses on investments within the NDTF and Duke Energy Indiana Grantor Trust are deferred as regulatory assets pursuant to regulatory accounting.

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.

	As of December 31, 2009
	Fair Value(a)		Unrealized Loss Position >12 months				Unrealized Loss Position <12 months
	(in millions)
Equity Securities	$	164		$	(7	)	$	(23	)
Corporate Debt Securities		38			—			(2	)
Municipal Bonds		59			—			(8	)
U.S. Government Bonds		93			(1	)		—
Auction Rate Securities(b)		198			(53	)		—
Other		51			(15	)		(3	)
Total	$	603		$	(76	)	$	(36	)

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	As of December 31, 2008
	Fair Value(a)		Unrealized Loss Position >12 months				Unrealized Loss Position <12 months
	(in millions)
Equity Securities	$	353		$	(12	)	$	(151	)
Corporate Debt Securities		38			(3	)		(4	)
Municipal Bonds		66			—			(10	)
Auction Rate Securities(b)		224			—			(46	)
Other		108			(3	)		(28	)
Total	$	789		$	(18	)	$	(239	)

(a) The table above includes fair values of approximately $298 million and $486 million at December 31, 2009 and 2008, respectively, associated with investments held in the NDTF. Additionally, the table above includes fair values of approximately $27 million and $33 million at December 31, 2009 and 2008, respectively, associated with investments held in the Duke Energy Indiana Grantor Trust.

(b) See Note 9 for information about fair value measurements related to investments in auction rate debt securities.

11. Goodwill and Intangible Assets

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

	Balance January 1, 2009		Impairment of Goodwill		Acquisitions, Foreign Exchange and Other Changes		Balance December 31, 2009
	(in millions)
U.S. Franchised Electric and Gas	$	3,500	$	—	$	(17)	$	3,483
Commercial Power(a)		960		(371)		(20)		569
International Energy		260		—		38		298
Total consolidated	$	4,720	$	(371)	$	1	$	4,350
	Balance January 1, 2008		Impairment of Goodwill		Acquisitions, Foreign Exchange and Other Changes		Balance December 31, 2008
	(in millions)
U.S. Franchised Electric and Gas	$	3,478	$	—	$	22	$	3,500
Commercial Power		871		—		89		960
International Energy		293		—		(33)		260
Total consolidated	$	4,642	$	—	$	78	$	4,720

(a) The 2009 impairment charge, which is disclosed below, is the first goodwill impairment charge recorded by Duke Energy since the initial transaction occurred that resulted in the recognition of goodwill.

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.

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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 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.

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. 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:

• Decline in load (electricity demand) forecast—As a result of lower demand due to the continuing economic recession, forecasts evolved throughout 2009 that indicate that lower demand levels may persist longer than previously anticipated. The potential for prolonged suppressed sales growth, lower sales volume forecasts and greater uncertainty with respect to sales volume forecasts had a significant impact to the valuation of this reporting unit.

• Depressed market power prices—Low natural gas and coal prices have put downward pressure on market prices for power. As the economic recession continued throughout 2009, demand for power remained low and market prices were at lower levels than previously forecasted. In Ohio, Duke Energy provides power to retail customers under the ESP, which utilizes rates approved by the PUCO through 2011. These rates are currently above market prices for generation services. The current low levels of market prices impact price forecasts and places uncertainty over the pricing of power after the expiration of the ESP at the end of 2011. Additionally, customers have recently begun to select alternative energy generation service providers, as allowed by Ohio legislation, which further erodes margins on sales.

• Carbon legislation/regulation developments—On June 26, 2009, the U.S. House of Representatives passed The American Clean Energy and Security Act of 2009 (ACES) to encourage the development of clean energy sources and reduce greenhouse gas emissions. The ACES would create an economy-wide cap and trade program for large sources of greenhouse gas emissions. In September 2009, the U.S. Senate made significant progress towards their own version of climate legislation and, also in 2009, the EPA began actions that could lead to its regulation of greenhouse gas emissions absent carbon legislation. Climate legislation has the potential to significantly increase the costs of coal and other carbon-intensive electricity generation throughout the U.S., which could impact the value of the coal fired generating plants, particularly in non-regulated environments.

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.

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

	December 31, 2009		December 31,     2008
	(in millions)
Emission allowances	$	274	$	300
Gas, coal and power contracts		296		296
Wind development rights(a)		127		161
Other		66		68
Total gross carrying amount		763		825
Accumulated amortization—gas, coal and power contracts		(140)		(117)
Accumulated amortization—wind development rights		(2)		—
Accumulated amortization—other		(28)		(28)
Total accumulated amortization		(170)		(145)
Total intangible assets, net	$	593	$	680

(a) As discussed further below and in Note 3, the decrease in wind development rights primarily relates to the sale of certain projects that were acquired as part of Catamount in September 2008.

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:

	December 31, 2009		December 31,     2008
	(in millions)
Gross carrying value at beginning of period	$	300	$	426
Purchases of emission allowances		93		62
Sales and consumption of emission allowances (a)(b)		(120)		(116)
Impairment of emission allowances		—		(82)
Other changes		1		10
Gross carrying value at end of period	$	274	$	300

(a) Carrying value of emission allowances are recognized via a charge to expense when consumed.

(b) See Note 3 for a discussion of gains and losses on sales of emission allowances by U.S. Franchised Electric and Gas and Commercial Power.

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.

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	2010		2011		2012		2013		2014
	(in millions)
Amortization expense	$	136	$	38	$	34	$	31	$	30

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 SO₂ emissions 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 SO₂ emissions 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 SO₂ allowances 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_x allowances 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 SO₂ allowances 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.

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Notes To Consolidated Financial Statements—(Continued)

12. Investments in Unconsolidated Affiliates and Related Party Transactions

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

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Notes To Consolidated Financial Statements—(Continued)

Investments in Equity Method Unconsolidated Affiliates

	As of:
	December 31, 2009							December 31, 2008
	Domestic			International		Total		Domestic		International		Total
		(in millions)
U.S. Franchised Electric and Gas		$	4	$	—	$	4	$	3	$	—	$	3
Commercial Power			198		—		198		226		—		226
International Energy(a)			—		153		153		—		161		161
Other			71		10		81		73		10		83
Total		$	273	$	163	$	436	$	302	$	171	$	473

(a) As discussed above, International Energy recorded an approximate $18 million pre-tax impairment to write-down the value of its Attiki investment to fair value.

Equity in Earnings (Losses) of Equity Method Unconsolidated Affiliates

	For the Years Ended:
	December 31, 2009								December 31, 2008								December 31, 2007
	Domestic			International		Total(a)			Domestic			International		Total(a)			Domestic			International		Total(a)
	(in millions)
U.S. Franchised Electric and Gas	$	(10	)	$	—	$	(10	)	$	(16	)	$	—	$	(16	)	$	(2	)	$	—	$	(2	)
Commercial Power		7			—		7			16			—		16			17			—		17
International Energy		—			72		72			—			127		127			—			102		102
Other(b)		—			1		1			(230	)		1		(229	)		38			2		40
Total	$	(3	)	$	73	$	70		$	(230	)	$	128	$	(102	)	$	53		$	104	$	157

(a) Duke Energy’s share of net earnings from these unconsolidated affiliates is reflected in the Consolidated Statements of Operations as Equity in Earnings (Losses) of Unconsolidated Affiliates.

(b) Amounts for the year ended December 31, 2008 and 2007 include Duke Energy’s proportionate share of impairment charges recorded by Crescent of approximately $238 million and $32 million pre-tax, respectively.

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.

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Notes To Consolidated Financial Statements—(Continued)

Summarized Combined Financial Information of Equity Method Unconsolidated Affiliates

	As of December 31,
	2009			2008
	(in millions)
Balance Sheet
Current assets		$	1,154	$	1,399
Non-current assets			2,353		4,072
Current liabilities			(920)		(1,489)
Non-current liabilities			(744)		(2,038)
Net assets		$	1,843	$	1,944

	For the Years Ended December 31,
		2009		2008		2007
		(in millions)
Income Statement
Operating revenues		$	1,509	$	2,683	$	2,284
Operating expenses			1,252		2,407		1,634
Net income			257		58		462

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.

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Summary Condensed Financial Information

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:

	Year Ended December 31, 2008	Year Ended December 31, 2007
	(in millions)
Operating revenues	$   407	$ 536
Operating expenses	$   754	$ 415
Operating income	$  (347)	$ 121
Net income(a)	$  (420)	$   76

(a) 2008 net income includes the gain recorded by Crescent on the sale of land to Duke Energy that was eliminated by Duke Energy, as discussed further above.

	December 31, 2008
	(in millions)
Current assets	$        77
Non-current assets	$  1,685
Current liabilities	$     471
Non-current liabilities	$  1,341
Noncontrolling interest	$        (1)

13. Discontinued Operations

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.

Year Ended December 31, 2008

Commercial Power

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.

Year Ended December 31, 2007

Commercial Power

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.

International Energy

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.

Spin-off of Natural Gas Businesses

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.

Other Transactions and Balances with Spectra Energy

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.

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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.

14. Property, Plant and Equipment

		December 31,
	Estimated Useful Life	2009		2008
	(Years)	(in millions)
Land	—	$	725	$	687
Plant—Regulated
Electric generation, distribution and transmission(a)	8 – 125		35,983		34,005
Natural gas transmission and distribution	12 – 60		1,694		1,566
Other buildings and improvements(a)	25 – 100		617		564
Plant—Unregulated
Electric generation, distribution and transmission(a)	8 – 100		5,120		3,989
Other buildings and improvements(a)	20 – 90		1,855		1,698
Nuclear fuel	—		1,079		966
Equipment(a)	4 – 33		799		658
Vehicles	5 – 26		77		81
Construction in process	—		5,336		4,379
Other(a)	5 – 33		2,077		1,711
Total property, plant and equipment			55,362		50,304
Total accumulated depreciation—regulated(b), (c)			(15,526)		(14,681)
Total accumulated depreciation—unregulated(c)			(1,886)		(1,587)
Total net property, plant and equipment		$	37,950	$	34,036

(a) Includes capitalized leases of approximately $384 million and $208 million at December 31, 2009 and 2008, respectively.

(b) Includes accumulated amortization of nuclear fuel of approximately $603 million and $484 million at December 31, 2009 and 2008, respectively.

(c) Includes aggregate accumulated amortization of capitalized leases of approximately $20 million and $37 million for 2009 and 2008, respectively.

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.

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15. Debt and Credit Facilities

Summary of Debt and Related Terms

	Weighted- Average Rate		Year Due	December 31,
				2009			2008
				(in millions)
Unsecured debt	6.1	%	2010 – 2037	$	7,922		$	6,360
Secured debt	3.4	%	2010 – 2017		660			737
First mortgage bonds(a)	5.7	%	2010 – 2040		5,940			4,165
Capital leases	6.7	%	2010 – 2046		248			137
Other debt(b)	1.1	%	2010 – 2041		1,843			2,084
Notes payable and commercial paper(c)(d)	0.4	%			450			993
Fair value hedge carrying value adjustment					18			25
Unamortized debt discount and premium, net					(66	)		(62	)
Total debt(e)					17,015			14,439
Current maturities of long-term debt					(902	)		(646	)
Short-term notes payable and commercial paper(f)					—			(543	)
Total long-term debt				$	16,113		$	13,250

(a) As of December 31, 2009, substantially all of U.S. Franchised Electric and Gas’ electric plant in service is mortgaged under the mortgage bond indenture of Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana.

(b) Includes $1,410 million and $1,569 million of Duke Energy tax-exempt bonds as of December 31, 2009 and 2008, respectively. As of December 31, 2009 and 2008, $331 million and $404 million, respectively, was secured by first mortgage bonds and $433 million and $494 million, respectively, was secured by a letter of credit.

(c) Includes $450 million as of both December 31, 2009 and 2008 that was classified as Long-term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities which back-stop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted-average days to maturity was 14 days as of December 31, 2009 and 10 days as of December 31, 2008.

(d) Includes approximately $279 million at December 31, 2008 related to Duke Energy Ohio’s drawdown under the master credit facility.

(e) As of December 31, 2009 and 2008, $479 million and $414 million, respectively, of debt was denominated in Brazilian Reals.

(f) Weighted-average rates on outstanding short-term notes payable and commercial paper was 3.4% as of December 31, 2008.

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.

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 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 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.

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%.

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 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.

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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 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 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 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 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.

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.

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 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 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.

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 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 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.

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

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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.

Maturities, Call Options and Acceleration Clauses.

Annual Maturities as of December 31, 2009

	(in millions)
2010	$	902
2011		602
2012		2,247
2013		1,443
2014		1,398
Thereafter		10,423
Total long-term debt, including current maturities	$	17,015

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.

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Master Credit Facility Summary as of December 31, 2009 (in millions)^(a)

	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

(a) This summary excludes certain demand facilities and committed facilities that are insignificant in size or which generally support very specific requirements, which primarily include facilities that backstop various outstanding tax-exempt bonds.

(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower.

(c) Contains sub limits at December 31, 2009 as follows: $1,097 million for Duke Energy, $840 million for Duke Energy Carolinas, $650 million for Duke Energy Ohio, $450 million for Duke Energy Indiana and $100 million for Duke Energy Kentucky.

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:

	Amounts Borrowed Under Master Credit Facility
		(in millions)
Duke Energy Corporation		$	274
Duke Energy Indiana			123
Total		$	397

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.

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.

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.

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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.

16. Commitments and Contingencies

General Insurance

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.

Nuclear Insurance

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.

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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.

Environmental

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

Litigation

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.

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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.

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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 CO₂ emissions 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 CO₂ contributed 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

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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.

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.

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.

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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.

Other Commitments and Contingencies

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.

Operating and Capital Lease Commitments

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:

	Operating Leases			Capital Leases
		(in millions)
2010		$	108		$	26
2011			78			29
2012			64			27
2013			52			25
2014			37			22
Thereafter			197			119
Total future minimum lease payments		$	536		$	248

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17. Guarantees and Indemnifications

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

18. Earnings Per Share

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.

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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.

(in millions, except per share amounts)	Income		Average Shares	EPS
2009
Income from continuing operations attributable to Duke Energy common shareholders, as adjusted for participating securities—basic	$	1,061	1,293	$	0.82
Effect of dilutive securities:
Stock options, phantom, performance and unvested stock			1
Income from continuing operations attributable to Duke Energy common shareholders, as adjusted for participating securities—diluted	$	1,061	1,294	$	0.82
2008
Income from continuing operations attributable to Duke Energy common shareholders, as adjusted for participating securities—basic	$	1,276	1,265	$	1.01
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock			2
Income from continuing operations attributable to Duke Energy common shareholders, as adjusted for participating securities—diluted	$	1,276	1,267	$	1.01
2007
Income from continuing operations attributable to Duke Energy common shareholders, as adjusted for participating securities—basic	$	1,518	1,260	$	1.21
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock			4
Contingently convertible bond			1
Income from continuing operations attributable to Duke Energy common shareholders, as adjusted for participating securities—diluted	$	1,518	1,265	$	1.20

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.

19. 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 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.

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Stock-Based Compensation Expense

Pre-tax stock-based compensation expense recorded in the Consolidated Statements of Operations is as follows:

	For the Years Ended December 31,
	2009(a)		2008(a)		2007
	(in millions)
Stock Options	$	2	$	2	$	5
Phantom Awards		17		17		20
Performance Awards		20		23		12
Other Stock Awards		1		1		2
Total	$	40	$	43	$	39

(a) Excludes stock-based compensation cost capitalized as a component of property, plant and equipment of approximately $4 million and $3 million for the years ended December 31, 2009 and 2008, respectively.

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.

Stock Option Activity

	Options (in thousands)		Weighted- Average Exercise Price		Weighted- Average Remaining Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2008	19,790		$	17
Granted	603			15
Exercised	(1,822	)		13
Forfeited or expired	(1,265	)		17
Outstanding at December 31, 2009	17,306		$	18	3.1	$	37
Exercisable at December 31, 2009	16,703		$	18	2.8	$	36
Options Expected to Vest	603		$	15	9.1	$	2

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:

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Weighted-Average Assumptions for Option Pricing

Risk-free interest rate(a)	2.0%
Expected dividend yield(b)	5.4%
Expected life(c)	6.0 yrs.
Expected volatility(d)	26.7%

(a) The risk free rate is based upon the U.S. Treasury Constant Maturity rates as of the grant date.

(b) The expected dividend yield is based upon annualized dividends and the 1-year average closing stock price.

(c) The expected term of options is derived from historical data.

(d) Volatility is based upon 50% historical and 50% implied volatility. Historic volatility is based on Duke Energy’s historical volatility over the expected life using daily stock prices. Implied volatility is the average for all option contracts with a term greater than six months using the strike price closest to the stock price on the valuation date.

Phantom Stock Awards

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:

	Shares (in thousands)	Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2008	2,446	$22
Granted	1,096	14
Vested	(1,108)	21
Forfeited	(68)	19
Outstanding at December 31, 2009	2,366	$19
Phantom Stock Awards Expected to Vest	2,286	$19

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.

Performance Awards

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.

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Notes To Consolidated Financial Statements—(Continued)

The following table summarizes information about stock-based performance awards outstanding at December 31, 2009:

	Shares (in thousands)	Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2008	4,980	$16
Granted	3,426	13
Vested	(1,069)	19
Forfeited	(468)	16
Outstanding at December 31, 2009	6,869	$14
Stock-based Performance Awards Expected to Vest	4,177	$14

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

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:

	Shares (in thousands)	Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2008	219	$29
Vested	(48)	29
Forfeited	(3)	28
Outstanding at December 31, 2009	168	$28
Other Stock Awards Expected to Vest	162	$28

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.

20. Employee Benefit Plans

Defined Benefit Retirement Plans

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.

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Notes To Consolidated Financial Statements—(Continued)

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

Components of Net Periodic Pension Costs: Qualified Pension Plans

	For the Years Ended December 31,
	2009(a)			2008(a)			2007(a)
	(in millions)
Service cost	$	85		$	92		$	96
Interest cost on projected benefit obligation		257			254			246
Expected return on plan assets		(362	)		(340	)		(319	)
Amortization of prior service cost		7			7			5
Amortization of loss		2			13			32
Other		17			20			20
Net periodic pension costs	$	6		$	46		$	80

(a) These amounts exclude approximately $10 million, $13 million and $17 million for the years ended December 31, 2009, 2008 and 2007, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy’s merger with Cinergy in April 2006.

Qualified Pension Plans—Other Changes in Plan Assets and Projected Benefit Obligations

Recognized in Accumulated Other Comprehensive Income and Regulatory Assets^(a)

	For the year ended December 31, 2009
	(in millions)
Regulatory assets, net decrease		$(22)
Accumulated other comprehensive (income)/loss
Deferred income tax asset		9
Actuarial gain arising during 2009		(8)
Prior service credit arising during 2009		(7)
Amortization of prior year actuarial losses		(1)
Amortization of prior year prior service cost		(4)
Net amount recognized in accumulated other comprehensive (income)/loss		$(11)

(a) Excludes actuarial gains recognized in other accumulated comprehensive income of approximately $9 million, net of tax, associated with a Brazilian retirement plan.

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Reconciliation of Funded Status to Net Amount Recognized: Qualified Pension Plans

	As of and for the Years Ended December 31,
	2009			2008
		(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date		$	4,161		$	4,301
Service cost			85			92
Interest cost			257			254
Actuarial losses (gains)			415			(182)
Plan amendments			(9)			—
Obligation assumed from plan merger			7			—
Benefits paid			(221)			(304)
Obligation at measurement date		$	4,695		$	4,161

The accumulated benefit obligation was approximately $4,409 million and $3,823 million at December 31, 2009 and 2008, respectively.

	As of and for the Years Ended December 31,
	2009			2008
		(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date		$	2,853		$	4,321
Actual return on plan assets			787			(1,164)
Benefits paid			(221)			(304)
Assets received from plan merger			5			—
Employer contributions			800			—
Plan assets at measurement date		$	4,224		$	2,853

Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

	As of and for the Years Ended December 31,
	2009			2008
		(in millions)
Accrued pension liability		$	(471)		$	(1,308)

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Notes To Consolidated Financial Statements—(Continued)

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:

	As of December 31,
	2009			2008
	(in millions)
Regulatory assets	$	909		$	931
Accumulated other comprehensive (income) loss
Deferred income tax asset		(206	)		(215	)
Prior service cost		27			38
Net actuarial loss		528			537
Net amount recognized in accumulated other comprehensive (income) loss(a)	$	349		$	360

(a) Excludes accumulated other comprehensive income of approximately $21 million and $12 million, respectively, net of tax, associated with a Brazilian retirement plan.

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.

Additional Information:

Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

	As of December 31,
	2009		2008
	(in millions)
Projected benefit obligation	$	4,695	$	4,161
Accumulated benefit obligation		4,409		3,823
Fair value of plan assets		4,224		2,853

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Notes To Consolidated Financial Statements—(Continued)

Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting

Benefit Obligations	2009	2008	2007
	(percentages)
Discount rate	5.50	6.50	6.00
Salary increase (graded by age)	4.50	4.50	5.00
Determined Expense	2009	2008	2007
Discount rate	6.50	6.00	5.75
Salary increase	4.50	5.00	5.00
Expected long-term rate of return on plan assets	8.50	8.50	8.50

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

Components of Net Periodic Pension Costs: Non-Qualified Pension Plans

	For the Years Ended December 31,
	2009		2008		2007
	(in millions)
Service cost	$	2	$	2	$	2
Interest cost on projected benefit obligation		10		10		10
Amortization of prior service cost		2		3		2
Amortization of actuarial loss		—		1		—
Settlement credit		(1)		—		—
Net periodic pension costs	$	13	$	16	$	14

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Notes To Consolidated Financial Statements—(Continued)

Non-qualified Pension Plans—Other Changes in Plan Assets and Projected Benefit Obligations

Recognized in Accumulated Other Comprehensive Income

	For the year ended December 31, 2009
	(in millions)
Accumulated other comprehensive (income)/loss
Deferred income tax asset		$	(4)
Actuarial losses arising during 2009			15
Amortization of prior year actuarial losses			(1)
Amortization of prior year prior service cost			(3)
Net amount recognized in accumulated other comprehensive (income)/loss		$	7

Reconciliation of Funded Status to Net Amount Recognized: Non-Qualified Pension Plans

	As of and for the Years Ended December 31,
	2009		2008
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	166	$	172
Service cost		2		2
Interest cost		10		10
Actuarial losses (gains)		14		(4)
Benefits paid		(19)		(14)
Obligation at measurement date	$	173	$	166

	As of and for the Years Ended December 31,
	2009		2008
	(in millions)
Change in Fair Value of Plan Assets
Benefits paid	$	(19)	$	(14)
Employer contributions		19		14
Plan assets at measurement date	$	—	$	—

The accumulated benefit obligation was approximately $159 million and $154 million at December 31, 2009 and 2008, respectively.

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Notes To Consolidated Financial Statements—(Continued)

Non-Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

	As of December 31,
	2009		2008
	(in millions)
Accrued pension liability(a)	$	(173)	$	(166)

(a) Includes approximately $15 million and $20 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2009 and 2008, respectively.

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:

	As of December 31,
	2009		2008
	(in millions)
Accumulated other comprehensive (income) loss
Deferred income tax asset	$	(7)	$	(3)
Prior service cost		12		15
Net actuarial loss (gain)		8		(6)
Net amount recognized in accumulated other comprehensive (income) loss	$	13	$	6

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.

Additional Information:

Non-Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

	As of December 31,
	2009	2008
	(in millions)
Projected benefit obligation	$173	$166
Accumulated benefit obligation	159	154
Fair value of plan assets	—	—

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Notes To Consolidated Financial Statements—(Continued)

Non-Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting

Benefit Obligations	2009	2008	2007
	(percentages)
Discount rate	5.50	6.50	6.00
Salary increase	4.50	4.50	5.00
Determined Expense	2009	2008	2007
Discount rate	6.50	6.00	5.75
Salary increase	4.50	5.00	5.00

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.

Other Post-Retirement Benefit Plans

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.

Components of Net Periodic Other Post-Retirement Benefit Costs

	For the Years Ended December 31,
	2009(a)			2008(a)			2007(a)
	(in millions)
Service cost	$	7		$	7		$	11
Interest cost on accumulated post-retirement benefit obligation		46			44			57
Expected return on plan assets		(16	)		(16	)		(9	)
Amortization of prior service (credit) cost		(8	)		(8	)		2
Amortization of net transition liability		10			11			10
Amortization of (gain) loss		(5	)		(2	)		6
Special termination benefit cost		—			—			8
Prior period accounting true-up adjustment(b)		—			(55	)		—
Net periodic other post-retirement benefit costs	$	34		$	(19	)	$	85

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Notes To Consolidated Financial Statements—(Continued)

(a) These amounts exclude approximately $9 million, $9 million and $10 million for the years ended December 31, 2009, 2008 and 2007, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy’s merger with Cinergy in April 2006.

(b) Represents the correction of errors, primarily in periods prior to 2008, related to the accounting for Duke Energy’s other post-retirement benefit plans that would have reduced amounts recorded as other post-retirement benefit expense during those historical periods. Of this amount, approximately $15 million was capitalized as a component of property, plant and equipment.

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

	For the year ended December 31, 2009
	(in millions)
Regulatory assets, net increase		$	66
Regulatory liabilities, net increase			91
Accumulated other comprehensive (income)/loss
Deferred income tax liability			(2)
Actuarial loss arising during 2009			3
Amortization of prior year prior service credit			2
Amortization of prior year actuarial gains			1
Amortization of prior year net transition liability			(2)
Net amount recognized in accumulated other comprehensive (income)/loss		$	2

Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs

	As of and for the Years Ended December 31,
	2009		2008
	(in millions)
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	738	$	905
Service cost		7		7
Interest cost		46		44
Plan participants’ contributions		21		22
Actuarial gain		(11)		(170)
Plan amendments		—		(10)
Plan transfer		2		—
Benefits paid		(80)		(65)
Accrued retiree drug subsidy		5		5
Accumulated post-retirement benefit obligation at measurement date	$	728	$	738

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Notes To Consolidated Financial Statements—(Continued)

	As of and for the Years Ended December 31,
	2009		2008
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	169	$	224
Actual return on plan assets		28		(49)
Benefits paid		(80)		(65)
Employer contributions		31		37
Plan participants’ contributions		21		22
Plan assets at measurement date	$	169	$	169

Duke Energy uses a December 31 measurement date for its plan assets.

Other Post-Retirement Benefit Plans- Amounts Recognized in the Consolidated Balance Sheets Consist of:

	As of December 31,
	2009			2008
	(in millions)
Accrued other post-retirement liability(a)	$	(559	)	$	(569	)

(a) Includes approximately $3 million and $2 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2009 and 2008, respectively.

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Notes To Consolidated Financial Statements—(Continued)

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:

	As of December 31,
	2009		2008
	(in millions)
Regulatory assets	$	73	$	7
Regulatory liabilities		91		—
Accumulated other comprehensive (income)/loss:
Deferred income tax liability		2		4
Net transition obligation		4		6
Prior service credit		(14)		(16)
Net actuarial loss (gain)		3		(1)
Net amount recognized in accumulated other comprehensive (income)/loss	$	(5)	$	(7)

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.

Assumptions Used for Other Post-Retirement Benefits Accounting

Determined Benefit Obligations	2009	2008	2007
	(percentages)
Discount rate	5.50	6.50	6.00
Determined Expense	2009	2008	2007
Discount rate	6.50	6.00	5.75
Expected long-term rate of return on plan assets	5.53-8.50	5.53-8.50	5.53-8.50
Assumed tax rate(a)	35.0	35.0	35.0

(a) Applicable to the health care portion of funded post-retirement benefits.

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.

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Notes To Consolidated Financial Statements—(Continued)

Assumed Health Care Cost Trend Rates^(a)

	Medicare Trend Rate				Prescription Drug Trend Rate
	2009		2008		2009		2008
Health care cost trend rate assumed for next year	8.50	%	8.50	%	11.00	%	11.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2019		2013		2024		2022

(a) Health care cost trend rates include prescription drug trend rate due to the effect of the Modernization Act.

Sensitivity to Changes in Assumed Health Care Cost Trend Rates (in millions)

	1-Percentage- Point Increase	1-Percentage- Point Decrease
Effect on total service and interest costs	$  3	$  (2)
Effect on post-retirement benefit obligation	38	(34)

Expected Benefit Payments

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.

	Qualified Plans	Non-Qualified Plans	Other Post- Retirement Plans(a)	Total
		(in millions)
Years Ended December 31,
2010	$  405	$  16	$  56	$  477
2011	423	16	60	499
2012	433	15	61	509
2013	431	14	62	507
2014	429	22	63	514
2015 – 2019	2,020	60	323	2,403

(a) Duke Energy expects to receive future subsidies under Medicare Part D of approximately $4 million in each of the years 2010-2013, approximately $5 million in 2014, and a total of approximately $24 million during the years 2015-2019.

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Notes To Consolidated Financial Statements—(Continued)

Plan Assets

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:

		Percentage at December 31,
Asset Category	Target Allocation	2009	2008
U.S. equity securities	34%	33%	31%
Non-U.S. equity securities	20	20	17
Global equity securities	10	10	10
Debt securities	32	28	36
Real estate and cash	4	9	6
Total	100%	100%	100%

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:

VEBA I

		Percentage at December 31,
Asset Category	Target Allocation	2009	2008
U.S. equity securities	30%	23%	20%
Debt securities	45	37	40
Cash	25	40	40
Total	100%	100%	100%

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Notes To Consolidated Financial Statements—(Continued)

VEBA II

		Percentage at December 31,
Asset Category	Target Allocation	2009	2008
U.S. equity securities	50%	—%	38%
Debt securities	50	92	52
Cash	—	8	10
Total	100%	100%	100%

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.

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 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.

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 following table provides the fair value measurement amounts for Master Trust qualified pension and other post-retirement assets at December 31, 2009.

	Total Fair Value Amounts at December 31, 2009(a)	Level 1	Level 2	Level 3
	(in millions)
Description
Equity securities	$  2,587	$  1,733	$     831	$        23
Corporate bonds	1,008	—	989	19
Short-term investment funds	341	39	302	—
Partnership interests	109	—	—	109
Real estate investment trust	64	—	—	64
U.S. Government securities	57	—	57	—
Other investments	43	38	4	1
Guaranteed investment contracts	38	—	—	38
Government bonds - Foreign	33	—	32	1
Asset backed securities	19	—	18	1
Government and commercial mortgage backed securities	14	—	14	—
Total Assets	$  4,313	$  1,810	$  2,247	$     256

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Notes To Consolidated Financial Statements—(Continued)

(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.

	Total Fair Value Amounts at December 31, 2009	Level 1	Level 2	Level 3
	(in millions)
Description
Cash and cash equivalents	$    27	$  —	$  27	$  —
Equity securities	12	11	1	—
Debt securities	19	—	19	—
Total Assets	$    58	$  11	$    47	$  —

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):

Year Ended December 31, 2009
Balance at January 1, 2009	$  318
Purchases, sales, issuances and settlements (net)	(23)
Total losses, (realized and unrealized) and other	(39)
Balance at December 31, 2009	$  256

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.

Employee Savings Plans

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.

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Notes To Consolidated Financial Statements—(Continued)

21. Variable Interest Entities

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:

Notes Receivable Maturities

	(in millions)
2010		$	8
2011			10
2012			11
2013			13
2014			15
Thereafter			37
Total		$	94

Accounts Receivable Securitization.

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

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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.

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Notes To Consolidated Financial Statements—(Continued)

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:

	2009		2008
	(in millions)
Receivables sold as of December 31,	$	619	$	748
Less: Retained interests		340		292
Net receivables sold as of December 31,	$	279	$	456
Purchased beneficial interest	$	—	$	—
Sales
Receivables sold	$	5,506	$	5,717
Loss recognized on sale		43		60
Cash flows
Cash proceeds from receivables sold	$	5,416	$	5,664
Collection fees received		3		3
Return received on retained interests		27		37

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.

22. Other Income and Expenses, net

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 the years ended December 31,
	2009		2008		2007
	(in millions)
Income/(Expense):
Interest income	$  77		$ 130		$ 192
Foreign exchange gains (losses)(a)	23		(20	)	14
AFUDC equity	153		148		69
Deferred returns	(7	)	(11	)	(15	)
Impairments of available-for-sale securities(b)	—		(13	)	—
Other	38		(2	)	11
Total	$284		$ 232		$ 271

(a) Primarily relates to International Energy’s remeasurement of certain cash and debt balances into the functional currency.

(b) See Note 10 for additional information.

23. Subsequent Events

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.

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

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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.

24. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(In millions, except per share data)
2009
Operating revenues	$	3,312	$	2,913	$	3,396	$	3,110	$	12,731
Operating income		681		528		445		595		2,249
Net income attributable to Duke Energy Corporation		344		276		109		346		1,075
Earnings per share:
Basic(a)	$	0.27	$	0.21	$	0.08	$	0.26	$	0.83
Diluted(a)	$	0.27	$	0.21	$	0.08	$	0.26	$	0.83
2008
Operating revenues	$	3,337	$	3,229	$	3,508	$	3,133	$	13,207
Operating income		751		683		577		500		2,511
Income before extraordinary items		465		351		215		260		1,291
Net income attributable to Duke Energy Corporation		465		351		215		331		1,362
Earnings per share (before extraordinary items):
Basic(a)	$	0.37	$	0.28	$	0.17	$	0.21	$	1.03
Diluted(a)	$	0.37	$	0.28	$	0.17	$	0.21	$	1.02
Earnings per share:
Basic(a)	$	0.37	$	0.28	$	0.17	$	0.26	$	1.08
Diluted(a)	$	0.37	$	0.28	$	0.17	$	0.26	$	1.07

(a) Quarterly EPS amounts are meant to be stand-alone calculations and are not always additive to full-year amount due to rounding.

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).

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SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

CONDENSED STATEMENTS OF OPERATIONS

(In millions, except per-share amounts)

	Years Ended December 31,
	2009		2008		2007
Operating Revenues	$	-	$	-	$	15
Operating Expenses		1		(4)		(1)
Operating (Loss) Income		(1)		4		16
Equity in Earnings of Subsidiaries		1,095		1,275		1,421
Other Income and Expenses, net		9		(8)		52
Interest Expense		99		42		23
Income Before Income Taxes		1,004		1,229		1,466
Income Tax Benefit		(59)		(50)		(56)
Income From Continuing Operations		1,063		1,279		1,522
Income (Loss) From Discontinued Operations, net of tax		12		16		(22)
Income Before Extraordinary Items		1,075		1,295		1,500
Extraordinary Items, net of tax		-		67		-
Net Income	$	1,075	$	1,362	$	1,500
Common Stock Data
Earnings per share (from continuing operations)
Basic	$	0.82	$	1.01	$	1.21
Diluted	$	0.82	$	1.01	$	1.20
Earnings (loss) per share (from discontinued operations)
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	$	-
Earnings per share
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

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SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

BALANCE SHEETS

(In millions, except per-share amounts)

	December 31,
	2009		2008
ASSETS
Current Assets
Cash and cash equivalents	$	365	$	5
Short-term investments		-		5
Receivables		1,240		894
Other		55		175
Total current assets		1,660		1,079
Investments and Other Assets
Notes receivable		450		450
Investment in consolidated subsidiaries		23,361		21,814
Other		1,099		1,106
Total investments and other assets		24,910		23,370
Total Assets	$	26,570	$	24,449
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	102	$	102
Notes payable and commercial paper		-		264
Taxes accrued		-		27
Other		71		92
Total current liabilities		173		485
Long-term Debt		2,971		1,224
Other Long-Term Liabilities
Deferred income taxes		175		35
Other		1,501		1,717
Total other long-term liabilities		1,676		1,752
Commitments and Contingencies
Common Stockholders’ Equity
Common Stock, $0.001 par value, 2 billion shares authorized; 1,309 million and 1,272 million shares outstanding at December 31, 2009 and December 31, 2008, respectively		1		1
Additional paid-in capital		20,661		20,106
Retained earnings		1,460		1,607
Accumulated other comprehensive loss		(372)		(726)
Total common stockholders’ equity		21,750		20,988
Total Liabilities and Common Stockholders’ Equity	$	26,570	$	24,449

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SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

CONDENSED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2009		2008		2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,075	$	1,362	$	1,500
Adjustments to reconcile net income to net cash (used in) provided by operating activities		(1,002)		(748)		(1,164)
Net cash (used in) provided by operating activities		73		614		336
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of available-for-sale securities		-		(1,117)		(14,881)
Proceeds from sales and maturities of available-for-sale securities		17		1,367		15,740
Investment in wholly-owned subsidiary		(250)		-		(204)
Notes receivable from affiliates, net		(272)		(765)		(548)
Other		9		(19)		(7)
Net cash (used in) provided by investing activities		(496)		(534)		100
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		1,740		771		-
Issuance of common stock related to employee benefit plans		519		133		50
Notes payable and commercial paper		(269)		112		561
Dividends paid		(1,222)		(1,143)		(1,089)
Other		15		27		21
Net cash provided by (used in) financing activities		783		(100)		(457)
Net increase (decrease) in cash and cash equivalents		360		(20)		(21)
Cash and cash equivalents at beginning of period		5		25		46
Cash and cash equivalents at end of period	$	365	$	5	$	25

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SCHEDULE I—CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

1. Basis of Presentation

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.

2. Debt

Summary of Debt and Related Terms

	Weighted- Average		December 31,
	Rate	Year Due	2009		2008
			(in millions)
Unsecured debt	4.9%	2012 – 2019	$	2,521	$	774
Commercial paper(a)	0.4%			450		714
Total debt				2,971		1,488
Short-term notes payable and commercial paper				—		(264)
Total long-term debt			$	2,971	$	1,224

(a) Includes $450 million as of both December 31, 2009 and 2008 that was classified as Long-term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities which back-stop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted-average days to maturity was 14 days as of December 31, 2009 and 10 days as of December 31, 2008.

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 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 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 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.

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.

Annual Maturities as of December 31, 2009

	(in millions)
2010	$	—
2011		—
2012		274
2013		249
2014		1,249
Thereafter		1,199
Total long-term debt, including current maturities	$	2,971

151

DUKE ENERGY CORPORATION

SCHEDULE I—CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

3. Commitments and Contingencies

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.

4. Related Party Transactions

Balances due to or due from related parties included in the Balance Sheets as of December 31, 2009 and 2008 are as follows:

	December 31,
Assets (Liabilities)	2009			2008
	(in millions)
Current assets due from affiliated companies(a)(b)	$	78		$	8
Current liabilities due to affiliated companies(c)	$	(101	)	$	(100	)
Non-current liabilities due to affiliated companies(d)	$	(766	)	$	(766	)

(a) Balance excludes assets or liabilities associated with money pool arrangements, which are discussed below.

(b) The balances at December 31, 2009 and 2008 are classified as Receivables on the Balance Sheets.

(c) The balances at December 31, 2009 and 2008 are classified as Accounts Payable on the Balance Sheets.

(d) The balances at December 31, 2009 and 2008 are classified as Other within Other Long-Term Liabilities on the Balance Sheets.

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.

152

DUKE ENERGY CORPORATION

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND REVERSE

			Additions:
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts		Deductions(a)		Balance at End of Period
	(In millions)
December 31, 2009:
Injuries and damages	$	1,035	$	—	$	—	$	51	$	984
Allowance for doubtful accounts		42		23		9		26		48
Other(b)		555		52		24		235		396
	$	1,632	$	75	$	33	$	312	$	1,428
December 31, 2008:
Injuries and damages	$	1,086	$	—	$	—	$	51	$	1,035
Allowance for doubtful accounts		67		34		—		59		42
Other(b)		623		137		36		241		555
	$	1,776	$	171	$	36	$	351	$	1,632
December 31, 2007:
Injuries and damages	$	1,184	$	5	$	16	$	119	$	1,086
Allowance for doubtful accounts		94		37		7		71		67
Other(b)		1,105		98		109		689		623
	$	2,383	$	140	$	132	$	879	$	1,776

(a) Principally cash payments and reserve reversals. For 2007, this also includes the effects of amounts included in the spin-off of Spectra Energy Corp. (Spectra Energy) on January 2, 2007.

(b) Principally nuclear property insurance reserves at Duke Energy Carolinas, insurance reserves at Bison Insurance Company Limited (Bison) and other reserves, included in Other within Current Liabilities or Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

The valuation and reserve amounts above do not include unrecognized tax benefits amounts or deferred tax asset valuation allowance amounts.

153

PART II

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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

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.

Changes in Internal Control over Financial Reporting

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.

Management’s Annual Report On Internal Control Over Financial Reporting

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.

154

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

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.

Item 11. Executive Compensation.

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.

Item 14. Principal Accounting Fees and Services.

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.

155

PART IV

Item 15. Exhibits, Financial Statement Schedules.

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

Duke Energy Corporation:

Consolidated Financial Statements

Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007

Consolidated Balance Sheets as of December 31, 2009 and 2008

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

Notes to the Consolidated Financial Statements

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

Report of Independent Registered Public Accounting Firm

(b) Exhibits—See Exhibit Index immediately following the signature page.

156

SIGNATURES

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.

Date: February 26, 2010

DUKE ENERGY CORPORATION (Registrant)
By:	/s/    JAMES E. ROGERS
	James E. Rogers Chairman, President and Chief Executive Officer

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.

(i) James E. Rogers*

Chairman, President and Chief Executive Officer (Principal Executive Officer and Director)

(ii) /s/ Lynn J. Good

Group Executive and Chief Financial Officer (Principal Financial Officer)

(iii) Steven K. Young*

Senior Vice President and Controller (Principal Accounting Officer)

(iv) William Barnet, III*

Director

G. Alex Bernhardt, Sr.*

Director

Michael G. Browning*

Director

Daniel R. DiMicco*

Director

John H. Forsgren*

Director

Ann M. Gray*

Director

James H. Hance, Jr.*

Director

E. James Reinsch*

Director

James T. Rhodes*

Director

Philip R. Sharp*

Director

Dudley S. Taft*

Director

Date: February 26, 2010

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.

By:	/s/    LYNN J. GOOD
	Attorney-In-Fact

157

PART IV

EXHIBIT INDEX

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.

Exhibit Number
2.1	Agreement and Plan of Merger, dated as of May 8, 2005, as amended as of July 11, 2005, as of October 3, 2005 and as of March 30, 2006, by and among the registrant, Duke Energy Corporation, Cinergy Corp., Deer Acquisition Corp., and Cougar Acquisition Corp. (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 2-1).
2.2	Separation and Distribution Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with the Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 2.1).
3.1	Amended and restated Certificate of Incorporation (filed with the Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 3-1).
3.2	Amended and Restated By-Laws of registrant (filed with the Form 8-K of Duke Energy Corporation, File No. 1-32853, March 3, 2008, as Exhibit 3.1).
10.1	Purchase and Sale Agreement dated as of January 8, 2006, by and among Duke Energy Americas, LLC, and LSP Bay II Harbor Holding, LLC (filed with the Form 10-Q of the registrant for the quarter ended March 31, 2006, File No. 1-32853, as Exhibit 10.2).
10.1.1	Amendment to Purchase and Sale Agreement, dated as of May 4, 2006, by and among Duke Energy Americas, LLC, LS Power Generation, LLC (formerly known as LSP Bay II Harbor Holding, LLC), LSP Gen Finance Co, LLC, LSP South Bay Holdings, LLC, LSP Oakland Holdings, LLC, and LSP Morro Bay Holdings, LLC ((filed with the Form 10-Q of the registrant for the quarter ended March 31, 2006, File No. 1-32853, as Exhibit 10.2.1).
10.2**	Directors’ Charitable Giving Program (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 1992, File No. 1-4928, as Exhibit 10-P).
10.2.1**	Amendment to Directors’ Charitable Giving Program dated June 18, 1997 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-1.1).
10.2.2**	Amendment to Directors’ Charitable Giving Program dated July 28, 1997 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-1.2).
10.2.3**	Amendment to Directors’ Charitable Giving Program dated February 18, 1998 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-1.3).
10.3**	Duke Energy Corporation 1998 Long-Term Incentive Plan, as amended (filed as Exhibit 1 to Schedule 14A of Duke Energy Carolinas, LLC, March 28, 2003, File No. 1-4928).
10.4**	Duke Energy Corporation Executive Short-Term Incentive Plan (filed as Exhibit 2 to Schedule 14A of Duke Energy Carolinas, LLC, March 28, 2003, File No. 1-4928).
10.5**	Duke Energy Corporation Executive Savings Plan, as amended and restated (filed with Form 8-K of Duke Energy Corporation, October 31, 2007, File No. 1-32853, as Exhibit 10.1).
10.6**	Non-Qualified Option Agreement dated as of November 17, 2003 pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan, by and between Duke Energy Corporation and Paul M. Anderson (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-18.4).
10.7**	Form of Phantom Stock Award Agreement dated February 28, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and each of Fred J. Fowler, David L. Hauser, Jimmy W. Mogg and Ruth G. Shaw (filed with the Form 8-K of Duke Energy Carolinas, LLC, File No. 1-4928, February 28, 2005, as Exhibit 10-2).
10.8**	Form of Phantom Stock Award Agreement dated as of May 11, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and Jimmy W. Mogg. (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended June 30, 2005, File No. 1-4928, as Exhibit 10-6).
10.9**	Form of Phantom Stock Award Agreement dated as of May 12, 2005, pursuant to Duke Energy Corporation 1998 Long-Term Incentive Plan by and between Duke Energy Corporation and nonemployee directors (filed in Form 8-K of Duke Energy Carolinas, LLC, May 17, 2005, File No. 1-4928, as Exhibit 10-1).
10.10	Form of Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 10.1).

E-1

Exhibit Number
10.11	Form of Performance Share Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 4, 2006, as Exhibit 10.2).
10.12**	Employment Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.1).
10.12.1**	Performance Award Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.2).
10.12.2**	Phantom Stock Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.3).
10.13**	Form Phantom Stock Award Agreement and Election to Defer (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 16, 2006, as Exhibit 10.1).
10.14	Agreements with Piedmont Electric Membership Corporation, Rutherford Electric Membership Corporation and Blue Ridge Electric Membership Corporation to provide wholesale electricity and related power scheduling services from September 1, 2006 through December 31, 2021 (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.15).
10.15	Purchase and Sale Agreement by and among Cinergy Capital & Trading, Inc., as Seller, and Fortis Bank, S.A./N.V., as Buyer, dated as of June 26, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, June 30, 2006, as Exhibit 10.1).
10.16**	Form of Amendment to Performance Award Agreement and Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, August 24, 2006, as Exhibit 10.1).
10.17**	Form of Amendment to Phantom Stock Award Agreement (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, August 24, 2006, as Exhibit 10.2).
10.18	Formation and Sale Agreement by and among Duke Ventures, LLC, Crescent Resources, LLC, Morgan Stanley Real Estate Fund V U.S. L.P., Morgan Stanley Real Estate Fund V Special U.S., L.P., Morgan Stanley Real Estate Investors V U.S., L.P., MSP Real Estate Fund V, L.P., and Morgan Stanley Strategic Investments, Inc., dated as of September 7, 2006 (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2006, File No. 1-32853, as Exhibit 10.3).
10.19	Fifteenth Supplemental Indenture, dated as of April 3, 2006, among the registrant, Duke Energy and JPMorgan Chase Bank, N.A. (as successor to Guaranty Trust Company of New York), as trustee (the “Trustee”), supplementing the Senior Indenture, dated as of September 1, 1998, between Duke Energy Carolinas, LLC (formerly Duke Energy Corporation) and the Trustee (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.1).
10.19.1	Stock Option Grant Agreement between Duke Energy Corporation and James E. Rogers, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.4).
10.20**	Duke Energy Corporation 2006 Long-Term Incentive Plan (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, October 27, 2006, as Exhibit 10.1).
10.21	Tax Matters Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 10.1).
10.22	Transition Services Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 10.2).
10.22.1	Amendment No. 1 to the Transition Services Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2007, File No. 1-32853, as Exhibit 10.4).
10.22.2	Amendment No. 2 to the Transition Services Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2007, File No. 1-32853, as Exhibit 10.5).
10.22.3	Amendment No. 3 to the Transition Services Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2007, File No. 1-32853, as Exhibit 10.3).
10.22.4	Amendment No. 4 to the Transition Services Agreement, dated as of June 30, 2007, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2007, File No. 1-32853, as Exhibit 10.1).
10.23	Employee Matters Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp. (filed with

E-2

Exhibit Number
	Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as Exhibit 10.3).
10.24	First Amendment to Employee Matters Agreement, dated as of September 28, 2007 (filed in Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2007, File No. 1-32853, as Exhibit 10.3).
10.25**	Duke Energy Corporation Directors’ Savings Plan I & II, as amended and restated (filed with Form 8-K of Duke Energy Corporation, dated October 31, 2007, File No. 1-4298, as Exhibit 10.2).
10.26**	Form of Phantom Stock Award Agreement (filed in Form 8-K of Duke Energy Corporation, March 8, 2007, File No. 1-32853, as item 10.01).
10.27**	Form of Performance Share Award Agreement (filed in Form 8-K of Duke Energy Corporation, March 8, 2007, File No. 1-32853, as item 10.02).
10.28	Separation and Distribution Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 8-K of Duke Energy Corporation, File No. 1-32853, December 15, 2006, as item 2.1).
10.28.1	Amendment No. 1 to the Separation and Distribution Agreement, dated as of December 13, 2006, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2007, File No. 1-32853, as Exhibit 10.3).
10.29**	Amendment to the Duke Energy Corporation 1998 Long-Term Incentive Plan, effective as of February 27, 2007, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2007, File No. 1-32853, as Exhibit 10.6).
10.30**	Amendment to the Duke Energy Corporation 2006 Long-Term Incentive Plan, effective as of February 27, 2007, by and between Duke Energy Corporation and Spectra Energy Corp. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2007, File No. 1-32853, as Exhibit 10.7).
10.31	$2,650,000,000 Amended and Restated Credit Agreement, dated as of June 28, 2007, among Duke Energy Corporation, Duke Energy Carolinas, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, Inc. and Duke Energy Kentucky, Inc., as Borrowers, the banks listed therein, Wachovia Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, National Association, Barclays Bank PLC, Bank of America, N.A. and Citibank, N.A., as Co-Syndication Agents and The Bank of Tokyo-Mitsubishi, Ltd., New York Branch and Credit Suisse, as Co-Documentation Agents (filed in Form 8-K of Duke Energy Corporation, July 5, 2007, File No. 1-32853, as Exhibit 10.1; the agreement was executed June 28).
10.31.1	Amendment No. 1 to Amended and Restated Credit Agreement (filed in Form 8-K of Duke Energy Corporation, March 12, 2008, File No. 1-32853, as Exhibit 10.1).
10.32	Engineering, Procurement and Construction Agreement, dated July 11, 2007, by and between Duke Energy Carolinas, LLC and Stone & Webster National Engineering P.C. (portions of the exhibit 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 Exchange Act of 1934, as amended) (filed in Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2007, File No. 1-32853, as Exhibit 10.2).
10.33**	Change in Control Agreement by and between Duke Energy Corporation and James L. Turner, dated April 4, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.64.1).
10.34**	Change in Control Agreement by and between Duke Energy Corporation and Marc E. Manly, dated April 4, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.66.1).
10.35	Amended and Restated Engineering, Procurement and Construction Agreement, dated February 20, 2008, by and between Duke Energy Carolinas, LLC and Stone & Webster National Engineering P.C. (portions of the exhibit 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 Exchange Act of 1934, as amended) (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2008, File No. 1-32853, as Exhibit 10.1).
10.36**	Form of Phantom Stock Agreement (filed on Form 8-K of Duke Energy Corporation, February 22, 2008, File No. 1-32853, as Exhibit 10.1).
10.37**	Form of Performance Share Agreement (filed on Form 8-K of Duke Energy Corporation, February 22, 2008, File No. 1-32853, as Exhibit 10.2).
10.38	Amendment No. 1 to the Amended and Restated Credit Agreement (filed on Form 8-K of Duke Energy Corporation, March 12, 2008, File No. 1- 32853, as Exhibit 10.1).

E-3

Exhibit Number
10.39**	Summary of Director Compensation Program (filed in Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2008, File No. 1-32853, as Exhibit 10.1).
10.40	Agreement and Plan of Merger by and among DEGS Wind I, LLC, DEGS Wind Vermont, Inc., Catamount Energy Corporation (filed in Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2008, File No. 1-32853, as Exhibit 10.2).
*10.41***	Amended and Restated Engineering and Construction Agreement, dated as of December 21, 2009, by and between Duke Energy Carolinas, LLC and Shaw North Carolina, Inc.
10.42	Operating Agreement of Pioneer Transmission, LLC (filed in Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2008, File No. 1-32583, as Exhibit 10.1).
10.43**	Amendment to Duke Energy Corporation Executive Savings Plan, effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583, as Exhibit 10.1).
10.44**	Duke Energy Corporation Executive Cash Balance Plan, as Amended and Restated Effective August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583, as Exhibit 10.2).
10.45**	Amendment to Employment Agreement with James E. Rogers, effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583 as Exhibit 10.3).
10.46**	Form of Amended and Restated Change in Control Agreement, effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583 as Exhibit 10.4).
10.47**	Amendment to Phantom Stock and Performance Awards with James E. Rogers, effective as of august 26, 2008 (filed on Form 8-K of Duke Energy Corporation September 2, 2008, File No. 1-32853, as Exhibit 10.5).
10.48**	Amendment to Deferred Compensation Agreement with James E. Rogers, effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583, as Exhibit 10.6).
10.49**	Amendment to Award Agreements pursuant to the Long-Term Incentive Plans (Employees), effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583, as Exhibit 10.7).
10.50**	Amendment to Award Agreements pursuant to the Long-Term Incentive Plans (Directors), effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583, as Exhibit 99.1).
10.51**	Amendment to Duke Energy Corporation Directors’ Savings Plan, effective as of August 26, 2008 (filed on Form 8-K of Duke Energy Corporation, September 2, 2008, File No. 1-32583, as Exhibit 99.2).
10.52**	Deferred Compensation Agreement dated December 16, 1992, between PSI Energy, Inc. and James E. Rogers, Jr.
10.53	Engineering, Procurement and Construction Management Agreement dated December 15, 2008 between Duke Energy Indiana, Inc. and Bechtel Power Corporation. (Portions of the exhibit 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 Exchange Act of 1934, as amended).
10.54	Retirement Agreement by and between Duke Energy Business Services LLC and David L. Hauser, effective as of June 22, 2009 (filed on Form 8-K of Duke Energy Corporation, June 26, 2009, File No. 1-32853, as Exhibit 99.1).
*12	Computation of Ratio of Earnings to Fixed Charges.
*21	List of Subsidiaries.
*23.1	Consent of Independent Registered Public Accounting Firm.
*24.1	Power of attorney authorizing Lynn J. Good and others to sign the annual report on behalf of the registrant and certain of its directors and officers.
*24.2	Certified copy of resolution of the Board of Directors of the registrant authorizing power of attorney.

E-4

Exhibit Number
*31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Financials in XBRL Format

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.

E-5

EX-10.41

Exhibit 10.41

FOIA CONFIDENTIAL TREATMENT REQUESTED

PORTIONS OF THIS EXHIBIT MARKED BY *** HAVE BEEN OMITTED PURSUANT TO A

REQUEST FOR CONFIDENTIAL TREATMENT FILED SEPARATELY WITH THE SECURITIES

AND EXCHANGE COMMISSION

FIRST AMENDED AND RESTATED

ENGINEERING AND CONSTRUCTION AGREEMENT

between

DUKE ENERGY CAROLINAS, LLC, as Owner

and

SHAW NORTH CAROLINA, INC, as Contractor

for the

CONSTRUCTION OF A COMBUSTION TURBINE COMBINED CYCLE ELECTRICAL

GENERATION FACILITY AT THE BUCK GENERATING FACILITY IN ROWAN

COUNTY, NORTH CAROLINA

Dated December 21, 2009

Table of Contents

			Page
1.	DEFINITIONS		2
2.	GENERAL PROVISIONS		12
	2.1	Intent of Contract Documents	12
	2.2	Independent Contractor	12
	2.3	Subcontracting; Approved Subcontractors	12
	2.4	Assignment of Subcontracts	13
	2.5	Interpretation	14
	2.6	Inclusion; Order of Precedence	15
	2.7	Days	15
3.	CONTRACTOR RESPONSIBILITIES		15
	3.1	Performance of the Services; Commencement of Work	15
	3.2	Professional Standards	17
	3.3	Sufficient Personnel	18
	3.4	Supervision and Discipline	18
	3.5	Contractor’s Key Personnel	18
	3.6	Design and Engineering	18
	3.7	Quality Assurance Plan	19
	3.8	Safety Management Plan	19
	3.9	[Intentionally Omitted]	19
	3.10	Utility Use	19
	3.11	Spare Parts	19
	3.12	Subcontractor Presence	20
	3.13	Current Records; Record Drawings	20
	3.14	Transportation Costs	21
	3.15	O&M Manuals	21
	3.16	Control of Work	21
	3.17	Emergencies	21
	3.18	Local Conditions	21
	3.19	Use of Site; Owner Access	21
	3.20	Compliance with Laws	22
	3.21	Permits and Approvals	22
	3.22	Delivery of Project Baseline Documentation; Periodic Reports and Meetings	22
	3.23	Signage	23
	3.24	Interference with Traffic	23
	3.25	Supply of Water and Disposal of Sewage	23
	3.26	Housekeeping	23
4.	OWNER RESPONSIBILITIES		24
	4.1	Owner’s Representative	24

i

	4.2	Access	24
	4.3	Permits	24
	4.4	Owner Equipment	24
	4.5	Fuel and Utilities	24
	4.6	Operation and Maintenance Staff	25
	4.7	Job Site Rules	25
	4.8	Payment	25
5.	EQUIPMENT AND WORKMANSHIP		25
	5.1	Quality of Equipment and Workmanship	25
	5.2	Cost of Tests	25
	5.3	Samples	25
	5.4	Inspection of Operations	26
	5.5	Examination of Work before Covering	26
	5.6	Uncovering and Making Openings	26
6.	SCHEDULE		26
	6.1	Continuation of Work	26
	6.2	Schedule Requirements; Updates	26
	6.3	***	26
7.	CONTRACT PRICE; COMPENSATION AND PAYMENT		27
	7.1	***	27
	7.2	Determination of Monthly Payments of Contract Price.	27
	7.3	***	27
	7.4	Deficient Invoices and Payments	27
	7.5	***	28
	7.6	Final Payment	28
	7.7	Certification by Contractor	28
	7.8	No Acceptance by Payment	29
	7.9	Revenue from Use of Facility	29
8.	CHANGE ORDERS		29
	8.1	Changes	29
	8.2	Change Proposals	29
	8.3	Change Orders	30
	8.4	Owner Caused Changes	30
	8.5	Contractor Proposed Changes	30
9.	FORCE MAJEURE		30
	9.1	Event of Force Majeure	30
	9.2	Notice	31
	9.3	Suspension; Termination Due to Force Majeure	31

ii

10.	MECHANICAL COMPLETION; PERFORMANCE TESTING; SUBSTANTIAL COMPLETION; FINAL COMPLETION		31
	10.1	Mechanical Completion Inspection	31
	10.2	Mechanical Completion	31
	10.3	Performance Testing	32
	10.4	Satisfaction of Performance Testing	33
	10.5	Substantial Completion Punch List	33
	10.6	Substantial Completion	33
	10.7	Final Completion	34
11.	OWNER’S RIGHT TO OPERATE		35
	11.1	Intentionally Omitted	35
	11.2	Owner’s Right to Operate Prior to Satisfaction of Performance Guarantees	35
12.	***		35
	12.1	***	35
	12.2	***	35
	12.3	***	35
	12.4	Payment	35
13.	WARRANTY		36
	13.1	Services Warranty Period	36
	13.2	Equipment Warranty Period	36
	13.3	Extension of Warranty Periods	36
	13.4	Defects	36
	13.5	Responsibility for Warranty Work	37
	13.6	Title Warranty	37
	13.7	Intellectual Property Warranty	37
	13.8	Warranty Assistance	37
	13.9	Conditions of Warranty	37
	13.10	Exclusive Warranties	38
14.	INDEMNIFICATION		38
	14.1	Contractor’s Indemnity	38
	14.2	Owner’s Indemnity	38
	14.3	Intellectual Property Indemnity	39
	14.4	Indemnity Procedures for Third Party Claims	39
15.	INSURANCE		40
	15.1	*** Builder’s Risk	40
	15.2	***	41
	15.3	Contractor’s and Subcontractor’s Standard Insurance Requirements	43

iii

	15.4	General Insurance Requirements	44
	15.5	Insurance Pricing Assumptions	46
16.	PROJECT CREDIT SUPPORT		46
	16.1	Financial Information	46
	16.2	***	46
	16.3	***	47
17.	LIMITATION OF LIABILITY		47
	17.1	No Consequential Damages	47
	17.2	***	47
18.	LIENS		47
	18.1	Liens	47
	18.2	Discharge or Bond	47
19.	INTELLECTUAL PROPERTY		47
	19.1	Delivery of Documentation	47
	19.2	Ownership of Rights in Documentation	48
	19.3	Ownership of Invention Rights	48
	19.4	Disclosure of Documentation	48
	19.5	Other Licenses	48
20.	CONFIDENTIAL INFORMATION		48
	20.1	Confidentiality Obligations	49
	20.2	Permitted Disclosures	49
	20.3	Publicity	49
21.	ENVIRONMENTAL; HAZARDOUS MATERIALS		49
	21.1	Material Safety Data Sheets	49
	21.2	Facility Use, Storage Removal	50
	21.3	Notice of Presence	50
	21.4	Labeling; Training	50
	21.5	Handling, Collection, Removal Transportation and Disposal	50
	21.6	Notice of Discovery	51
	21.7	Policies and Procedures	51
	21.8	Asbestos Containing Products	51
	21.9	Pre-Existing Hazardous Material	51
22.	TITLE; RISK OF LOSS		51
	22.1	Transfer of Title; Security Interest	51

iv

	22.2	Risk of Loss	52
	22.3	Contractor Tools	52
23.	SUSPENSION; DEFAULT; TERMINATION		52
	23.1	Suspension	52
	23.2	Contractor Events of Default	53
	23.3	Owner Remedies	53
	23.4	Owner Event of Default	54
	23.5	Contractor Remedies	54
	23.6	Termination for Convenience	54
	23.7	Termination for Force Majeure	55
	23.8	Effect of Termination	55
24.	SAFETY; INCIDENT REPORTING		55
	24.1	Environmental, Health and Safety Programs	55
	24.2	OSHA and Other Laws	56
	24.3	Worksite Safety	57
	24.4	Dangerous Materials	58
	24.5	Loading	58
	24.6	Cooperation in Governmental Investigation	58
	24.7	Audit	58
25.	QUALIFICATIONS AND PROTECTION OF ASSIGNED PERSONNEL		58
	25.1	Contractor’s Personnel	58
	25.2	Drug and Alcohol Testing	59
	25.3	Training of Employees	59
	25.4	Compliance with Employment Laws; Policies	59
	25.5	Substitution	60
26.	RECORDS AND AUDIT		60
	26.1	Technical Documentation	60
	26.2	Accounting Records	60
	26.3	Owner’s Right to Audit	60
	26.4	Sales Tax and Privilege Tax Records	61
27.	TAXES		61
	27.1	Employment Taxes	61
	27.2	Sales and Use Taxes on Contractor Tools	61
	27.3	Sales and Use Tax on Equipment; Privilege Tax	61
	27.4	State Property Taxes	63
	27.5	Tax Indemnification	63
	27.6	Pollution Control Equipment Information	63

v

28.	DISPUTE RESOLUTION		63
	28.1	Resolution by the Parties	63
	28.2	Arbitration Proceedings	64
	28.3	Continuation of Work	64
	28.4	Confidentiality	64
29.	MISCELLANEOUS PROVISIONS		64
	29.1	Governing Laws	65
	29.2	Entire Agreement	65
	29.3	Successors and Assigns	65
	29.4	No Third Party Beneficiaries	65
	29.5	Rights Exclusive	65
	29.6	No Waiver	65
	29.7	Crisis Response	66
	29.8	Survival	66
	29.9	Severability	66
	29.10	Notices	66
	29.11	Vienna Convention	67
	29.12	Counterparts	67

vi

EXHIBITS

Exhibit A        Technical Documentation
Exhibit A-1	Specifications, Scope of Work and Drawings
	***
	Attachment 2 - Division of Responsibility (DOR)
	***
	Attachment 5 - P&ID’s
	Attachment 6 - Equipment List
	Attachment 7 - Electrical One Lines
	Attachment 8 - Raw Water Analysis
	Attachment 9 - Gas Analysis
	Attachment 10 - Basis of Design - Mechanical
	Attachment 11 - Basis of Design - Electrical
	Attachment 12 - Basis of Design - Instrumentation & Controls
	Attachment 13 - Basis of Design - Civil Structural
	Attachment 14 - Clarifications and Assumptions
Exhibit A-2	Performance Test Procedures and Guarantees
Exhibit A-3	Schedule of Drawings
Exhibit A-4	Site Description
Exhibit B        Schedule (Including Key Contractor Schedule Milestones)
Exhibit C        ***
Exhibit D        List of Contractor Supplied Permits
Exhibit E        List of Owner Supplied Permits
Exhibit F        List of Contractor Key Personnel
Exhibit G        Subcontractors

vii

Exhibit G-1	List of Approved Subcontractors
Exhibit G-2	List of Subcontracts under ***
Exhibit H        Credit Support
Exhibit H-1	***
Exhibit H-2	***
Exhibit I        ***
Attachment 1	***
Exhibit J        Owner’s Drug and Alcohol Testing Policy
Exhibit K        ***+
Exhibit K-1	***
Exhibit K-2	***
Exhibit K-3	***

⁺ The Project Baseline Documentation shall be delivered within sixty *** after the Amendment Date.

viii

FIRST AMENDED AND RESTATED

ENGINEERING AND CONSTRUCTION AGREEMENT

This FIRST AMENDED AND RESTATED ENGINEERING AND CONSTRUCTION AGREEMENT (the “Agreement”) is entered into as of the 21st day of December, 2009 (the “Amendment Date”), between DUKE ENERGY CAROLINAS, LLC, a North Carolina limited liability company having its principal place of business in Charlotte, North Carolina (“Owner”), and SHAW NORTH CAROLINA, INC., a North Carolina corporation having its principal place of business in Charlotte, North Carolina (“Contractor” and, together with Owner, collectively the “Parties” and individually a “Party”).

RECITALS

WHEREAS, Owner and Contractor are parties to that certain Engineering and Construction Agreement, dated as of May 5, 2008 (the “Original Agreement”), pursuant to which Owner engaged Contractor to design, engineer, construct and commission a new nominally rated 620 MW combustion turbine combined cycle electric power plant at the Buck Generating Facility (the “Facility”) in Rowan County, North Carolina, which will consist of (i) two combustion turbine generators, (ii) two natural circulation, duct fired, heat recovery steam generators and (iii) one reheat condensing steam turbine generator (the “Project”);

WHEREAS, the Original Agreement provided for *** and schedule finalization process whereby the Parties agreed to update and refine various terms and conditions, including *** and schedule up and to the ***;

WHEREAS, pursuant to that letter dated as of October 21, 2008 and prior to the completion of the ***, Owner directed Contractor to suspend performance of the Work under the Original Agreement, subject to the continuation and completion of certain Work in progress and other Site activities specified therein;

WHEREAS, pursuant to that certain Limited Notice to Proceed, dated as of June 25, 2009 (the “June 2009 Limited Notice to Proceed”), Owner granted Contractor a limited authorization to (i) proceed with Site preparation activities, (ii) resume all design and engineering activities relating to the Project, (iii) continue performing limited procurement activities and (iv) ***;

WHEREAS, in connection with the issuance of the June 2009 Limited Notice to Proceed, the Parties agreed to make certain amendments and modifications to the Original Agreement, including changes to the manner in which certain ***, in each case, as further described in that certain Change Order issued on June 25, 2009 (the “June 2009 Change Order”);

WHEREAS, as of the Amendment Date, the Parties have updated and finalized the *** as set forth herein; and

WHEREAS, the Parties hereto desire to amend and restated the Original Agreement in the manner set forth herein in order to reflect the finalization of those terms and conditions subject to updating and refinement through ***, incorporate the changes set forth in the June 2009 Change

1

Order, modify the scope of Work to eliminate the simple-cycle phase-in, and the other changes set forth herein;

NOW, THEREFORE, in consideration of the recitals, the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1. DEFINITIONS

The following capitalized words and phrases used in this Agreement shall have the following meanings unless otherwise noted:

“Affiliate” shall mean, with respect to any Person, any other Person that, directly or indirectly, through one or more intermediaries, Controls, is Controlled by, or is under common Control with such first Person at such time, where “Control” shall mean (a) the possession, directly or indirectly, of the power to direct or cause the direction of management and policies of a Person, whether through the ownership of voting securities, as a trustee or executor, by contract or credit arrangement, or otherwise, or (b) the ownership, directly or indirectly, of fifty percent (50%) or more of the equity interest in a Person.

“Agreement” shall have the meaning set forth in the first paragraph above and shall include all Exhibits and all Amendments hereto (including to the extent applicable, all Change Orders).

“Amendment Date” shall have the meaning set forth in the first paragraph of this Agreement.

“Baseline Budget” shall mean a breakdown of the *** as of the Amendment Date, broken down in time-phased increments (based upon the activities to be completed by Contractor in accordance with the Baseline Schedule), with such *** organized in a Work Breakdown Structure (WBS) which allocates such costs to discrete scopes of Work and other specific tasks, including the Key Contractor Schedule Milestones, as such budget may be revised, amended, updated or otherwise modified by Change Orders in the manner set forth herein.

*** shall mean the projected cash flow plan as of the Amendment Date, allocated on a month by month basis, for the anticipated cash flow amounts to be paid each month by Owner to Contractor for the Work to be completed by Contractor in accordance with the Baseline Schedule, as such plan may be revised, amended, updated or otherwise modified by Change Orders in the manner set forth herein. The Parties hereto hereby acknowledge and agree that the *** shall be identical to the Cash Flow Plan in effect as of the Amendment Date.

“Baseline Schedule” shall mean a network-based detailed Level III CPM schedule depicting the critical path as of the Amendment Date, including the Key Contractor Schedule Milestones, for completion of the Work, as such schedule may be revised, amended, updated or otherwise modified by Change Orders in the manner set forth herein. The Parties hereto hereby acknowledge and agree that the Baseline Schedule shall be derived from, and consistent in all respects with, the Schedule in effect as of the Amendment Date.

“Business Day” shall mean every Day other than Saturday, Sunday or a legal holiday recognized by the State.

2

***

“Change” shall have the meaning set forth in Section 8.1.

“Change in Law” shall mean a change to a Law, or a change in the binding interpretation or application of a Law after the Effective Date that results in an increase in *** for Contractor to perform the Work, which increase in *** Contractor would not have incurred but for this Agreement; provided, however, that a “Change in Law” shall not include any change to a Law that is enacted by any Government Authority prior to the Effective Date but, by its terms, does not come into effect until after the Effective Date.

“Change Order” shall have the meaning set forth in Section 8.3.

“Commissioning” shall mean the activities required to be conducted by Contractor pursuant to the terms of this Agreement in order to bring the Facility from an inactive condition, when construction is essentially complete, to a state where the Facility is ready for the commencement of operation, including pre-commissioning, start-up, individual system and integrated, functional verification and synchronization of all equipment within the Facility.

“Confidential Information” shall mean, with respect to any Party, all written, verbal, electronic and other information and documents such Party provides or makes available to the other Party relating in any way to this Agreement which are marked as being “Proprietary” to such Party at the time of disclosure, or for verbal information reduced to a writing and marked or designated as being “Proprietary” to a such Party within seven (7) Days after such verbal disclosure. “Confidential Information” shall not include any Documentation or any other information that: (a) was already known to the other Party at the time it was disclosed by such Party; (b) was available to the public at the time it was disclosed by such Party; (c) becomes available to the public after being disclosed by such Party through no wrongful act of, or breach of this Agreement by, the other Party; (d) is received by the other Party without restriction as to use or disclosure from a third party; or (e) is independently developed by the other Party without benefit of any disclosure of information by such Party.

“Contract Price” shall mean ***.

“Contractor” shall have the meaning set forth in the first paragraph above and shall include respective successors and permitted assigns.

“Contractor Default” shall have the meaning set forth in Section 23.2.

“Contractor Permits” shall have the meaning set forth in Section 3.21.

“Contractor’s Project Manager” shall mean the Person whom Contractor designates in Exhibit F to issue and receive communications on Contractor’s behalf under this Agreement.

“Contractor’s Site Representative” shall mean the Person whom Contractor designates in Exhibit F to represent Contractor at the Site.

“Cost Comparison Report” shall mean either, as the context may require:

3

(a) a report for a specified period which compares *** during such period against *** for such period, including a breakdown of ***; or

(b) a report for a specified period which compares the *** such date against the ***,

in each case, *** together with evidence reasonably required in order for Owner to ***.

***

“Day” shall mean a calendar day, including Saturdays, Sundays, and holidays.

“Defects” shall have the meaning set forth in Section 13.4.

***

“Design Documents” shall have the meaning set forth in Section 3.6.

“Dispute” shall have the meaning set forth in Section 28.1.

“Documentation” shall mean such materials in printed or electronic format that are or are to be delivered hereunder or otherwise agreed by the Parties to be delivered by Contractor to Owner, including Design Documents, specifications (including the Specifications), schedules (including the Schedule), schematics, drawings (including Final Completion “as built” drawings in accordance with Section 19.1 as specified in Exhibit A-3), blueprints, memoranda, letters, notes, isometrics, computer programs and software, flow charts, logic diagrams, graphs, studies, system descriptions, lists, charts, diagrams, standards, criteria, assumptions, measurements, procedures (including the Testing Procedure), instructions, reports, test data and results, analyses, calculations, formulas, computations, plans, empirical and other correlations, models, manuals (including software manuals and O&M Manuals) and training materials to be provided in accordance with Exhibit A-1, Attachment 1, that are necessary for the design, Commissioning, operation, maintenance, modification or decommissioning of the Facility.

“Effective Date” shall mean May 5, 2008, which is the date of execution by Owner and Contractor of the Original Agreement.

“Electrical Output” shall mean the net electrical power, as measured at the high side of the main step-up transformer, that is produced by the Facility in kilowatts (kW) during the Performance Testing, at the test specified operating conditions, and corrected to the base performance conditions set forth herein and in Exhibit A-2.

***

“Equipment” shall mean any and all material, structure, buildings, apparatus, equipment, spare parts, hardware, goods, tools, supplies, and other personal property, all as intended to become a permanent part of the Facility, that Contractor furnishes, or is required to furnish, hereunder in accordance with this Agreement, including the Specifications, or otherwise for the Facility. “Equipment” includes all of the foregoing items that Contractor furnishes through a Subcontractor. For the purposes of this Agreement, “Equipment” shall not include any Owner Equipment.

“Equipment Warranty Period” shall have the meaning set forth in Section 13.2.

4

***

“Facility” shall have the meaning set forth in the Recitals.

***

“Final Completion” shall mean that the Facility shall have achieved all of the conditions set forth in Section 10.7.

“Final Completion Date” shall mean the date on which Final Completion of the Facility occurs.

“Final Payment Invoice” shall have the meaning set forth in Section 7.6.

***

“Force Majeure” shall mean an unforeseeable event or cause that is beyond the reasonable control of a Party, including by way of example, but not limited to:

(a) acts of God, war, riots, insurrection, terrorism, rebellion, floods, hurricanes, tornadoes, earthquakes, lightning, pandemic, epidemics, and other natural calamities;

(b) explosions or fires;

(c) strikes, lockouts, or other labor disputes, but excluding strikes, lockouts or work stoppages involving only employees of Contractor;

(d) a Change in Law, but only to the extent such Change in Law delays a Party or increases its cost, as demonstrated by credible evidence, in its performance of its obligations under this Agreement;

(e) actions or inactions of any Government Authority; and

(f) delays in obtaining goods or services from any Subcontractor caused by the occurrence of any Force Majeure event;

provided, however, that an event or cause shall not be an event of Force Majeure unless it: (i) directly impacts the Work under this Agreement, (ii) is not attributable to an act or omission of, including a breach of this Agreement by, such Party, or its employees, officers, agents or Subcontractors, unless such act or omission is itself a result of Force Majeure, and (iii) cannot be cured, remedied, avoided, offset, or otherwise overcome by the prompt exercise of reasonable diligence by such Party (or any Person over whom such Party has control). For the avoidance of doubt, “Force Majeure” shall not include (A) changes in general economic conditions such as inflation, interest rates or other factors of general application, and Contractor shall not be entitled to equitable relief therefor, and (B) Owner’s inability to meet any of its payment obligations for whatever reason when due, and Owner shall not be excused from such obligation.

“Full Notice to Proceed” shall mean the written notice that Owner gives to Contractor fully authorizing Contractor to proceed with the Work hereunder. The Parties hereto hereby acknowledge

5

and agree that this executed Agreement shall constitute the issuance by Owner of the Full Notice to Proceed with respect to the Work to be completed by Contractor hereunder.

“Government Authority” shall mean any federal, state, county, city, local, municipal, foreign or other government or quasi-governmental authority or any department, agency, subdivision, court or other tribunal of any of the foregoing.

“Government Approvals” shall mean all permits, licenses, authorizations, consents, decrees, waivers, privileges and approvals from and filings with any Government Authority required for or material to the development, financing, ownership, construction, operation or maintenance of the Facility in accordance with this Agreement, including the CPCN and other work permits, environmental permits, licenses and construction permits.

“Gross Negligence” shall mean a conscious and voluntary disregard of the need to use reasonable care, which is likely to cause foreseeable grave injury or harm to persons, property or both.

“Guaranteed Substantial Completion Date” shall mean the date of *** (as such date may be adjusted by Change Order).

“Guaranteed Final Completion Date” shall mean the date of *** (as such date may be adjusted by Change Order).

“Guarantor” shall mean ***.

“Hazardous Materials” shall mean substances defined as “hazardous substances” pursuant to Section 101(14) Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986 (42 U.S.C. Sections 9601 et seq.); those substances defined as “hazardous waste” pursuant to Section 1004(5) of the Resource, Conservation and Recovery Act (42 U.S.C. Section 6901 et seq.); those substances designated as a “hazardous substance” pursuant to Section 311 (b )(2)(A) or as a “toxic pollutant” pursuant to Section 307(a)(1) of the Clean Water Act (33 U.S.C. Sections 1251 et seq.); those substances defined as “hazardous materials” pursuant to Section 103 of the Hazardous Materials Transportation Act (49) U.S.C. Sections 1801 et seq.); those substances regulated as a “chemical substance or mixture” or as an “imminently hazardous chemical substance or mixture” pursuant to Section 6 or 7 of the Toxic Substances Control Act (15 U.S.C. Sections 2601 et seq.); those substances defined as “contaminants” pursuant to Section 1401 of the Safe Drinking Water Act (42 U.S.C. Sections 300f et seq.), if present in excess of permissible levels; those substances regulated pursuant to the Oil Pollution Act of 1990 (33 U.S.C. Sections 2701 et seq.); those substances defined as a “pesticide” pursuant to Section 2(u) of the Federal Insecticide, Fungicide, and Rodenticide Act as amended by the Federal Environmental Pesticide Control Act of 1972 and by the Federal Pesticide Act of 1978 (7 U.S.C. Sections 136 et seq.); those substances defined as “toxic materials” or “harmful physical agents” pursuant to Section 6 of the Occupational Safety and Health Act (29 U.S.C. Section 651 et seq.); those substances defined as “hazardous air pollutants” pursuant to Section 112(a)(6), or “regulated substance” pursuant to Section 112(a)(2)(B) of the Clean Air Act (42 U.S.C. Sections 7401 et seq.); those substances defined as “extremely hazardous substances” pursuant to Section 302(a)(2) of the Emergency Planning & Community Right-to-Know Act of 1986 (42 U.S.C. Sections 11001 et seq.); and those other hazardous substances, hazardous wastes, toxic pollutants, hazardous materials, chemical substances or mixtures, imminently hazardous chemical

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substances or mixtures, contaminants, pesticides, by-product materials, toxic materials, harmful physical agents, air pollutants, regulated substances, or extremely hazardous substances defined in any regulations promulgated pursuant to any of the foregoing environmental Laws, and all other contaminants, toxins, pollutants, hazardous substances, substances, materials and contaminants, polluted, toxic and hazardous materials, the use, disposition, possession or control of which is regulated by one or more Laws.

“Heat Rate” shall mean the test calculated net heat rate in BTU/kW-hr in HHV for the Facility during the Performance Testing at the test specified operating conditions and corrected to the base performance conditions set forth in Exhibit A-2.

“Insolvent” shall mean, with respect to either Party, that such Party becomes insolvent, or fails generally to pay its debts as they become due, or admits in writing its inability to pay its debts as they become due, or makes a general assignment for the benefit of creditors; commences any case, proceeding or other action seeking reorganization, arrangement, adjustment, liquidation, dissolution or composition of itself or its debts or assets, or adopts an arrangement with creditors, under any bankruptcy, moratorium, rearrangement, insolvency, reorganization or similar law of the United States or any state thereof for the relief of creditors or affecting the rights or remedies of creditors generally.

“June 2009 Change Order” shall have the meaning set forth in the Recitals.

***

“June 2009 Limited Notice to Proceed” shall have the meaning set forth in the Recitals.

“Key Contractor Schedule Milestone” shall mean a Milestone set forth in Exhibit B that is identified as a “Key Contractor Schedule Milestone.”

“Laws” shall mean, at any date of determination, all statutes, laws, codes, ordinances, orders, judgments, decrees, injunctions, licenses, rules, permits, approvals, agreements, and regulations, including all applicable codes, standards, rules and regulations of the State, in effect on such date, including all Government Approvals.

“Lien” shall mean any lien, mortgage, pledge, encumbrance, charge, security interest, defect in title, or other claim filed or asserted in connection with the Project by or through Contractor, a Subcontractor or any other third party under the control or supervision of Contractor or any Subcontractor against the Facility, the Site, the Equipment, the Owner Equipment or any other structure or equipment at the Site.

***

“Limited Notice to Proceed” shall mean a written notice that Owner gives to Contractor authorizing Contractor to proceed with the Work hereunder in a limited manner.

“Major Subcontractor” shall mean any Subcontractor who is engaged by Contractor: (i) to perform any Services or provide any Equipment that exceeds or is expected to exceed, in the aggregate with all prior provision of Services or Equipment by that Subcontractor, $***; or (ii) that, although not exceeding $*** in the aggregate for Equipment or Services, is performing Services or providing Equipment that is expressly listed in the table attached hereto as Exhibit G-2.

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“Make Right Performance Guarantees” shall mean those Performance Guarantees designated as such in Exhibit A-2 for which the payment of a Performance Liquidated damage as a remedy shall not be an option for Contractor, which shall include the Permitted Emission Limits.

“Mechanical Completion” shall mean that the Facility shall have achieved all of the conditions set forth in Section 10.2.

“Milestone” shall mean an event or series of events in the execution of the Work as set forth in Exhibit B.

“Minimum Performance Guarantees” shall mean, the achievement by the *** under the performance conditions set forth in Exhibit A-2 of (a) a *** not exceeding *** of the applicable Performance Guarantees (or *** BTU/kW-hr HHV), and (b) an *** not less than *** of the applicable Performance Guarantees (or *** kW) (both of which are achieved while meeting the Permitted Emission Limits).

*** shall have the meaning set forth in Section 7.5(a).

“*** Payment Invoice” shall have the meaning set forth in Section 7.2(a).

“Monthly Progress and Cost Report” shall have the meaning set forth in Section 3.22(c).

“O&M Manuals” shall mean those manuals prepared by Subcontractors relating to the operation or maintenance of the Equipment provided by such Subcontractor.

“Original Agreement” shall have the meaning set forth in the Recitals.

“OSHA” shall have the meaning set forth in Section 24.2.

“OSHA Standards” shall have the meaning set forth in Section 24.2(b).

“Owner” shall have the meaning set forth in the first paragraph above and shall include its successors and assigns.

*** shall mean the ***, including specifically the following items:

(a) *** and features from the ***;

(b) ***;

(c) *** from the ***; and

(d) ***

“Owner Equipment Contracts” shall mean, collectively, *** and any other contract executed between Owner and a third-party supplier of equipment, including the Owner Equipment, for the Project, as each contract may be updated and amended from time to time.

“Owner Permits” shall have the meaning set forth in Section 4.3.

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“Owner’s Project Director” shall mean the Person that Owner designates in writing to issue and receive communications on Owner’s behalf under this Agreement.

“Performance Guarantees” shall mean the achievement by *** under the applicable performance conditions set forth in Exhibit A-2 of (a) a *** not exceeding *** and (b) an *** not less than *** kW (both of which are achieved while meeting the Permitted Emission Limits).

*** shall mean (a) *** per each *** measured as *** over the applicable *** for *** and (b) *** per each kW under the applicable *** for ***.

*** shall mean, as of any date of determination, an amount equal to the *** and *** as of such date.

“Performance Testing” shall mean the tests, conducted in accordance with this Agreement, including the Testing Procedures, by which Contractor demonstrates that the Facility meets, for Substantial Completion, the Minimum Performance Guarantees, or for Final Completion, the Performance Guarantees.

“Permitted Emission Limits” shall mean those specific emission limits for each regulated pollutant set forth in the Buck Station Title V Permit Modification dated October 15, 2008 issued by the North Carolina Department of Environment and Natural Resources (NCDENR) Division of Air Quality authorizing the construction and operation of the Facility and which specifies the methods of measurement, recordation, and compliance and which are designated as such and set forth in Exhibit A-2.

“Person” shall mean any individual, company, corporation, partnership, joint venture, association, joint stock company, limited liability company, trust, estate, unincorporated organization, Government Authority or other entity having legal capacity.

***

“Prime Interest Rate” shall mean, as of a particular date, the prime rate of interest as published on that date in The Wall Street Journal, and generally defined therein as “the base rate on corporate loans posted by at least 75% of the nation’s 30 largest banks.” If The Wall Street Journal is not published on a date for which the interest rate must be determined, the prime interest rate shall be the prime rate published in The Wall Street Journal on the nearest-preceding date on which The Wall Street Journal was published. If The Wall Street Journal discontinues publishing a prime rate, the prime interest rate shall be the prime rate announced publicly from time to time by Bank of America, N.A. or its successor.

***

“Progress Meetings” shall have the meaning set forth in Section 3.22(d).

“Project” shall have the meaning set forth in the Recitals.

“Project Baseline” shall mean the anticipated costs to be incurred by Contractor in order to complete the Project (or any portion of the Project), the schedule upon which Contractor is projected to complete the Project (or any portion of the Project), and the resources necessary to complete the

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Project (or any portion of the Project), and the detailed components thereof, in each case, as reflected in the Baseline Budget, the *** and the Baseline Schedule.

“Project Management Review Package” shall mean a written report prepared by Contractor covering a specified reporting period, which report shall include: (a) a schedule report detailing the progress of the Work against the Baseline Schedule through the end of the previous reporting period, depicting critical path activities and a comparison of the Key Contractor Schedule Milestones set forth in the Baseline Schedule to the Key Contractor Schedule Milestones set forth in the up-to-date Schedule, together with a brief critical path analysis with respect thereto, (b) a statement of any significant issues which remain unresolved and Contractor’s recommendations for resolving the same, (c) all Key Project Statistics, (d) a statement of any significant Project risks which remain outstanding, (e) a description of the safety status of the Project, together with a graphical depiction of such status, (f) a summary detailing the status of open PARs and a running summary of all Change Orders issued or requested under the Agreement, (g) a table describing the quantity used by Contractor to complete the Work performed, (h) a summary detailing the status of all major purchase orders and subcontracts issued or signed by Contractor with respect to the Work, (i) a summary of any significant Project events which are scheduled or expected to occur during the following ***, (j) an engineering summary and composite performance graph, (k) a construction summary and composite performance graph, (l) turnover and commissioning status graph and (n) such other information as Owner may reasonably request on an as-needed basis.

“Prudent Industry Practice” shall mean those practices, methods, equipment, specifications and standards of safety and performance, as the same may change from time to time, as are commonly used, or are generally accepted, in construction or operations of electric power generation facilities similar to the Facility, which in the exercise of reasonable judgment and in light of the facts known at the time the decision was made, after due and diligent inquiry, are considered good, safe and prudent practices in connection with the engineering, design, construction, commissioning, testing, operation and maintenance of facilities similar to the Facility with commensurate standards of safety, performance, dependability, efficiency, and economy, and as are in accordance with generally accepted standards of professional care, skill, diligence, and competence applicable to engineering, design, construction, commissioning, testing, operation, maintenance and construction practices in the United States.

“Quality Assurance Plan” shall have the meaning as set forth in Section 3.7.

***

“Reporting Period” shall mean, with respect to any month, the period of time commencing on the Effective Date and ending on the last day of Contractor’s reporting period (as determined in the ordinary course of business consistent with Contractor’s past practices) for such month.

“Sales Tax” shall mean any current or future sales, use or similar tax imposed on Contractor, any Subcontractor or Owner with respect to the Work by the State or any other Government Authority.

“Schedule” shall mean a network-based detailed Level II CPM schedule depicting the critical path, including the Key Contractor Schedule Milestones, for completion of the Work, as set forth in Exhibit B, as modified or updated from time to time in accordance with the terms of this Agreement.

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“Scope of Work” shall mean all Work on the Project as set forth in Exhibit A-1.

“Screening Measures” shall mean all applicable immigration checks (including compliance with the Immigration Reform Control Act of 1986 and I-9 requirements), drug and alcohol tests in compliance with Owner’s Drug and Alcohol Testing Policy attached hereto as Exhibit J, a terrorist watch database search, a social security trace, criminal background checks (including but not limited to checks for any felony convictions for the past seven years) and such other screening measures as a reasonably prudent employer would deem appropriate; provided that, nothing shall require Contractor to perform any screening activities that violate the federal Fair Credit Reporting Act, Title VII of the Civil Rights Act of 1964 or any other applicable Law.

“Services” shall mean all labor, transportation, packaging, storage, designing, drawing, engineering, demolition, Site preparation, manufacturing, construction, commissioning, installation, testing, equipping, verification, training, procurement (whether procurement of Equipment, Documentation, licenses to intellectual property granted herein or otherwise) and other work, services and actions (including pursuant to any warranty obligations) to be performed by Contractor under this Agreement *** (whether at the Site or otherwise) in connection with, or relating to, the Facility (or any component thereof, including any Equipment and any Owner Equipment). “Services” includes (a) all of the foregoing items that Contractor provides through a Subcontractor and (b) the services that Contractor provides with respect to Owner Equipment pursuant to Section 3.1(a)(ii).

“Services Warranty Period” shall have the meaning set forth in Section 13.1.

“Site” shall mean the physical location as described in Exhibit A-4 upon which Contractor shall construct the Facility and perform related Work.

“Specifications” shall mean the Facility specifications in Exhibit A-1.

*** shall have the meaning set forth in Section 16.3.

“State” shall mean the State of North Carolina.

“Subcontractor” shall mean a Person, including any vendor, materialman or supplier, who has a contract (whether written or oral, a purchase order or otherwise) with Contractor or a contract with any Person hired by Contractor or with a Person of any lower tier to Contractor (e.g., a second- or third-tier subcontractor) to perform any of the Services or to furnish any Equipment, at the Site or elsewhere.

“Substantial Completion” shall mean that the Facility shall have achieved all of the conditions set forth in Section 10.6.

“Substantial Completion Date” shall mean the date on which Substantial Completion actually occurs.

“Substantial Completion Punch List” shall mean the written list of items of Work (which Contractor prepares and with which Owner agrees prior to Substantial Completion) that remain to be completed by Contractor after Substantial Completion but prior to Final Completion and which shall not affect the safety, reliability, operability or mechanical or electrical integrity of the Facility.

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“*** Substantial Completion Date” shall mean the date of *** (as such date may be adjusted by Change Order).

***

“Taxes” shall mean all present and future license, documentation, recording and registration fees, all taxes (including income, gross receipts, unincorporated business income, payroll, sales, use, privilege, personal property (tangible and intangible), real estate, excise and stamp taxes), levies, imports, duties, assessments, fees (customs or otherwise), charges and withholdings of any nature whatsoever, and all penalties, fines, additions to tax, and interest imposed by any Government Authority.

“Testing Procedures” shall mean those procedures prepared for the Performance Testing by Contractor in accordance with Exhibit A-2 and reasonably acceptable to Owner.

“Third Party Claim” shall mean any claim, demand or cause of action of every kind and character by any Person other than Owner or Contractor. For the avoidance of doubt, a claim, demand or cause of action by an employee of Owner or Contractor (unless made on behalf of Owner or Contractor) shall be considered a Third Party Claim hereunder.

***

“Warranty Period” shall mean, as the context may require, the Services Warranty Period or the Equipment Warranty Period, as each may be extended from time to time with respect to any Service or Equipment as provided in Section 13.3.

“Work” shall mean, as the context may require, either (a) the Equipment and the Services or (b) the Equipment or the Services.

2. GENERAL PROVISIONS

2.1 Intent of Contract Documents. It is the intent of the Parties that Contractor provide the Equipment and perform the Services and all of its other obligations under this Agreement for the Contract Price, *** which shall not be increased, except in accordance with Article 8 or as otherwise expressly set forth herein.

2.2 Independent Contractor. Contractor shall perform and execute the provisions of this Agreement as an independent contractor to Owner and shall not in any respect be deemed or act, or hold itself out, as an agent of Owner for any purpose or reason whatsoever, except as contemplated in Section 3.1(a)(ii).

2.3 Subcontracting; Approved Subcontractors.

(a) The Parties have agreed upon the list of approved Subcontractors set forth in Exhibit G-1 for the Services and Equipment listed in Exhibit G-1. Contractor shall have the right to have that portion of the Services identified in Exhibit G-1 performed by the approved Subcontractor for such Service, and the right to purchase Equipment identified in Exhibit G-1 from the approved Subcontractor for such Equipment. For all Major Subcontractors that are listed in Exhibit G-1 and for the scope of Services and Equipment that are listed in Exhibit G-2, Contractor shall provide

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Owner with an opportunity to participate in Contractor’s bid process, including but not limited to, review of Contractor’s bid proposals, participation in vendor presentations and meetings, review of proposed subcontractor’s bid responses, review and participation in Contractor’s technical and commercial evaluations of bid responses, and participation in Contractor’s meetings to discuss bid selection. In addition, not less than *** prior to such time as Contractor desires to award or execute a subcontract with a proposed Major Subcontractor, Contractor shall provide notice to Owner of such intention. If, prior to execution of a subcontract with such Major Subcontractor, Owner desires that Contractor engage an alternative Major Subcontractor in lieu of the Major Subcontractor that is preferred by Contractor, Owner shall consult in good faith with Contractor on the difference in value, if any, between the bid price of the Major Subcontractor desired by Owner and the Major Subcontractor preferred by Contractor, plus any additional impacts to Schedule or warranties attributable to selecting the alternative Major Subcontractor in lieu of the preferred Major Subcontractor. If desired by Owner, Contractor shall engage such alternative approved Major Subcontractor but shall be entitled to a Change Order for the schedule, cost, warranty or other impacts in selecting the alternative Major Subcontractor.

(b) If Contractor desires to engage a Subcontractor that is not identified in Exhibit G-1 as an approved Subcontractor that will be providing Equipment or Services, then Contractor shall provide Owner with an opportunity to participate in Contractor’s bid process, including but not limited to, review of Contractor’s bid proposals, participation in vendor presentations and meetings, review of proposed subcontractor’s bid responses, review and participation in Contractor’s technical and commercial evaluations of bid responses, and participation in Contractor’s meetings to discuss bid selection. Before Contractor enters into any contract with, or otherwise engages, such Subcontractor to perform such Services, Contractor shall deliver to Owner for Owner’s review and approval (w) the name of the Subcontractor that Contractor proposes to use in the performance of such on-Site Services, (x) a statement in reasonable detail of the reasons why the proposed Subcontractor is preferred over any approved Subcontractor, (y) a description of any impacts to Schedule, warranties, interconnection with other Equipment or otherwise attributable to selecting the Subcontractor and (z) the information (and any additional information as Owner may reasonably request) on which Contractor is basing its desire to engage such Subcontractor. Owner shall have the right to reject any such Subcontractor; provided that Owner’s rejection shall be reasonable and shall occur within ten (10) Business Days after Contractor submits to Owner all of the information noted in clauses (w) through (z) above.

(c) Contractor shall not allow any Subcontractor that Owner rejects to perform any portion of the Services. Unless otherwise mutually agreed in writing, no contractual relationship shall exist between Owner and any Subcontractor with respect to any of the Services or the Equipment. Contractor shall be fully responsible for all acts, omissions, failures and faults of all Subcontractors as fully as if they were the acts, omissions, failures and faults of Contractor. The exercise of this right by Contractor to subcontract shall not in any way increase the costs, expenses or liabilities of Owner.

2.4 Assignment of Subcontracts. All subcontracts between Contractor and its Subcontractors shall be in writing and shall, to the extent commercially reasonable, contain provisions, which Contractor shall not waive, release, modify or impair (a) obligating each Subcontractor that may receive access to any Owner Confidential Information, to protect such Owner Confidential Information in accordance with the provisions of this Agreement; (b) as applicable, sufficient to ensure that Contractor has the right to grant the intellectual property licenses and assignments that are granted to Owner herein; and (c) giving Contractor an unrestricted right to assign the subcontract and

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all benefits, interests, rights and causes of action arising under it to Owner, an Affiliate of Owner or an operator of the Facility, as designated by Owner. At the request of Owner, Contractor shall provide Owner with copies of all warranties of each Subcontractor relating to any of the Work, and Contractor shall comply with any request by Owner upon the termination of this Agreement pursuant to Article 23 or prior to the expiration of the Warranty Period to assign the benefit of any Subcontractor warranty to Owner, an Affiliate of Owner or an operator of the Facility, as designated by Owner; provided that, unless otherwise agreed, Contractor shall not be required to assign any rights to claims that Contractor may have against such Subcontractor at the time of the assignment of such benefit.

2.5 Interpretation.

(a) Headings. The titles and headings in this Agreement are inserted for convenience only and shall not be used for the purposes of construing or interpreting this Agreement.

(b) References. References to natural persons include Persons. References to “Articles” and “Sections” are references to Articles and Sections of this Agreement. References to “Exhibits” are references to the Exhibits attached to this Agreement, including all attachments to and documents and information incorporated therein, and all Exhibits are incorporated into this Agreement by reference.

(c) Gender. Words importing one gender include the other gender.

(d) Without Limitation. The words “include” and “including” are not words of limitation and shall be deemed to be followed by the words “without limitation.”

(e) Amendments. All references in this Agreement to contracts, agreements or other documents shall be deemed to mean those contracts, agreements or documents as the same may be modified, supplemented or amended from time to time.

(f) Industry Meanings. Words and abbreviations not otherwise defined in this Agreement which have well-known technical or design, engineering or construction industry meanings in the United States are used in this Agreement in accordance with those recognized meanings.

(g) Agreement. Provisions including the word “agree”, “agreed” or “agreement” require the agreement to be recorded in writing.

(h) Written. Provisions including the word “written” or “in writing” mean hand-written, type-written, printed or electronically made and resulting in a permanent record.

(i) Drafting. Neither Contractor nor Owner shall assert or claim a presumption disfavoring the other by virtue of the fact that this Agreement was drafted primarily by legal counsel for the other, and this Agreement shall be construed as if drafted jointly by Owner and Contractor and no presumption or burden of proof will arise favoring or disfavoring any Party by virtue of the authorship of any of the provisions of this Agreement.

***

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2.6 Inclusion; Order of Precedence. This Agreement (excluding the Exhibits) and the Exhibits shall be considered complementary, and what is required by one shall be binding as if required by all. The Parties shall attempt to give effect to all provisions. The failure to list a requirement specifically in one document, once that requirement is specifically listed in another, shall not imply the inapplicability of that requirement, and Contractor shall provide as part of its obligations hereunder all items required to conform the Work to the Specifications and the other standards in this Agreement. In the event of a conflict between this Agreement (excluding the Exhibits) and the Exhibits, this Agreement (excluding the Exhibits) shall control and the conflicting provisions shall be interpreted so as to accord with the provisions of this Agreement (excluding the Exhibits). Notwithstanding the foregoing, conflicts regarding Scope of Work matters shall be governed by Exhibit A-1. Later dated amendments, Exhibits or Change Orders shall take precedence over earlier dated amendments, Exhibits or Change Orders.

2.7 Days. If a payment obligation falls due on a Day other than a Business Day, the obligation shall be deemed to be due on the next Business Day.

3. CONTRACTOR RESPONSIBILITIES

3.1 Performance of the Services; Commencement of Work.

(a) Performance of the Services.

(i) Scope of Services for Work. With respect to all Work, Contractor shall diligently, duly and properly perform and complete the Services in accordance with this Agreement; procure, provide and pay for all items (other than Owner Equipment) and services necessary for the proper execution and completion of the Services, whether temporary or permanent and whether or not incorporated or to be incorporated into the Facility, including all procurement, design and engineering services (except for such services for the Owner Equipment), all installation and construction services, administration, management, training (consistent with Exhibit A-1, Attachment 1) and coordination, all Commissioning and verification services, and all labor, Equipment, construction aids, furnishings, equipment, supplies, insurance (other than Owner insurance), permits (other than Owner Permits), licenses, inspections, storage and transportation, O&M Manuals, and all other items, facilities and services necessary to perform or provide the Work and complete the Facility. Contractor shall design, construct and install the Equipment on an engineering and construction basis pursuant to this Agreement, including providing all necessary civil, structural, mechanical, and electrical engineering services, all control equipment necessary for the design, construction and operation of the Equipment, all interconnections set forth in the Specifications, and all equipment not specifically described in the Specifications (other than Owner Equipment) which is customary and necessary to meet the requirements of the Specifications and the Performance Guarantees. Work not specifically delineated in this Section or elsewhere shall be performed and provided by Contractor to the extent customary and necessary to complete the Facility (other than procurement, supply and provision of Owner Equipment) in accordance with Prudent Industry Practices. *** Contractor shall execute the entire Services in a manner that will enable Contractor to achieve Substantial Completion by the Guaranteed Substantial Completion Date and Final Completion by the Guaranteed Final Completion Date.

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(ii) Scope of Services Relating to Owner Equipment. Owner shall be responsible for procuring, supplying and providing the Owner Equipment by the dates set forth in the Schedule. The Owner Equipment shall be provided pursuant to contracts between Owner and the suppliers of such Owner Equipment (collectively, the “Owner Equipment Contracts”). Owner shall provide Contractor with the relevant portions of the Owner Equipment Contract in order for Contractor to perform its obligations under this Section. With respect to such Owner Equipment, the Parties hereby agree as follows:

(A) Owner hereby authorizes Contractor to, and Contractor hereby agrees to, act as Owner’s agent for the purpose of generally administering the Owner Equipment Contracts on behalf of Owner and assuring compliance by Owner and suppliers with the terms thereof. Contractor shall perform such services in the manner that a reasonably prudent contractor experienced in the design and construction of combined cycle electric-generating facilities would perform if such contractor, instead of Owner, were a party to such Owner Equipment Contracts. Such agency services shall include but shall not be limited to reviewing design documents, obtaining design interface and delivery schedule information, coordinating and expediting delivery of such Owner Equipment, diligently asserting Owner’s rights, maintaining appropriate records, providing to Owner any notices delivered to Contractor by the supplier of the Owner Equipment, regularly updating Owner with respect to the status of the performance of the suppliers of the Owner Equipment, assisting Owner in pursuing available remedies against the suppliers of the Owner Equipment, including assistance to Owner in the administration and coordination of warranty claims for such Owner Equipment and enforcing the repair, replacement or refurbishment of such Owner Equipment as necessary, consulting with Owner with respect to any material issues, attending meetings and otherwise interfacing with the suppliers of the Owner Equipment, and carrying out the directions of Owner, all as necessary in order to ensure performance by the respective suppliers under the Owner Equipment Contracts in accordance with the terms and condition set forth in such Owner Equipment Contracts. Notwithstanding the foregoing, Contractor shall have no authority to, and shall not, take any of the following actions under or with respect to the Owner Equipment Contracts absent prior direction from Owner: (1) consent to any change order; (2) agree to or permit any amendment, modification, or supplement; (3) waive any of Owner’s rights or the obligations of the suppliers of the Owner Equipment; (4) increase any of Owner’s obligations or the rights of the suppliers of the Owner Equipment; (5) initiate or conduct any litigation or other similar proceedings; (6) take any action that would cause a default or breach by Owner of an Owner Equipment Contract; or (7) agree to or consent to termination or suspension of work or activities thereunder. Owner shall consult with Contractor on any performance or schedule concerns before making payments to the suppliers of the Owner Equipment after the Effective Date.

(B) In addition to the agency services set forth in Section 3.1(a)(ii)(A), Contractor shall also provide timely review and response to all Owner Equipment designs, specifications and drawings, provide all on-site storage and transportation, provide on-site administration and coordination and reasonable office space, provide installation and integration services with respect to the Owner Equipment in accordance with the Schedule, perform inspections of such Owner Equipment, perform all installation, commissioning and Performance Testing for all such Owner

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Equipment, conduct quality surveillance and start-up of such Owner Equipment to the extent permitted under the Owner Equipment Contracts, coordinate training, provide Owner Equipment manuals, and provide other related services reasonably necessary to install and interconnect such Owner Equipment to the Equipment and the Facility as contemplated by Contractor’s Scope of Work.

(C) For the avoidance of doubt, notwithstanding anything to the contrary, Contractor shall have no liability to Owner for payment of any performance liquidated damages specified within the Owner Equipment Contracts for any shortfall in the performance of such Owner Equipment (including failure to meet performance guarantees) or for the payment of any delay liquidated damages specified within the Owner Equipment Contracts for the late delivery of such Owner Equipment. Contractor shall be entitled to a Change Order granting equitable relief from any impact on Contractor’s cost or schedule of performance under this Agreement attributable to a breach by the suppliers of the Owner Equipment of the terms of the Owner Equipment Contracts, except to the extent that such breach is caused by Contractor failing to fulfill its obligations under this Agreement.

(D) Owner and Contractor hereby acknowledge that the Work is only a portion of the work required for the completion of the entire Project and that the successful and timely completion of the Project will require the good faith, prompt and courteous coordination and collaboration among many contractors, subcontractors and other Persons, including Owner and the suppliers of Owner Equipment. Owner and Contractor also acknowledge that both parties are entering into this Agreement in material reliance on the agreement by each other to provide such good faith, prompt and courteous coordination and collaboration and to perform the Work in accordance with the terms and conditions set forth herein in order to achieve the successful and timely completion of the Project.

(b) Work Under Limited Notices to Proceed. From the Effective Date until the Amendment Date, Owner has issued from time to time Limited Notices to Proceed for Contractor to perform certain portions of the Work with respect to the Facility as set forth in each such Limited Notice to Proceed. Such portions of the Work have been performed for the price and in the manner set forth in each such Limited Notice to Proceed. Each open Limited Notice to Proceed shall expire upon the earlier of (i) the date set forth in such Limited Notice to Proceed or (ii) the Amendment Date.

(c) Work After Full Notice to Proceed. The Parties hereto hereby acknowledge and agree that this executed Agreement shall constitute the issuance by Owner of the Full Notice to Proceed with respect to the Work to be completed by Contractor hereunder. Therefore, Contractor hereby receives full authorization to provide the full scope of Work relating to the Project until such Work is completed unless this Agreement is earlier terminated in accordance with Article 23. Contractor shall perform its obligations under this Agreement in accordance with the agreed upon Schedule, as such Schedule may be modified or updated from time to time in accordance with the terms of this Agreement.

3.2 Professional Standards. Contractor shall perform and complete the Services and its other obligations under this Agreement, and all Equipment shall be, in accordance with all applicable Laws, this Agreement and Prudent Industry Practices. In the event of any conflict between any of the

17

authorities in the foregoing sentence, all applicable Laws shall control over the terms of this Agreement and Prudent Industry Practices, and the terms of this Agreement shall control over Prudent Industry Practices.

3.3 Sufficient Personnel. At all times during the term of this Agreement, Contractor shall employ a sufficient number of qualified Persons, who shall be licensed if required by applicable Laws, so that Contractor may complete the Services and Contractor’s other obligations under this Agreement in an efficient, prompt, economical and professional manner and in accordance with the Schedule. Without in any way limiting the foregoing, Contractor shall, for example, employ a sufficient number of qualified buyers, inspectors, and expediters necessary to provide all equipment, materials and supplies to be provided by Contractor hereunder in a timely manner consistent with the Schedule. Contractor shall provide all technical services and supervision for Commissioning and verification. Contractor shall also provide all construction services and craft personnel as required for system adjustments during Commissioning and verification. Owner shall provide and pay for its own operations and maintenance staff during Commissioning and verification.

3.4 Supervision and Discipline. Contractor shall supervise, coordinate and direct the Services using Contractor’s best skill, judgment and attention. Contractor shall enforce strict discipline and good order among Contractor’s employees, Subcontractors’ employees and all other Persons carrying out the Services. Contractor shall at all times take all necessary reasonable precautions to prevent any unlawful or disorderly conduct by or among its employees, employees of Subcontractors and other Persons performing the Services and for the preservation of the peace and the protection of Persons and property at, or in the immediate vicinity of, the Site. Contractor shall only permit the employment of Persons who are fit at the time they are employed and on each Day they perform the Services, who are skilled in the tasks assigned to them, and who are qualified to perform the tasks assigned to them. Contractor shall be responsible for labor peace on the Site and Contractor shall at all times implement policies and practices designed to avoid work stoppages, slowdowns, disputes and strikes where reasonably possible and practical under the circumstances.

3.5 Contractor’s Key Personnel. Exhibit F contains a list of Contractor’s key personnel who shall be responsible for supervising the performance of Contractor’s obligations under this Agreement. That list includes the designation of Contractor’s Project Manager and Contractor’s Site Representative. Any replacement of the key personnel listed in Exhibit F shall be subject to the prior written approval of Owner, which consent Owner shall not unreasonably withhold or delay. Contractor’s Project Manager shall act as Contractor’s liaison with Owner and shall have the authority (a) to administer this Agreement on behalf of Contractor, (b) to oversee, direct, and manage the responsibilities of Contractor under this Agreement, and (c) to bind Contractor as to the day-to-day project management operations under the Agreement. Contractor’s Site Representative or other Contractor supervisory personnel shall be present at the Site at all times when the Services are being performed at the Site.

3.6 Design and Engineering. Prior to the Effective Date, Contractor shall have scrutinized, and satisfied itself as to the adequacy of, the Specifications (including design criteria and calculations, if any) for completion of the Facility. Contractor shall be responsible for the design of the Facility and for the accuracy of the Specifications. Any data or information received by Contractor, from Owner or otherwise, shall not relieve Contractor from its responsibility for the design of the Facility and execution of the Services. Contractor shall engage all supervisors, engineers, designers, draftsmen and other Persons necessary for the preparation of all Documentation required for the Work. In connection with the Documentation, Contractor shall prepare working drawings and specifications

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setting forth in detail the requirements for the construction of the Facility in accordance with this Agreement (the “Design Documents”). Contractor shall submit those Design Documents identified in Exhibit A-3 for Owner’s review, and Owner shall complete its review of, and provide any comments to Contractor with respect to, the Design Documents within ten *** of receiving such Design Documents from Contractor (and such Design Documents shall be deemed reviewed without comment if Contractor does not receive any comments from Owner within such time period). If Owner notifies Contractor that the Design Documents fail to comply with this Agreement, Contractor shall correct such Design Documents and shall resubmit them for Owner’s prompt review within five (5) Business Days in accordance herewith. Owner shall be entitled, but not obligated, to review and comment on all other Design Documents not identified in Exhibit A-3. Any review by Owner of any Design Documents pursuant to this Section shall not relieve Contractor from any obligation or responsibility under this Agreement. If errors, omissions, ambiguities, inconsistencies, inadequacies or other defects are found in the Design Documents, they and the Work shall be corrected as part of the ***, notwithstanding any prior consent or approval of Owner of any such Design Documents or Work.

3.7 Quality Assurance Plan. Contractor shall develop, implement and maintain a written plan for quality assurance of the Services (the “Quality Assurance Plan”), which shall include: work safety; security at the Site; fitness for duty; management and control of the design, engineering, and construction services; management and control of Subcontractors; and such other matters as Owner may reasonably request. Such plan shall meet Owner’s corporate and Site-specific policies and requirements and the requirements of all applicable Laws. On August 4, 2008 (L-Shaw-Duke-000002), Contractor delivered the Quality Assurance Plan, Revision A, dated July 21, 2008, to Owner for review and comment. Owner has reviewed and approved such Quality Assurance Plan, and Contractor shall have the right to rely on such plan in performing the Services. Contractor shall also require all Subcontractors to establish, implement and maintain appropriate quality control and safety programs with respect to their respective portions of the Services. Contractor shall provide Owner and its employees, agents, representatives and invitees with reasonable access to the Work wherever located for observation and inspection, including but not limited to auditing of all activities for conformance with the requirements of the plan and all requirements of the Agreement. Inspections and audits of Contractor’s Subcontractors will be coordinated with Contractor.

3.8 Safety Management Plan. Contractor shall develop, implement and maintain a written safety management plan that complies with the requirements set forth in Article 24. On July 30, 2008 (L-Shaw-Duke-0000001), Contractor delivered the Site Specific Safety Plan, Revision A, dated July 29, 2008, to Owner for review and comment. Owner has reviewed and approved such Site Specific Safety Plan, and Contractor shall have the right to rely on such plan in performing the Services.

3.9 [Intentionally Omitted].

3.10 Utility Use. Subject to Section 4.5, from the Effective Date until Final Completion, Contractor shall be responsible in connection with its scope of Work and as part of the *** to maintain and pay for all temporary construction utilities required to perform the Services, including electricity (from the designated Owner tie-in points), fuel (other than gas fuel used for Commissioning, Performance Testing and operation), communication systems for Contractor’s temporary office facilities (including telephones for Owner’s staff), water (potable and raw), construction waste disposal and wastewater disposal.

3.11 Spare Parts.

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(a) Erection, Start-up and Commissioning Spare Parts. Owner and Contractor shall consult in good faith on an ‘open book’ basis to determine the nature and quantity of spare parts required for installation, erection, start-up, commissioning and performance testing for the Equipment for the Facility, including all gases, gaskets, fuses, instruments, etc. and other consumable, expendable and engineered items that may be required during construction, start-up, commissioning or performance testing of such Equipment. Contractor shall recommend to Owner for approval the spare parts to be purchased by Contractor for such installation, erection, start-up and commissioning, with such Owner approval not to be unreasonably withheld or delayed. Owner shall own all such spare parts for which it has made payment, and, prior to Substantial Completion, Contractor shall provide Owner with a complete list of all such spare parts (including manufacturer name and part number and other descriptive information) that were not used during construction, start-up, commissioning or performance testing of such Equipment.

(b) Recommended Operation and Maintenance (O&M) Spare Parts. At least ninety days (90) Days prior to Substantial Completion, Contractor shall provide a list of spare parts that Contractor (or its Subcontractors) recommends as necessary for Owner to have on hand to maintain operability of the Equipment (taking into account the length of time required to obtain such spare parts) to enable prompt repair of the Equipment for the Facility for a period of *** following Substantial Completion. Summary and detailed information on each spare part shall be listed by Contractor in a format as reasonably requested by Owner. Each spare part listed shall include all items for which the spare part is intended to support. All spare parts shall comply with the requirements of the Specifications and shall be identical or equivalent to the original specified, including documentation identical in kind and format to that required for the original equipment or material. Pricing, delivery lead times and any limitations on shelf life shall be included for each spare part. Owner shall procure such spare parts as it determines in its sole discretion.

(c) Owner Equipment Spare Parts. Acting as Owner’s agent pursuant to Section 3.1(a)(ii)(A), Contractor shall coordinate, expedite and manage delivery from each supplier of Owner Equipment a recommended list of spare parts required for Commissioning and start-up of such Owner Equipment at such times as shall be necessary to permit Contractor to remain in compliance with the Schedule. Owner shall timely acquire, pay and deliver for all such spare parts. Owner shall make available at no cost to Contractor to utilize for Owner Equipment during start-up and testing, spare parts acquired by Owner for the Owner Equipment.

3.12 Subcontractor Presence. Contractor shall be responsible for notifying and paying any Subcontractor representative that it deems necessary to be present for technical assistance at (a) any training session, (b) erection supervision, (c) Commissioning, or (d) the Performance Testing. Similarly, Owner, at its cost, shall ensure that an adequate number of qualified representatives from those suppliers supplying Owner Equipment are present for technical assistance at the above-listed events.

3.13 Current Records; Record Drawings. Contractor shall maintain in good order and make available to Owner, for inspection at the Site at all times, at least one record copy of the Documentation marked currently to record all material changes made during construction. Before, and as a condition to, Final Completion of the Facility, Contractor shall deliver to Owner the Documentation, including one set of reproducible as-built drawings (in accordance with Section 19.1) listed in Exhibit A-3 (in hard copy and electronic formats (non-native files) reasonably requested by Owner), showing all material changes made during construction with respect to the Facility.

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3.14 Transportation Costs. Contractor shall arrange and pay for all transportation, storage and transfer costs incurred in connection with the Work, except for the transportation and storage costs attributable to Owner Equipment, which transportation and storage costs shall be paid by Owner.

3.15 O&M Manuals. Contractor shall deliver to Owner O&M Manuals for Contractor-supplied Equipment within *** of delivery of such Equipment to the Site such that Owner has sufficient time to prepare facility manuals utilizing such O&M Manuals to support operator training.

3.16 Control of Work. Contractor shall have care, custody and control over that portion of the Site at which it performs construction Work and shall be solely responsible for all construction means, methods, techniques, sequences, procedures, safety and quality assurance, and quality control programs in connection with the performance of the Services. Contractor shall, *** provide all necessary security at that portion of the Site under Contractor’s care, custody and control, including a suitable fence around such portion of the Site, and the prohibition and prevention of access and entrance to such portion of the Site by all unnecessary and unauthorized Persons. Contractor shall strictly control the admission of Persons to such portion of the Site and no such Person (other than the employees, officers or directors of the Parties or their Affiliates) who is not required for the performance or supervision of the Services shall be admitted without the prior approval of Owner (such approval not to be unreasonably withheld or delayed). To the extent any damages to the Site or property thereon, including the Facility, are covered by Owner’s Builder’s Risk policy or other property insurance ***. To the extent any damages to the Site or property thereon, including the Facility, are not covered by Owner’s Builder’s Risk policy or other property insurance and if such damages arise from theft or vandalism due to Contractor’s or its Subcontractor’s negligence, then Contractor shall be liable for such damages up to the amount of the loss incurred, which shall be included ***.

3.17 Emergencies. In the event of any emergency endangering life or property, Contractor shall take all actions as may be reasonable and necessary to prevent, avoid or mitigate injury, damage or loss and shall promptly report each such emergency, and Contractor’s responses thereto, to Owner.

3.18 Local Conditions. Contractor has reviewed the Site and the access to the Site, all as described in Exhibit A-4, and acknowledges that they are sufficient for the performance of the Services. Contractor warrants that it has taken all steps necessary to ascertain the nature and location of the Services and that it has investigated and satisfied itself as to the general and local conditions that can affect the Facility, the Site or the performance of the Services, including: (a) conditions bearing on access, egress, transportation, waste disposal, handling, lay down, parking and storage of materials; (b) the availability of labor, water, electric power, other utilities and roads needed for construction; (c) uncertainties of normal weather or other observable physical conditions at the Site; and (d) the character of equipment and facilities needed before and during the performance of the Services.

3.19 Use of Site; Owner Access. Contractor shall confine its operations at the Site to areas permitted by applicable Laws, this Agreement and the Exhibits hereto. Contractor shall prepare, implement and enforce written Site rules necessary for the safe, efficient and proper prosecution of the Work. Those rules shall, at a minimum, comply with Owner Environmental Health and Safety manual and all applicable Laws. Contractor shall provide Owner, the suppliers of the Owner Equipment, and their respective employees, agents, representatives and invitees with reasonable access to the Work wherever located for observation and inspection; provided, that Contractor may provide, and Owner, the suppliers of the Owner Equipment and shall accept, an escort or other safety

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measures that Contractor, in its reasonable discretion, deems necessary or advisable. As a *** and as part of the ***, Contractor shall provide Owner and its Owner Equipment vendors with *** office spaces on the Site which shall be outfitted in a customary manner (including a conference room) as more fully described in Exhibit A-1. Those office facilities shall be connected to and serviced by the usual utilities, subject to Sections 3.10 and 4.5.

3.20 Compliance with Laws. Contractor shall comply, and shall cause all Subcontractors to comply, with all applicable Laws and Change Orders that relate to Changes in Law relating to the Work or the Facility, and Contractor shall give all applicable notices with respect to, and in accordance with, any applicable Laws. Contractor shall ensure that the Facility, as designed and constructed, complies, and, when operated in accordance with Prudent Industry Practices, shall comply with all applicable Laws. Notwithstanding the foregoing, or anything else in this Agreement to the contrary, Contractor’s obligation with respect to water, air and other emissions of the Facility shall be limited to the requirements set forth in the Specifications. If not otherwise exempted by Title 48 and to the extent applicable, Contractor will make a good faith effort to comply with 48 CFR §52.219-8, Utilization of Small, Small Disadvantaged, and Women-Owned Small Business Concerns, and 48 CFR §52.219-9, Small, Small Disadvantaged, and Women-Owned Small Business Subcontracting Plan, as such sections may be amended, modified, restated or renumbered.

3.21 Permits and Approvals. Contractor shall be responsible for obtaining, renewing and maintaining all permits, licenses, approvals and certifications customary and necessary for Contractor to demolish, Site prepare, engineer, detail, fabricate, furnish, deliver, unload, store, erect, install, commission (but only those permits exclusively used for commissioning) and inspect the Work, all as described in Exhibit D (collectively, the “Contractor Permits”). Contractor shall provide reasonable assistance and documents to Owner in connection with Owner’s efforts to obtain the Owner Permits. Contractor represents that, to the best of its knowledge, the Contractor Permits listed in Exhibit D are the customary permits, approvals and certifications required to be obtained by Contractor for its performance of the Services. Upon Contractor’s request, Owner shall provide Contractor reasonable cooperation and assistance in obtaining and maintaining Contractor Permits.

3.22 Delivery of Project Baseline Documentation; Periodic Reports and Meetings.

(a) Project Baseline Documentation. Within *** after the Amendment Date, Contractor shall deliver to Owner a copy of (i) the Baseline Budget, (ii) the ***, and (iii) the Baseline Schedule, each of which shall be correct and true at the time of submittal and in form and substance reasonably acceptable to Owner. The foregoing documents shall be attached to the Agreement as Exhibits K-1, K-2 and K-3, respectively, upon delivery thereof.

(b) Monthly ***. Prior to or concurrently with the delivery of each Monthly Payment Invoice provided in accordance with Section 7.2(a), Contractor shall prepare and submit to Owner a (i) *** covering all construction Work for the Reporting Period ending during the immediately prior month and (ii) *** covering all engineering and design Work for the Reporting Period ending during the immediately prior month. Owner may review source data at the Project Site or Contractor’s home office located in Charlotte, North Carolina. Contractor shall provide copies of such documentation and materials as Owner may reasonably request on an as-needed basis to substantiate the information provided by Contractor in such ***. Contractor shall provide the foregoing *** in both hard copy (one) and electronic versions (all graphs and tables shall be provided in MS Excel format).

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(c) Monthly Project Management Review Packages. No later than *** after the date each *** is due, Contractor shall prepare and submit to Owner a (i) Project Management Review Package covering Contractor’s previous Reporting Period and (ii) a cost summary report covering Contractor’s previous Reporting Period (collectively, the “Monthly Progress and Cost Report”). Contractor shall provide copies of such documentation and materials as Owner may reasonably request on an as-needed basis to substantiate the information provided by Contractor in such reports. Contractor shall provide the foregoing reports in both hard copy (one) and electronic versions (all graphs and tables shall be provided in MS Excel format).

(d) Attendance and Participation at Meetings. From the Effective Date until the Final Completion Date, Contractor shall attend and participate in regular meetings with Owner which shall occur monthly (or upon such other interval as the Parties agree in writing) for the purpose of discussing the status of the Work and anticipating and resolving any problems (“Progress Meetings”). The Progress Meetings may also include, at the request of Owner, consultants and other Persons. Contractor shall prepare and promptly deliver to Owner written minutes of each meeting; provided, that the publication or distribution of such minutes shall not constitute a permitted basis for providing notice, or otherwise asserting claims, under this Agreement by any Party. No implication whatsoever shall be drawn as consequence of a failure by any Party to comment on or object to any minutes prepared or distributed by Contractor. Unless otherwise mutually agreed, Contractor’s Site Representative shall attend all Progress Meetings after Contractor mobilizes to the Site. In addition to the above monthly Progress Meetings, Contractor shall hold regularly scheduled (but not less frequently than weekly during construction) status or scheduling meetings with its Subcontractors as appropriate, and Owner shall have the right but not the obligation to attend and participate in such weekly status meetings; provided, that, if Contractor determines in its reasonable discretion that Owner’s attendance at the meeting would prohibit Contractor from effectively addressing confidential or sensitive issues, Contractor shall have the right to bar Owner from that portion of such meetings.

3.23 Signage. Neither Contractor nor its Subcontractors shall display, install, erect or maintain any advertising or other signage at the Site without Owner’s prior written approval, other than signs and notices required by applicable Laws, related safety or work rules, site identification, or used to solicit employees for the performance of the Services.

3.24 Interference with Traffic. Contractor shall carry out the Services so as not to interfere unnecessarily or improperly with (a) Owner’s operations at or in the vicinity of the Site, including the existing Buck coal facility located adjacent to the Site, or (b) access to, use of or occupation of public or private roads, footpaths or properties in the possession of Owner or any other Person. Contractor shall communicate with, and ascertain the requirements of, all Government Authorities in relation to vehicular access to and egress from the Site and shall comply with any such requirements. Contractor shall be deemed to have satisfied itself as to, and shall be fully responsible for, the routing for delivery of heavy or large loads to the Site so as to satisfy any requirements of Government Authorities with respect thereto.

3.25 Supply of Water and Disposal of Sewage. Contractor shall provide, within the Site, an adequate supply of drinking and other water for the use of those Persons working on the Site. Contractor shall dispose of, either off-Site or through the Facility’s septic system or other approved method, all on-Site sewage effluent during performance of the Services.

3.26 Housekeeping. At all times during the term of this Agreement, Contractor shall keep the Site and surrounding area adjacent to where the Services are actually being performed, free from waste

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materials, equipment, rubbish, debris and other garbage, and liquid and non-liquid materials whether spilled, dropped, discharged, blown out or leaked. Contractor shall employ adequate dust control measures. To the extent practicable, Contractor and all Subcontractors shall utilize reasonable waste reduction and recycling techniques at the Site. Before the Final Completion Date, Contractor shall remove from the Site all tools, trailers, surplus and waste materials, and rubbish, and shall otherwise leave the Facility and the Site in a neat and clean condition. If Contractor fails to perform such housekeeping services, Owner, following notice and a reasonable opportunity for Contractor to cure, may perform such services, and all reasonable and necessary costs incurred in connection therewith shall be assessed against the ***.

4. OWNER RESPONSIBILITIES

Owner shall perform the responsibilities set forth in this Article at its own expense and at those reasonable times as may be required by Contractor for the successful completion of the Work in accordance with the Schedule.

4.1 Owner’s Representative. Owner shall appoint Owner’s Project Director with whom Contractor may consult at all reasonable times, and whose instructions, requests and decisions shall be binding upon Owner as to all matters pertaining to this Agreement and the performance of the Parties under this Agreement; provided, that no amendment or modification of this Agreement shall be effected except by an amendment, and no Change shall be effected except as provided in Article 8.

4.2 Access. Subject to Section 11.2, from the Amendment Date until the Substantial Completion Date, Owner shall provide Contractor, at no additional cost to Contractor, unrestricted right of access to such portion of the Site as Contractor may reasonably require for the construction of the Facility and for Contractor’s office, warehouse, shop buildings, welding facilities, Contractor’s equipment storage, lay down area, and employee parking. After the Substantial Completion Date, Owner shall allow Contractor reasonable access to the applicable portion of the Site in order to achieve Final Completion.

4.3 Permits. Owner shall be responsible for obtaining, renewing and maintaining the permits, licenses, approvals and certifications necessary for the operation, maintenance, use and ownership of the Facility, including the permits listed in Exhibit E (collectively, the “Owner Permits”). Contractor shall provide Owner with all reasonably necessary information, documents, data, criteria and performance characteristics of the Facility requested or required by Owner to assist Owner in obtaining Owner Permits.

4.4 Owner Equipment. Owner shall procure and provide Owner Equipment by the dates set forth in the Schedule to prevent delay. Except to the extent that the failure of any Owner Equipment to be provided by the dates set forth in the Schedule or to perform in accordance with its manufacturer’s specifications is caused by Contractor’s failure to perform its obligations in accordance with this Agreement, any impact to Contractor from the delay (or re-sequence) in delivery or performance of Owner Equipment shall give rise to a Change.

4.5 Fuel and Utilities. Owner shall provide, at no cost to Contractor, the electrical interconnect for power export from the Facility at the interconnection points identified in Exhibit A-1, and all fuel necessary for Commissioning and Performance Testing when requested by Contractor and as

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required in accordance with the Schedule. Commencing on the Substantial Completion Date, *** for the operation of the Facility.

4.6 Operation and Maintenance Staff. At the earlier of: (a) six (6) months prior to the *** Completion Date as set forth in the Schedule, or (b) the actual date of Mechanical Completion, Owner shall provide, under the direction of Contractor through Substantial Completion, at no cost to Contractor, the complement of qualified operation and maintenance personnel for applicable Commissioning, Performance Testing and operation of the Facility. In addition, Owner, at its cost, shall ensure that an adequate number of qualified representatives from those suppliers supplying Owner Equipment are present at Commissioning or Performance Testing as necessary for technical assistance.

4.7 Job Site Rules. From the date on which Owner provides Contractor access to the Site to perform the Work until the Substantial Completion Date, Owner, its representatives and agents shall abide by all reasonable Site safety rules promulgated by Contractor.

4.8 Payment. In accordance with the terms and conditions of this Agreement, Owner shall pay Contractor the Contract Price. Owner shall make all payments promptly when due.

5. EQUIPMENT AND WORKMANSHIP

5.1 Quality of Equipment and Workmanship. All Equipment and workmanship shall be subject to such tests as Owner may reasonably require at the place of manufacture, fabrication or preparation, or at the Site or at such other place or places as may be mutually agreed upon by the Parties, including any place of an independent third party. Contractor shall provide such assistance, labor, electricity, fuels, stores, apparatus and instruments as are reasonably required for examining, measuring and testing any Equipment and Owner Equipment in accordance with Exhibit A-2 (other than specialty tools as listed in Owner Equipment Contracts) and workmanship, before incorporation into the Facility.

5.2 Cost of Tests.

(a) Subject to the last sentence of Section 10.4, the cost of conducting any test related to the Work shall be ***.

(b) If the results of any such test indicate that the applicable Equipment or workmanship do not conform to the requirements of this Agreement (including the Specifications and Prudent Industry Practices) and Owner has reasonable grounds to suspect that any other similar Equipment or workmanship may not conform to the requirements of this Agreement (including the Specifications and Prudent Industry Practices), Owner may require Contractor to carry out further tests, which in the reasonable opinion of Owner are necessary to verify that such other similar Equipment or workmanship conforms to the requirements of this Agreement (including the Specifications and Prudent Industry Practices). The costs of any such tests shall be borne by *** and shall be borne by ***.

5.3 Samples. At the reasonable request of Owner and at Owner’s cost, Contractor shall supply Owner with samples of Equipment (for which samples can reasonably be provided). The manufacturer’s standard samples (with relevant information) and any additional samples shall be labeled as to origin and intended use in the Facility.

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5.4 Inspection of Operations. Owner (and its representatives) shall at all reasonable times have access to the Site and to all workshops and places where Equipment or Owner Equipment is being manufactured, fabricated or prepared for the Facility. Contractor shall provide Owner a reasonable opportunity to be present for any tests of any Equipment or Owner Equipment.

5.5 Examination of Work before Covering. For certain agreed parts of the Work as set forth in Exhibit A-1, Contractor shall give notice to Owner whenever any such part of the Equipment or Owner Equipment, as applicable, or foundations is or are ready or about to be ready for examination and Owner shall, without unreasonable delay, attend (or inform Contractor that it is unnecessary for it to attend) for the purpose of examining and measuring such part of the Equipment or Owner Equipment, as applicable, or of examining such Work. No part of such Equipment or Owner Equipment shall be covered up or put out of view without affording Owner a reasonable opportunity to examine and measure any such part of the Equipment or Owner Equipment.

5.6 Uncovering and Making Openings. If, following discovery of defective workmanship or materials in any part of the Work, Owner has reasonable grounds to suspect that further parts of the Work may be similarly defective, Contractor shall, upon the reasonable request of Owner, provide Owner clear evidence that such other parts are not defective to the reasonable satisfaction of Owner or shall uncover such further parts of the Work or make further openings, in or through the same, and Contractor shall inspect and repair, if necessary, any such parts. The costs of such work carried out by Contractor under this Section shall be part of the ***, unless the parts of the Work so uncovered turn out to be not defective, in which case Owner shall bear such costs.

6. SCHEDULE

6.1 Continuation of Work. This executed Agreement constitutes the Full Notice to Proceed with respect to the Project, and Contractor has commenced performance of the Work with respect thereto and shall continuously and diligently fulfill its obligations under this Agreement. Contractor shall perform its obligations under this Agreement in accordance with the Schedule set forth in Exhibit B, as such may be modified and updated from time to time in accordance with the terms of this Agreement. ***.

6.2 Schedule Requirements; Updates. A copy of the Schedule (which shall be true and correct as of the Amendment Date), along with Key Contractor Schedule Milestones, is attached hereto as Exhibit B. The Parties agree that the Schedule and the Key Contractor Schedule Milestones within the Schedule reflect dates for completion of Work activities by Contractor in order to meet the Targeted Substantial Completion Date. In addition, Contractor shall prepare and make available to Owner at all times at the Site, or such other location mutually agreed upon by the Parties, a current, working copy of the Schedule. Unless otherwise mutually agreed upon by the Parties, Contractor shall update the working copy of the current Schedule monthly and shall provide a copy to Owner as a component of each Monthly Progress and Cost Report; provided, however, that no update of or revisions to the working copy of the Schedule shall be deemed to alter, revise or otherwise change the date for any Key Contractor Schedule Milestones, the Guaranteed Substantial Completion Date or the Guaranteed Final Completion Date, all of which shall be amended only by a duly executed Change Order or amendment hereto.

6.3 ***

(a) ***

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(b) ***

(c) ***

7. CONTRACT PRICE; COMPENSATION AND PAYMENT

7.1 *** (a) ***

(b) [Intentionally Omitted].

(c) [Intentionally Omitted].

(d) ***

7.2 Determination of Monthly Payments of Contract Price.

(a) *** Payment Invoice. ***, Contractor shall submit to Owner *** for payment of the amount set forth in the Cash Flow Plan for such month and any other additions or deductions that may have become due, and subject to any limitations, under this Agreement, including those under Sections 7.1(d), 7.3(a), 7.3(b) and 7.5. Submittal of each Monthly Payment Invoice shall constitute a representation by Contractor that (x) Contractor has performed and completed all Work included in each Cost Comparison Report previously provided hereunder, (y) *** previously provided hereunder have been calculated and determined in accordance with the requirements of this Agreement, and (z) the amounts included in such *** Payment Invoice for the current month are the correct amounts due and owing to Contactor in accordance with this Article 7 and ***.

(b) ***

(c) ***

7.3 ***

7.4 Deficient Invoices and Payments.

(a) If any *** is deficient, Contractor shall be required to resubmit that *** in proper form; provided, however, that Owner shall pay any portion of it that is not deficient or subject to dispute. Owner shall review each *** and shall endeavor to make exceptions, if any, by providing Contractor with written notice by the earlier of (i) such date the Monthly Payment Invoice is paid by Owner or (ii) *** Days after Owner receives the ***. Notwithstanding anything in this Article to the contrary, the failure of Owner to raise an exception shall not preclude Owner from subsequently seeking, and Contractor from paying, a refund of any amounts to which Contractor was not entitled under this Agreement, and Owner may, by any payment pursuant to Section 7.2, make any correction or modification that should properly be made to any amount previously considered due.

(b) If Owner provides no exceptions within such time period, Owner shall pay Contractor, within *** Days of its receipt of such *** and such substantiating documentation and materials as Owner may have reasonably required, in U.S. dollars the amounts designated in such ***, plus any additions and less any deductions which may have become due under this Agreement, as reflected in such ***. Any amount of a *** that Owner disputes shall be resolved promptly in accordance with Article 28. Once the dispute is resolved, Owner or Contractor, as applicable, shall

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pay any amount owing promptly after the date of the final resolution. If for any reason Owner fails to pay Contractor for all sums due and owing (other than sums that are the subject of a good faith dispute or permitted to be withheld pursuant to this Section 7.4(b)) within *** Days after receipt of a substantiated *** which complies with the requirements of this Article, interest shall thereafter accrue on such sums due and owing at the *** until paid.

(c) If any Services performed or Equipment supplied by Contractor for which payment has been made hereunder is not in accordance with this Agreement, Owner may withhold from any Monthly Payment Invoice the cost of rectification or replacement until such rectification or replacement has been completed, and, if Contractor is failing to perform any Services or provide any Equipment in accordance with this Agreement and Owner has so notified Contractor in writing, Owner may withhold from any Monthly Payment Invoice the estimated value of such Work until it has been performed or provided in accordance with this Agreement.

7.5 ***

(a) *** Contractor in prior ***, and the amount of such *** that exceeds *** threshold, together with the total cumulative amounts for all prior Monthly Payment Invoices, will not cause the Contractor to exceed the total cumulative value of the Cash Flow Plan through such month, then Owner shall pay such Monthly Payment Invoice in full. ***.

(b) The Parties acknowledge that nothing in this Section limits, and the Parties shall not construe this Section as limiting, Contractor’s ability to accelerate Key Contractor Schedule Milestones, provided that Owner shall not be obligated to pay more than the *** Amount for any given month. The Parties also acknowledge and agree that nothing in this Section limits, and the Parties shall not construe this Section as limiting, Contractor’s ability to update the Schedule, other than delaying the Key Contractor Schedule Milestones, in accordance with Section 6.2. ***.

7.6 Final Payment. Upon achievement of Final Completion, Contractor shall submit to Owner an invoice for the final payment and other payments due under this Agreement (the “Final Payment Invoice”) which shall set forth all remaining amounts due to it pursuant to this Agreement. When submitting the Final Payment Invoice, Contractor shall submit a written notice, reasonably satisfactory to Owner, confirming that the total of the applicable Final Payment Invoice represents full and final settlement of all monies due to Contractor under this Agreement. If requested by Owner, the Final Payment Invoice shall also include a waiver (or a bond if a Lien exists to indemnify Owner against such Lien) of any Liens; provided, that the waiver or bond may contain a requirement that Owner pay such Final Payment Invoice. The procedures set forth in Section 7.2(b) (including application of any late payment charge) shall be followed for payment of the applicable Final Payment Invoice, and Owner shall be entitled to offset against any Monthly Payment Invoice or Final Payment Invoice any amounts owing by Contractor to Owner under this Agreement, including any Liquidated Damages owed after application of the cost sharing provisions in Section 7.3.

7.7 Certification by Contractor. In each Monthly Payment Invoice and in the Final Payment Invoice, Contractor shall certify as follows:

“There are no known Liens (or such Liens are bonded over) outstanding at the date of this invoice, all amounts that are due and payable to any third party (including Subcontractors) with respect to the Work as of the date of this invoice have been paid or are included in the amount requested in this invoice, and, except for those bills not

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paid but so included and amounts disputed between Owner and Contractor, there is no known basis for the creation of any Liens, except in respect to payments to any Subcontractor withheld for proper reasons in accordance with the contract with such Subcontractor. Contractor hereby waives and releases, to the extent of the receipt of payment requested in this invoice, any right to any Lien with respect to payment for such portion of the Work included in this invoice.”

7.8 No Acceptance by Payment. Owner’s payment of any invoice, including a Final Payment Invoice, does not constitute approval or acceptance of any item or cost in that invoice nor shall be construed to relieve Contractor of any of its obligations under this Agreement.

7.9 Revenue from Use of Facility. Owner shall be entitled to all revenue derived from or in connection with operation or use of the Facility before and after the Substantial Completion Date.

8. CHANGE ORDERS

8.1 Changes. Without invalidating this Agreement, Owner may order changes in the Specifications or the Work consisting of additions, deletions or other revisions (each, a “Change”), provided, that Owner may not delete all Work through this Article.

8.2 Change Proposals. If Owner desires to make a Change, it shall submit a written proposal to Contractor describing the Change requested. Contractor shall promptly review Owner’s proposal and submit to Owner an estimate of the cost to develop a Change Order for such Change, such development costs to be estimated consistent with ***. If the estimated costs to develop the Change Order are reasonably acceptable to Owner, Owner shall promptly provide notice thereof to Contractor in writing. Upon receipt of such notice, Contractor’s Project Manager shall promptly notify Owner in writing, as soon as practicable, either by giving reasons why Contractor, either directly or indirectly through a Subcontractor, could not effect such Change (if this is the case) or by submitting a proposed Change Order, which shall include in reasonable detail:

(a) the effect and impact, if any, that the Change would have, in Contractor’s reasonable judgment, on the Work, *** the Schedule, any warranties herein and the operation or maintenance of the Facility,

(b) Contractor’s proposal for any necessary modifications to Work, *** the Schedule or any warranties herein, and

(c) Contractor’s proposal for any necessary modifications to any other provisions of this Agreement, including the Specifications, the Milestones, the Cash Flow Plan or the Performance Guarantees.

Contractor shall provide Owner such supporting documentation for the foregoing as Owner may reasonably request. Notwithstanding the foregoing, Contractor shall not, as a result thereof, be entitled to any payment hereunder or any extension of the Schedule if such Change was necessary as a result of the fault of Contractor, including any breach by Contractor of this Agreement. For all proposed Change Orders to the scope of Work, the Parties agree that the Contractor shall apply or deduct, as applicable, *** to implement or remove such scope of Work, as applicable. Owner shall, as soon as practicable after receipt of such submittal and supporting documentation, respond with any comments or questions. Contractor shall not delay any Work while awaiting a response. If Owner

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responds with comments or questions, Contractor shall endeavor to address such comments or answer such questions as soon as practicable. If Owner decides not to proceed with a Change, it shall reimburse Contractor for its efforts in developing the estimates and other information regarding the potential Change *** (such reimbursement to be either outside the Contract Price or through a separate Change Order); provided, that Owner shall only be required to reimburse Contractor if Contractor has complied with the cost proposal requirements set forth above.

8.3 Change Orders. If Owner wishes to proceed with the Change, Owner shall issue a written order to Contractor authorizing the Change and setting forth any revisions to this Agreement that it deems, in good faith, necessary or appropriate to effect the Change (the “Change Order”). If Contractor refuses to accept such revisions in the Change Order, Contractor shall provide Owner written notice thereof within ten (10) Business Days of its receipt of the Change Order, describing in reasonable detail its objections to the Change Order. Owner shall be entitled, despite such notice from Contractor, to require Contractor to continue to perform its obligations hereunder as would be modified by the Change Order; provided, that, if Owner requires Contractor to so perform and Contractor has provided Owner timely notice objecting to such Change Order, (x) the Parties shall resolve the Dispute over the necessary or appropriate revisions in accordance with the dispute resolution procedures set forth in Article 28 and (y) if the Change involves additional or disputed Work, Owner shall continue to pay Contractor pursuant to the payment terms hereof, subject to resolution of the Dispute pursuant to Article 28 (Owner may require any dispute over price to be resolved pursuant to an “open book” process), ***. Once the Dispute is resolved, any amount owing will be paid within thirty (30) Days after the date of resolution. Contractor shall furnish to Owner such receipts or other vouchers as may be necessary to prove the amounts paid and labor performed on *** and, before ordering materials, shall submit to Owner quotations for the same for Owner’s approval (such approval not to be unreasonably delayed or withheld). Promptly after the end of each month, Contractor shall deliver to Owner a priced statement of the labor and materials used during such month associated with such Change performed on ***.

8.4 Owner Caused Changes. If Contractor experiences an increase in costs or a delay in Contractor’s ability to perform the Work due to Owner or due to a delay in the delivery of any Owner Equipment or a delay resulting from a defect in any Owner Equipment or a breach of the Owner Equipment Contracts by the suppliers of the Owner Equipment, and such delay or defect is not the result of Contractor’s failure to comply with the requirements of this Agreement, Contractor shall be entitled to a Change and an equitable adjustment in the *** and/or the Schedule.

8.5 Contractor Proposed Changes. Contractor shall have the right to request a Change but shall have no right to require a Change which is not contemplated by this Agreement without the prior written consent of Owner; however, nothing herein shall be construed to restrict Contractor’s right to request an equitable adjustment in the *** and Schedule to mitigate impacts caused by events such as, but not limited to, Force Majeure and Change in Law.

9. FORCE MAJEURE

9.1 Event of Force Majeure. The performance by Owner or Contractor under this Agreement shall be excused to the extent that such Party’s performance is delayed or prevented by reason of an event of Force Majeure. If a Party is or will be reasonably prevented from performing its obligations under this Agreement by an event of Force Majeure, such Party shall use all commercially reasonable efforts to remove the cause affecting such non-performance and to minimize and mitigate any delay in or impact upon the performance of this Agreement or any damage to or other impact upon the

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Equipment or the Owner Equipment. If an event of Force Majeure occurs, the Parties shall *** to: (a) *** for a period of time reasonably necessary to overcome the effect of the delay, and (b) the Contract Price, ***; provided, that Contractor shall *** on Change Orders which result from an event of Force Majeure.

9.2 Notice. If a Party is or will be reasonably prevented from performing its obligations under this Agreement by an event of Force Majeure, then it shall notify the other Party of the obligations, the performance of which is or will be prevented, and the nature and cause of the event in writing within *** after the notifying Party or its Project Manager becomes aware, through the exercise of reasonable diligence, of the event of Force Majeure. The Party affected by an event of Force Majeure shall provide the other Party with weekly updates (a) estimating its expected duration, the cost of any remedial action, and the probable impact on the performance of its obligations hereunder, (b) of the actions taken to remove or overcome the event of Force Majeure and (c) of the efforts taken to mitigate or limit damages to the other Party. The Party affected by an event of Force Majeure shall also provide written notice to the other Party when it ceases to be so affected.

9.3 Suspension; Termination Due to Force Majeure. If any event of Force Majeure claimed by Contractor delays Contractor’s performance for an aggregate time period greater than *** consecutive Days, then Owner, in its sole and absolute discretion, shall have the right to terminate this Agreement (or the affected portion of the Work) without penalty in accordance with Section 23.7. If any event of Force Majeure claimed by Owner delays Contractor’s performance of substantially all of the Work for an aggregate time period greater than *** consecutive Days, then Contractor, in its sole and absolute discretion, shall have the right to suspend performance and demobilize under this Agreement without penalty in accordance with Section 23.7. If any event of Force Majeure claimed by Owner delays Contractor’s performance of substantially all of the Work in any *** time period for an aggregate time period greater than *** Days, then Contractor, in its sole and absolute discretion, shall have the right to terminate this Agreement without penalty in accordance with Section 23.7.

10. MECHANICAL COMPLETION; PERFORMANCE TESTING; SUBSTANTIAL COMPLETION; FINAL COMPLETION

10.1 Mechanical Completion Inspection. At least thirty (30) Days prior to the date upon which Contractor expects to achieve Mechanical Completion, Contractor shall notify Owner in writing thereof and shall take necessary measures to allow a preliminary inspection of the Facility to be conducted by Owner and its representatives. Contractor shall include with such notice documents and information prudent or convenient for Owner to determine whether Mechanical Completion is achieved. If Owner notifies Contractor of any deficiencies in the Work, Contractor shall immediately remedy such deficiencies as part of the *** and provide Owner with the relevant documentary evidence of the correction.

10.2 Mechanical Completion. “Mechanical Completion” shall be deemed to have occurred upon satisfaction of all of the following conditions:

(a) All materials, equipment and systems related to the safe start-up and testing of the Facility shall have been constructed and installed in accordance with this Agreement, including the Specifications and applicable Laws, and in a manner that does not void any warranties, and the Equipment and Owner Equipment for the Facility shall be mechanically and electrically sound, all required pre-operational testing for the Facility shall have been satisfactorily completed, and all

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systems for the Facility shall have been checked for alignment, lubrication, rotation and hydrostatic and pneumatic pressure integrity;

(b) All systems and components for the Facility shall have been flushed and cleaned out as necessary, and the Equipment and Owner Equipment for the Facility shall be ready to support the commencement of Performance Testing for the Facility;

(c) The Parties shall have agreed upon the Testing Procedures for the Facility;

(d) The Equipment and Owner Equipment for the Facility shall be capable of being tested in accordance with Exhibit A-2 without damage thereto or any other portion of the Facility or to any property or injury to any Person and in compliance with all applicable Laws and all permits and licenses required by such Laws;

(e) Contractor shall have provided the applicable Documentation that is needed to start-up, operate and maintain the Facility (including the O&M Manuals), which Documentation shall have been approved, in the reasonable determination of Owner, as adequate for the start-up, operation and maintenance of the Facility (such approval not to be unreasonably withheld or delayed);

(f) Contractor shall have provided the training of Owner’s personnel and representatives as required by Exhibit A-1 for operation of the Facility; and

(g) Contractor shall have delivered to Owner a certificate signed by Contractor certifying that all of the preceding conditions in this Section 0 have been satisfied.

Contractor shall not commence Performance Testing for the Facility until all of the above conditions for Mechanical Completion have been satisfied and Contractor shall have provided the required prior notice to Owner of the applicable Performance Testing and given Owner an opportunity to attend.

If Contractor is unable to satisfy any of the foregoing conditions as a result of any event or circumstance for which neither Contractor nor any Subcontractor is responsible, the improper performance of any Owner Equipment or any other fault of any supplier of any Owner Equipment, and Contractor has complied with its obligations relating to such Owner Equipment in accordance with Section 3.1(a)(ii), Contractor shall be entitled to a Change Order providing, at Owner’s election, that such condition is deemed to have been satisfied (but only to the extent Contractor is unable to satisfy such condition) or for *** and the Schedule or otherwise as may be reasonable under the circumstances.

10.3 Performance Testing. As soon as reasonably practicable following Mechanical Completion and after providing Owner at least five (5) Business Days prior written notice (unless Owner agrees to a shorter notice period or regulatory requirements necessitate a longer notice period), Contractor shall commence Performance Testing of the Facility, which Performance Testing shall be completed in accordance with Exhibit A-2. Owner and its agents, representatives and invitees, including any independent third party inspector and any of its other contractors for the Project or their respective agents, representatives and invitees, shall have the right to attend and witness the Performance Testing. After the completion of Performance Testing for the Facility, Contractor shall determine and submit to Owner, in writing and electronically, the raw data and completed results of such Performance Testing, together with a comparison of such results to the applicable Performance

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Guarantees and a statement whether such results satisfy the applicable Performance Guarantees. By submitting such raw data and completed results, Contractor represents that such raw data, and the conversion of such raw data into the test results, is accurate.

10.4 Satisfaction of Performance Testing. Within *** Days after it receives the results for all of the Performance Testing for the Facility, including the underlying raw data and other information required by Section 10.3, Owner shall respond in writing to Contractor stating whether (a) such Performance Testing was performed according to the Testing Procedures, and (b) the results of such Performance Testing satisfied the applicable Performance Guarantees, or, if Owner does not believe that is the case, Owner shall provide its reasons. Upon its receipt of any such response from Owner that is not in the affirmative, Contractor shall promptly take whatever action shall be necessary to cure the defect in such Performance Testing, adjust or modify any of the Equipment, or require adjustment or modification of Owner Equipment in accordance with Section 3.1(a)(ii), or otherwise in order to satisfy the applicable Performance Guarantees so noted by Owner and shall promptly repeat such Performance Testing in accordance with Section 10.3 and this Section. If, following such Performance Testing, either: (a) Owner agrees that the applicable Performance Guarantees have been satisfied and that such Performance Testing was performed according to the Testing Procedures, (b) the failure to meet any applicable Performance Guarantee is attributable to the performance of Owner Equipment (other than due to Contractor’s failure to fulfill its obligations set forth in Section 3.1(a)), or (c) Owner fails to respond within the time period set forth above, then the applicable Performance Guarantees shall be deemed to have been satisfied on the date of completion of such Performance Testing for the purposes of calculating the applicable Delay Liquidated Damages. Notwithstanding anything in this Article to the contrary, no agreement, confirmation, statement or otherwise of, or the lack thereof from, Owner relating to whether such Performance Testing was performed according to the Testing Procedures or whether the results of such Performance Testing satisfied the applicable Performance Guarantees shall relieve Contractor of any of its obligations under this Agreement. All costs that Contractor incurs in satisfying its obligations under this Article are part of the ***, except that Contractor shall be reimbursed through a Change Order for additional costs it may incur due to defects in Owner Equipment that are not the result of Contractor’s failure to comply with the requirements set forth in this Agreement or damage to Equipment included in the Facility that was not the fault of Contractor or any Subcontractor, including for any repeat Performance Testing and the consumables and spare parts associated therewith.

10.5 Substantial Completion Punch List. Prior to Substantial Completion, Contractor shall submit to Owner, for Owner’s review and approval (not to be unreasonably withheld or delayed), the Substantial Completion Punch List. Following review and approval of such Substantial Completion Punch List, Contractor shall work diligently to complete all items contained thereon in a timely manner in accordance with this Agreement.

10.6 Substantial Completion. “Substantial Completion” shall be deemed to have occurred upon satisfaction of all of the following conditions:

(a) Mechanical Completion shall have been achieved;

(b) The Facility shall be capable of being operated in accordance with the Specifications without damage thereto or to any property or injury to any Person and in compliance with all Owner Permits, Laws and orders of all Government Authorities then in effect;

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(c) Contractor shall have performed Performance Testing for the Facility and the results of such Performance Testing shall have satisfied the applicable Minimum Performance Guarantees, all according to the applicable Testing Procedures and the requirements of Article 10;

(d) Contractor shall have completed the performance of the Services according to all of the provisions of this Agreement, with the exception of those items specified in the Substantial Completion Punch List, which Contractor shall have prepared and for which Contractor shall have received approval from Owner (such approval not to be unreasonably withheld or delayed);

(e) Contractor shall have delivered to Owner all Documentation that Contractor is required to deliver to Owner pursuant to Exhibit A-3; and

(f) Contractor shall have delivered to Owner a certificate signed by Contractor certifying that all of the preceding conditions in this Section have been satisfied.

Upon satisfaction of all of the foregoing conditions for Substantial Completion, Owner shall accept the Facility, subject to Final Completion according to this Article 10, by delivering to Contractor notice of that acceptance promptly, and Contractor shall turn over risk of loss and care, custody, control and operation of the Facility to Owner. For the purposes of calculating Liquidated Damages, the date upon which Contractor submits the certifying notice required by this Section 10.6 (if such notice is accurate) shall be deemed the Substantial Completion Date.

If Contractor is unable to satisfy any of the foregoing conditions as a result of any event or circumstance for which neither Contractor nor any Subcontractor is responsible or as a result of the improper performance of any Owner Equipment or any other fault of any supplier of any Owner Equipment and Contractor has complied with its obligations relating to such Owner Equipment in accordance with Section 3.1(a)(ii), Contractor shall be entitled to a Change Order providing, at Owner’s election, that such condition is deemed to have been satisfied (but only to the extent Contractor is unable to satisfy such condition) or for *** and the Guaranteed Substantial Completion Date or otherwise as may be reasonable under the circumstances.

10.7 Final Completion. “Final Completion” shall be deemed to have occurred upon satisfaction of all of the following conditions:

(a) Contractor shall have achieved all conditions for Substantial Completion;

(b) Contractor shall have completed all Performance Testing and either (i) all Performance Guarantees shall have been satisfied according to the Testing Procedures, or (ii) Contractor shall have satisfied all of the Make Right Performance Guarantees and shall have satisfied its Performance Liquidated Damage obligations as required by Section 12.2 for those Performance Guarantees that allow a performance buy-down;

(c) The performance of the Services (except for Services relating to any warranty Work) shall be one hundred percent (100%) complete, including the completion (or buying down) by Contractor of all items on the Substantial Completion Punch List in accordance with this Agreement;

(d) Contractor shall have delivered to Owner the Documentation that Contractor is required to deliver to Owner pursuant to Exhibit A-3 dated as of the Final Completion Date;

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(e) There shall exist no Contractor Default and no event which, with the passage of time or the giving of notice or both, would be a Contractor Default; and

(f) Contractor shall have delivered to Owner a certificate signed by Contractor certifying that all of the preceding conditions in this Section have been satisfied.

11. OWNER’S RIGHT TO OPERATE

11.1 Intentionally Omitted.

11.2 Owner’s Right to Operate Prior to Satisfaction of Performance Guarantees. If the Facility fails to satisfy the Performance Guarantees during the Performance Testing or fails to achieve Substantial Completion by the Guaranteed Substantial Completion Date and the Facility can be operated in compliance with applicable Laws, Owner, in its sole discretion, shall have the right nonetheless to operate the Facility and shall give Contractor written notice of its decision. If Owner elects to operate the Facility and, during such time, does not permit Contractor to cure the Defects necessary to satisfy the Minimum Performance Guarantees, then the Guaranteed Substantial Completion Date and Guaranteed Final Completion Date (if such dates have not passed) shall be extended on an equitable basis until such time as Owner tenders the Facility to Contractor for further Services and Performance Testing, and Contractor shall be entitled to a Change Order for equitable schedule and/or price adjustment. Owner shall bear the risk of loss during such time as it operates the Facility. Owner’s operation of the Facility under this Section shall not reduce Contractor’s obligations under this Agreement, including Contractor’s obligation to cause the Facility to satisfy the Specifications and applicable Performance Guarantees, except for normal wear and tear and operation not in accordance with the Specifications or Prudent Industry Practices. Notwithstanding anything to the contrary, if Owner elects to operate the Facility for more than *** as contemplated in this Section 11.2, and such election to operate prevents Contractor from proceeding timely with curing any Defects during such operating time, then the degradation curves set forth in Exhibit A-2 shall apply.

12. ***

12.1 ***

12.2 ***

12.3 ***

12.4 Payment. The *** specified in Sections 12.1 and 12.2, if owing following the application of the provision of Section 12.3, shall be due and payable *** written demand by Owner. *** that remain unpaid after the expiration of such ten-Day period shall bear interest at the Prime Interest Rate plus 4% per annum or the highest rate allowed by applicable Law, whichever is less. Any *** disputed by Contractor and determined to be payable pursuant to the resolution of such dispute in accordance with this Agreement shall also bear interest from the expiration of the ten-Day period referred to above at the Prime Interest Rate plus 4% per annum or the highest rate allowed by applicable Law, whichever is less. Notwithstanding the assessment of interest, and in addition to its other rights and remedies, Owner shall have the right to offset the amount of any *** plus interest against any amounts due or that may become due to Contractor under this Agreement. Any amounts of *** determined to be wrongfully assessed against Contractor by Owner shall bear interest, from

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the time such amounts were paid by Contractor or offset by Owner, at the Prime Interest Rate plus 4% per annum or the highest rate allowed by applicable Law, whichever is less.

13. WARRANTY

13.1 Services Warranty Period. Contractor warrants that all Services will be performed in a professional and workmanlike manner, will conform to the requirements of this Agreement, including the requirements set forth in Section 3.1(a)(ii), and will reflect competent professional knowledge and judgment for a period commencing on the date such Service was performed and ending *** after the Substantial Completion Date (the “Services Warranty Period”), provided that the Services Warranty Period for each Service performed with respect to the Substantial Completion Punch List shall commence upon Contractor’s completion of, and Owner’s acceptance of, such Service and shall continue for a period of *** thereafter or after the Substantial Completion Date, whichever is later.

13.2 Equipment Warranty Period. Contractor warrants that the Equipment furnished to Owner will be free from Defects in workmanship and material and will conform to this Agreement, including the Specifications, for a period of *** from Substantial Completion (the “Equipment Warranty Period”), provided that the Equipment Warranty Period for each item on the Substantial Completion Punch List shall commence upon Contractor’s completion of, and Owner’s acceptance of, the particular Substantial Completion Punch List item and shall continue for a period of *** thereafter or after the Substantial Completion Date, whichever is later. In addition, to the extent the Owner and Contractor negotiate an equipment warranty period with a Subcontractor that exceeds the time periods set forth herein, Contractor shall assign for the benefit of the Owner any such warranty period that exceeds the *** period.

13.3 Extension of Warranty Periods. If a Defect (as defined in Section 13.4) is discovered within the applicable Warranty Period and such Defect is not cured to the reasonable satisfaction of Owner, then the applicable Warranty Period shall be extended to the *** of the date such Defect was corrected, but only with respect to the Equipment or Service that was the subject of such Defect. In no event shall any Services Warranty Period or Equipment Warranty Period extend beyond *** from the Substantial Completion Date.

13.4 Defects. If, within the Services Warranty Period or Equipment Warranty Period, as applicable, breaches or failures of the foregoing warranties (“Defects”) are discovered by Owner or Contractor, Contractor shall commence, within a timely manner upon being discovered or upon notice from Owner, to correct, and diligently and continually prosecute measures which are reasonably calculated to correct, such Defects, including re-performance or re-provision of any affected portion of the Work and repair of any resulting damage, and shall demonstrate to Owner’s reasonable satisfaction that such Defects have been properly corrected. The Parties shall use commercially reasonable efforts to coordinate performance of warranty Work at a time responsive to and consistent with Owner’s interest in the efficient operation of its business and so as to minimize revenue loss to Owner and to avoid disruption of Owner’s operations at the Facility. Contractor shall be responsible for all inspection, removal, packaging, transportation, installation, and consulting for the correction of Defects. Owner shall provide Contractor with reasonable access at the Site to correct Defects. All costs of correcting Warranty Defects shall be treated ***. All such Warranty costs shall be ***.

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13.5 Responsibility for Warranty Work. Contractor shall have primary liability with respect to the warranties in this Agreement other than for the Owner Equipment, whether or not any Defect or other matter is also covered by a warranty of a Subcontractor, and Owner need only look to Contractor for corrective action. In addition, Contractor’s warranties shall not be restricted in any manner by any warranty of a Subcontractor, and the refusal of a Subcontractor to provide or honor a warranty or to correct defective, deficient or nonconforming Work shall not excuse Contractor from its liability on its warranties to Owner. Contractor shall have no responsibility to perform any warranty Work with respect to Owner Equipment unless any Defect with respect to such Owner Equipment is attributable to Contractor’s failure to comply with the requirements set forth in Section 3.1(a).

13.6 Title Warranty. Contractor warrants that it shall provide to, and, effective as of the applicable date set forth in Section 22.1, hereby assigns and transfers to, Owner good, marketable and exclusive title to the paid-up Equipment, free and clear of all Liens; provided, however, that Contractor shall not be required to assign and transfer to Owner good, marketable and exclusive title to certain intellectual property to be licensed to Owner as provided in Article 19. Contractor represents and warrants that it has the right to grant the license rights granted by Contractor herein. In the event of any nonconformity with or breach of this Section, Contractor shall, at its own expense, promptly, and in any event within thirty (30) Days thereof, remove any Lien on any of such Equipment or otherwise provide Owner good, marketable and exclusive title to such Equipment, free and clear of all Liens, or, as the case may be, provide Owner the license rights purported to be granted by Contractor herein; provided, that, if Contractor is unable within such thirty (30) Day period to remove such Lien, Contractor may post a bond in an amount (and otherwise in form and substance) reasonably acceptable to Owner so long as Contractor continues to use all commercially reasonable efforts to remove such Lien as promptly as practicable. This Section shall survive the expiration, cancellation or termination of this Agreement.

13.7 Intellectual Property Warranty. Contactor represents and warrants that the Services performed by Contractor or its Subcontractors, the Equipment and the Documentation, or any part of any of the foregoing, will not infringe or constitute a misappropriation of any right of any third party, including any copyrights, mask work rights, patent rights, trademark rights, trade secret rights or confidentiality rights.

13.8 Warranty Assistance. During the Warranty Periods, Owner shall, without cost to Contractor: (a) provide Contractor reasonable working access (subject to such restrictions and conditions as Owner may have instituted generally for its contractors) to the Site to remove, disassemble, replace and reinstall any Equipment with respect to which a Defect exists; (b) remove any material or structures not provided or installed by Contractor; and (c) provide Contractor reasonable access to Facility personnel as are reasonably necessary to assist Contractor in the performance of its warranty obligations.

13.9 Conditions of Warranty. To the extent that Contractor shows that any failure by Contractor to meet the foregoing warranties is the result of (a) Owner’s failure to maintain the Equipment furnished in a reasonable manner or in accordance with any reasonable Contractor requirements conveyed to Owner, (b) Owner’s failure to operate the Equipment within its rating or to operate and maintain the Equipment in a reasonable manner consistent with equipment vendors’ instructions, (c) Owner subjecting the Equipment to abuse or misuse, or (d) normal wear and tear or corrosion inherent in the operation of the Facility, then, to that extent, Contractor shall be excused for said failure.

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13.10 Exclusive Warranties. THE WARRANTIES SET FORTH IN THIS AGREEMENT ARE EXCLUSIVE AND ARE IN LIEU OF ALL OTHER WARRANTIES WHETHER STATUTORY, EXPRESS, OR IMPLIED (INCLUDING ALL WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, AND ALL WARRANTIES ARISING FROM COURSE OF DEALING OR USAGE OF TRADE). Correction of Defects in the manner and within the period of time provided herein shall constitute complete fulfillment of all of the liabilities of Contractor with respect to such Defect, whether the claims by Owner are based in contract, in tort (including negligence and strict liability), or otherwise.

14. INDEMNIFICATION

14.1 Contractor’s Indemnity. Contractor shall indemnify and hold harmless Owner, its parents and Affiliates, and their respective partners, shareholders, members, agents, employees, officers, directors and lenders (collectively, the “Owner Indemnitees”) from and against:

(a) any and all Third Party Claims and all damages, liabilities, losses, costs and expenses associated therewith (including attorneys’ fees and other professionals’ fees) for any injury of or death to persons, damage to or destruction of third party property, contamination of the environment or injury to natural resources, whether contractual, in tort, or as a matter of strict liability or liability imposed by Law, to the extent any of the foregoing arise out of the negligent or willful or wanton acts or omissions of Contractor, any Subcontractor or any of their respective employees, agents or third parties over which either has reasonable control during the performance of the Services, and

(b) any and all claims, demands or causes of action of every kind and character by any Person and all damages, liabilities, losses, costs and expenses associated therewith (including attorneys’ fees and other professionals’ fees) for:

(i) any violation or alleged violation of Laws by Contractor, any Subcontractor or any of their respective employees, agents or third parties over which either has reasonable control (unless caused by Owner, any of Owner’s Affiliates or subcontractors, or any of their respective employees or agents or third parties over which any of them has control);

(ii) any action taken by Contractor, any Subcontractor or any of their respective employees, agents or third parties over which either has reasonable control, which action results directly in Owner violating any Law; or

(iii) any prohibited assignment by Contractor of this Agreement.

14.2 Owner’s Indemnity. Owner shall indemnify and hold harmless Contractor, its parents and Affiliates and their respective partners, shareholders, members, agents, employees, officers, directors, and lenders (collectively, the “Contractor Indemnitees” and, together with the Owner Indemnitees, collectively the “Indemnified Parties” and individually an “Indemnified Party”) from and against:

(a) any and all Third Party Claims and all damages, liabilities, losses, costs and expenses associated therewith (including attorneys’ fees and other professionals’ fees) for any injury of or death to persons, damage to or destruction of third party property, contamination of the environment or injury to natural resources, whether contractual, in tort, or as a matter of strict liability or liability imposed by Law, to the extent any of the foregoing arise out of the negligent or willful or wanton

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acts or omissions of Owner or any of its employees, agents or third parties over which it has reasonable control during the performance of the Services; and

(b) any and all claims, demands or causes of action of every kind and character by any Person and all damages, liabilities, losses, costs and expenses associated therewith (including attorneys’ fees and other professionals’ fees) for:

(i) any violation or alleged violation of Laws by Owner, its employees or agents or third parties over which it has control (unless directly caused by Contractor, any of Contractor’s Affiliates, any Subcontractor, or any of their respective employees or agents or third parties over which any of them has control);

(ii) any prohibited assignment of this Agreement by Owner; or

(iii) any pre-existing Hazardous Materials.

14.3 Intellectual Property Indemnity. Contractor shall, at its own non-reimbursable expense, defend, indemnify and hold harmless Owner Indemnitees against any and all damages, liabilities, losses, costs and expenses (including attorneys’ fees and other professionals’ fees) associated with any claims, suits or proceedings brought against any of the Owner Indemnitees based on an allegation that any Services performed by Contractor or its Subcontractors, the Facility, the Documentation or the Equipment, or any part thereof, or use thereof, constitutes an infringement or misappropriation of any right of any third party, including any copyrights, mask work rights, United States patent rights, trademark rights, trade secret rights, confidentiality rights or other property rights, if Contractor is notified promptly in writing and given authority, information, and assistance for the defense or settlement of such claim suit or proceeding. Contractor will not be responsible for any settlement of such suit or proceeding made without its written consent. Contractor shall obtain Owner’s written consent, which may be withheld in Owner’s sole discretion, prior to entering into any settlement of any such claim suit or proceeding that does not include a complete liability release for all Owner Indemnitees or that would prohibit or restrict use of any part of the Facility, the Documentation or the Equipment by any Owner Indemnitees. If the use of the Facility, the Documentation or the Equipment, or any part thereof, as a result of any such claim, suit or proceeding is held to constitute infringement, and its use by any of the Owner Indemnitees is enjoined, Contractor shall, at its option and its own non-reimbursable expense, either: (i) procure for such Owner Indemnitees the right to continue using the Facility, the Documentation or the Equipment, or any part thereof to the full extent provided herein; (ii) replace same with substantially equivalent non-infringing Facility, Documentation or Equipment or parts thereof acceptable to Owner; or (iii) modify same in a manner acceptable to Owner and in conformance with the functional requirements of this Agreement so it becomes non-infringing. Contractor shall flow down the requirements of this Section 14.3 and make Owner direct beneficiary of the indemnification obligation in its subcontracts with all Major Subcontractors. Notwithstanding anything to the contrary, Contractor’s obligations under this Section 14.3 shall not apply to the Owner Equipment or any manuals or other documentation provided by the supplier of the Owner Equipment.

14.4 Indemnity Procedures for Third Party Claims.

(a) In the event of a Third Party Claim with respect to which an Indemnified Party has a claim for indemnification under this Article, then the Indemnified Party must notify the indemnifying Party thereof in writing of the existence of such Third Party Claim and must deliver copies of any

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documents served on the Indemnified Party with respect to such Third Party Claim; provided, however, that any failure to notify the indemnifying Party or deliver such copies will not relieve the indemnifying Party from any obligation hereunder unless (and then solely to the extent that) the indemnifying Party is materially prejudiced by such failure.

(b) The indemnifying Party shall have the right to conduct and control, through counsel of its own choosing, reasonably acceptable to the Indemnified Party, any Third Party Claim; provided, however, that (i) if requested by the Indemnified Party, the indemnifying Party provides the Indemnified Party with evidence reasonably acceptable to the Indemnified Party that the indemnifying Party will have the financial resources to defend against the Third Party Claim and fulfill its indemnification obligations hereunder, (ii) the Indemnified Party may, at its election, participate in the defense thereof at its sole cost and expense and (iii) if (A) the indemnifying Party shall fail to defend any Third Party Claim, (B) the Parties mutually agree in writing to allow the Indemnified Party to assume the defense of such Third Party Claim and forego any indemnity claimed under this Article, (C) in the reasonable opinion of legal counsel for the Indemnified Party, such Third Party Claim involves the potential imposition of criminal liability on the Indemnified Party, its directors, officers, employees or agents, (D) in the reasonable opinion of legal counsel for the Indemnified Party, the Third Party Claim involves, or is likely to involve, any claim by any Government Authority or (E) in the reasonable opinion of legal counsel for the Indemnified Party, an actual or potential conflict of interest exists where it is advisable for such Indemnified Party to be represented by separate counsel, then the Indemnified Party shall be entitled to control and assume responsibility for the defense of such Third Party Claim, at the cost and expense of the indemnified Party. The indemnifying Party may, in any event, participate in such proceedings at its own cost and expense.

(c) The indemnifying Party, in the defense of any such litigation, other proceeding or other claim, shall have the right in its sole discretion to settle such Third Party Claim only if (i) such settlement involves only the payment of money and execution of appropriate releases of the Indemnified Party and its Affiliates, (ii) there is no finding or admission of any violation of Law, and (iii) the Indemnified Party or its Affiliates will have no liability with respect to such compromise or settlement. Otherwise, no such Third Party Claim shall be settled or agreed to without the prior written consent of the Indemnified Party. The Indemnified Party and the indemnifying Party shall fully cooperate in good faith in connection with such defense and shall cause their legal counsel, accountants and affiliates to do so, and shall make available to the other Party all relevant books, records, and information (in such Party’s control) during normal business hours, and shall furnish to each other such other assistance as the other Party may reasonably require in connection with such defense, including making employees of the Indemnified Party available to testify and assist others in testifying in any such proceedings.

15. INSURANCE

15.1 *** Builder’s Risk

(a) ***

(b) ***

(c) *** shall be in the name of the Owner. Contractor, its Affiliates and its Subcontractors *** shall be included as an additional insured.

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(d) ***, Contractor (and its Subcontractors) shall be responsible for deductibles up to *** per occurrence for all other real property and tangible personal property (except up to *** per occurrence for start-up and testing of all Equipment) at the Site ***.

(e) *** shall, and shall cause its underwriters to, waive subrogation against *** and its *** on such *** insurance policy except for any claims or matters in which the Equipment warranty or the Services warranty provided by *** hereunder are involved. It is further agreed that *** may elect to ***. In the event that *** elects to self-insure *** shall waive its right to recover the cost to repair or replace such loss or damage from *** in excess of the deductible and to the extent that coverage would have been available had Owner obtained the foregoing *** insurance policy. Should a loss be sustained at the Site and in the course of construction to property that is to be incorporated into the Project, *** shall replace or repair such loss or damage in accordance with the terms of this Agreement, and *** shall be reimbursed for all such costs plus the cost of extended overhead (including for home office costs and procurement costs). *** shall act on behalf of ***, for the purpose of adjusting any loss ***.

15.2 ***

(a) ***. Within *** of the Amendment Date, until Final Completion, *** and without limiting its indemnity obligations under this Agreement, Contractor shall establish a ***, and shall, for all tiers who have enrolled or shall enroll in the ***, procure, maintain and pay the premiums for ***:

Type	Coverage Amount
(a)     Workers’ Compensation including U.S. Longshoremen’s and Harbor Workers Act Coverage or other required coverage as appropriate and including b) below	Statutory
(b)    Employers Liability	*** each accident; *** each employee disease; *** policy limit disease

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Type	Coverage Amount
(c)     Commercial General Liability Insurance shall be written ISO occurrence Form (CG 00 01 10 01) or equivalent and must include the following: •   Products Liability/Completed Operations for *** beyond Final Completion •   Coverage for all premises and operations. The policy shall be endorsed to provide the Designated Construction Project(s) General Aggregate Limit Endorsement (ISO CG 2503, Ed 03/97) •   If Work to be performed includes construction or demolition operations within 50 feet of any railroad property and affecting any railroad bridge or trestle, tracks, road-beds, tunnel, underpass or crossing, then such policy will include a Railroad’s Contractual Liability Endorsement (ISO CG 2417, Ed 01/96); •   Coverage for demolition and removal of any building or structure, collapse, explosion, blasting, excavation and damage to property below the surface of the ground (XCU coverage). •   Hazard and Personal Injury, with Employee Exclusion and Contractual Exclusion Deleted	*** per occurrence with *** aggregate project specific (with dedicated coverage amounts fully available to any obligation under this Agreement)
(d)     Umbrella/Excess Liability Insurance following form and excess of coverages in sections a, b and c above. Hired and Non-Owned automobile coverage added via endorsement for Owner and Contractor	*** project specific per occurrence and aggregate (with dedicated coverage amounts that are fully available to any obligations under this Agreement)

(b) ***. Owner shall have authority to exclude any Subcontractor ***, such decision not to be unreasonably delayed or withheld. Until (a) ***, and (b) ***, for all such Subcontractors who *** but who are engaged to perform any Service under this Agreement, Contractor shall itself obtain

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and maintain and shall obtain and maintain a certificate of insurance from such Subcontractor evidencing that its Subcontractors have obtained and will maintain and keep in full force and effect, as part of the ***, Workers Compensation, Employers Liability, General Liability and Excess Liability insurance in the amounts and per the requirements listed in Section 15.2(a) above and that meet the requirements of Section 15.2(c) and Section 15.4 below. Such insurance will defend and indemnify Contractor, such Subcontractor, and Owner and their respective trustees, directors, officers, partners, agents, representatives, and employees from claims of the type and minimum limits as set forth in Section 15.2(a) above.

(c) ***. All of the above-referenced insurance coverages in (a) and (b) above and the additional insurance coverages as required from time to time as noted in Section 15.3 below (which are for loss exposure other than Workers Compensation, General Liability, Employers Liability and Excess Liability) shall be in forms approved by Owner (which approval evaluation shall not be unreasonably withheld or delayed) and with insurance companies approved to do business in the State that have (and shall maintain during the applicable policy period) a minimum A.M. Best rating of A-VII. The insurance shall be maintained until ***, except for Products Liability/Completed Operations coverage, which shall be maintained for *** beyond such date. ***. Liability insurance coverage limits set forth herein are minimums, and dedicated to Services performed for Owner related to the Project.

15.3 Contractor’s and Subcontractor’s Standard Insurance Requirements. *** of any tier, and whether ***, shall comply with all insurance requirements in subsections (a) through (g) below ***:

Type	Coverage Amount
(a)     Automobile, Bodily Injury and Property Damage Liability insurance on ISO form (CA 00 01 10 01) or equivalent. Must include coverage for the following: (1) owned motor vehicles; (2) hired motor vehicles; (3) other non-owned vehicles; and (4) coverage for certain railroad operations CA2070 10/01.	*** per occurrence
(b)     All Risk Contractor’s Equipment Insurance covering owned, used, and leased equipment required to perform the Work. Contractors or Subcontractors may elect to self insure such exposure if approved in writing by Owner, which approval shall not be unreasonably withheld or delayed.
(c)     Workers Compensation and Employers Liability Insurance covering Off-Site Activities Only (if enrolled in the CCIP, otherwise no site limitation), and having North Carolina Statutory Limits with All States coverage including U.S. Longshoremen’s and Harbor Workers Act Coverage as appropriate and Employer’s Liability Limits.	*** Each Accident Bodily Injury by Disease *** Policy Limit Bodily Injury by Disease. *** Each Disease Bodily Injury by Disease.
(d)     Commercial General Liability Insurance covering	*** per occurrence, *** Annual

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Type	Coverage Amount
Off-Site Activities Only (if enrolled in the CCIP, otherwise no site limitation).	Aggregate.
(e)     If aircraft are used in performance of the Services, Contractor shall provide or cause the operators of Aircraft to provide Aircraft Liability Insurance	*** combined single limit
(f)      If Ocean Cargo Shipments are made, Contractor shall provide Open Cargo Insurance	The maximum value of shipment, including packing, freight duties, and fees
(g)     If performing any design, engineering or architectural Services, Professional Liability Insurance (also known as errors and omissions insurance), which shall insure Contractor’s/Subcontractor’s liability arising out of or relating to any design, engineering or architectural Services.	*** project specific limit with reporting requirements for claims made forms of *** after Final Completion.

Prior to beginning Work at the Site, Contractor shall obtain from each Subcontractor of every tier industry standard ACORD (or other Owner approved form) certificates evidencing the above coverages and shall make available such certificates to Owner’s designated insurance administrator upon request. All coverages and certificates further shall show Owner as an additional insured (except Worker’s Compensation). All insurance coverage (except Professional Liability, if any) shall include a waiver of subrogation rights by the insurer against Owner.

15.4 General Insurance Requirements.

(a) The provisions of Section 15.2 and Section 15.3 above do not modify or change any responsibility of Contractor or its Subcontractors as stated elsewhere in this Agreement. Owner assumes no responsibility for the solvency of any insurer to settle any claim. The insurance requirements herein are separate and apart from and in no way limit Contractor’s Indemnity as stated in Section 14 of this Agreement. Anything herein to the contrary notwithstanding, the liabilities of Contractor under this Agreement shall survive and not be terminated, reduced or otherwise limited by any expiration or termination of insurance coverages. Neither approval nor failure to disapprove insurance furnished by Contractor shall relieve Contractor from responsibility to provide insurance as required by this Agreement. No policy shall contain an exclusion that it would not respond to cover losses for damages to any Owner pre-existing property. All policies of insurance required in Section 15.2 and Section 15.3 above shall be endorsed or shall otherwise provide that Contractor’s insurance shall be primary with respect to Contractor’s acts or omissions and not be in excess of, or contributing with, any insurance maintained by Owner (other than any Builders Risk as provided in this Agreement). Owner and its successors and assigns shall be named as additional insureds for their imputed liability as a result of Contractor’s negligent operations hereunder, using ISO additional insured (CG 20 10) or equivalent, under all policies of liability insurance to be maintained by Contractor (except Worker’s Compensation Insurance and Professional Liability). The liability policies of insurance shall be endorsed or shall otherwise include a severability of interest. The

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policies set forth in this Article shall each contain a provision that coverages afforded under the policies will not be cancelled, renewed or materially modified unless at least *** prior written notice via certified United States mail has been given to Contractor and Owner or to any other entities as herein or hereinafter required, at the address so provided to the insurance company. All insurance required by this Article shall be provided by companies reasonably acceptable to Owner and that have (and shall maintain during the applicable policy period) an AM Best Rating of A- VII or higher. Certificates shall be provided to Owner on industry standard ACORD or Owner approved form showing such coverage in full force and effect shall be delivered to Owner within *** of the Amendment Date, within *** of each policy renewal or change and from time to time thereafter, as may be requested by Owner. All policies shall include waivers of any right of subrogation of the insurers there under against Owner and its successors and assigns using standard ISO forms or equivalent. The existence of any self-insured retentions (SIRS) over which the required policies apply must be disclosed to and approved by Owner, such approval not to be unreasonably withheld or delayed. Contractor shall provide copies of CCIP placement and renewal policies and all endorsements to the Owner not later than *** following placement or renewal.

(b) Contractor shall comply with the conditions stipulated in each of the insurance policies. None of the insurance coverage required hereunder shall be on “claims-made” forms, except Professional Liability. Coverage amounts must be fully available to any obligations under this Agreement (not eroded by any other project or agreement) and apply on an annual basis. CCIP provisions for excluding Subcontractors must be disclosed and approved by Owner in writing prior to CCIP effective date.

(c) If any of the Project specific insurance required under this Article shall be directly or indirectly depleted by *** or more (whether due to payment of insurance proceeds, creation of a reserve or otherwise) prior to Final Completion, Contractor shall obtain from the insurer a reinstatement option, if commercially available at a cost comparable to the original policy cost, to each such policy at least equal to the depleted amount. *** shall bear the cost of such option (including the cost associated with the reinstatement). Contractor shall cause such insurer to send to Owner a notice of such reinstatement and a copy of the reinstated policy related thereto upon Owner exercising and payment for the reinstatement.

(d) The insurance policies required by this Article shall allow for occupancy and utilization of the Facility, the Equipment and the Site by Owner, its Affiliates and any person reasonably permitted access thereto by Owner.

(e) During the time any Subcontractor is engaged to perform any Service under this Agreement, Contractor shall obtain a certificate of insurance from such Subcontractor evidencing that such Subcontractor has obtained, and will maintain and keep in full force and effect (required only for off-Site Work ***, otherwise for all Work performed by any Subcontractor), Worker’s Compensation in statutory amounts, Employer’s Liability, Commercial General Liability, Automobile Insurance and all other policies reasonably necessary to perform such Service with adequate coverages and in such amounts in accordance with Contractor’s normal practices and consistent with Good Industry Practices, and provide Owner with evidence acceptable to Owner of such coverage, or Contractor shall maintain such coverage under its own insurance policies ***. Contractor shall ensure that all Subcontractors obtain and maintain prudent insurance coverages. All Subcontractor coverages shall waive subrogation rights against Owner and Contractor. All Subcontractor coverages shall name Owner and Contractor as additional insureds (except Workers Compensation and Professional Liability).

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(f) Any certificates of renewal with respect to any insurance policy required to be maintained by Contractor hereunder shall be delivered to Owner promptly after renewal. Contractor shall insure that the insurer shall submit a copy of all receipts for premiums paid to Contractor promptly after payment of such premiums. Contractor shall be solely responsible for the timely payment in full of premiums for all insurance required of it hereunder. Should Contractor fail to provide or maintain any insurance required hereunder, Owner shall have the right, but not the obligation, to provide or maintain any such insurance, and to deduct the cost thereof from any amounts due and payable to Contractor, or, in the event there are no such amounts due and payable, Contractor shall reimburse Owner for such costs on demand. Contractor shall not unreasonably refuse to cooperate or to take any actions requested or necessary to prosecute any claims under any insurance policy required to be maintained by Contractor hereunder.

(g) With respect to ocean marine shipments, Contractor shall obtain at *** prior to any such shipment, cargo insurance covering “all risks” of loss or damage to property shipped, components of property shipped, or items contained in or shipped in or with the property shipped. This coverage is to be written on a replacement cost basis and in the full insurable value of these items, including packing and freight charges plus duties and fees. The coverage required by this paragraph shall continue in effect until appropriate coverage commences at the Site.

15.5 Insurance Pricing Assumptions. The Parties hereto hereby acknowledge and agree that the insurance requirements set forth herein are part *** are based upon the following base assumptions relating to such requirements: (a) Contractor’s Site payroll and site Work hours provided are based upon the terms and conditions set forth herein; (b) the total Site Work hours provided includes all appropriate hours applicable to a “wrap-up” type insurance program, including direct craft hours, subcontract hours (including F&E hours), field non-manual hours, start up hours and all applicable indirect, productivity and escalation adjustments; (c) total Site Work hours excludes hours not applicable to a “wrap-up” type insurance program, including home office, overtime and overtime related productivity, bonuses and per diem; (d) total Site payroll is calculated using bare labor rates and contains no markups, including burdens and benefits; (e) ***; (f) any additional costs to Owner associated with the “wrap-up” program for any reason, including changes in market premiums, claims, losses, deductibles or retentions shall be ***; (g) *** will remain in place until Final Completion of the project unless agreed to by Owner and (h) allowance of Owner representative(s) to attend any appropriate *** including claims status reviews.

16. PROJECT CREDIT SUPPORT

16.1 Financial Information. From the Effective Date until Final Completion, the Guarantor shall deliver to Owner (a) within *** Days following the end of each fiscal year, a copy of its annual report (or, if there is no such report, a copy of such report for its parent company) containing audited, consolidated financial statements for such fiscal year, and (b) within *** Days after the end of each of its first three fiscal quarters of each fiscal year, a copy of its quarterly report (or, if there is no such report, a copy of such report for its parent company) containing unaudited consolidated financial statements for such fiscal quarter. In all cases, the statements shall be prepared in accordance with generally accepted accounting principles. To the extent such quarterly reports are not available, upon the reasonable request of Owner in response to a credit event in the marketplace, Guarantor shall provide unaudited management financial information for such fiscal quarter.

16.2 ***

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16.3 ***

17. LIMITATION OF LIABILITY

17.1 No Consequential Damages. *** THEREOF, LOSS OF PROFITS OR REVENUES OR THE LOSS OF USE THEREOF, OR COST OF PURCHASED OR REPLACEMENT POWER.

17.2 *** CONTRACTOR’S AND ITS AFFILIATES’ AND SUBCONTRACTORS’ TOTAL AGGREGATE LIABILITY TO OWNER UNDER THIS AGREEMENT, WHETHER BASED ON CONTRACT, TORT (INCLUDING NEGLIGENCE, STRICT LIABILITY OR OTHERWISE), GUARANTEE, WARRANTY OR OTHERWISE, SHALL NOT EXCEED *** (THE “MAXIMUM LIABILITY AMOUNT”); PROVIDED, HOWEVER, THE MAXIMUM LIABILITY AMOUNT SHALL NOT APPLY TO, AND NO CREDIT SHALL BE ISSUED AGAINST THAT LIMITATION FOR (A) A PARTY’S INDEMNITY OBLIGATIONS HEREUNDER FOR THIRD PARTY CLAIMS FOR PERSONAL INJURY OR PROPERTY DAMAGE, (B) THE PROCEEDS THAT WOULD BE AVAILABLE, BUT FOR THIS SECTION, FROM INSURANCE THAT A PARTY IS REQUIRED TO MAINTAIN IN ACCORDANCE WITH THIS AGREEMENT, OR (C) CLAIMS WHICH ARISE FROM A BREACH OF OBLIGATIONS UNDER ARTICLE 18 OR ARTICLE 19.

18. LIENS

18.1 Liens. Contractor shall keep the Facility, the Site, the Equipment, the Owner Equipment and all other structures and equipment at the Site free from all Liens (unless such Lien is due to the non-payment by Owner of a Monthly Payment Invoice which is not the subject of a good faith dispute), and shall promptly notify Owner of any such Liens.

18.2 Discharge or Bond. Without limiting Contractor’s obligations under Section 14.1(a), Contractor shall take prompt steps to discharge or bond any Lien (unless such Lien is due to the non-payment by Owner of a Monthly Payment Invoice which is not the subject of a good faith dispute). If Contractor fails to so discharge or promptly bond any such Lien, Owner shall have the right, upon notifying Contractor in writing and providing Contractor reasonable time to discharge or bond the Lien, to take any and all reasonable actions and steps to satisfy, defend, settle or otherwise remove the Lien and consider all associated costs as ***. Contractor shall have the right to contest any Lien, provided that it first must provide to the lienholder, a court or other third Person, as applicable, a bond or other assurances of payment necessary to remove such Lien in accordance with the Laws of the State.

19. INTELLECTUAL PROPERTY

19.1 Delivery of Documentation. Prior to Final Completion, Contractor shall supply to Owner physical and electronic copies of all Documentation. All such Documentation shall include any corrections, improvements, and enhancements to such Documentation that were incorporated during the construction of the Facility and shall be the then-current revision thereof or on an “as-built” basis as of Final Completion. Except as otherwise set forth herein, Contractor shall submit all Contractor developed drawings to Owner electronically in native CAD format (dgn. or dwg. only), with signed hard copies of such drawings, which shall be of the same revision and status as the electronically delivered drawings. In lieu of such Contractor developed drawings being delivered in native CAD format, Contractor may deliver such drawings electronically in “tiff” format; provided, that such

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electronic file contains signatures and stamps and maintains the same revision and status as the hard copies of such drawings. In addition, any Subcontractor developed drawings, including, without limitation, (a) piping and instrumentation diagrams (P&IDs) that are not reproduced on Contractor’s P&IDs and (b) drawings of pre-fabricated buildings shall, in each case, also be provided by Contractor electronically in native CAD format (dgn. or dwg. only). On a case by case basis, Owner may permit such Subcontractor developed drawings to be delivered electronically in “tiff” format in lieu of such CAD format. Contractor shall provide Owner, during the Warranty Period and at no additional cost, any corrections to errors discovered by Contractor or Owner in the Documentation subsequent to Final Completion. Contractor shall promptly notify Owner of the discovery of any such errors.

19.2 Ownership of Rights in Documentation. All rights, title and interests in and to the paid-up Documentation shall be owned by Owner; provided, that all rights, title and interests in and to Contractor Confidential Information within the Documentation shall remain with Contractor or its licensors. For such Contractor Confidential Information, Contractor hereby grants to Owner a non-transferable (except only as part of the sale or transfer of the Facility), royalty-free, fully paid up, irrevocable, sub-licensable, nonexclusive license to use and copy such Contractor Confidential Information, but only for the purposes of Facility maintenance, operation, training, modification, consultation, repair, decommissioning and compliance with Laws, and subject to the restrictions on Contractor Confidential Information set forth in Section 20.1.

19.3 Ownership of Invention Rights. Contractor shall retain the ownership rights in any and all discoveries and inventions (patentable or un-patentable) that Contractor makes, creates, develops, discovers or produces in connection with the performance of the Services; provided, however, that Contractor hereby grants to Owner a non-transferable (except only as part of the sale or transfer of the Facility), royalty-free, fully paid up, irrevocable, sub-licensable, nonexclusive license to use and copy such discoveries and inventions for the purposes of Facility maintenance, operation, training, modification, consultation, repair, decommissioning and compliance with Laws.

19.4 Disclosure of Documentation. Owner may disclose or otherwise make available Documentation to a third party with whom Owner contracts for maintenance, operation, training, modification, repair, consultation or decommissioning or other activities relating to the Facility in order to comply with applicable Laws; provided, that, if such Documentation contains Contractor’s Confidential Information, the provisions of Section 20.1 shall apply. In the event of a Contractor Default and Owner termination, in addition to the rights above and notwithstanding anything in this Agreement to the contrary, Owner shall have the right to disclose the Documentation to third parties with whom Owner contracts for engineering, construction, commissioning or testing of the Project, provided that, prior to such disclosure, such third parties shall execute a confidentiality agreement at least as strict as the requirements set forth herein.

19.5 Other Licenses. To the extent that a license may be required under any patent, trade secret right or other proprietary right of Contractor or any Subcontractor to maintain, operate, conduct training, modify, repair, or decommission the Facility or comply with applicable Laws, Contractor hereby grants to Owner a non-transferable (except only as part of the sale or transfer of the Facility), royalty-free, fully paid up, irrevocable, nonexclusive license under such patent, trade secret and other proprietary right for such purposes.

20. CONFIDENTIAL INFORMATION

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20.1 Confidentiality Obligations. Each Party agrees: (a) to treat the other Party’s Confidential Information as confidential and to take reasonable precautions to prevent unauthorized disclosure or use of the other Party’s Confidential Information, such precautions taken being at least as great as the precautions taken by such Party to protect its own Confidential Information (but in no case less than reasonable care); (b) not to disclose the other Party’s Confidential Information to any third party other than as provided in Section 20.2 or with the other Party’s prior written authorization; and (c) not to use the other Party’s Confidential Information except for performance of this Agreement, compliance with applicable Laws, or maintenance, operation, training, modification, repair, consultation or decommissioning of the Facility.

20.2 Permitted Disclosures. A Party may disclose the other Party’s Confidential Information to third parties as follows:

(a) A Party may disclose the other Party’s Confidential Information to any Government Authority if required to do so, in which case the Party from whom such disclosure is required shall (i) give the other Party all reasonably possible notice so as to facilitate such other Party being able, should it so desire, to seek a protective order or similar protection, and (ii) fully cooperate with the other Party’s efforts, at the other Party’s expense, to obtain such protection.

(b) Contractor may disclose Owner’s Confidential Information to a Subcontractor if (i) such disclosure is necessary for Subcontractor’s performance of its subcontract with Contractor and (ii) such Subcontractor first executes a written confidentiality agreement with Contractor (unless a confidentiality obligation is already included in the Subcontract) in substance reasonably acceptable to Owner.

(c) Subject to the requirements of Section 19.4, Owner may disclose Contractor’s Confidential Information to (i) potential investors; (ii) third parties engaged by Owner to provide consultation regarding the Facility; (iii) third parties with which Owner contracts for engineering, construction, commissioning, testing, maintenance, operation, training, modification, repair, consultation or decommissioning of the Facility or other activities relating to the Facility undertaken in order to comply with applicable Laws or request of Governmental Authorities having jurisdiction over the Facility or Owner; and (iv) purchasers and prospective purchasers of the Facility, provided, that in any of the foregoing instances the third parties to which disclosure is made first execute a written confidentiality agreement with Owner which provides Contractor protections which are at least as strict as the requirements set forth herein.

20.3 Publicity. Unless required by law or securities practice and regulations, Contractor shall not make any announcement, give any photographs, or release any information concerning all or a portion of the Work, this Agreement, or the Facility, to any member of the public, press, Person, or any official body, without Owner’s prior written consent; provided, that Contractor may, at any time after Owner’s first public announcement of the Project or this Agreement, include the Project (but not the details of this Agreement) in its regular experience lists.

21. ENVIRONMENTAL; HAZARDOUS MATERIALS

21.1 Material Safety Data Sheets. Contractor shall provide to Owner all Material Safety Data Sheets covering all Hazardous Materials and hazardous chemicals to be furnished, used, applied, or stored by Contractor, or any of its Subcontractors, at the Site in connection with the Services. Contractor shall provide Owner’s Project Director with copies of any such Material Safety Data

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Sheets prior to entry at the Site or with a document certifying that no Hazardous Materials or hazardous chemicals will be brought onto the Site by Contractor, or any of its Subcontractors, during the performance of the Services. Contractor shall coordinate with Owner’s Project Director to provide a listing of all of Contractor’s hazardous chemicals and their quantities at the Site for purposes of chemical inventory reporting pursuant to 40 C.F.R. Part 370 and similar State regulations.

21.2 Facility Use, Storage Removal. When the use or storage of explosives or other Hazardous Materials or equipment is necessary for the performance of the Services, Contractor shall exercise the utmost care and shall conduct its activities under the supervision of properly qualified personnel in accordance with all applicable Laws. Before the Substantial Completion Date, Contractor shall collect (for removal by Owner from the Site) in accordance with all applicable Laws all explosives and other Hazardous Materials that Contractor or its Subcontractors brought onto the Site or hazardous chemicals and equipment Contractor or its Subcontractors used, stored or located at the Site or any neighboring property, unless the same have been permanently incorporated into the Facility. All such equipment and materials shall be collected, containerized and stored in accordance with all applicable Laws, and Contractor shall so certify in writing to Owner.

21.3 Notice of Presence. Prior to bringing any Hazardous Material or other hazardous chemicals to the Site, Contractor shall provide written notice to Owner identifying any such Hazardous Materials or hazardous chemicals that Contractor, or its Subcontractors, proposes to bring onto the Site.

21.4 Labeling; Training. Contractor shall label all Hazardous Materials that Contractor or its Subcontractors bring to the Site and train all employees and other Persons, as necessary, in the safe use of such Hazardous Materials as required by all applicable Laws.

21.5 Handling, Collection, Removal Transportation and Disposal.

(a) Unless otherwise agreed by the Parties, Contractor shall be responsible for the proper handling, collection, and containerizing of all Hazardous Materials generated or brought onto the Site by Contractor or any Subcontractor or spilled or introduced into or at the Site by Contractor or any Subcontractor, including any Hazardous Materials furnished, used, applied or stored at the Site by Contractor, including, used oils, greases, and solvents from flushing and cleaning processes performed under the Agreement. Such Hazardous Materials will then be delivered to Owner for proper storage, transportation and disposal. All activities performed by Contractor in connection with the handling, collection and containerizing of such Hazardous Materials shall be performed in accordance with the requirements of all Government Authorities and all applicable Laws. For the avoidance of doubt, Contractor has no obligations with respect to the handling, collection, removal, disposal or containerizing of any pre-existing Hazardous Materials except to the extent the Gross Negligence or willful misconduct or wanton acts of Contractor or its Subcontractors caused the release of such pre-existing Hazardous Materials in which case Contractor shall remediate the released contamination.

(b) Contractor has included time in the Schedule for satisfying its obligations as to all Hazardous Materials that it is responsible for under this Agreement by virtue of such Hazardous Materials being brought onto the Site by Contractor or its Subcontractors. Contractor shall not seek, and shall not be entitled to receive, any payment hereunder or extension of time in the Schedule as a result of satisfying its obligations with respect as to any such Hazardous Materials brought onto the

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Site by Contractor or its Subcontractors, including the handling, collection, or containerizing of such Hazardous Materials.

21.6 Notice of Discovery. Contractor shall provide prompt written notice to Owner of all suspected Hazardous Materials that Contractor finds during performance of the Services.

21.7 Policies and Procedures. Contractor shall adhere to all Site policies and procedures for environmental compliance, including Owner’s Environmental Work Practices Manual and Hazardous Material safety programs. If no such Site policies or procedures exist, Contractor shall develop, implement and enforce effective written policies and procedures applicable to the Services, within the framework of all applicable Laws, for general Site safety and the proper labeling, handling, collection and containerizing of any Hazardous Materials at the Site in order to ensure the highest standards of prudent practice at the Site for the safety of all employees, agents and representatives of Contractor and any of its Subcontractors.

21.8 Asbestos Containing Products. Except as otherwise authorized by Owner in writing, all Equipment or Owner Equipment furnished, delivered or installed by Contractor and all materials and tools used by Contractor in the performance of the Services at the Site shall contain zero percent asbestos or refractory ceramic fibers. If Owner authorizes in writing such delivery or use, Contractor shall clearly mark all containers or other materials containing asbestos or refractory ceramic fibers, and such containers or materials shall be sealed to prevent any leakage of asbestos or ceramic fibers. Contractor shall indemnify, defend and hold harmless Owner from and against any and all claims, demands and damages incurred from any unauthorized asbestos or refractory ceramic furnished or delivered to or installed at the Site by Contractor or any Subcontractor.

21.9 Pre-Existing Hazardous Material. Owner shall indemnify Contractor and its Subcontractors from any liability in connection with any pre-existing Hazardous Material, except to the extent such liability was caused by the Gross Negligence or willful misconduct or wanton acts or omissions of Contractor or its Subcontractors. Except as provided above, Owner shall at all times remain the responsible Party for all pre-existing Hazardous Material and its remediation. Any assistance provided by Contractor shall be pursuant to a mutually agreed Change Order, and Contractor shall be entitled to a Change Order for equitable price and/or schedule adjustment if its cost or performance is impacted by the discovery of any pre-existing Hazardous Materials.

22. TITLE; RISK OF LOSS

22.1 Transfer of Title; Security Interest. Except as otherwise expressly provided in this Agreement, good, exclusive and marketable title, free and clear of all Liens (other than Liens created by the non-payment by Owner of a Monthly Payment Invoice which is not the subject of a good faith dispute), to the Equipment and to each of the constituent parts thereof shall pass to Owner upon the (i) delivery of such Equipment or constituent part thereof to the Site and (ii) payment of the amount then due under a Monthly Payment Invoice covering such Equipment or constituent part of such Equipment, notwithstanding any disputed amounts withheld or offset by Owner against any payment sought by Contractor in accordance with the terms of this Agreement. The passage of title to Owner shall not be deemed an acceptance or approval of such Equipment (or any Service), affect the allocation of risk of loss, affect any security interest in favor of Owner therein or otherwise relieve Contractor of any obligation under this Agreement to provide and pay for transportation and storage in connection with the Equipment. Further, upon the passage of title, the Equipment, the constituent

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parts thereof and the unused spare parts shall be specifically excluded from the bankruptcy estate of Contractor in the event of any bankruptcy or insolvency proceeding involving Contractor.

22.2 Risk of Loss. Whether or not title has passed to Owner, the risk of loss for all Equipment to be installed as a component of the Facility shall remain with Contractor until, and shall pass to Owner upon, Substantial Completion. Risk of loss for all Owner Equipment to be installed as a component of the Facility shall pass to Contractor upon its arrival at the Site and shall remain with Contractor until, and shall pass to Owner upon, Substantial Completion. Contractor shall be obligated to replace, repair or reconstruct the Equipment or the Owner Equipment that is lost, damaged, or destroyed during the period in which Contractor has risk of loss. For Equipment or Materials that are removed from the Site for repair, replacement or refurbishment under the Warranty, the risk of loss to such Equipment or Materials shall pass to Contractor once moved from the location at which it was installed. Owner will resume the risk of loss of such Equipment or Materials upon completion of re-installation of the repaired, replaced or refurbished Equipment at the Facility.

22.3 Contractor Tools. Risk of loss or damage to the equipment or tools of Contractor, all Subcontractors, and their respective employees and agents shall at all times remain with those parties, and Owner shall have no responsibility for such equipment or tools.

23. SUSPENSION; DEFAULT; TERMINATION

23.1 Suspension.

(a) Owner may, in its sole discretion, order Contractor to suspend all or any portion of the Work for a period of time as Owner may request. Contractor shall comply with such order. The suspension shall commence on the Day specified in Owner’s written notice to Contractor which shall be at least *** after Owner gives Contractor such notice.

(b) Contractor may suspend the Work without liability as if Owner had ordered a suspension in accordance with Section 23.1(a) upon written notice to Owner after the occurrence of any of the following:

(i) Nonpayment. Owner fails to pay or cause to be paid any amount that is not subject to a good faith dispute and has become due and payable by it to Contractor under this Agreement within *** after receipt of written notice that such amounts are past due;

(ii) Insurance. Owner fails to obtain and maintain insurance as required by this Agreement; and

(iii) Breach. Owner breaches any of its material obligations under this Agreement (other than those obligations relating to the matters set forth in Section 23.1(b)(i) or (ii)) and for which no other remedy is specified in this Agreement and, if such breach is capable of being cured, Owner fails to cure such breach within *** after written notice of such breach, provided that such cure period shall be extended to *** after written notice of such breach if such breach is capable of being cured but not within ***, and Owner immediately commences to cure such breach and diligently and continually prosecutes measures which are reasonably calculated to cure such breach within such *** period.

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(c) During any such suspension: (i) Contractor shall take reasonable precautions to protect, store and secure the Equipment and Owner Equipment against deterioration, loss or damage, and (ii) Owner shall reimburse Contractor on a current time and material basis consistent with the terms and conditions set forth in Exhibit I for all its costs, including those incurred in connection with the foregoing and for its (including its Subcontractors’) stand-by charges as well as demobilization and remobilization charges. Contractor shall resume any suspended Services promptly, but in no event later than fifteen (15) Days after Owner gives Contractor written notice to do so, or, for other provisions of this Agreement that allow Contractor to treat an action or inaction by Owner as a suspension, promptly following the reason for such suspension ceasing and, in each case, shall use its best efforts to fully resume the Services as soon as reasonably possible. Upon any suspension of all or any portion of the Services in accordance with this Section 23.1, Contractor shall be entitled to an equitable adjustment in the *** and the Schedule in accordance with Article 8.

23.2 Contractor Events of Default. Contractor shall be in default of its obligations pursuant to this Agreement upon the occurrence of any one or more of the following circumstances (each, a “Contractor Default”):

(a) Nonpayment. Contractor fails to pay or cause to be paid any amount that is not subject to a good faith dispute and has become due and payable by it to Owner under this Agreement within *** after receipt of written notice that such amounts are past due;

(b) Insolvency. Contractor or its Guarantor becomes Insolvent;

(c) Assignment. Contractor assigns or transfers, or attempts to assign or transfer, this Agreement or any right or interest herein, except as expressly permitted by this Agreement;

(d) Insurance. Contractor fails to obtain and maintain insurance as required under this Agreement;

(e) Performance Guarantees. Contractor fails to satisfy the Minimum Performance Guarantees by the Guaranteed Final Completion Date;

(f) Breach. Contractor breaches any of its material obligations under this Agreement other than those obligations relating to the matters set forth in Section 23.2(a) through (e) above and for which no other remedy is specified in the Agreement and, if such breach is capable of being cured, Contractor fails to ***; and

(g) Delay in Schedule. It is forecasted that Contractor will fail to meet Substantial Completion by the Guaranteed Final Completion Date as set forth in Section 6.3(b) hereof and, if such forecasted delay is capable of being cured, Contractor fails to cure such forecasted Schedule delay within *** after written notice of such breach, provided that the above cure period shall be extended to *** after written notice of such breach if such forecasted delay is capable of being cured within such *** period and Contractor is demonstrating continuous and diligent efforts to cure such breach and the forecasted Schedule is not slipping further behind.

23.3 Owner Remedies. In the event of a Contractor Default, Owner shall have any or all of the following rights and remedies:

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(a) Termination. Subject to the limitations on Contractor’s liability, Owner, without prejudice to any of its other rights or remedies under this Agreement, may terminate this Agreement or remove any portion of the Work from Contractor’s scope hereunder immediately by delivery of a notice of termination to Contractor;

(b) Equitable Remedies. Subject to the limitations on liability set forth in this Agreement, Owner may seek equitable relief, including injunctive relief, to cause Contractor to take action, or to refrain from taking action, pursuant to this Agreement, or to make restitution of amounts improperly retained or received under this Agreement; and

(c) Damages. Subject to Article 17, Section 7.3 and the other exclusive remedies set forth in this Agreement, Owner shall be entitled to seek all other remedies at law or in equity.

23.4 Owner Event of Default. Owner shall be in default of its obligations pursuant to this Agreement upon the occurrence of any one or more of the following circumstances (each, an “Owner Default”):

(a) Nonpayment. Owner fails to pay or cause to be paid any amount that is not subject to a good faith dispute and has become due and payable by it to Contractor under this Agreement within *** after receipt of written notice that such amounts are past due; and

(b) Insolvency. Owner becomes Insolvent.

23.5 Contractor Remedies. In the event of an Owner Default, Contractor shall have any or all of the following rights and remedies:

(a) Termination/Suspension. Contractor, without prejudice to any of its other rights or remedies under this Agreement, may terminate this Agreement or suspend performance of the Work immediately by delivery of written notice thereof to Owner, and such termination/suspension shall be deemed as if done for convenience of Owner under Section 23.6(a) or 23.1 (as applicable);

(b) Equitable Remedies. Subject to the limitations on liability set forth in this Agreement, Contractor may seek equitable relief, including injunctive relief or specific performance, to cause Owner to take action, or to refrain from taking action, pursuant to this Agreement, or to make restitution of amounts improperly retained or received under this Agreement; and

(c) Damages. Subject to Article 17, Contractor shall be entitled to seek all other remedies or damages available in equity or at law.

23.6 Termination for Convenience.

(a) Termination Rights. Owner may terminate this Agreement at its convenience and in its entirety upon prior written notice to Contractor, in which event Owner shall pay the cancellation charges set forth in Section 23.6(b).

(b) Cancellation Charges.

(i) [Intentionally Omitted.]

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(ii) If Owner terminates this Agreement under Section 23.6(a) at any time after the Amendment Date, Owner shall pay termination charges to Contractor, as Contractor’s exclusive remedy, which termination charges shall consist of all amounts billed or currently billable by Contractor and due and owing under this Agreement for Equipment delivered (or being fabricated for delivery) and Services performed in accordance with this Agreement prior to such termination (including in-progress work) and all unavoidable and reasonably incurred termination charges, such as those incurred through demobilization and storage or through cancellation charges paid to Subcontractors. The total amount payable by Owner as a termination charge shall be reduced by (A) any rebates, credits or refunds obtained, (B) the reasonable salvage value for undelivered and unpaid for Equipment, or (C) the sale of such Equipment to a third party, with the understanding that Owner, at its exclusive preference, may accept delivery of complete or incomplete Equipment included in the termination charges.

23.7 Termination for Force Majeure. Owner or Contractor may terminate this Agreement in its entirety, and without liability, due to Force Majeure in accordance with the terms of Article 9.

23.8 Effect of Termination. Upon termination of this Agreement or removal of any portion of the Work pursuant to this Article, Contractor shall immediately:

(a) stop the performance of all Services (or the Services included in the removed portion of the Work) except as may be necessary to preserve the Equipment and Owner Equipment as requested by Owner;

(b) issue no further purchase orders and enter into no further contracts relating to the Work (or the removed portion of the Work) except with the prior written consent of Owner;

(c) assign to Owner, upon Owner’s request, all rights of Contractor under contracts or purchase orders entered into by Contractor in connection with this Agreement (or the removed portion of the Work);

(d) to the extent possible, upon Owner’s request, terminate existing contracts and purchase orders entered into by Contractor in connection with this Agreement (or the removed portion of the Work);

(e) deliver all then existing Documentation (or the Documentation relating to the removed portion of the Work), including drafts thereof (subject to Article 19), to Owner in hard copy and electronic formats reasonably requested by Owner; and

(f) turn over care, custody and control at the Site of all Equipment (to the extent that Owner does not refuse to accept any such Equipment) and Owner Equipment (or to the extent relating to the removed portion of the Work).

24. SAFETY; INCIDENT REPORTING.

24.1 Environmental, Health and Safety Programs. Contractor shall be responsible for initiating, maintaining and supervising all safety precautions and programs in connection with its performance of the Agreement, including appropriate precautions and programs for areas in and around the Site. Without limiting the generality of the foregoing, Contractor shall comply with all applicable Laws

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and meet the requirements of all of Owner’s environmental, health, safety, and security policies and manuals as amended from time to time, including the Duke Energy Safe Work Practices Manual, the Duke Energy Scaffold Manual, the Duke Energy Lifting Program, the Duke Energy Environment, Health, and Safety Manual and the Duke Energy Contractor EHS Compliance Program. A copy of any policies and manuals of Owner shall be provided to Contractor upon request. Contractor shall designate a responsible, qualified full-time member of Contractor’s organization at the Site whose duty shall be the prevention of incidents and injuries and addressing unsafe and undesirable behavior for each of the following three (3) areas: environmental matters (U.S. Environmental Protection Agency and any applicable State agency), health matters (industrial hygiene and employee health hazard prevention/mitigation) and safety matters, as each area relates to construction activities generally and the Work specifically. One individual may be designated for more than one of these three areas if the individual is qualified in all such areas.

24.2 OSHA and Other Laws. Contractor shall give notices and comply with all applicable Laws bearing on the safety of Persons or property or their protection from damage, injury or loss, including the Occupational Safety and Health Act (“OSHA”) and the Americans with Disabilities Act.

(a) Contractor represents that it is familiar with the Site, the Services to be performed, the Equipment to be provided, the Facility to which the Equipment will be a part, the hazards of the Work, and, if applicable, the Material Safety Data Sheets for, and the hazards of, the Hazardous Materials or hazardous chemicals that Contractor is expected to provide. Contractor acknowledges that Material Safety Data Sheets of all chemicals located at the Site are available to Contractor’s employees upon a request made to Owner’s Project Director, or other safety representative of Owner at the Site. Contractor also represents that it is familiar with the labeling system used in the workplace.

(b) Contractor acknowledges that OSHA and regulatory standards or State plan equivalent (collectively, the “OSHA Standards”) require that its employees be trained in various subjects, such as, but not limited to, the hazards of, and standards applicable to, the Work (29 C.F.R. § 1926.21(b)(2)) (applicable to construction work), lockout/tagout (29 C.F.R. § 1910.147), confined space entry (29 C.F.R. §§ 1926.21(b)(6) or 1910.146), and asbestos (29 C.F.R. §§ 1910.1001 or 1926.1101). Contractor warrants that its employees and their supervisors have been trained in accordance with all applicable OSHA Standards, and that they have been trained to recognize and avoid any hazards related to the Work, and to perform the Services safely and without danger to any employee or to any property.

(c) Contractor represents that its employees are or will be equipped with the personal protective equipment required by applicable OSHA Standards in 29 C.F.R. Parts 1926 and 1910, and with the personal protective equipment required to protect its employees against other serious health or safety hazards. Contractor agrees that it shall discipline its employees who violate any OSHA Standards or applicable Laws in accordance with its own policies and procedures.

(d) Contractor represents that it will comply with all OSHA Standards applicable to the Work, including those requiring pre-employment testing of employees, such as but not limited to, pulmonary testing, blood testing, urine testing, hearing testing, respirator fit testing, drug screening, and/or applicable medical surveillance testing.

(e) Contractor shall fully comply with its safety programs and/or any Site specific safety plans which Owner has reviewed and accepted.

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(f) Within twenty four (24) hours of a request, or as soon as possible, and to the extent permitted by applicable Law, Contractor shall provide copies of any and a11 training for its employees concerning any safety and health standard, any substantive or technical training requirement of the job or the results of any occupational testing to Owner.

24.3 Worksite Safety.

(a) Contractor shall take all reasonable precautions for the safety of, and shall provide reasonable protection to prevent damage, injury or loss to Persons and property resulting from the Work, including:

(i) Contractor employees, Subcontractors and other Persons performing the Services and all Persons who may be affected by the performance of the Services;

(ii) the Equipment and Owner Equipment to be incorporated into the Facility, whether in storage on or off the Site or under the care, custody or control of Contractor or Subcontractors; and

(iii) other property at or adjacent to the Site, including trees, shrubs, lawns, walks, pavements, roadways, structures and utilities.

(b) Contractor shall give notices and shall comply with applicable Laws bearing on safety of persons or property or their protection from damage, injury or loss.

(c) Contractor shall be responsible for initiating, maintaining and supervising all safety precautions and programs in connection with the Work. Contractor shall erect, maintain or undertake, as required by existing conditions and the performance of the Agreement, all reasonable safeguards for the safety and protection of Persons and property, including posting danger signs and other warnings against hazards, promulgating safety regulations, and notifying owners and users of adjacent sites and utilities. Those precautions may include providing security guards.

(d) Contractor agrees to provide to Owner the name, title, and phone number of its emergency contact person prior to the commencement of the Services.

(e) Within twenty four (24) hours of its occurrence and in addition to reporting to Government Authorities as required by applicable Law, Contractor shall notify Owner in writing of any incident, injury or illness experienced by a Contractor employee in the performance of any of the Services or on any part of Owner’s premises or lands, and shall provide copies of the OSHA 101 and OSHA 200 or 300 log entry for such incident, injury or illness. Within one week of the incident, injury or illness, Contractor shall provide a preliminary written report of the incident, injury or illness and the measures to prevent a similar occurrence in the future. Owner has the right to request a final report, which Contractor shall provide within one week of Owner’s request. All such reports shall be in accordance with Owner’s policies and procedures. For all accidents which cause, or nearly cause, death, serious bodily injury or property damage, Contractor shall immediately notify Owner’s Project Director and Owner’s health and safety representative by telephone or messenger, giving full details and statements of any witnesses.

(f) Upon request from Owner, Contractor shall provide an OSHA log listing injuries or illnesses sustained by Contractor employees during the five (5) years preceding the request in any of

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Owner’s process areas subject to Owner’s process safety management standard, 29 C.F.R. § 1910.119, as provided to Contractor.

24.4 Dangerous Materials. When the use or storage of explosives or other dangerous materials or equipment or unusual methods are necessary for the Work, Contractor shall exercise utmost care and carryon its activities only under the supervision of properly qualified personnel. Contractor shall notify Owner’s Project Director prior to bringing any explosives onto the Site.

24.5 Loading. Contractor shall not load or permit any part of the Equipment or Owner Equipment to be loaded at the Site so as to endanger the safety of Persons or property.

24.6 Cooperation in Governmental Investigation. Contractor and its Subcontractors of whatever tier shall assist Owner in responding to requests by any Government Authority for information in connection with inspections or investigations of Owner relating to the Work involving Contractor or its Subcontractors of whatever tier performed for Owner, on Owner’s property, involving Owner’s employees, equipment or processes. Within one (1) Day of the request, or upon such other reasonable time as agreed by the Parties, Contractor shall make its employees available at the Site for interviews and shall produce copies of any documents relevant to the investigation to Owner. Except as prohibited by Law, Contractor shall promptly inform Owner of inspections and investigations on Contractor’s property, and of subpoenas, document requests, requests for information, deposition notices, discovery requests, or similar requests by any Government Authority, concerning Owner, the Work, or any accidents, injuries, illnesses or claims resulting from the Work.

24.7 Audit. To the extent permitted by applicable Law, Owner shall have the right to review and copy all of Contractor’s documents that relate to safety and health at the Site, including Contractor’s safety and health programs, safety and health training records, OSHA recordkeeping forms (such as 101, 200, 300 and 301), any incident report or first report of injuries form and any industrial hygiene monitoring test results.

25. QUALIFICATIONS AND PROTECTION OF ASSIGNED PERSONNEL

25.1 Contractor’s Personnel. Contractor shall comply in all respects with all applicable labor and immigration Laws that may impact Contractor’s Work under this Agreement, including the Immigration Reform and Control Act of 1986 and Form I-9 requirements. Without limiting the generality of the foregoing, Contractor shall perform all required employment eligibility and verification checks and maintain all required employment records. Contractor acknowledges and agrees that it is responsible for conducting adequate screening of its employees and agents prior to starting the Work. By providing an employee or Subcontractor under this Agreement, Contractor warrants and represents that it has completed the Screening Measures with respect to such employee or Subcontractor and that such Screening Measures did not reveal any information that could adversely affect such employee’s or Subcontractor’s suitability for employment or engagement by Contractor or competence or ability to perform duties under this Agreement. If in doubt whether a suitability, competence or ability concern exists, Contractor shall discuss with Owner the relevant facts and Owner will determine, in its sole discretion, whether such Person should be allowed to perform the Work. Owner, in its sole discretion, shall have the option of barring from the Site any person whom Owner determines does not meet the qualification requirements set forth above. In all circumstances, Contractor shall ensure that the substance and manner of any and all Screening Measures performed by Contractor pursuant to this Section conform fully to applicable Law. Contractor shall supervise, coordinate and direct the Work using Contractor’s best skill, judgment

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and attention. Owner shall have the right to bar from the Site any Person employed or engaged by Contractor or Subcontractor who engages in misconduct or is incompetent or negligent while on the Site or while performing the Services, or whom Owner has previously terminated for cause or otherwise dismissed or barred from the Site. Upon request of Owner, Contractor shall immediately remove those Persons to whom Owner objects from the Site and shall not allow the further performance of the Services by those Persons. In addition, if Contractor learns of any such misconduct, incompetence or negligence independent of Owner’s objection, Contractor shall remove such Persons from the Site, shall not allow any further performance of the Services by such Persons and shall promptly notify Owner of such misconduct, incompetence or negligence and the actions taken by Contractor as a result thereof. In either such event, any cost for replacement of such Persons shall be at Contractor’s expense.

25.2 Drug and Alcohol Testing. Neither Contractor nor its Subcontractors shall in any way use, possess, or be under the influence of illegal drugs or controlled substances or consume or be under the influence of alcoholic beverages during the performance of the Services. Any person (whether employed or retained by Contractor or any Subcontractor or otherwise) under the influence, or in possession of, alcohol, any illegal drug, or any controlled substance, will be removed from the Site and, subject to Owner’s fitness for duty program requirements, shall be prevented from performing any future Services at the Site or elsewhere related to the Project. Contractor shall have in place a drug testing program meeting the requirements of all applicable Laws and Owner’s Drug and Alcohol Testing Policy (MICCS Substance Abuse Program, dated as of July, 2007) attached hereto as Exhibit J, as such policy may be updated by Owner from time to time generally for its contractors, and shall furnish to Owner proof of compliance with such regulations and policies, including a copy of Contractor’s drug and alcohol testing plan and an affidavit stating that Contractor is in compliance, and will remain in compliance, with such regulations and policies for the duration of this Agreement. Upon request, and to the extent permitted by law, Contractor will furnish Owner copies of the records of employee drug and alcohol test results required to be kept by Law. Contractor will indemnify and hold harmless Owner from any and all liability for (a) Contractor’s or any Subcontractor’s personnel who fail a drug or alcohol test given under any Government Authority regulations, and (b) any claims made by a Contractor’s or Subcontractor’s employee resulting from removal from the Site as provided in this Article. If Contractor fails to comply with these regulations while performing under this Agreement, such noncompliance will be deemed a breach of this Agreement, and Contractor shall be liable for such breach, as well as for all direct damages arising out of such noncompliance.

25.3 Training of Employees. Contractor represents that all Contractor and Subcontractor personnel have received all necessary training regarding environmental, OSHA and any other matters required by applicable Laws and relevant to the Work. Training on implementation of any additional environmental mitigation measures appropriate for the Work will be specified by Owner before commencement of the Services.

25.4 Compliance with Employment Laws; Policies. All Services shall be performed in accordance with all applicable Laws, including worker’s compensation Laws, minimum and maximum salary and wage statutes and regulations, and licensing Laws and regulations. Contractor shall fully reimburse Owner for any and all fines or penalties of whatever kind or type that Owner may incur as the result of and to the extent caused by Contractor’s failure to fully comply with and fulfill any of the provisions of this Article. Contractor shall adopt and utilize a subcontracting plan with its first-tier Subcontractors that complies with 48 C.F.R. 52-219-9 for Small Diverse Suppliers (“SDS”). In addition, Contractor shall (a) utilize SDS as required by law; (b) provide Owner with a

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quarterly status report in the format set forth on Owner’s website at www.duke-energy.com, or in such other format as is reasonably acceptable to Owner; (c) enter the SDS data in any report on Owner’s website at www.duke-energy.com and (d) provide Owner, its designated auditors and any applicable government agency the right of access during normal business hours to inspect any records related to SDS and compliance with this section.

25.5 Substitution. Contractor reserves the right to change any of its personnel performing Services. In such event, Contractor shall provide replacement personnel meeting the requisite qualifications and who have equal or better capabilities and shall bear any additional travel and living expenses associated with providing such replacement personnel.

26. RECORDS AND AUDIT

26.1 Technical Documentation. Except to the extent applicable Laws require a longer retention, Contractor shall maintain and shall cause its Subcontractors to maintain all technical documentation relative to the Equipment and the Owner Equipment for a period of three (3) years after the Final Completion Date. Contractor shall give Owner thirty (30) Days prior written notice before destroying or disposing of any such documentation or records and a reasonable opportunity for Owner during such period to make copies of any such documentation.

26.2 Accounting Records. Except to the extent applicable Laws require a longer retention, Contractor shall maintain and shall cause its Subcontractors to maintain complete accounting records relating to all Work performed or provided under this Agreement (which records shall include an estimate of installed costs per component in accordance with FERC accounting requirements) on a time and material, or reimbursement, basis in accordance with generally accepted accounting principles in the United States, as set forth in pronouncements of the Financial Accounting Standards Board (and its predecessors) and the American Institute of Certified Public Accountants, for a period of three (3) years after the Final Completion Date, except that records relating to Sales Taxes for such items must be retained for four (4) years as specified in Section 26.4. Contractor shall give Owner thirty (30) Days prior written notice before destroying or disposing of any such accounting records and a reasonable opportunity for Owner during such period to make copies of any such documentation.

26.3 Owner’s Right to Audit. For verification of *** claimed by Contractor *** or for any Work performed or provided on a cost reimbursement basis or for any suspended, terminated, delayed or accelerated Services, Owner or a third party auditor selected by Owner and reasonably acceptable to Contractor (which acceptance shall not be unreasonably withheld or delayed) shall have the right and access at reasonable times during normal business hours to examine and audit Contractor’s records and books related to all those costs as is reasonably necessary for Owner to verify such costs. As part of any such audit, Contractor shall provide data in the appropriate electronic native file format (i.e. Microsoft Word, Excel, Primavera, etc.) such that the data may be effectively sorted, summed, and evaluated. However, Owner or Owner’s representative shall have no right to audit records or books concerning the make-up of any agreed upon lump sum amounts or fixed rates or multipliers. If any audit by the auditor reveals charges or costs charged to or paid by Owner as costs or fees which are not proper or exceed the rates or amounts permitted hereunder for any such matters, then Owner shall be entitled upon demand for a refund from Contractor of all such amounts, plus interest thereon from the date of payment by Owner until the date of refund by Contractor at a rate of the lesser of (a) the Prime Interest Rate plus 1% or (b) the maximum rate allowed by applicable law. Likewise, if any audit or if any examination by any state or local taxing agency reveals additional

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Sales Tax to be imposed upon Contractor for under collection of tax from Owner on a taxable sale to Owner, then Contractor shall be entitled, upon demand, for a refund from Owner of all such amounts, plus interest at the foregoing rate.

26.4 Sales Tax and Privilege Tax Records. Contractor shall provide to Owner all information and data Owner may from time to time reasonably request and otherwise fully cooperate with Owner in connection with the reporting of (a) any Sales Taxes and Privilege Taxes payable with respect to the Work and (b) any assessment, refund claim or proceeding relating to Taxes payable with respect to the Work. Contractor shall require its Subcontractors to provide to Contractor all information and data Contractor may reasonably request for purposes of complying with the preceding sentence and otherwise fully cooperate with Owner. Contractor shall retain, and shall require Subcontractors to retain, copies of such documentation and all documentation relating to purchases relating to the Work or the payment of Sales Taxes and Privilege Taxes, if any, for a period of not less than four (4) years from the Final Completion Date. Contractor shall ensure that its contracts with all Subcontractors effectuate the provision of this Section. Contractor’s and Owner’s obligations under this Section shall survive the termination, cancellation or expiration of this Agreement for any reason and shall last so long as is necessary to resolve any and all matters regarding Taxes attributable to the Work; provided, that if Owner requires Contractor to take action under this Section at any time after the later of (i) two (2) years after delivery of the piece of Equipment or (ii) two (2) years after completion of the particular item of Work, Owner shall reimburse Contractor for all actual and reasonable expenses Contractor incurs in taking those actions.

27. TAXES

27.1 Employment Taxes. Neither Owner nor its officers, employees, agents, consultants or other representatives shall have any liability for any payroll or employment compensation taxes, for Social Security taxes, or for labor-related withholding taxes, for Contractor and its Subcontractors (including manufacturers); or any of their employees; and Contractor agrees to hold Owner, his Consultants, and his other contractors harmless against any claim or liability therefore.

27.2 Sales and Use Taxes on Contractor Tools. Contractor shall pay all taxes on Contractor’s purchases of goods, tools, equipment, supplies and other consumables which are not permanently incorporated into the Facility and which remain the property of Contractor. Contractor shall also pay all taxes attributable to Contractor’s construction equipment, temporary buildings and other property used by Contractor in its performance of this Agreement. Contractor shall pay those taxes when assessed, without claim against Owner for reimbursement. Contractor shall impose a similar obligation on all Subcontractors and shall ensure that no Subcontractor shall have any claim against Owner for reimbursement of those taxes.

27.3 Sales and Use Tax on Equipment; Privilege Tax. Notwithstanding the above, the *** does not include monies for the payment of any sales and use taxes on Equipment incorporated into the Facility. Contractor, on behalf of itself and all of its Subcontractors (including manufacturers), is therefore responsible for consulting with Owner on Equipment purchases and working with Owner to obtain the best sales and use tax and privilege tax benefits for Owner. Owner is currently authorized under the North Carolina General Statutes to purchase certain Equipment exempt from the sales and use tax, but subject to the privilege tax at a rate of 1% with a maximum tax of eighty dollars ($80) per article. Owner will specifically identify property which will be subject to the privilege tax. Owner will issue Form E-595E to Contractor to support the exemption from the sales and use tax. Contractor shall register with the state of North Carolina for payment of the privilege tax. Contractor

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will issue Form E-595E to its suppliers to facilitate exempt purchases of property subject to the privilege tax. As required by law, Contractor will accrue the privilege tax on these purchases and remit the appropriate amount to the state. Sales tax should be billed by the supplier on Contractor’s purchases of property subject to the North Carolina sales tax. Owner shall reimburse Contractor, *** for Contractor’s actual costs incurred in paying any sales and use tax for which Contractor may become obligated to pay in connection with the Equipment incorporated into the Facility.

(a) Contractor, its Subcontractors, manufacturers and suppliers shall make reasonable commercial efforts to purchase Equipment to minimize the tax, but shall not be restricted from making out-of-state purchases of such Equipment. Contractor shall use its commercially reasonable efforts to ensure that Owner is afforded the best sales/use and privilege tax treatment by the State. Contractor shall use all reasonable efforts to ensure that all out-of-state purchases made by Contractor and its Subcontractors (including manufacturers) are shipped FOB the Facility (North Carolina) free of Sales Taxes. Owner shall reimburse Contractor for all sales and use taxes and privilege taxes paid by Contractor and its Subcontractors (including manufacturers) upon written confirmation from Contractor that the items purchased could not reasonably be purchased free of Sales Taxes.

(b) Contractor agrees that it and its Subcontractors, suppliers, and manufacturers will clearly identify on each original invoice covering the purchase of Equipment, the amount of sales and use tax. Should additional information and detail be required by Owner and the North Carolina Department of Revenue to verify amounts paid for purchases of Equipment under this Agreement, Contractor and its Subcontractors, suppliers, and manufacturers shall supply such additional information and invoices in sufficient detail to verify:

(i) That such Equipment was purchased free of State sales and use taxes; or that for out-of-state purchases, the invoices indicate the amount of foreign sales and use tax separately stated and paid;

(ii) The privilege tax was accrued and remitted to the State of North Carolina for such Equipment;

(iii) The actual purchase prices of such Equipment;

(iv) The date of delivery to the Site of such Equipment;

(v) A description of the function of such Equipment; and

(vi) The Federal Energy Regulatory Commission (FERC) Code identification for such Equipment.

(c) As a condition to Final Completion, Contractor shall provide Owner with an affidavit that all invoices which include sales and use taxes or privilege tax have been paid and that Contractor and all its Subcontractors, suppliers, and manufacturers have no outstanding claims or expenses relating to sales and use tax or privilege tax.

(d) Both Parties shall provide to the other any documentation or information requested in order to submit and obtain a refund of any taxes erroneously paid as part of this Agreement. The Parties agree that any refunds received shall belong to the Party which bore the economic burden of

62

paying the tax. The Parties’ obligations under this Section shall survive termination or expiration of the Agreement.

27.4 State Property Taxes. Contractor and Owner agree that Owner shall be responsible for the filing requirements and payment obligations for all state and local taxes on the Site and the Equipment incorporated into the Facility; provided, that Contractor shall be responsible for the filing of property tax returns and the payment of state and local property taxes on construction equipment, tools and material which is not incorporated into the Facility and which is owned, used or leased by Contractor to perform the Services. Owner and Contractor acknowledge that construction equipment property tax costs are included in the leasing costs included in the Contract Price. If Contractor owns construction equipment and leases such construction equipment to Owner, Contractor shall remain responsible for the filing and payment of all property taxes due on such construction equipment.

27.5 Tax Indemnification.

(a) Except in cases where such tax assessment is the result of the Gross Negligence or willful or wanton misconduct by Contractor, Owner shall defend, reimburse, indemnify and hold Contractor harmless for all costs and expenses incurred by Contractor as a result of Owner’s formal protest of any sales and use taxes paid or assessed and property taxes paid or assessed on the Site or the Equipment, or any other similar tax, whether local, state or federal, including any litigation expenses in the event Owner decides to protest a sales or use tax assessment. Owner shall not be responsible for any costs incurred by Contractor necessary to substantiate or verify information for any tax audit conducted in the normal course of business.

(b) Except in the cased of Gross Negligence or willful or wanton misconduct by Owner, Contractor shall defend, reimburse, indemnify and hold Owner harmless for all costs and expenses incurred by Owner as a result of Contractor’s formal protest of any employment Taxes, or any sales and use taxes and property taxes paid or assessed on Contractor’s equipment or tools, or of any payroll or employment compensation taxes, or Social Security taxes, or for labor-related withholding taxes, or any other similar tax, whether local, state or federal for Contractor; its Subcontractors (including manufacturers); or any of their employees, paid or assessed, including any litigation expenses in the event Contractor decides to protest the said employment, withholding, and similar taxes.

27.6 Pollution Control Equipment Information. Contractor shall supply Owner with all reasonable information and cost analyses requested by Owner for qualifying air, water or noise pollution control equipment for exemption from sales and use taxes, property taxes and any other tax credits, refunds or exemptions available to Owner. Contractor shall supply any further information as requested by Owner to apply for a certificate from the North Carolina Department of Environment and Natural Resources (DNHR) or other appropriate Government Authority to qualify for the above exemptions.

28. DISPUTE RESOLUTION

28.1 Resolution by the Parties. The Parties shall attempt to resolve any claims, disputes and other controversies arising out of or relating to this Agreement (collectively, “Disputes”) promptly by negotiation and mediation between executives who have authority to settle the Dispute and who are at a higher level of management than the persons with direct responsibility for administration of this Agreement.

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28.2 Arbitration Proceedings.

(a) Demand for Arbitration. If the Dispute has not been resolved by negotiation within *** Days of the disputing Party’s initial notice (or such longer period as the Parties may agree), the Parties shall fully and finally settle the Dispute by binding arbitration. All arbitration proceedings shall take place in Charlotte, North Carolina under the auspices of the American Arbitration Association (“AAA”) in accordance with the AAA Construction Industry Arbitration Rules then in effect (the “Rules”), and shall be governed by the Federal Arbitration Act, 9 U.S.C. §§ 1-16. For all Disputes where the amount in controversy is less than $***, the arbitration proceedings shall be conducted by a *** selected in accordance with the Rules. For all Disputes where the amount in controversy is at least $***, the arbitration proceedings shall be conducted by a *** selected in accordance with the Rules. No demand for arbitration shall be made or permitted after the date when the institution of a civil action based on the Dispute would be barred by the applicable statute of limitations or repose of the State.

(b) Equitable Remedies. The procedures specified in this Article shall be the sole and exclusive procedures for the resolution of Disputes between the Parties arising out of or relating to this Agreement; provided, however, that a Party may file a complaint in a court of competent jurisdiction on issues of statute of limitations or repose or to seek injunctive relief, specific performance, sequestration, garnishment, attachment, or an appointment of a receiver. Preservation of these remedies does not limit the power of the arbitrator(s) to grant similar remedies, and despite such actions, the Parties will continue to participate in good faith in and be bound by the dispute resolution procedures specified in this Article.

(c) Award; Binding Nature. The arbitrator(s)’ decision shall be by majority vote and shall be issued in a writing and shall be final and binding upon the Parties, and judgment may be entered on the award in any court of competent jurisdiction. The cost of all arbitrators shall be borne equally by the Parties.

(d) Discovery. Either Party may apply to the arbitrators for the privilege of conducting discovery. The right to conduct discovery shall be granted by the arbitrators in their sole discretion with a view to avoiding surprise and providing reasonable access to necessary information or to information likely to be presented during the course of the arbitration, provided that, where the amount in controversy is at least $***, the Parties shall have the rights to discovery set forth in Rules 26 through 36 of the Federal Rules of Civil Procedure.

28.3 Continuation of Work. Pending the final resolution of any Dispute, Contractor shall proceed diligently with the performance or provision of the Work and its other duties and obligations without diminution of effort and Owner shall continue to compensate Contractor as set forth under this Agreement, including payment to Contractor provisionally on a time and material basis *** for all disputed Work.

28.4 Confidentiality. Except as may be required by applicable Law, each Party shall treat the existence, content or results of any settlement discussion pursuant to this Article 28 or arbitration as Confidential Information of the other Party in accordance with Section 20.1 and shall use commercially reasonable efforts to cause any arbitrator(s) to keep such information confidential.

29. MISCELLANEOUS PROVISIONS

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29.1 Governing Laws. This Agreement shall be governed by and construed in accordance with the laws of the State, without reference to its conflict of laws principles.

29.2 Entire Agreement. This Agreement represents the entire agreement between Owner and Contractor with respect to the subject matter hereof, and supersedes all prior negotiations, binding documents, representations and agreements, whether written or oral, with respect to the subject matter hereof, including the Original Agreement. This Agreement may be amended or modified only by a written instrument duly executed by each of the Parties.

29.3 Successors and Assigns. Neither this Agreement nor any right, interest or obligation hereunder may be assigned by Contactor without the prior written consent of Owner, and any attempt to do so shall be void, except that the whole of this Agreement may be assigned by Contractor upon prior written notice to Owner (a) to a parent company or a wholly-owned Affiliate, provided that Contractor shall not be relieved of any of its obligations hereunder, or (b) to a transferee who acquires all or substantially all of the assets of Contractor and whose market capitalization exceeds $*** and whose long term senior unsecured, uninsured debt is rated at least Baa3 by Moody’s or BBB- by Standard & Poor’s at the time of the transfer, or whose creditworthiness is otherwise reasonably satisfactory to Owner, provided that, in each such case, such assignee demonstrates to the reasonable satisfaction of Owner that it is capable of fulfilling all of the obligations of Contractor hereunder, including the grant of the licenses provided herein. Subject to the preceding sentence, this Agreement is binding upon, inures to the benefit of and is enforceable by the Parties and their respective successors and assigns. Owner, including any Party constituting Owner, may assign this Agreement or any benefit, interest, right or cause of action arising under this Agreement to any Person with notice to, but without the consent of, Contractor under the following circumstances: (a) the assignee is an Affiliate or subsidiary of the Owner and the assignee has a credit rating that is at least S&P BBB-, Moody’s Baa3 or whose creditworthiness is otherwise reasonably satisfactory to Contractor, (b) the assignee has acquired ownership of, or the right to operate, the Facility for which an assignment is being made and the assignee’s senior unsecured debt has a credit rating of S&P BBB-, Moody’s Baa3, or (c) such assignee is otherwise reasonably acceptable to Contractor. Owner (or the assigning Party that constitutes a part of Owner, as applicable) shall obtain written assurances from the assignee of limitation of and protection against liability following the proposed transfer at least equivalent to that afforded Contractor and Subcontractors hereunder. Any transfer contrary to this Section shall make the assigning Party constituting Owner the indemnitor of Contractor against any liabilities incurred in excess of those that would have been incurred had no such transfer taken place.

29.4 No Third Party Beneficiaries. Except as expressly set forth in this Agreement, the provisions of this Agreement are intended for the sole benefit of Owner and Contractor, and there are no third party beneficiaries. No reference herein to any other Person shall restrict in any way the ability of the Parties to amend or modify this Agreement from time to time in their sole and absolute discretion.

29.5 Rights Exclusive. The rights and remedies of Owner and the liabilities of Contractor as set forth in this Agreement shall be the exclusive rights, remedies and liabilities of the Parties.

29.6 No Waiver. No course of dealing or failure of Owner or Contractor to enforce strictly any term, right or condition of this Agreement shall be construed as a waiver of that term, right or

65

condition. No express waiver of any term, right or condition of this Agreement shall operate as a waiver of any other term, right or condition.

29.7 Crisis Response. Notwithstanding anything to the contrary herein, any actions taken or authorized by Owner in a good faith belief that such actions are necessary to ensure safe operation of the Facility or respond to an emergency or abnormal condition at the Facility shall not constitute a breach hereof or absolve Contractor of any of its obligations hereunder.

29.8 Survival. Article 14 (Indemnification), Article 17 (Limitation of Liability), Article 19 (Intellectual Property), Article 20 (Confidential Information), Article 27 (Taxes), Article 28 (Dispute Resolution), Article 29 (Miscellaneous Provisions) and all other Sections providing for indemnification or limitation of or protection against liability of either Party shall survive the termination, cancellation, or expiration of this Agreement.

29.9 Severability. If any provision of this Agreement or the application of this Agreement to any Person or circumstance shall to any extent be held invalid or unenforceable by a court of competent jurisdiction or arbitrators under Article 28, then (i) the remainder of this Agreement and the application of that provision to Persons or circumstances other than those as to which it is specifically held invalid or unenforceable shall not be affected, and every remaining provision of this Agreement shall be valid and binding to the fullest extent permitted by Laws, and (ii) a suitable and equitable provision shall be substituted for such invalid or unenforceable provision in order to carry out, so far as may be valid and enforceable, the intent and purpose of such invalid or unenforceable provision.

29.10 Notices. Any notices, demands or other communication to be sent or given hereunder by either Party shall in every case be in writing and shall be deemed properly served if (a) delivered personally to the recipient, (b) sent to the recipient by reputable express courier service (charges paid) or (c) mailed to the recipient by registered or certified mail, return receipt requested and postage paid. Date of service of such notice shall be (i) the date such notice is personally delivered, (ii) three (3) days after the date of mailing if sent by certified or registered mail, or (iii) one (1) day after date of delivery to the overnight courier if sent by overnight courier. Such notices, demands and other communications shall be sent to the addresses indicated below or such other address or to the attention of such other person as the recipient has indicated by prior written notice to the sending party in accordance with this Section:

If to Owner:	Duke Energy Carolinas, LLC
	Mail Code EC11T
	P. O. Box 1006
	Charlotte, NC 28201-1006
	Attn: ***
	Facsimile No: ***
with a copy to:	Duke Energy Carolinas, LLC
	Mail Code EC11X
	P.O. Box 1006
	Charlotte, NC 28201-1006
	Attn: ***
	Facsimile No.: ***

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	Duke Energy Carolinas, LLC
	Mail Code EC03T
	526 South Church Street
	Charlotte, NC 28202
	Attn: ***
	Facsimile No.: ***
If to Contractor:	Shaw North Carolina, Inc.
	Attn: ***
	100 Technology Center Drive
	Stoughton, MA 02072
	Facsimile No.: ***
	Telephone No.: ***
	Shaw North Carolina, Inc.
	Attn: ***
	128 South Tryon Street, Suite 600
	Charlotte, NC 28202
	Facsimile No.: ***
	Telephone No.: ***

29.11 Vienna Convention. The Parties hereby expressly agree to exclude and disclaim the application of the provisions of the United Nations Convention on Contracts for the International Sale of Goods (also referred to as the Vienna Convention), and any successor convention or legislation, to this Agreement.

29.12 Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be executed by its duly authorized representative as of the date first above written.

DUKE ENERGY CAROLINAS, LLC		SHAW NORTH CAROLINA, INC.
By:	/s/ James L. Turner	By:	/s/ Monty Glover
Name:	James L. Turner	Name:	Monty Glover
Title:	President & COO, U.S. Franchised Electric & Gas	Title:	Executive Vice President

EXHIBIT A-1

***

EXHIBIT A-1

Attachment 1

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EXHIBIT A-1

Attachment 2 – Division of Responsibility (DOR)

***

EXHIBIT A-1

Attachment 3

***

EXHIBIT A-1

Attachment 4

***

EXHIBIT A-1

Attachment 5 – P&ID’s

***

EXHIBIT A-1

Attachment 6 – Equipment List

***

EXHIBIT A-1

Attachment 7 – Electrical One Lines

***

EXHIBIT A-1

Attachment 8 – Raw Water Analysis

***

EXHIBIT A-1

Attachment 9 – Gas Analysis

***

EXHIBIT A-1

Attachment 10 – Basis of Design – Mechanical

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EXHIBIT A-1

Attachment 11 – Basis of Design – Electrical

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EXHIBIT A-1

Attachment 12 – Basis of Design – Instrumentation & Controls

***

EXHIBIT A-1

Attachment 13 – Basis of Design – Civil Structural

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EXHIBIT A-1

Attachment 14 – Clarifications and Assumptions

***

	J.O./W.O.NO: 131861 PAGE: Cover CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

EXHIBIT A-2

EXHIBIT A-2

PERFORMANCE TESTING OF BUCK COMBINED CYCLE GUARANTEES

UNIT NET HEAT RATE, OUTPUT, & EMISSIONS

AND

PERFORMANCE VERIFICATION OF PLANT EQUIPMENT

	J.O./W.O.NO: 131861 PAGE: 1 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

1.0 INTRODUCTION

1.1 OBJECTIVE

This Exhibit establishes conditions, parameters and methods for Performance Testing of Buck Combined Cycle Net Electrical Output, Heat Rate and Emission guarantees established by the Agreement, corrected to the Base Performance Conditions identified in Section 7 of this Exhibit.

Buck Combined Cycle Net Electrical Output will be tested, calculated and corrected based on the fully duct-fired case steam flow. Net Heat Rate will be tested, calculated and corrected based on the no duct firing condition with two combustion turbines operating at base load.

Additionally, Performance Verification of the Combustion Turbines, Heat Recovery Steam Generators, and Steam Turbine along with major plant equipment and systems is addressed during the Combined Cycle Performance Test.

The Contractor shall also provide testing procedures for validation of Owner furnished equipment Guarantees ***. All such tests shall also be tested in accordance with this Exhibit and measured while simultaneously achieving Guaranteed Emission Limits.

Emission Compliance Testing, including CEMS Certification testing, may occur prior to Substantial and Final Completion, with Guaranteed Emission Limits verified during Performance Testing either with the certifiable CEMS (defined in Section 8.3) or certified temporary test equipment.

If tuning or other adjustments that may effect emissions occur after non-CEMS monitored emission acceptance and prior to Substantial and/or Final Completion, the Owner may require re-testing of emission compliance of non-CEMS monitored parameters to verify that tuning has not violated emission compliance.

***

1.2 PERFORMANCE TEST PROGRAM PHILOSOPHY

Table A-2 summarizes the Performance Testing and Equipment Verification Program. The purpose of the Performance Test and Equipment Verification Program is fivefold:

1.2.1 ASME Code Testing

a. Performance Testing - Confirm that Combined Cycle Net Electrical Output and Net Heat Rate guarantees contained in the Agreement are met, using ASME Performance Test Code PTC 46, adjusted as mutually agreed by Contractor and Owner. If these guarantee values are not met, then the Contractor will establish

1

	J.O./W.O.NO: 131861 PAGE: 2 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

the shortfall value for application of remedies or damages addressed in the Agreement with the Contractor.

1.2.2 Non Code Testing

a. Combustion Turbine, Heat Recovery Steam Generator, and Steam Turbine Testing will be run concurrently, with the Net Plant Performance Test. Confirm the Performance Guarantees of Owner Equipment are met, using permanently installed station instrumentation and/or instruments installed for the plant Performance Test. Per agreement with the Owner’s equipment Contractor this test will establish the shortfall value if the tested and corrected values are not within the limits of uncertainty and contractual tolerances.

b. Other Major Equipment Verification - Report the performance of the other major equipment listed in Section 8.1, using data collected during plant Performance Testing using permanently installed station instrumentation and/or instruments installed for the plant Performance Test. If Performance Guarantees are not met for Plant Net Electrical Output or Plant Net Heat Rate, then concurrent individual Equipment Verification Testing results collected during the plant Performance Testing will be evaluated to determine if further component testing, as described in section 8.1, is necessary to establish an estimate of the shortfall value, for possible Code Testing. If Performance Guarantees are met for Plant Net Electrical Output and Plant Net Heat Rate, Equipment Verification Test reports for components tested during the Plant Performance Test shall be reported to Owner. If Owner determines that additional testing, including Code Testing, may provide efficiency and capacity benefits, Owner may employ Contractor, with a contract change order for additional analysis and testing beyond the scope of the Target Price.

c. Plant Baseline Data - Establish the overall plant Baseline Performance Data for key operating parameters based on a combination of data taken during the plant Performance Test and concurrent testing of the Combustion Turbine, Heat Recovery Steam Generator and Steam Turbine Performance Test and to include DCS collected data.

d.

1.3 AGREEMENT AUTHORITY

The Agreement contains specific information concerning guarantees, results, re-testing, schedule, remedies, liquidated damages and warranties, and is not addressed in this Performance Testing Exhibit.

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	J.O./W.O.NO: 131861 PAGE: 3 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

1.4 NET PLANT PERFORMANCE

The Contractor’s Net Electrical Output and Net Heat Rate Performance Guarantees are based on the guaranteed performance of the Owner Equipment. Plant performance test results shall be corrected for Owner Equipment performance shortfalls that are not attributable to Contractor responsibility. Shortfalls in the Owner supplied equipment will be verified as part of the PTP data recording, correction calculations and analysis process which will be documented in the Plant Performance Test results report.

The Guaranteed Combined Cycle Net Heat Rate is determined by the following methodology:

GNHR = (NG/((GT1+GT2 Output) + ST Output – BOP Aux – HRSG Aux - GSUL)) * (1 + EPC Margin)

Where:

NG = Natural Gas Consumed (btu/hr HHV) in Combustion Turbines based on General Electric guarantee condition corrected to Base Performance Conditions.

GT1 & GT2 Output = Net Electrical Output (kw) of Combustion Turbines, less generator excitation power, based on General Electric guarantee corrected to Base Performance Conditions.

ST Output = Net Electrical Output (kw) of Steam Turbine, less generator excitation power, based on General Electric predicted performance corrected to Base Performance Conditions, corresponding to the HRSG unfired guarantee Case 10.

BOP Aux = Power consumption (kw) of Contractor supplied balance of plant equipment.

HRSG Aux = Power consumption (kW) of HRSG vendor supplied equipment.

GSUL – Losses across generator step-up transformers and auxiliary power use by generator step-up transformers.

EPC Margin = ***

The Guaranteed Combined Cycle Net Electrical Output is determined by the following methodology:

GNEO = ((GT1+GT2 Output) + ST Output – BOP Aux – HRSG Aux – GSUL) * (1 - EPC Margin)

Where:

GT Output = Net Electrical Output (kw) of Combustion Turbines, less generator excitation power, based on General Electric guarantee corrected to Base Performance Conditions.

ST Output = Net Electrical Output Net (kw) of Steam Turbine, less generator excitation

3

	J.O./W.O.NO: 131861 PAGE: 4 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

power, based on General Electric guarantee performance corrected to Base Performance Conditions, corresponding to the HRSG fully duct fired guarantee Case 15

BOP Aux = Power consumption (kw) of Contractor supplied balance of plant equipment.

HRSG Aux = Power consumption (kw) of HRSG vendor supplied equipment.

GSUL – Losses across generator step-up transformers and auxiliary power use by generator step-up transformers.

EPC Margin = ***

1.5 SUBSTANTIAL COMPLETION TESTING

The initial Performance Testing is used to satisfy the Minimum Performance Guarantees. This Test shall be satisfied by the same methods as the Plant Performance Test methodology, except where a substitute test method is approved by the Owner.

The initial Performance Test may satisfy the requirement of the Performance Guarantees if performed in accordance with Section 6. of this Exhibit.

2.0 TEST RESPONSIBILITY

All testing described in this Exhibit is in Contractor’s scope of services / work unless otherwise stated.

Test Contractor approved by the Owner, shall conduct the Plant Performance Test, concurrent with the Combustion Turbine, Heat Recovery Steam Generator and Steam Turbine Performance Test, and compile the Plant Baseline Data.

The Test Contractor shall be responsible for the Performance Test Plan (PTP), test instrumentation including calibration and set up, pre and post test uncertainty analysis, conduct of the testing, data acquisition, data reduction, post test calculations, and test report for Plant Performance Testing, and concurrent Combustion Turbine, Heat Recovery Steam Generator and Steam Turbine Testing, Plant Baseline Data and Major Equipment Verification.

The Owner shall make available to the Contractor, the most current version of all Owner Equipment vendor performance, correction curves, correction software, thermal kits, test protocol requirements, draft test plans, and other such related data necessary for the Contractor to complete the Performance Test Plan. This Owner Equipment vendor data shall be provided in a timely manner such that the Contractor has reasonable time to review and comment for mutual approval with the Owner and for incorporation into the Contractor’s PTP.

3.0 PERFORMANCE TEST PLAN

4

	J.O./W.O.NO: 131861 PAGE: 5 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

The Contractor will submit *** prior to commencement of the Performance Test a complete detailed Performance Test Plan (PTP) mutually approved by Owner, Test Contractor, Contractor and Owner Equipment Contractors. The PTP will constitute an agreement for the Performance Testing by the Parties to the test. Differences between the Test Procedures or methods contained in/or developed in accordance with the PTP and the respective Agreements or established industry test codes are by written mutual agreement of the Parties to the test, as approved in the PTP.

The PTP form and contents shall specifically meet the requirements of ASME PTC 46 – 1996, Section 3.2 “Test Plan”, where ASME Code Testing procedures are being applied.

4.0 TEST UNCERTAINTY

Pre-Test uncertainties (for ASME Code Tests) will be calculated in accordance with applicable ASME Codes, and shall not exceed ASME PTC requirements for the applicable Code Test unless specifically agreed to by the Owner and the Contractor. Post test field verifications will be performed on instruments measuring parameters where there is no redundancy or for which the data is questionable.

5.0 DEGRADATION

Degradation shall be applied to the Plant Net Electrical Output and Net Heat Rate Tests, in accordance with Owner Equipment guarantees. An enthalpy drop test shall be performed on the steam turbine by the Test Contractor as soon as practical after startup, and prior to the Plant Net Heat Rate and Net Electrical Output Test. Degradation attributed to the steam turbine shall be based on enthalpy drop test results in accordance with Steam Turbine Generator guarantees.

Degradation due to the Gas Turbine will be based on the actual operating hours of each individual turbine and applied based on that component’s affect on the overall facility Performance Guarantee. The Manufacturer’s Curve will be used. Degradation due to the Steam Turbine will be based on the change in efficiency as determined by the enthalpy drop test and that component’s affect on the overall facility Performance Guarantee.

Corrections to test results due to degradation that are directly and solely attributable to Contractor’s actions shall not be applied. This includes both equipment scope and schedule effects.

6.0 PERFORMANCE TESTING – ASME CODE TESTING

6.1 TEST RUNS AND CORRECTIONS

Performance Testing involves set-up, testing, measurements and data collection, subsequent

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	J.O./W.O.NO: 131861 PAGE: 6 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

calculations and corrections. A series of *** individual Test Runs meeting the Code requirements for duration (no less than *** each), shall be performed at the test conditions for both the Plant Net Electrical Output and Net Heat Rate Tests, which Buck Combined Cycle is subject to at the time of the testing. Test operational and data stability requirements set forth in ASME Codes shall be met.

Results of the *** Test Runs shall be corrected to Base Performance Conditions and averaged for comparison. The Net Plant Performance Test corrected results will be compared to the Performance Guarantee values for Net Electrical Output and Net Heat Rate. The Combustion Turbine, Heat Recovery Steam Generator and Steam Turbine test data will be corrected to Owner Equipment Contract conditions and compared to contract guarantee values.

Demonstration of the Combustion Turbine, Heat Recovery Steam Generator and Steam Turbine performance will require the Test Contractor to perform measurement/correction methodology required by the mutually agreed test criteria to be specified in the PTP.

Contractor shall provide all required ASME PTC 46, correction data as mutually agreed to by the Contractor and the Owner and to be specified in the PTP. At a minimum, raw source data for curves or correction curve equations shall be supplied. Curves may be additionally supplied as well, but priority of test correction source will be, in order of preference: (1) Manufacturer provided source data or curve equations, (2) best fit equations of Manufacturer provided data or curves, (3) visual reads of Manufacturer provided data or curves, and (4) Contractor supplied data, curves, and equations. Contractor shall submit, as part of the proposed PTP, all correction calculations, correction data and any thermal models for review and approval *** prior to commencement of testing.

6.2 INSTRUMENT CALIBRATION

Instrument calibration, where defined in the PTP, shall meet ASME PTC Code requirements. Test Contractor shall submit all instrument calibration data to the Contractor and Owner for review prior to the commencement of the Performance Test. Flow devices meeting the requirements set forth by ASME Code to measure primary parameters and variables need not undergo inspection following the Performance Test if the devices have not experienced conditions that would violate their integrity. Such conditions include steam blows and chemical cleaning.

6.3 TEST EQUIPMENT AND INSTRUMENTS

The Contractor will have the responsibility for providing all test instrumentation and equipment, whether temporary or permanently installed. Instrumentation, where defined in the PTP, shall meet the requirements of the applicable ASME PTC Code, in order that the calculated pre test uncertainty does not exceed ASME Code requirements.

6

	J.O./W.O.NO: 131861 PAGE: 7 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

6.4 TEST INTERRUPTION

Test runs are not required to be continuous, but shall occur within the same *** hour period, in order to assure that the Buck Combined Cycle configuration and the test conditions are relatively similar. ***

6.5 BUCK COMBINED CYCLE PERFORMANCE TESTING

The Buck Combined Cycle Performance Test will be in accordance with ASME PTC 46-1996 “Performance Code on Overall Plant Performance”, except where modified by the Contract, or by mutual agreement by the Parties to the Test and to be defined in the PTP.

6.5.1 Electrical Terminal Point of Guarantees – Buck Combined Cycle Performance Testing

The electrical terminal point of the Buck Combined Cycle Performance Guarantee is as measured at the high side of the main step up transformers. Transformer losses (main step up) due to corrections to Base Performance Conditions will be included as part of the post test corrections.

6.5.2 Performance Test Auxiliary Loads

The Plant Net Electrical Output and Net Heat Rate Guarantee shall include all BOP auxiliary loads, including pumps, fans, motors, heaters, air conditioning, lighting, material handling and miscellaneous equipment that are required to operate the equipment in a normal plant configuration. Electrical loads for generator excitation will also be included if supplied from plant auxiliary bus.

The auxiliary load methodology for the Performance Test will be based on operation during the Base Performance Conditions defined in Section 7.0. The following is the type of operation that is expected:

a. All normal interior lighting shall be energized.

b. All air conditioning/heating/ventilation required to maintain the plant environment on the test day will be operating.

c. All equipment required for normal full load operation will be energized.

d. Redundant or surge capacity equipment shall be energized, active power being supplied but equipment not running.

Water treatment and other loads of a cycling nature shall be characterized prior to the Performance Test. The Contractor will submit, as part of the PTP, procedures for the determination of these cycling loads, for Owner approval.

Auxiliary loads for major Owner Equipment will be individually measured for

7

	J.O./W.O.NO: 131861 PAGE: 8 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

determining satisfaction of Owner Equipment Contract guarantees.

Preliminary auxiliary loads testing and results calculations shall occur prior to commencement of Performance Testing (this testing is not required for Substantial Completion). Results shall be submitted to the Owner and approved prior to Performance Testing.

Testing will determine the kw-hr consumed per unit of material, for correction to the plant auxiliary loads measured. Where appropriate, and approved by the Owner, operation of cycling loads during the test can be substituted.

6.5.3 Plant Configuration

During the Performance Test, except as identified below, the plant will be aligned and operated in the normal plant configuration – as approved by the Owner, with regards to mechanical and electrical components and systems. All steam and water drains and traps will be aligned for safe system operation.

HRSG continuous blowdown will be isolated during the test runs.

Drains or traps with leakage that cannot be repaired prior to test may be isolated during test runs if safe to do so, otherwise corrections will be applied to test results as determined by the Contractor

Gas turbine inlet air chillers will not be energized

The DCS will be in automatic operation, except where approved by the Owner. Setpoints, system limits, alarms and trips will be in normal plant configuration and will not be deviated from, for the purpose of the Performance Test.

6.6 COMBUSTION TURBINE, HEAT RECOVERY STEAM GENERATOR, AND STEAM TURBINE

A Combustion Turbine Verification test will be run concurrent with the Plant Net Electrical Output and Heat Rate test to demonstrate the combustion turbine performance. A Steam Turbine Verification test will also be run concurrently to demonstrate the steam turbine performance. Likewise, the Heat Recovery Steam Generator Verification test will also be run concurrently to demonstrate the HRSG performance. These Tests shall be in accordance with the mutually agreed to test procedures in the PTP. Test procedures shall also provide for demonstration of individual auxiliary loads for Combustion Turbine, Steam Turbine, and Heat Recovery Steam Generator.

6.7 TEST AND DATA REPORT

The Contractor shall provide a complete report in accordance with ASME PTC 46 unless otherwise mutually agreed to by Contractor and Owner for the Net Electrical Output and Net Heat Rate Tests for the Combined Cycle. The Contractor shall also provide a complete report of the test results for the Combustion Turbine, Heat Recovery Steam Generator and Steam

8

	J.O./W.O.NO: 131861 PAGE: 9 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

Turbine and other major equipment Verification Tests respectively and more specifically with the procedures as mutually agreed to by the Owner and the Contractor which will be outlined in the PTP. The report will be submitted within the time specified in the Agreement. A preliminary report of results shall be submitted within the time specified in the Agreement. The report shall be submitted in both electronic and paper format. Final report contents shall be defined in the Performance Test Plan. This shall include, but not be limited to:

a. Calibration data for all instruments used in calculations

b. Raw and summary averaged data for each Test Run

c. Key Plant DCS data during each Test Run, as identified by the Owner prior to the Test

d. All calculations and corrections, including correction curves and data.

e. Final performance correction calculations shall be in Excel and submitted as an Excel format file.

7.0 BASE PERFORMANCE CONDITIONS

Performance Guarantees are based on the following reference conditions. Test results for the Performance Testing will be corrected to these conditions as detailed in the Performance Test Plan:

a. Power Factor (low side of main step up) = ***

b. Fuel – Performance Fuel as identified in Table A-2.3, ***

c. Ambient dry-bulb temperature – ***

d. Ambient wet-bulb temperature – ***

e. Barometric Pressure – ***

f. Owner supplied equipment guarantee/expected performance:

***

g. Combined Cycle Net Electrical Output Guarantee is based on full duct-firing, and no inlet chilling, corresponding to case *** of Contractor’s project heat balances.

h. Combined Cycle Net Heat Rate Guarantee is based on no duct firing, no inlet chilling, and both CTGs at base load, corresponding to case *** of Contractor’s project heat balances.

i. Where a conflict exists due to a referenced file and an approved revision of a manufacturer’s data or the Contractor’s data, the most recent revision shall apply.

9

	J.O./W.O.NO: 131861 PAGE: 10 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

8.0 PERFORMANCE TESTING – NON CODE TESTING

8.1 OTHER MAJOR EQUIPMENT VERIFICATION AND EQUIPMENT PERFORMANCE TESTING

The Contractor shall report the performance of major equipment, using data collected during Performance Testing to determine the performance of the major equipment listed below, using station instrumentation. The Equipment Verification Tests will be conducted utilizing permanently installed plant instrumentation and procedures to be defined in the PTP. No test instrumentation will be installed specifically for the Equipment Verification Tests (e.g., Circ Water flow rate).

This testing is not required to be in strict accordance with applicable Test Codes referenced in Manufacturer contracts, but shall be of sufficient accuracy to give indication of the equipment performance. Equipment design data, such as pump curves and control valve flow coefficients, may be used to supplement the test data for equipment performance indication. The results shall be corrected to Manufacturer contract conditions as part of the Test Report. The Contractor shall supply all raw data and calculations as part of the Test Report.

Even if Performance Guarantees are met for Plant Net Electrical Output and Plant Net Heat Rate, Owner may determine that additional testing, as a change order to the Contractor, including Code Testing, is required to maximize efficiency and capacity benefits.

Equipment Performance Testing may be conducted on certain major equipment if Performance Guarantees are not met for Plant Net Electrical Output or Plant Net Heat Rate and the Performance Test results indicate specific deficiencies; testing will be limited to the equipment listed below; and will be based on station instrumentation.

Owner will use these reports to make a determination concerning the need for further detailed Code testing of equipment.

a. Feedwater, Hotwell Condensate pumps

b. Circulating water pumps

c. Cooling tower

d. Condenser

e. Main Step Up transformers

10

	J.O./W.O.NO: 131861 PAGE: 11 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

f. Water Treatment

8.2 PLANT BASELINE DATA

The Contractor shall report the overall baseline performance data for key operating parameters (to be identified with Owner’s mutual agreement, in the Performance Test Plan) based on a combination of data taken during the Net Plant Performance Test, and concurrent Combustion Turbine, Heat Recovery Steam Generator and Steam Turbine Performance Test and DCS collected data. The goal is to establish initial Plant Baseline Data for comparison for future operation.

The basis of the report shall be uncorrected averaged data from both the DCS and temporary performance test instrumentation from one of the Performance Testing Test Runs selected by the Owner.

8.3 EMISSIONS COMPLIANCE TEST AND CEMS CERTIFICATION

Emissions Compliance Tests, and CEMS Certification will be performed by Owner. Owner will make available the necessary equipment for CTG emissions tuning.

Prior to Substantial Completion and after the combined cycle configuration is sufficiently complete so that all systems are capable of safe operation in accordance with applicable Laws, Prudent Industry Practices and the Project Manuals, Owner shall test the HRSG stacks in accordance with the requirements of applicable government regulations to verify compliance with the Permitted Emission Limits (the “Emissions Compliance Test”). The Emissions Compliance Test for combined cycle may be completed concurrently with Performance Testing to ensure that equipment degradation corrections are avoided or minimized. Stack emissions will be measured during the Performance Test by temporary certified CEMS testing equipment or by the permanent plant CEMS if it is certifiable. The Contractor and Owner shall jointly develop a schedule for providing the Owner necessary forms, data and reports well in advance of regulatory required Owner notifications and submittals. Owner shall prepare forms, data and reports in accordance with Applicable Permits and regulatory requirements.

11

	J.O./W.O.NO: 131861 PAGE: 12 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

Table A-2

			Part of
Parameter	Guarantee	Test Method Note 1	Performance Test	Verification Test
Combined Cycle Net Heat Rate	EPC	PTC 46	X
Combined Cycle Net Electrical Output	EPC	PTC 46	X
Combustion Turbine Net Electrical Output	Manuf. Contract	Verification Test		X
Steam Turbine •   Net Output	Manuf. Contract	Verification Test		X
HRSG •   Steaming Capacity •   SH and RH Outlet Temp •   RH dP	Manuf. Contract See Notes	Verification Test		X

12

	J.O./W.O.NO: 131861 PAGE: 13 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

NOTES

1. All ASME Code Tests will require application of additional ASME Test Code requirements such as PTC 1 and the PTC 19 Series. Where conflict exists, the most recent approved PTC will govern. Plant Performance will be based on the ASME 1967 Steam Tables or the steam tables used for Owner supplied equipment guarantees, if different.

13

	J.O./W.O.NO: 131861 PAGE: 14 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

TABLE A-2.1

Buck Combined Cycle Make Right Guarantees
Combustion Turbine Generator Supplied	Guarantee	Test Responsibility	Contract Responsibility
***	Manufacturer’s contract	***	***
***	Manufacturer’s contract	***	***
***	Manufacturer’s contract	***	***
***	Manufacturer’s contract
Heat Recovery Steam Generator Supplied	Guarantee
***	Manufacturer’s contract	***	***
***	Manufacturer’s contract	***	***
***	Manufacturer’s contract	***	***
***	Manufacturer’s contract	***	***
Auxiliary Boiler
***	Air Permit	***	***
***	Air Permit	***	***
***	Air Permit	***	***
Diesel Generator
***	Air Permit	***	***
***	Air Permit	***	***
***	Air Permit	***	***
***	Air Permit	***	***
Diesel Fire Pump
***	Air Permit	***	***
***	Air Permit	***	***
***	Air Permit	***	***
***	Air Permit	***	***

14

	J.O./W.O.NO: 131861 PAGE: 15 of 15 CLIENT:	REVISION: 0 Duke Energy Carolinas, LLC
Exhibit A-2 Performance Test and Guarantees	PROJECT:	Duke Buck Station CTCC
	LOCATION:	Salisbury, North Carolina

Table A-2.3: Natural Gas Composition Basis

CONSTITUENT	PERCENTAGE BY VOLUME
***	***
***	***
***	***
***	***
***	***
***	***
***	***
***	***
***	***
***	***
***	***
***	***
***	***

15

EXHIBIT A-3

Schedule of Drawings

***

EXHIBIT A-4

EXHIBIT A-4

Site Description

LOCATION:

The station is located in Rowan County, in North Carolina, on Dukeville Road, approximately 50 miles from Charlotte and Greensboro.

DIRECTIONS:

From I-85 North:	Take Exit 81 (Spencer exit)
	Turn left on Long Ferry Road and travel approximately 1.4 miles
	Turn left on Dukeville Road and continue to Buck Steam Station entrance
From I-85 South:	Take Exit 81 (Spencer exit)
	Turn right on Long Ferry Road and travel approximately 1.4 miles
	Turn left on Dukeville Road and continue to Buck Steam Station entrance

ADDRESS:

Buck Steam Station

1555 Dukeville Road

Salisbury, NC 28146

PHONE: (704) 645-2700

EXISTING SITE CONDITIONS

• The existing condition of paved plant roads and the main plant entrance road shall be considered deteriorated.

• The Contractor may use all plant roadways to move materials as required. Any material transports required that will involve the use of roads within the existing station fenceline will require prior approval from station management. Any material transport required that has the potential to block the back entrance to the existing station shall be coordinated with the Station Project Coordinator.

• The grounds around the Station are currently bounded by a chain link fence.

• Contractor to provide temporary fencing associated with the Project that will isolate the Project from the existing plant, as identified on Attachment A-3 in Exhibit A-1 of the Agreement.

• The Contractor shall not at any time block traffic flow in or out of the main entrance to the Station via Dukeville Road without prior written approval from the Owner’s Project Director.

• Construction laydown and contractor parking locations for use by the Contractor are identified on Attachment A-3 in Exhibit A-1 of the Agreement. Contractor is allowed to modify roadway leading to construction warehouse and laydown areas to provide egress across existing ash sluice lines. At all times, egress through the back gate for the existing facility must be maintained.

• Contractor to assure the existing ash sluice lines operations are not impacted by construction activities for the duration of the Project.

• Existing street lights along back entrance to the existing facility will have to be removed for construction of the project. Contractor to assure lighting around the new facility will be adequate for traffic flow along the new back gate entrance.

• Access to the Site for the Contractor will be via a gated entrance off of Dukeville Road, established by the Contractor. The Contractor will provide a guard to monitor and operate the gate during normal construction hours as defined by the Contractor. Staffing of the gate outside of the normally defined construction hours will require approval of the Owner’s Project Director with prior notification of extended hours. If required, the established gate along Dukeville Road may be modified by the Contractor to account for access of both union and non-union employees. Union and non-union parking shall be segregated by the Contractor.

• Requests for special deliveries to the Contractor through the Station’s main entrance gate are required in advance and are subject to the Owner’s approval.

• The Contractor understands that other contractors executing work at the Station not related to the CTCC Project will also use Dukeville Road during the Project.

• Attachment A-3 in Exhibit A-1 of the Agreement illustrates areas that will be made available to the Contractor for parking, office space, laydown, and construction activities. The Contractor may request additional areas to use in addition to those illustrated on this attachment. Access to these areas is subject to the approval of the Owner’s Project Director. Denial of access by the Owner to the additional areas requested shall not provide grounds for issuance of a Change Order by the Contractor.

• Digital pictures to document the existing conditions of the site prior to start of CTCC construction activities are located in Citadon under the following path: Buck CTCC/Document Management/Project Management/Photographs/Pre Construction.

STATION ACTIVITIES POTENTIALLY INTERACTING WITH THE CTCC PROJECT:

Table A4-1 provides a summary of other Station activities that may potentially impact the CTCC Project during the implementation phase. Both the Owner and the Contractor will demonstrate cooperative efforts to minimize the impact of these activities with respect to the Contractor’s Site construction and commissioning activities.

SECURITY THREAT LEVELS

The Contractor shall be aware of the Security Threat Level system that is employed by the Owner at Buck Steam Station.

SECURITY PLAN DURING CONSTRUCTION

Attachment A-3 in Exhibit A-1 of the Agreement illustrates temporary fencing to be installed during the construction phase. The intent is to isolate the Contractor’s site activities as much as possible from the day to day operations of the Station. The Contractor will be permitted to work inside the construction fence as required. The Contractor shall be held accountable for controlling access through the Project Gates while they are being used for either employee or material movement. The Contractor shall be held accountable for closing and locking the Project Gates after each use. Project Gates mean those gates under the control of the Contractor for the ingress and egress

of personnel, construction equipment or material to the Project site. Temporary relocation of the construction fencing by the Contractor is acceptable to provide access for specific construction activities. The Contractor shall permit Station employees access into the construction areas to commission, operate, and maintain equipment as necessary.

Table A4-1

Other Station Activities Potentially Interacting with the Buck CTCC Project

Innage/Outage	Unit	Approximate Length of Outage	Remarks
***	Unit 3	One week	Boiler Inspection
	Unit 4	One week	Boiler Inspection
	All Units	One weekend	Station Outage
***	Unit 5	One week	Boiler Inspection
***	Unit 3	One week	Boiler Inspection
	Unit 6	One week	Boiler Inspection
***	Unit 5	One week	Boiler Inspection
***	Unit 6	One week	Boiler Inspection
***	Unit 3		Retirement
	Unit 4		Retirement

EXHIBIT B

Schedule (Including Key Contractor Schedule Milestones)

***

EXHIBIT C

***

EXHIBIT D

EXHIBIT D

Contractor Permits and Utilities

Type of Contractor Permit	Comments
Construction Permits *	Potential permits include demolition, burning, blasting, and fueling. Contractor to check with Rowan County for building permit requirements.
Temporary Construction Power Supply Inspection	Contractor to verify inspection requirements with Rowan County.
Over the road hauling permits for Station/Buck CC plant material	Required for material delivered to the station. (Contractor to plan for two week minimum for notification and approval from DOT.)
Over the road hauling permits for Contractor equipment	Contractor construction equipment will be permitted by Contractor. Contractor to plan for *** minimum for notification and approval from DOT.
Access Road Issues (repairs, mailboxes, etc,,)- if required	The scope of this item may not require a permit. Planning and scoping during and after construction is needed to determine responsible party for repair and cost estimating.
FAA Notification for Temporary Structures or Equipment	Permit required for any crane exceeding a height of 276 feet above ground level NOTE: FAA permitting for the stack to be by Owner, if required.
Erosion Control	Complete. Any necessary revisions should be filed a minimum of *** before permit need date.
Stormwater Management Plan	Complete.
Boiler Inspections; Required for Aux Boiler	Permit/certification required prior to startup of boiler.
Elevators	Contractor to obtain necessary permits for installation and inspection of all elevators installed by Contractor
Temporary Buildings	Define layout and building and discuss permitting requirements with the County. Contractor to obtain any permits necessary for installation and occupancy of temporary buildings.
Administrative Building - Permanent facility for Duke	Define layout and building and discuss permitting needs with the County. Contractor to obtain any permits necessary for installation and occupancy of buildings.

Type of Contractor Utilities and Equipments	Description
Potable Water	Drinking water and ice will be provided by Contractor for all construction personnel working on the Project including all Contractor subcontractors. This will begin with site mobilization and continue throughout construction. Contractor may use bottled water in office complex, all field water kegs may be filled from the station potable water supply. Contractor will consider a tank with pump for construction facilities. Contractor to check with county to determine permit needs, if any.
Toilet Facilities	Toilet Facilities will be leased-portable units and will be provided by the Contractor. Port-a-jons may be provided by either the Contractor or Subcontractor as required for their own personnel. Contractor facilities will be in place during mobilization, the number and placement of units will be adjusted to suit staffing levels as the project progresses. Currently there are no plans to tie the Construction facilities into the station sanitary sewer system. Pump and haul permit is not required.
Fuel for Contractor equipment.	Fuel for equipment will be the responsibility of the equipment owner/leaser. For Contractor equipment, a double walled gasoline fuel tank (no more than 500 gallons), located within a temporary berm, will be maintained for small equipment fueling. Larger equipment will be fueled directly from a fuel delivery truck. Oil spill cleanup material (oil dry, absorbent pads, etc.) will be available for spill cleanups resulting from refueling activities.
Construction Power Distribution (From Owner – furnished points of service).	Contractor is responsible for distribution of temporary construction power including hook-up of Contractor distribution system to secondary side of Owner’s transformer. Owner will provide electric power, supply transformer and provide hook-up of primary side of transformer. Temporary power permit will be discussed with the county.
Telephone and Data Communications	Contractor will provide voice data communication equipment.
Scrap Metal Disposal	Contractor shall dispose of all scrap metal as a result of the erection of the Facility.
Waste Disposal	Contractor and Contractor subcontractors will provide for their own general trash removal (excludes Hazardous Wastes).
Railroad Tie Disposal	Contractor shall remove all railroad ties it brings onto the Project site.
Compressed Air	Contractor compressed air will be provided by portable gas, diesel or electric compressors starting with a single compressor as needed with additional units added as required. All Contractors’ subcontractors will be responsible for supplying their own compressed air. Gas or diesel generators will require the Contractor or Contractor subcontractors as the case may be to notify the State as insignificant sources listed in the air permit.
Construction (Service) Water	Contractor will provide haulage of water received from designated location provided by the Owner (fire hydrants) Contractor will provide piping, storage and pumping for temporary service water needs.
“Raising” utilities on primary access roads	Contractor will work with Rowan County and local utility companies to minimize the need for raising utilities crossing or alongside access roads.

EXHIBIT E

EXHIBIT E

Owner Permits and Utilities

Type of Owner Permit	Comments
Minor Source Air Permit Modification	Permit received
FAA Notification For New Stacks	Not applicable- stacks shorter than required height for FAA notification (200’).
Stormwater Management Plan	Permit received
Isolated Wetlands Permit	Permit received
NPDES Permit Modification	Permit received
ATC (Authorization To Construct) (Wastewater Treatment)	ATC required for: 1) Neutralization tank (from demin system, 2) Main Yard Sump,and 3) Septic Tank (assuming routing to ash basin). Design requirements for these systems must be supplied by Contractor in sufficient time to secure permit to support construction.
Conditional Use Permit	Permit received
Lighting Requirements for Stack and HRSG	Aviation lighting not required for HRSG.
Well Permit	Permit received. Contractor will tie-in to existing well currently supplying potable water to Buck Steam Station.

Type of Owner Utilities and Equipments	Description
Power for Contractor Equipment and Tools (Construction Electrical Power)	Owner will provide power tap. Contractor to cover the costs of auxiliary power used during construction, provided power feed does not come from retail service line. Contractor to provide construction power requirements (KVA and voltage). Tap location and transformer location to be mutually agreed upon by Shaw and Duke. All distribution from provided taps to be provided by Shaw.
Construction (Service) Water	Initially Owner will provide a source for Shaw to fill tanker truck with service water. Tap into existing service water may be provided later.
Spoil Disposal Areas	Shaw will place soil and rock spoils on-Site in areas identified by Owner. Shaw will dispose of concrete and asphalt off- Site.
Asbestos and Lead Paint Abatement/Disposal	Owner is responsible for all asbestos and lead paint abatement and disposal.
Fuel Oil Contaminated Soil/Rock/Concrete	Owner is responsible for removal and disposal of contaminated soil/rock/concrete.
Railroad Ties Disposal	Owner is responsible for disposal of all railroad ties removed if rail upgrade work is required (no tie removal required at this point in scope development). Contractor is responsible for stockpiling any railroad ties used during construction at an on-Site location to be determined by Owner (if necessary). Contractor provided railroad ties will be handled by Contractor and will be removed after construction is complete.
Parking, Laydown, Construction Trailer Areas (Contractor responsible for site improvements such as grading, paving, etc.)	Owner will provide space onsite for parking, laydown, construction trailers, etc. Contractor is responsible for preparation and maintenance (grading, paving, etc.) of these areas.

EXHIBIT F

	J.O./W.O. NO.: 131861 PAGE: 1 of 1 CLIENT	REVISION: D Duke Energy Carolinas, LLC
CONTRACTOR’S KEY PERSONNEL	PROJECT	Buck Combined Cycle Project
Exhibit F	LOCATION:	Salisbury, North Carolina

Contractor’s Key Personnel will be responsible for supervising the performance of Contractor’s obligations under this Agreement. Any replacement of the key personnel listed below shall be subject to the prior written approval of Owner which the Owner shall not unreasonably withhold or delay. Contractor’s Project Manager shall act as Contractor’s liaison with Owner and shall have the authority (a) to administer this Agreement on behalf of Contractor, (b) to oversee and direct the execution of the responsibilities of Contractor under this Agreement, and (c) to bind Contractor as to the day-to-day project management operations under the Agreement.

Project Position	Person
Project Manager	***
Assistant Project Manager	***
Construction Manager	***
Project Engineering Manager	***
Lead Engineer Electrical	***
Lead Engineer Piping	***
Lead Engineer Mechanical – Equipment	***
Lead Engineer I&C	***
Lead Mechanical Engineer – Process	***
Lead Structural Engineer	***
Lead Engineer CSA	***
Subcontracts Manager – Field	***
Procurement Manager	***

EXHIBIT G-1

List of Approved Subcontractors

***

EXHIBIT G-2

List of Subcontracts under ***

***

EXHIBIT H-1

***

EXHIBIT H-2

***

EXHIBIT I

***

EXHIBIT I

Attachment 1

***

EXHIBIT J

526 South Church Street Charlotte, NC 28202   Mailing Address: EC11T / P.O. Box 1006 Charlotte, NC 28201-1006   ***   ***

May 7, 2009

To:	All Duke Energy Suppliers participating in the Duke Energy Contractor Fitness for Duty Program
Subject:	Revision to Duke Energy Contractor Fitness for Duty Program

For the purpose of continually enhancing our safety culture and aligning employee and contractor approaches, Duke Energy is making the following changes to our Contractor Fitness for Duty Program:

Violations (invalid status) *** resulting from Duke Energy’s random drug/alcohol testing program will result in a *** removal from Duke Energy property. A drug violation includes a positive drug test or having two consecutive diluted test results without a valid medical explanation. An alcohol violation includes any alcohol confirmation test of *** or greater. An individual so impacted may return to work on Duke property after the one year period and completion of the required SAP process.

A subsequent violation, at any time, will result in a permanent ban from Duke Energy property.

A refusal or adulteration/sample substitution or alcohol consumption/illegal drug use during work time will result in a permanent ban from Duke Energy property.

Please do not hesitate to contact *** you have any questions or concerns about this program.

Sincerely,

***

Generation Strategic Sourcing

Duke Energy Corporation

***

EXHIBIT J

Owner’s Drug and Alcohol Testing Policy

Duke Energy Regulated Generation

Contractor Substance Abuse Prevention and Drug Testing Policy

I. Objective

To provide a safe and healthful work environment, Duke Energy is committed to maintaining drug and alcohol free work places. Therefore, all contractors and their subcontractors must adhere to the following “Duke Energy — Regulated Generation, Contractor Substance Abuse Prevention and Drug Testing Policy”.

Duke Energy Regulated Generation has developed this program to provide the following benefits:

q Set minimum standards for contractor substance abuse programs.

q Improve construction safety performance.

q Provide a safe work environment for Duke Energy employees and their contractors.

II. Overview

A number of existing and proposed programs both nationally and regionally have been consulted in the development of this policy. The result is a core program, which can be supplemented if desired, but forms a common basis for establishing substance abuse programs. The Metropolitan Indianapolis Coalition for Construction Safety (MICCS) and the Construction Owners Association of the Tri-State (COATS) programs have been determined to meet Duke Energy’s minimum requirements. All contractors working for Duke Energy - Regulated Generation in the Midwest (Indiana, Ohio & Kentucky) must participate in either the MICCS or COATS Substance Abuse Prevention and Drug Testing Program. All contractors working for Duke Energy Regulated Generation in the Carolinas (North and South Carolina) must participate in the MICCS program. (Attachment I — MICCS). (Attachment II — COATS). This includes:

q Contractors must maintain a substance abuse program consistent with the MICCS and/or COATS requirements and submit it for review and approval to verify it meets their minimum requirements.

q Contractors must register their employees and subcontractors with MICCS/COATS. Substance abuse testing completed as part of a contractor’s substance abuse program must be submitted to MICCS/COATS to obtain employee and subcontractor registration.

q MICCS/COATS will issue a Substance Abuse Prevention Card to all contractors and their subcontractors once registered. Contractors and subcontractors must carry the Substance Abuse Prevention Card with them when on Duke property.

q New contractors and their subcontractors will be allowed a grace period of *** be registered in MICCS/COATS.

q Duke Energy will contract with a third party administrator, Midwest Toxicology Services, to assist contractors in registering with the MICCS and COATS programs.

Exceptions: Those contractors already required to participate in drug programs such as DOT, Coast Guard or carry a CDL in relationship with work being preformed at Duke Energy (e.g. package delivery) shall be exempt from participating in MICCS/COATS provided their participation this program is up to date and can be verified.

Additionally, visitors are not required to participate in this program. Visitors are defined as persons temporarily on site for a meeting, tour, or other non-employment activity and are typically escorted by station personnel.

III. Policy

The use, possession, distribution, sale, and/or manufacture of substances of abuse, alcohol, drug paraphernalia, or legal drugs being used for illegal purposes while performing work for Duke Energy and/or while on Duke property is prohibited.

The off the job use, possession, distribution, sale and/or manufacture of substances of abuse including alcohol which may adversely affect an employee’s job performance and has an adverse effect on safety will not be tolerated.

Testing of contractors’ employees will be conducted in accordance with the drug and alcohol testing requirements specified by MICCS and COATS programs as referenced in Section IV and Attachments I & II. Testing will be conducted under conditions of strict confidentiality and with the utmost regard for the dignity of individual employees.

Violation of this policy is grounds for disciplinary action up to and including being bared from Duke Energy facilities.

Any contractor performing work for Duke Energy Regulated Generation shall maintain in a substance abuse program consistent with the MICCS and/or COATS requirements and register their employees and subcontractors in these programs. For new contractors and their subcontractors a grace period of *** is allowed for registration in MICCS/COATS.

Station managers retain the right to use their discretion for emergency work; allowing contractors on site based on business needs, without a MICCS or COATS card.

All bid documents, as well as contract documents, will include contractor substance abuse testing requirements in accordance with this policy. Contractors, by signing the contract agreement, will thereby certify that their employees and subcontractors comply with this substance abuse policy.

IV. Drug and Alcohol Testing Requirements

All contractors must develop, implement, publish, maintain and enforce a contractor substance abuse policy consistent with the requirements specified in MICCS and/or COATS. (Reference the specific requirements outlined in Attachments I & II). In summary, these requirements include:

A. Pre-employment Testing:

Required to assure contractors and their subcontractors are substance free upon employment; are registered with MICCS/COATS; and are issued a substance abuse prevention card. The substance abuse prevention card must be available at all times when on Duke Energy property.

For new contractors and subcontractors a *** grace period will be allowed for MICCS/COATS registration and issuance of the substance abuse prevention card.

Annual Testing:

All contractors and subcontractors must pass at minimum an annual drug screen in order to maintain their substance abuse prevention card.

Random Testing:

In addition to requiring the performing of annual testing, Duke will conduct periodic random tests of contractors and subcontractors on site, as required, to assure a safe work place.

Reasonable Cause:

As established in the contractor’s substance abuse prevention program, additional testing may be conducted where there is reasonable cause to test. Duke Energy shall be notified of these circumstances and informed of the results.

Post Incident:

Testing shall be performed after an incident/accident, unless it is determined that the incident/accident was not the result of the actions of an employee/worker who was involved in the incident.

Test Failure or Refusal to Test:

Failure to pass a substance test is grounds for immediate action; disciplinary action is always conducted by the contractor, and severity may be up to and including being barred from Duke Energy facilities. Refusal to submit to a substance test is considered positive and is grounds for disciplinary action up to and including being barred from Duke Energy facilities until a valid Substance Abuse Prevention card can be provided.

***, Senior Vice President

Regulated Generation

Attachment 1 — MICCS Program	MICCS - Substance Abuse Program
Attachment 2 — COATS Program	COATS Program-

Substance Abuse Program

METRO INDIANAPOLIS COALITION FOR CONSTRUCTION SAFETY (MICCS) METRO

INDIANAPOLIS COALITION FOR CONSTRUCTION SAFETY (MICCS) Substance Abuse Program

Revision Date: July 24, 2007 Revision 2.0 Page-2 of 21

Table of Contents

Part 1. Introduction	3
1.1 Purpose	3
1.2 Benefits	3
1.3 MICCS ID Card and Database Protocol	3
Part 2. Revision History	4
Part 3. Definitions	5
Part 4. Tests: Procedures and Supporting Information	7
4.1 Reasons for Testing	7
4.1.1 Annual/Pre-employment Test	7
4.1.2 Follow-up Test	7
4.1.3 Post Accident Test	7
4.1.4 Probable Cause/Reasonable Suspicion Test	7
4.1.5 Random Test	8
4.1.6 Returning to Duty Test	8
4.2 Drug Testing Procedures	8
4.2.1 Specimen Collection	8
4.2.2 Laboratory Testing Procedures	9
4.2.3 MRO Procedures	9
4.2.4 Specimen Retest Protocol	9
4.3 Alcohol Testing Procedures	10
4.4 Test results	10
4.4.1 Adulterated Test	10
4.4.2 Diluted Test	10
4.4.3 Negative Test Result	10
4.4.4 Positive Alcohol Test	11
4.4.5 Positive Drug Test Result	11
4.4.6 Refusal to Test	11
4.5 Sanctions and Consequences for Failing a Drug Test	11
Part 5. Employee Responsibilities	13
Part 6. Auditing Information	14
Part 7. Contractor/employer responsibilities	15
APPENDIX A: SAMHSA Drug Screen	16
APPENDIX B: Diluted Specimen Processing	17
Instructions for Diluted Specimen Retest	17
Employee Instruction Prior to Retesting	17
APPENDIX C: Evaluation Form for Inability to Provide an Adequate Urine Specimen	18
APPENDIX D: Documentation When a Breath Test Cannot Be Conducted	20
APPENDIX E: Guidelines for Post-accident Testing	21

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Part 1. Introduction

1.1 Purpose

The use of alcohol and other drugs leads to unsafe working conditions for workers, since the impaired worker is a potential hazard to himself and to those working with him. The purpose of this document is to outline a substance abuse program which establishes and maintains a safe and healthy work environment, free from drugs and alcohol, in Central Indiana. Although this document provides essential information, it cannot address all situations that may arise. Therefore, it is recommended that MICCS owners implement, publish, maintain, and enforce a contractor substance abuse policy which includes prohibiting the unlawful use, possession, consumption, manufacture, distribution, and sale of controlled substances in the work place that meets or exceeds the guidelines presented in this document. All bid and contract documents should contain and adhere to the same stringent guidelines.

1.2 Benefits

MICCS has developed this program to provide the following benefits to the local construction industry:

Minimize the duplication of effort created by multiple substance abuse programs that would be necessary were it not for this industry-wide program.

Establish minimum standards for substance abuse programs for contractors and building trade unions.

Assist owners and contractors in developing substance abuse policies that result in increased safety for all on-site workers.

1.3 MICCS ID Card and Database Protocol

Test results from all MICCS required testing will be entered into the MICCS database. The employee’s annual test date is automatically updated with any negative drug result entry.

A MICCS ID Card will be issued to employees with a negative test result.

A new card will not be issued each time a test is taken. A new card will be issued as needed to update an employee’s photo and/or replace a worn unreadable card.

A MICCS ID Card displays the employee’s photo, name, and a computer generated identification number. A card cannot be issued without a photo.

The MICCS ID Card is the property of MICCS. Employers are to return invalid cards to MICCS.

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Part 2. Revision History

Revision	Revision Date	Reason for Revision/Change Request	Revised By
1.0		OCT 2004
2.0	JUL 2007	Reformatted document in MS Word. Modified content and organization.	Alan L. Slaff

Substance Abuse Program METRO INDIANAPOLIS COALITION FOR CONSTRUCTION SAFETY (MICCS)

METRO INDIANAPOLIS COALITION FOR CONSTRUCTION SAFETY (MICCS)

Substance Abuse Program

Revision Date: July 24, 2007 Revision 2.0 Page-2 of 21

Table of Contents

Part 1. Introduction	3
1.1 Purpose	3
1.2 Benefits	3
1.3 MICCS ID Card and Database Protocol	3
Part 2. Revision History	4
Part 3. Definitions	5
Part 4. Tests: Procedures and Supporting Information	7
4.1 Reasons for Testing	7
4.1.1 Annual/Pre-employment Test	7
4.1.2 Follow-up Test	7
4.1.3 Post Accident Test	7
4.1.4 Probable Cause/Reasonable Suspicion Test	7
4.1.5 Random Test	8
4.1.6 Returning to Duty Test	8
4.2 Drug Testing Procedures	8
4.2.1 Specimen Collection	8
4.2.2 Laboratory Testing Procedures	9
4.2.3 MRO Procedures	9
4.2.4 Specimen Retest Protocol	9
4.3 Alcohol Testing Procedures	10
4.4 Test results	10
4.4.1 Adulterated Test	10
4.4.2 Diluted Test	10
4.4.3 Negative Test Result	10
4.4.4 Positive Alcohol Test	11
4.4.5 Positive Drug Test Result	11
4.4.6 Refusal to Test	11
4.5 Sanctions and Consequences for Failing a Drug Test	11
Part 5. Employee Responsibilities	13
Part 6. Auditing Information	14
Part 7. Contractor/employer responsibilities	15
APPENDIX A: SAMHSA Drug Screen	16
APPENDIX B: Diluted Specimen Processing	17
Instructions for Diluted Specimen Retest	17
Employee Instruction Prior to Retesting	17
APPENDIX C: Evaluation Form for Inability to Provide an Adequate Urine Specimen	18
APPENDIX D: Documentation When a Breath Test Cannot Be Conducted	20
APPENDIX E: Guidelines for Post-accident Testing	21

METRO INDIANAPOLIS COALITION FOR CONSTRUCTION SAFETY (MICCS)

Substance Abuse Program

Revision Date: July 24, 2007 Revision 2.0 Page-3 of 21

Part 1. Introduction

1.1 Purpose

The use of alcohol and other drugs leads to unsafe working conditions for workers, since the impaired worker is a potential hazard to himself and to those working with him. The purpose of this document is to outline a substance abuse program which establishes and maintains a safe and healthy work environment, free from drugs and alcohol, in Central Indiana. Although this document provides essential information, it cannot address all situations that may arise. Therefore, it is recommended that MICCS owners implement, publish, maintain, and enforce a contractor substance abuse policy which includes prohibiting the unlawful use, possession, consumption, manufacture, distribution, and sale of controlled substances in the work place that meets or exceeds the guidelines presented in this document. All bid and contract documents should contain and adhere to the same stringent guidelines.

1.2 Benefits

MICCS has developed this program to provide the following benefits to the local construction industry: Minimize the duplication of effort created by multiple substance abuse programs that would be necessary were it not for this industry-wide program. Establish minimum standards for substance abuse programs for contractors and building trade unions. Assist owners and contractors in developing substance abuse policies that result in increased safety for all on-site workers.

1.3 MICCS ID Card and Database Protocol Test results from all MICCS required testing will be entered into the MICCS database. The employee’s annual test date is automatically updated with any negative drug result entry. A MICCS ID Card will be issued to employees with a negative test result. A new card will not be issued each time a test is taken. A new card will be issued as needed to update an employee’s photo and/or replace a worn unreadable card. A MICCS ID Card displays the employee’s photo, name, and a computer generated identification number. A card cannot be issued without a photo. The MICCS ID Card is the property of MICCS. Employers are to return invalid cards to MICCS.

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Part 2. Revision History

Revision Revision Date Reason for Revision/Change Request Revised By

1.0

OCT 2004

2.0

JUL 2007

Reformatted document in MS Word. Modified content and organization.

Alan L. Slaff

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Part 3. Definitions

The following terms and definitions are provided to ensure a common understanding of terms and consistency of use: Accredited Laboratory (SAMHSA). A federally certified laboratory approved by the Department of Health and Human Services (DHHS) for testing of prohibited items and substances. Accident/Incident. Any event caused by an employee, either directly or indirectly, that results in treatment by a health care provider, or that resulted in damage to property. This would also include any serious near miss incidents. Adulteration. Tampering with a test sample by the substitution or addition of other ingredients to mask the presence or use of illegal drugs, resulting in a specimen that contains a substance that is not expected to be present in human urine, or contains a substance expected to be present but is at a concentration that it is not consistent with human urine. Annual. Each employee’s obligation to be tested at least every 12 months. Controlled Substances. Includes all illegal drugs listed in this document with the Department of Transportation (DOT) limits and includes: Controlled substances, “look alike” and “designer” drugs Prescription drugs, used by a person other than the intended user Drug paraphernalia Alcoholic beverages, in the possession of or used by an employee on the premises, or while assigned to work off premises Contractor. Employees or subcontractors of a corporation, company, or entity that performs construction or maintenance work. Medical Review Officer (MRO). The licensed physician responsible for receiving laboratory results generated by a substance abuse testing program. An MRO has: knowledge of substance abuse disorders received appropriate medical training to interpret and evaluate an individual’s medical history been certified by either the American Association of Medical Review Officers (AAMRO) or the American College of Occupational and Environmental Medicine (ACOEM).

MICCS ID Card. A MICCS card is one that states that it meets the requirements of the MICCS substance abuse program, and/or reciprocity with the MICCS program, and is verifiable through the Construction Safesite © (www.constructionsafesite.org) site database. MICCS ID Card (Counterfeit). A MICCS Identification (ID) Card modified in any manner without authorization from MICCS. Owner. The corporation, company, agency, or other entity, that hires contractors to perform construction work and/or maintenance work on their premises. Pre-employment Site Entry. Screening of prospective employees to determine if an applicant is capable of safely performing required tasks and meeting the prerequisites for employment.

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Probable Cause/Reasonable Suspicion. Circumstances based on the objective evidence about the employee’s conduct in the work place which would cause a reasonable person to believe that the employee is demonstrating signs of impairment due to alcohol or other drugs. Note: See sections 4.1.4 and 4.3.

Construction SafeSite©: Construction Safesite© (www.constructionsafesite.org) is a verification database that gives MICCS the ability to track the availability of workers who have current drug tests, and who are available to work on MICCS jobsites. All third party administrators (TPAs) use this database. The worker can only be “available” for duty if all TPAs show him as “available”. If one TPA lists the employee as “not available”, his status in Construction Safesite© will be “not available”, and he will not be “available” until he becomes compliant with the program that is causing him to be “not available” and his status is changed. Substance Abuse Professional (SAP). An SAP can be a: licensed physician (Medical Doctor or Doctor of Osteopathy) licensed or certified psychologist licensed or certified social worker licensed or

certified employee assistance professional state-licensed or certified marriage and family therapist drug and alcohol counselor certified by the National Association of Alcoholism and Drug Abuse Counselors Certification Commission (NAADAC); or by the International Certification Reciprocity Consortium/Alcohol and Other Drug Abuse (ICRC); or by the National Board for Certified Counselors, Inc. and Affiliates/Master Addictions Counselor (NBCC). licensed or certified mental health counselor Or any additional licensed or certified professional as approved by the federal government for compliance with the Department of Transportation’s substance abuse program.

An SAP must have knowledge of and clinical experience in the diagnosis and treatment of substance abuse-related disorders. Test(s). (Note: All types of tests applicable to the MICCS program are defined in Part 4)

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Part 4. Tests: Procedures and Supporting Information

4.1 Reasons for Testing

Contractors are required to send all drug test results, regardless of the reason for testing, to MICCS to be entered in the MICCS database. The types of testing, associated information, guidelines, and time constraints, if applicable, as required by MICCS are shown below in alphabetical order.

4.1.1 Annual/Pre-employment Test Each onsite employee is to participate in annual testing, or provide documentation of having been tested within the past 12 months. The latest test date will become the employee’s new annual test date for participation in the MICCS program. An employer is prohibited from giving any more than 14 days notice of testing to an employee. Employers are responsible for notifying employees when their annual test is due.

4.1.2 Follow-up Test Follow-up testing is required after an employee has taken a return to duty test. The number of follow-up tests will be set by the SAP. A minimum of three is required. The test results must be negative. The employee will be notified by telephone or letter to report for testing the day after receiving notification. If the employee fails to complete follow-up testing, their MICCS ID Card will be marked non-compliant in the MICCS database until the employee reports for the follow-up test. Even though failure to complete the test may be due to the fact that the employee was laid off or out of the local area (i.e., for vacation), the employee is responsible to contact the third party administrator as soon as possible upon notification of receipt after the fact. The length of time that was designated by the SAP to complete their follow-up tests will be extended by the length of time they are non-compliant for not reporting for the test. The employee is responsible for payment.

4.1.3 Post Accident Test This test is required: When the employee is involved in any accident, incident, or event caused directly or indirectly by the employee. Results in treatment by a health care provider, or Results in damage to property. Including any serious near-miss incident The employee is to proceed directly for testing, or as soon as possible, and before the employee returns to the job site. It is the contractor/subcontractor’s responsibility to see that testing is done within the time frame described above. The employee shall be tested for both drugs and alcohol.

4.1.4 Probable Cause/Reasonable Suspicion Test This test is required at the time of observable probable cause circumstances based on objective evidence about the employee’s conduct in the workplace that would cause a reasonable person to believe that the employee is demonstrating signs of impairment due to alcohol or other drugs. Examples of objective evidence include an

employee showing signs of impairment such as, difficulty in maintaining balance, slurred speech, or erratic behavior, etc.

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These observations must be documented and a copy provided to the employee. Only supervisors who have had training on determining reasonable suspicion are qualified to require a reasonable suspicion test.

4.1.5 Random Test MICCS owners are required to have contractor employees working on their premises submit to immediate random drug and alcohol tests. It is the owner’s responsibility to see that their selection is truly random without discrimination or arbitrary selection. MICCS owner random testing is to be an unannounced, unscheduled drug and alcohol test. Upon notification, the employee must report immediately to the testing facility. Owners shall give notification of testing to the employee before the end of a shift to take the possibility of a 2 hour wait into consideration.

4.1.6 Returning to Duty Test After a positive test result, in order for an employee to return to work, the employee is required to take a return to duty test. The test result must be negative. The employee is responsible for payment.

4.2 Drug Testing Procedures

4.2.1 Specimen Collection Specimen collection will be conducted in accordance with 49 CFR Part 40 “Procedures for Transportation Workplace Drug and Alcohol Testing Programs”, and applicable state and federal law. Testing must be performed by a DHHS-approved laboratory. MICCS does not follow the complete regulatory testing requirements of the DOT, only the general guidelines. The MICCS procedures are designed to:

^¡ ensure the security and integrity of the specimen according to accepted federal DOT chain-of-custody guidelines.

^¡ make every reasonable effort to maintain the dignity of anyone submitting a specimen for this program. If an employee is unable to provide a specimen at the time of testing, the employee could be required to wait up to two hours without leaving the test facility. Failure to remain and complete the test is the same as a refusal to test with the same sanctions as a positive test result. Make sure that notification of random testing is given in ample time before the end of a shift. Types of specimens: The employee will provide a urine specimen for the drug test. In the event that an employee is physically unable to produce a proper urine sample, a test may be done by a different method, such as hair, saliva, etc., and must be approved by the third party administrator or the MICCS substance abuse committee. The employee must present written documentation (see Appendix C) from a medical doctor that supports his inability to provide a urine specimen to the MRO. The employee or company must contact the third party administrator for instructions on how to test using an alternate method. A photo ID must be presented at the time of collection to verify the employee’s identity. The employee will be asked to empty all pockets and display the contents to the collector. The employee will have up to two hours to provide a specimen. If the employee leaves before the two hours having not provided a specimen, this test will be processed the same as a refusal to test. The employee will be afforded privacy to provide the specimen unless The collector observes evidence of an employee’s attempt to tamper with a specimen, or The temperature range of the original specimen was out of normal range, or

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It appears that the specimen was tampered with, or The specimen was determined invalid by the laboratory Upon completion of testing the employee will be given a copy of the Custody and Control Form (CCF).

4.2.2 Laboratory Testing Procedures

All substance analysis will be done in SAMHSA laboratories certified by DHHS. Laboratory procedures will include: Initial screen on each specimen. In the event that the initial test is positive a confirmation test will automatically be performed using the GCMS method. A test is considered positive if the detected level of the drug is at or above the cutoff level shown in Appendix A. MICCS recommends that no adverse action or discipline be taken against any worker or applicant for employment on the basis of any positive test that has not been confirmed. Validity testing is required for each specimen. Each specimen is measured for creatinine level, specific gravity, and pH to determine if any of the following occurred: Adulterants or foreign substance were added to the urine, The specimen was substituted, or The urine was diluted. The laboratory will report all results to the MRO. The MRO will make a final determination of the verified results. The results will be reported to the designated employee representative.

4.2.3 MRO Procedures

All drug testing shall come under the control and supervision of a physician with confidentiality protected in accordance with state law and the “AMA Code of Ethical Conduct for Physicians Providing Occupational Medical Services” or the Medical Review Officer Manual developed by the National Institute on Drug Abuse (NIDA). All testing results shall be verified by an MRO. The MRO provides a medical review on all test results issued by the laboratory as follows: If the laboratory result is negative, the review is completed and a negative result is mailed. If the laboratory result is positive, adulterated, substituted, or invalid, the MRO will: Make one attempt to contact the donor by telephone to inform him of the results and complete an interview to determine whether a legitimate medical explanation exists for the result reported by the laboratory. If the MRO left a message, but did not talk to the employee by 10:00 AM of the following workday, the MRO will call the employer to report the results. In any case, the employee always has the opportunity to discuss the test results with the MRO. If the laboratory reports an invalid result to the MRO, the MRO will contact the employee and ask if the employee may have taken any medication that may interfere with some immunoassay tests. If the employee provides an acceptable explanation, the test will be canceled and no further testing will be required unless a negative result is required to obtain a valid MICCS ID Card. If the employee is unable to provide an acceptable explanation and denies having adulterated the specimen, the test will be canceled, and a second collection must take place immediately under direct observation

4.2.4 Specimen Retest Protocol When the MRO has informed the employee of a verified “positive drug test” or “refusal to test” because of adulteration or substitution, the employee/worker has 72 hours from the time of notification to request a retest of the specimen at a different SAMHSA laboratory. The employee may make the request verbally or in writing and make arrangements for payment with the MRO service, as the cost of the test is the responsibility of the employee. If the result of the retest is different from the original result, the test will be cancelled, and a recollection will be needed.

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4.3 Alcohol Testing Procedures

Alcohol testing is required for probable cause, post accident/incident, and for immediate random testing situations. Tests for alcohol shall be performed using the breath or blood to determine a Blood Alcohol Content (BAC). If possible, a breathalyzer type instrument conforming to DOT standards should be used. If not available, then a blood sample may be used. If blood testing is necessary, the contractor/owner is responsible to provide a documented reason as to the reasons why a breath test could not be performed (see Appendix D). Failure to provide a sufficient breath sample to complete a breath test or refusing to provide a blood sample will be considered a “refusal to test” and have the same consequences as a positive test. All alcohol test results with a confirmed BAC test level of .04 or higher will be considered positive and will require the employee to be removed from the owner’s property immediately. This result will also invalidate the employee’s MICCS ID Card. In order for the employee to become eligible for a MICCS ID Card again, the employee will have to complete the required program of rehabilitation outlined in this document. All alcohol test results with a confirmed BAC test level of .020 through .039 will require the employee to be removed from the owner’s property for 24 hours or until the employee’s next scheduled work time, whichever is longer. Any initial test that indicates a BAC level of .02 or greater must be confirmed by an Evidential Breath Testing Device (EBT) operated by the Breath Alcohol Technician (BAT). The confirmation test will be performed no sooner than 15 minutes and no later than 30 minutes following the completion of the initial test in accordance with current DOT guidelines.

4.4 Test results

4.4.1 Adulterated Test If a test was tampered with by the substitution or addition of other ingredients, the test result will be processed the same as a positive test result. When a recollection is required, i.e., due to adulteration or temperature, etc., the recollection will be observed according to DOT procedures.

4.4.2 Diluted Test A test result that produces a diluted specimen requires a retest. Refer to Appendix B for detailed instructions on how to process a diluted specimen. If the retest also produces a diluted specimen, it will carry the same consequences as a positive test result unless a valid medical reason exists.

4.4.3 Negative Test Result A drug result is considered negative if:

^¡ the laboratory finds no drug metabolite levels over the confirmed cutoff values, or

^¡ the screen test and confirmation test indicated the presence of a legal or illegal substance(s) in excess of the limits but the donor (employee) had a valid medical reason for the substance being detected in the specimen. An alcohol result is considered negative if the BAC is below 0.02. The employee’s MICCS ID Card will be updated in the MICCS database.

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4.4.4 Positive Alcohol Test

A positive alcohol test occurs if the breathalyzer test, or its equivalent test, indicates the presence of alcohol that meets or exceeds the cut-off limits of the DOT and the Commercial Drivers License (CDL) as shown in this document.

4.4.5 Positive Drug Test Result A result is considered positive if the presence of the drug meets or exceeds both the screening and confirmation levels listed in Appendix A. The test must be verified by the MRO. The MRO must determine that the test results are not from the use of

prescription or over the counter medications, food, or any reason other than the illegal use of unlawful substances or controlled substances.

4.4.6 Refusal to Test

Refusal to submit to a test will carry the same consequences as a positive test. A refusal to test occurs if an employee: Adulterated, substituted, or refused to provide a urine specimen Failed to appear for testing within a reasonable period of time Failed to remain at the testing site until the testing process was completed Failed to provide a sufficient amount of urine within 2 hours without a medical reason and/or failed to undergo an MRO directed medical evaluation for such a reason Failed to cooperate with any part of the testing process, which includes the use of abusive/threatening language or behavior Disrupted the testing process

4.5 Sanctions and Consequences for Failing a Test

MICCS requires employees, who test positive (including a refusal to test), to surrender their MICCS ID Card. The MICCS employer is required to refer employees with positive test results to a SAP for evaluation and treatment. The MICCS website has a listing of SAP’s located in the Indianapolis area who support and are knowledgable about the MICCS substance abuse program requirements. The employee must start a program of rehabilitation prior to returning to a MICCS owner’s site, and must continue and complete the rehabilitation in order to be eligible to work on a MICCS site. The rehabilitation must include the following steps:

1. The employee must arrange for an evaluation with a Substance Abuse Professional (SAP).

2. The SAP evaluation must specify that the employee: Must attend education classes and/or treatment. Must perform the actions recommended by the SAP or assigned rehabilitation specialists. Is subject to random follow-up testing not less than 3 times within the next 12 month from the employee’s return to work test. In cases where the employee was unable to complete the follow-up test due to being laid off or out of town, etc., the length of time that was designated by the SAP to complete their follow-up test will be extended by the length of time the employee was not available for testing. Will not be allowed to take another MICCS drug test for at least 14 days from the date of the first positive test.

3. The employee is required to submit a letter from the SAP to MICCS concerning their fitness for return to work including that the employee is eligible for a return to duty test.

4. The employee must take a return to duty test with negative results. These results must be submitted to MICCS for MICCS database entry.

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5. The employee must actively complete any ongoing rehabilitation and follow-up testing required by the SAP to keep the MICCS ID Card valid.

6. Arrangements for all costs are the responsibility of the employee.

7. If an employee tests positive 3 times within a 12 month period, the employee will not be eligible to retest or obtain an MICCS ID Card for a period of one year and will not be permitted to work on MICCS owner property during that period.

8. Failure to comply with any of the above sanctions shall result in the employee surrendering their MICCS ID Card. The status of the employee’s card will be changed to “not available” in the MICCS database.

9. The result of a person using a counterfeit drug card will be the same as a positive drug test.

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Part 5. Employee Responsibilities

Employee responsibilities are as follows: Report to work fit for duty. Be in the appropriate mental and physical condition necessary to work in a safe and competent manner, free of the influence of drugs and alcohol. Report to the employer any medications that may impair job performance or safety. Consent to and participate in owner/employer required tests Consent to the release of the drug test results to the employer, for the MICCS database, or for specific purposes required by law.

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Part 6. Auditing Information

The owner reserves the right, under conditions of strict confidentiality, to inspect the employer’s substance abuse testing program records within 24 hours of the owner’s notification of intent to audit. Owners are required to audit the validity of on-site employees at the time of entry to the job site and may audit them at any time thereafter. (See www.constructionsafesite.org).

MICCS employers are required to check the validity of all MICCS ID Cards through Construction Safesite© (www.constructionsafesite.org) upon hire and/or job site entry. Construction Safesite© will state that an employee’s MICCS ID card is either “available”, “not available”, or “no record with that ID”. Any problems and/or questions about a card status will be addressed by the third party administrator who holds the employee’s testing record. Third party administrators have the ability to make appropriate updates to the employee’s testing record so that his/her status is changed at Construction Safesite©.

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Part 7. Contractor/employer responsibilities

Contractor’s employees working on or visiting a participating owner’s job site, including workers, new hires, replacements, and supervisory personnel, are subject to annual testing, testing for probable cause/reasonable suspicion, post-accident/incident testing, random testing and return to duty/follow up testing as a condition of contract between the contractor and the owner. The contractor shall comply with owner requirements, when the owner requirements are more stringent than the contractor’s. The contractor should provide training to employees, including new hires, to help them understand the contractor’s substance abuse testing policy, the effects of substance abuse on personal health and the work environment. Recognizing the behaviors common to substance abuse and the procedures for conducting substance abuse testing should also be included as a part of this training for supervisor personnel who could be required to initiate a reasonable suspicion/probable cause test. Contractors are required to maintain a record keeping system that would allow an owner or another contractor with whom the contractor has entered into agreement, to effectively conduct a compliance audit.

To protect everyone’s legal interest contractors should obtain a written consent from each employee that allows the release of otherwise confidential testing information to an owner.

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APPENDIX A: Testing Panel

Drugs of abuse are tested in a routine SAMHSA 5-panel screen. The MICCS Substance Abuse Program uses the drug screen components and cut-off levels listed below. In addition to these levels and substances, the creatinine level and specific gravity of the specimen will be measured. If the creatinine level is less than 20 ml/dl and the specific gravity is less than 1.003, the sample will be considered dilute and another collection will be required. The second sample will be collected the morning after notification of a diluted specimen. Adulterated specimens will be processed the same as a positive test. The minimum requirement for a positive test result for alcohol will be a BAC of 0.04% w/vol., a level consistent with the DOT and CDL guidelines. New drugs, preliminary cut off and confirmation levels may be modified periodically in order to parallel the DOT and CDL guidelines. The MICCS Substance Abuse Program does not follow the complete regulatory testing requirements of the DOT, only the general guidelines. Type Preliminary Cut-off Levels (ng/ml) Confirmation Levels

Amphetamines

1000

500

Cocaine

300

150

PCP – Phencylidine

25

25

Opiates

2000

2000

THC – Cannabinoids

50

15

Ethanol (Alcohol)

.04% w/vol. (enzyme assay)

.04% w/vol. (GC/FD)

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APPENDIX B: Diluted Specimen Processing

Instructions for Diluted Specimen Retest

A diluted specimen result requires a retest. If this is a second diluted result without a medical reason, it will be processed the same as a positive test result. The MICCS database manager will report the dilute result to the employer’s representative. The employer must provide specific instructions on fluid intake (see below) to the employee prior to retesting to prevent another diluted specimen. The collection for another test must be done the morning after the employee has been notified. The employee may provide reasons for not being able to test which can be approved by the database manager. The database manager may reject the explanation. If the employee disputes the decision of the database manager, the employee can contact the MICCS office to submit a plea to the Substance Abuse Committee to consider further.

Employee Instruction Prior to Retesting

Here are instructions for the employee to be followed prior to retesting: Consume no fluids after 9:00 PM the night before the test. Limit fluid intake to a minimum the day of the test. The supervisor will inform the employee of the test time and location. It is the employee’s responsibility to monitor intake of fluids to prevent another dilute specimen.

If the employee has a medical condition that will cause a dilute specimen, the employee’s physician must provide medical information in writing to the MRO for evaluation. After reviewing the submitted information, the MRO will issue a final report to the employer.

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APPENDIX C: Evaluation Form for Inability to Provide an Adequate Urine Specimen

Purpose of Form: This physician referral form is to be used for an individual who was unable to provide a sufficient urine specimen within the time allowance stated in the MICCS Substance Abuse Policy. The MICCS policy states that a “refusal to test” will be issued if an individual is required to take a MICCS drug test and is unable to provide a sufficient specimen within the required time, unless the individual can provide a valid medical explanation. This form provides information to the employee, employer and the evaluation physician on the steps to be followed for the evaluation. This form should be filled out and given to the physician who will be doing the medical evaluation. The MICCS substance abuse program will follow the same general protocol used by DOT for handling these types of evaluation. The specific DOT protocol taken from 49 CFR Part 40.193 is summarized below and will be used as a guide for MICCS evaluations. Background Information from 49 CFR Part 40.193: When the collector informs the designated employee representative that an employee has not provided a sufficient amount of urine, they must, after consulting with the MRO (Medical Review Officer), direct the employee to obtain, within five working days, an evaluation from a licensed physician, acceptable to the MRO, who has expertise in the medical issues raised by the employee’s failure to provide a sufficient specimen. The referral physician must recommend that the MRO make one of the following determinations:

(1) A medical condition has, or with a high degree of probability, could have, precluded the employee from providing an adequate amount of urine.

(2) There is not an adequate basis for determining that a medical condition has, or with a high degree of probability, could have, precluded the employee from providing an adequate amount of urine. (For the purposes of this paragraph, a medical condition includes an ascertainable physiological condition (e.g., a urinary system dysfunction) or a documented pre-existing psychological disorder, but does not include unsupported assertions of “situational anxiety” or dehydration.)

After the referral physician completes the evaluation, they must provide a written statement of their recommendations and the basis for them to the MRO. Do not include in this statement detailed information on the employee’s medical condition beyond what is necessary to explain your conclusion. Employee/Employer information:

1. Employee must have an evaluation done by a physician as soon as possible. The employee must present this form to the evaluating physician The evaluation should be done within five working days or else the MRO will be required to issue a refusal to test. Time extensions beyond the five working days must be approved by the MRO.

2. Employee should sign this consent allowing the physician to release their findings to you and the MRO.

3. Failure to provide an acceptable statement from a physician will result in a refusal to test, which carries the same consequences as a positive test result.

Consent to Release Information (Employee needs to sign) I, , SSN , authorize the evaluating physician to release the findings of my evaluation to: Employer’s MRO: Physician’s Name Phone Fax Employer Employer Name Phone Fax Signature of employee Date of signature

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APPENDIX C - Continued Physician Information and Instructions: You have been requested to evaluate the individual indicated below because he/she was unable to provide an adequate amount of urine to complete a MICCS required drug test. Make sure you have read and understand the background information of 49 CFR Part 40.193 on the previous page. Your findings will assist the MRO in determining this individual’s final test status. Please make sure item #1. or #2. below has been completed and attach any additional information you feel is pertinent to this evaluation. If you have any questions regarding this evaluation, please call the MICCS database administrator, Midwest Toxicology at 317/262-2200 or 800/358-8450 (Ext. 203-Sharon Allen or Ext. 205-Tiffany Ellefson). Name & SSN (ID #) of employee: Employer Name/Address: Date employee was unable to complete required drug test: Name (printed) of physician performing evaluation: Physician Phone: Fax:

I have determined, in my reasonable medical judgment, that:              1. the employee does have a medical condition* that has, or with a high degree of probability, could have, precluded the employee from providing an adequate amount of urine.              2. there is not an adequate basis for determining that a medical condition* that has, or with a high degree of probability, could have, precluded the employee from providing an adequate amount of urine. *For purposes of this paragraph, a medical condition includes an ascertainable physiological condition (e.g., a urinary system dysfunction) or a documented pre-existing psychological disorder, but does not include unsupported assertions of “situational anxiety” or dehydration. Explanation of finding:                                          Printed Name of Physician Signature of Physician Date of Conclusion Please fax this completed form to the MRO and Employer listed in the consent area of this form.

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APPENDIX D: Documentation When a Breath Test Cannot Be Conducted

MICCS requires a breath alcohol test for qualifying post-accident situations and reasonable suspicion. MICCS has patterned their alcohol testing requirements after the regulatory testing requirements of DOT (Department of Transportation). DOT does not allow the use of blood for alcohol tests except in a few rare circumstances. The FMCSA (Federal Motor Carrier Safety Administration) division of DOT does allow employers to accept the results of breath or blood tests conducted by Federal, State, or local officials having independent authority in post-accident situations as long as the results of the tests can be obtained by the employer. The MICCS program’s policy will allow alcohol testing done by breath or blood. However, breath testing is the preferred method. Blood testing is only authorized when a breath test is impossible to obtain. The employer is responsible to provide a documented reason to the third party administrator as to why this alternative method (blood testing) was used. The form below can be used for such documentation and should be forwarded to the third party administrator.

Name of Employee

Date                                                                                    Complete explanation of why breath testing was not done:

¨ Employee had medical treatment that prevented a breath alcohol test from being done within the allowed time frame.

¨ There is no testing facility open that was capable of performing a breath alcohol test within the allowed time frame. Provide time and location information

¨ There was no testing facility capable of performing a breath alcohol test within the geographical area of where the testing needed to occur. Provide time and location information

¨ Other, please describe:

Company name and signature of Employer authorizing agent: Date                                                                                                       

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APPENDIX E: Guidelines for Post-accident Testing

MICCS policy requirement for Post-Accident Testing: A substance abuse drug and alcohol test of an onsite contractor employee is required when they are involved in any accident/incident or event, caused by them either directly or indirectly, that results in treatment by a health care provider, or that results in damage to property, including any serious near-miss incident. The employee should proceed directly for testing or as soon as possible. Recommended Steps for Post-Accident Testing:

1. Contractors are responsible to insure that a drug and alcohol test is completed for any accident or incident as defined above.

2. Needed medical treatment will take precedence over completing a drug and alcohol test. However, a drug and alcohol test should be done as soon as possible. The alcohol test should be administered within 2-hours of the accident/incident. If there is a delay of more than 2-hours, an explanation of why the testing was delayed or couldn’t be completed should be documented.

3. The contractor must insure that the facility who will be doing the post-accident test meets the following requirements.

a. Drug test requirement:

i. Use of a standard custody and control form

ii. Testing of specimen by a SAMHSA certified laboratory using the drug panel cut-off level set by MICCS

iii. Test result reviewed by a certified MRO (Medical Review Officer)

b. Alcohol Test requirements:

i. A breath test should always be administered unless breath testing is not an option.

ii A breath test should be done as soon as possible (within 2 hours). If it can’t be completed within 8 hours, testing should cease and documentation explaining the inability to complete testing within 8 hours should be forwarded to the third party administrator. iii The breath test should be administered by a certified BAT (Breath Alcohol Technician) using a breath testing device that meets the same requirement as DOT. iv If breath testing is not available, a blood draw may be used.

4. The results of all post-accident tests are required to be reported to the third party database administrator as soon as possible following any post-accident testing so the results may be entered into the database.

5. If any post-accident test result is positive the contractor must immediately remove the employee from the MICCS owner site and follow their company policy’s discipline for testing positive. Any positive test will render the employee’s MICCS card invalid.

EX-12

EXHIBIT 12

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

The ratio of earnings to fixed charges is calculated using the Securities and Exchange Commission guidelines.

	Year Ended December 31,
	2009		2008		2007		2006		2005
	(dollars in millions)
Earnings as defined for fixed charges calculation
Add:
Pre-tax income from continuing operations(a)	$	1,770	$	1,993	$	2,078	$	1,421	$	1,169
Fixed charges		892		883		797		1,382		1,159
Distributed income of equity investees		82		195		147		893		473
Deduct:
Preference security dividend requirements of consolidated subsidiaries		—		—		—		27		27
Interest capitalized(b)		102		93		71		56		23
Total earnings (as defined for the Fixed Charges calculation)	$	2,642	$	2,978	$	2,951	$	3,613	$	2,751
Fixed charges:
Interest on debt, including capitalized portions(b)	$	853	$	834	$	756	$	1,311	$	1,096
Estimate of interest within rental expense		39		49		41		44		36
Preference security dividend requirements of consolidated subsidiaries		—		—		—		27		27
Total fixed charges	$	892	$	883	$	797	$	1,382	$	1,159
Ratio of earnings to fixed charges		3.0		3.4		3.7		2.6		2.4

(a) Excludes amounts attributable to noncontrolling interests and income or loss from equity investees.

(b) Excludes equity costs related to Allowance for Funds Used During Construction that are included in Other Income and Expenses in the Consolidated Statements of Operations.

EX-21

EXHIBIT 21

LIST OF SUBSIDIARIES

The following is a list of certain subsidiaries (greater than 50% owned) of the registrant and their respective states or countries of incorporation:

Actividades A y D, S.A (Guatemala).	Cinergy Global Power Iberia, S.A. (Spain)
Advance SC LLC (South Carolina)	Cinergy Global Power Services Limited (England)
Aguaytia Energy del Peru S.R.L. Ltda. (Peru)	Cinergy Global Power, Inc. (Delaware)
Aguaytia Energy, LLC (Delaware)	Cinergy Global Resources, Inc. (Delaware)
Attiki Denmark ApS (Denmark)	Cinergy Global Trading Limited (England)
Bison Insurance Company Limited (Bermuda)	Cinergy Global Tsavo Power (Cayman Islands)
Brownsville Power I, L.L.C. (Delaware)	Cinergy Holdings BV (Netherlands)
Caldwell Power Company (North Carolina)	Cinergy Investments, Inc. (Delaware)
Catamount Celtic Energy Limited (Scotland)	Cinergy Limited Holdings, LLC (Delaware)
Catamount Energy Corporation(Vermont)	Cinergy Origination & Trade, LLC (Delaware)
Catamount Energy SC 1 (Scotland)	Cinergy Power Generation Services, LLC (Delaware)
Catamount Energy SC 2 (Scotland)	Cinergy Power Investments, Inc. (Ohio)
Catamount Energy SC 3 (Scotland)	Cinergy Receivables Company LLC (Delaware)
Catamount Heartlands Corporation (Delaware)	Cinergy Retail Power General, Inc.(Texas)
Catamount Rumford Corporation (Vermont)	Cinergy Retail Power Limited, Inc. (Delaware)
Catamount Sweetwater 1 LLC (Vermont)	Cinergy Retail Power, L.P. (Delaware)
Catamount Sweetwater 2 LLC (Vermont)	Cinergy Solutions - Utility, Inc. (Delaware)
Catamount Sweetwater 3 LLC(Vermont)	Cinergy Solutions Partners, LLC (Delaware)
Catamount Sweetwater 4-5 LLC (Vermont)	Cinergy Technology, Inc. (Indiana)
Catamount Sweetwater 6 LLC (Vermont)	Cinergy Two, Inc.(Delaware)
Catamount Sweetwater Corporation (Vermont)	Cinergy UK, Inc.(Delaware)
Catamount Sweetwater Holdings LLC (Vermont)	Cinergy Wholesale Energy, Inc.(Ohio)
Catawba Manufacturing and Electric Power Company (North Carolina)	Cinergy-Centrus Communications, Inc.(Delaware)
CEC UK1 Holding Corp. (Vermont)	Cinergy-Centrus, Inc. (Delaware)
CEC UK2 Holding Corp. (Vermont)	CinFuel Resources, Inc. (Delaware)
CEC Wind Development LLC (Vermont)	CinPower I, LLC (Delaware)
Centra Gas Toluca S.R.L. de C.V. (Mexico)	Claiborne Energy Services, Inc. (Louisiana)
CGP Global Greece Holdings, SA (Greece)	Comercializadora Duke Energy de Centro America, Limitada (Guatemala)
Cinergy Climate Change Investments, LLC (Delaware)	CSCC Holdings Limited Partnership (British Columbia, Canada)
Cinergy Corp. (Delaware)	CSGP General, LLC (Texas)
Cinergy Foundation, Inc. (Indiana)	CSGP Limited, LLC (Delaware)
Cinergy General Holdings, LLC (Delaware)	CST General, LLC (Texas)
Cinergy Global (Cayman) Holdings, Inc.(Cayman Islands)	CST Green Power, L.P. (Delaware)
Cinergy Global Ely, Inc. (Delaware)	CST Limited, LLC (Delaware)
Cinergy Global Hellas S.A. (Greece)	D/FD Holdings, LLC (Delaware)
Cinergy Global Holdings, Inc. (Delaware)	D/FD International Services Brasil Ltda. (Brazil)
Cinergy Global Power (UK) Limited (England)	D/FD Operating Services LLC (Delaware)
Cinergy Global Power Africa (Proprietary) Limited (South Africa)	DE Marketing Canada Ltd. (Canada-Federal)

DE Nuclear Engineering, Inc.(North Carolina)	Duke Energy Egenor S. en C. por A. (Peru)
DEB - Pequenas Centrais Hidrelétricas Ltda. (Brazil)	Duke Energy Electroquil Partners (Delaware)
DEGS Biomass, LLC (Delaware)	Duke Energy Engineering, Inc. (Ohio)
DEGS EPCOM College Park, LLC (Delaware)	Duke Energy Fossil-Hydro California, Inc. (Delaware)
DEGS GASCO, LLC (Delaware)	Duke Energy Fossil-Hydro, LLC (Delaware)
DEGS O&M, LLC (Delaware)	Duke Energy Generating S.A. (Argentina)
DEGS of Boca Raton, LLC (Delaware)	Duke Energy Generation Services Holding Company, Inc. (Delaware)
DEGS of Cincinnati, LLC (Ohio)	Duke Energy Generation Services, Inc. (Delaware)
DEGS of Delta Township, LLC (Delaware)	Duke Energy Group Holdings, LLC (Delaware)
DEGS of Lansing, LLC (Delaware)	Duke Energy Group, LLC(Delaware)
DEGS of Monaca, LLC (Delaware)	Duke Energy Indiana, Inc. (Indiana)
DEGS of Narrows, LLC (Delaware)	Duke Energy Industrial Sales, LLC (Delaware)
DEGS of Oklahoma, LLC(Delaware)	Duke Energy International (Europe) Holdings ApS (Denmark)
DEGS of Philadelphia, LLC (Delaware)	Duke Energy International (Europe) Limited (United Kingdom)
DEGS of San Diego, Inc. (Delaware)	Duke Energy International Argentina Holdings (Cayman Islands)
DEGS of Shreveport, LLC(Delaware)	Duke Energy International Argentina Marketing/Trading (Bermuda) Ltd. (Bermuda)
DEGS of South Charleston, LLC (Delaware)	Duke Energy International Asia Pacific Ltd. (Bermuda)
DEGS of St. Bernard, LLC(Delaware)	Duke Energy International Bolivia Holdings No. 1, LLC (Delaware)
DEGS of St. Paul, LLC(Delaware)	Duke Energy International Brasil Commercial, Ltda. (Brazil)
DEGS of Tuscola, Inc. (Delaware)	Duke Energy International Brasil Holdings, LLC (Delaware)
DEGS Three Buttes, LLC(Delaware)	Duke Energy International Brazil Holdings Ltd. (Bermuda)
DEGS Wind I, LLC (Delaware)	Duke Energy International Chile C.P.A. (Chile)
DEGS Wind Supply II, LLC (Delaware)	Duke Energy International Chile Holding I B.V. (Netherlands)
DEGS Wind Supply, LLC (Delaware)	Duke Energy International Chile Holding II B.V. (Netherlands)
Delta Township Utilities, LLC (Delaware)	Duke Energy International Comercializadora de El Salvador, S.A. de C.V. (El Salvador)
DENA Asset Partners, L.P. (Delaware)	Duke Energy International del Ecuador Cia. Ltda. (Ecuador)
DENA Partners Holding, LLC (Delaware)	Duke Energy International El Salvador Investments No. 1 Ltd (Bermuda)
DETMI Management, Inc. (Colorado)	Duke Energy International El Salvador Investments No. 1 y Cia. S. enC. de C.V. (El Salvador)
Dixilyn-Field (Nigeria) Limited (Nigeria)	Duke Energy International El Salvador, S en C de CV (El Salvador)
Dixilyn-Field Drilling Company (Delaware)	Duke Energy International Electroquil Holdings, LLC (Delaware)
Dixilyn-Field International Drilling Company, S.A. (Panama)	Duke Energy International Espana Holdings, S.L.U. (Spain)
Duke Broadband, LLC (Delaware)	Duke Energy International Group Cooperatie U.A. (Netherlands)
Duke Capital Partners, LLC (Delaware)	Duke Energy International Group, Ltd. (Bermuda)
Duke Communications Holdings, Inc. (Delaware)	Duke Energy International Guatemala Holdings No. 1, Ltd. (Bermuda)
Duke Energy Americas, LLC(Delaware)	Duke Energy International Guatemala Holdings No. 2, Ltd. (Bermuda)
Duke Energy Business Services LLC (Delaware)	Duke Energy International Guatemala Holdings No. 3 (Cayman Islands)
Duke Energy Carolinas Plant Operations, LLC(Delaware)	Duke Energy International Guatemala Limitada (Guatemala)
Duke Energy Carolinas, LLC (North Carolina)	Duke Energy International Guatemala y Compania Sociedad en Comandita por Acciones (Guatemala)
Duke Energy Cerros Colorados, S.A.(Argentina)	Duke Energy International Group Cooperatie U.A. (Netherlands)
Duke Energy Commercial Enterprises, Inc. (Indiana)	Duke Energy International Holding, Ltd. (Bermuda)
Duke Energy Corporate Services, Inc. (Delaware)	Duke Energy International Holdings B.V. (Netherlands)
Duke Energy Development Pty Ltd (Australia)	Duke Energy International Investments No. 2 Ltd. (Bermuda)

Duke Energy International Latin America, Ltd.(Bermuda)	Duke Trading Do Brasil Ltda. (Brazil)
Duke Energy International Mexico Holding Company I, S. de R.L. de C.V.(Mexico)	Duke Ventures II, LLC (Delaware)
Duke Energy International Mexico, S.A. de C.V. (Mexico)	Duke Ventures Real Estate, LLC (Delaware)
Duke Energy International Netherlands Financial Services B.V. (Netherlands)	Duke Ventures, LLC (Nevada)
Duke Energy International Operaciones Guatemala Limitada (Guatemala)	Duke/Fluor Daniel (North Carolina)
Duke Energy International Peru Inversiones No. 1, S.R.L.(Peru)	Duke/Fluor Daniel Caribbean, S.E. (Puerto Rico)
Duke Energy International Peru Investments No. 1, Ltd.(Bermuda)	Duke/Fluor Daniel El Salvador S.A. de C.V. (El Salvador)
Duke Energy International PJP Holdings, Ltd.(Bermuda)	Duke/Fluor Daniel International (Nevada)
Duke Energy International Southern Cone SRL (Argentina)	Duke/Fluor Daniel International Services (Nevada)
Duke Energy International Trading and Marketing (UK) Limited (United Kingdom)	Duke/Fluor Daniel International Services (Trinidad) Ltd. (Trinidad and Tobago)
Duke Energy International Transmision Guatemala Limitada (Guatemala)	Duke/Louis Dreyfus L.L.C. (Nevada)
Duke Energy International Uruguay Holdings, LLC (Delaware)	Duke-Cadence, Inc. (Indiana)
Duke Energy International Uruguay Investments, S.R.L. (Uruguay)	DukeNet Communications, LLC (Delaware)
Duke Energy International, Brasil Ltda. (Brazil)	Duke-Reliant Resources, Inc. (Delaware)
Duke Energy International, Geracao Paranapanema S.A. (Brazil)	DukeTec I, LLC
Duke Energy International, LLC (Delaware)	DukeTec II, LLC (Delaware)
Duke Energy Kentucky, Inc. (Kentucky)	DukeTec, LLC (Delaware)
Duke Energy Marketing America, LLC (Delaware)	Eastman Whipstock do Brasil Ltda.
Duke Energy Marketing Corp. (Nevada)	Eastman Whipstock, S.A. (Brazil)
Duke Energy Marketing Limited Partnership (Alberta, Canada)	Eastover Land Company (Kentucky)
Duke Energy Merchants, LLC (Delaware)	Eastover Mining Company (Kentucky)
Duke Energy Moapa, LLC (Delaware)	Electroquil, S.A. (Ecuador)
Duke Energy Murray Operating, LLC (Delaware)	Energy Pipelines International Company (Delaware)
Duke Energy North America, LLC (Delaware)	Equinox Vermont Corporation (Vermont)
Duke Energy Ohio, Inc. (Ohio)	Etenorte S.R.L.(Peru)
Duke Energy One, Inc. (Delaware)	Eteselva S. R. L.(Peru)
Duke Energy Peru Holdings S.R.L. (Peru)	eVent Resources Holdings LLC (Delaware)
Duke Energy Receivables Finance Company, LLC (Delaware)	eVent Resources I LLC (Delaware)
Duke Energy Registration Services, Inc. (Delaware)	eVent Resources Overseas I, LLC (Delaware)
Duke Energy Retail Sales, LLC (Delaware)	Gas Integral S.R.L. (Peru)
Duke Energy Royal, LLC (Delaware)	Generadora La Laguna Duke Energy International Guatemala y Cia., S.C.A. (Guatemala)
Duke Energy Services Canada ULC (British Columbia, Canada)	Greenville Gas and Electric Light and Power Company (South Carolina)
Duke Energy Services, Inc. (Delaware)	Happy Jack Windpower, LLC (Delaware)
Duke Energy Trading and Marketing, L.L.C. (Delaware)	IGC Aguaytia Partners, LLC (Cayman Islands)
Duke Energy Transmission Holding Company, LLC (Delaware)	Inver Energy Holdings (Cayman Islands) I
Duke Engineering & Services (Europe) Inc. (Delaware)	Inver Energy Holdings II (Cayman Islands)
Duke Engineering & Services International, Inc. (Cayman Islands)	Inver-Energy y Cia. SCA (Cayman Islands)
Duke Investments, LLC (Delaware)	Kit Carson Windpower, LLC (Delaware)
Duke Java, Inc. (Nevada)	KO Transmission Company (Kentucky)
Duke Project Services Australia Pty Ltd (Australia)	LH1, LLC (Delaware)
Duke Project Services, Inc. (North Carolina)	Louisiana Energy Services, LLC (Louisiana)
Duke Supply Network, LLC (Delaware)	MCP, LLC (South Carolina)
Duke Technologies, Inc. (Delaware)	Miami Power Corporation (Indiana)

North Allegheny Wind, LLC (Delaware)
NorthSouth Insurance Company Limited (Bermuda)	Termoselva S. R. L. (Peru)
Notrees Windpower, LP (Delaware)	Texas Eastern (Bermuda) Ltd. (Bermuda)
Oak Mountain Products, LLC (Delaware)	Texas Eastern Arabian Ltd. (Bermuda)
Ocotillo Windpower, LP (Delaware)	The Duke Energy Foundation (North Carolina)
Ohio River Valley Propane, LLC (Delaware)	Three Buttes Windpower, LLC (Delaware)
P.I.D.C. Aguaytia, L.L.C. (Delaware)	Top of the World Wind Energy LLC (Delaware)
Pan Service Company (Delaware)	TRES Timber, LLC (South Carolina)
PanEnergy Corp. (Delaware)	Tri-State Improvement Company (Ohio)
Peru Energy Holdings, LLC (Delaware)	Wateree Power Company (South Carolina)
Pioneer Transmission, LLC (Indiana)	Western Carolina Power Company (North Carolina)
Proyecto de Autoabastecimiento La Silla, S. de R.L. de C.V. (Mexico)	Willow Creek Wind Energy LLC (Delaware)
Sandy River Timber, LLC (South Carolina)	Willow Mountain Products, LLC (Delaware)
Seahorse do Brasil Servicos Maritimos Ltda. (Brazil)	Termoselva S. R. L. (Peru)
Searchlight Wind Energy LLC (Nevada)	Texas Eastern (Bermuda) Ltd. (Bermuda)
Silver Sage Windpower, LLC (Delaware)	Texas Eastern Arabian Ltd. (Bermuda)
South Construction Company, Inc. (Indiana)	The Duke Energy Foundation (North Carolina)
Southern Power Company (North Carolina)	Three Buttes Windpower, LLC (Delaware)
Spruce Mountain Investments, LLC (Delaware)	Top of the World Wind Energy LLC (Delaware)
Spruce Mountain Products, LLC (Delaware)	TRES Timber, LLC (South Carolina)
SUEZ-DEGS of Lansing, LLC (Delaware)	Tri-State Improvement Company (Ohio)
SUEZ-DEGS of Orlando LLC (Delaware)	Wateree Power Company (South Carolina)
Sugartree Timber, LLC (Delaware)
SYNCAP II, LLC (Delaware)
TBP Properties, LLC (South Carolina)
TE Happy Jack, LLC (Delaware)
TE Notrees, LLC (Delaware)
TE Ocotillo, LLC (Delaware)
TE Silver Sage, LLC (Delaware)
Teak Mountain Products, LLC (Delaware)
TEC Aguaytia, Ltd. (Bermuda)

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-157723, 333-157405, 333-146483, 333-132996 and 333-132992 on Form S-3 and Registration Statement Nos. 333-147132, 333-141023, 333-134080 and 333-132933 (including Post-effective Amendment No. 1 thereto) on Form S-8 of our report dated February 26, 2010, relating to the financial statements and financial statement schedules of Duke Energy Corporation and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Duke Energy Corporation for the year ended December 31, 2009.

/s/ DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 26, 2010

EX-24.1

EXHIBIT 24.1

DUKE ENERGY CORPORATION

Power of Attorney

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2009

(Annual Report)

The undersigned Duke Energy Corporation, a Delaware corporation and certain of its officers and/or directors, do each hereby constitute and appoint Lynn J. Good, David S. Maltz and Steven K. Young, and each of them, to act as attorneys-in-fact for and in the respective names, places and stead of the undersigned, to execute, seal, sign and file with the Securities and Exchange Commission the Annual Report of said Duke Energy Corporation on Form 10-K for the year ended December 31, 2009, of said Duke Energy Corporation and any and all amendments thereto, hereby granting to said attorneys-in-fact, and each of them, full power and authority to do and perform all and every act and thing whatsoever requisite, necessary or proper to be done in and about the premises, as fully to all intents and purposes as the undersigned, or any of them, might or could do if personally present, hereby ratifying and approving the acts of said attorneys-in-fact.

Executed as of the 23^rd day of February, 2010.

DUKE ENERGY CORPORATION
By:	/s/    JAMES E. ROGERS
	Chairman, President and Chief Executive Officer

(Corporate Seal)

ATTEST:

/s/    SUE C. HARRINGTON
Assistant Secretary
/s/    JAMES E. ROGERS	Chairman, President and Chief Executive Officer (Principal Executive Officer and Director)
James E. Rogers
/s/    LYNN J. GOOD	Group Executive and Chief Financial Officer (Principal Financial Officer)
Lynn J. Good
/s/    STEVEN K. YOUNG	Senior Vice President and Controller (Principal Accounting Officer)
Steven K. Young
/s/    WILLIAM BARNET, III	(Director)
William Barnet, III

/s/    G. ALEX BERNHARDT, SR.	(Director)
G. Alex Bernhardt, Sr.
/s/    MICHAEL G. BROWNING	(Director)
Michael G. Browning
/s/    DANIEL R. DIMICCO	(Director)
Daniel R. DiMicco
/s/    JOHN H. FORSGREN	(Director)
John H. Forsgren
/s/    ANN M. GRAY	(Director)
Ann M. Gray
/s/    JAMES H. HANCE, JR.	(Director)
James H. Hance, Jr.
/s/    E. JAMES REINSCH	(Director)
E. James Reinsch
/s/    JAMES T. RHODES	(Director)
James T. Rhodes
/s/    PHILIP R. SHARP	(Director)
Philip R. Sharp
/s/    DUDLEY S. TAFT	(Director)
Dudley S. Taft

EX-24.2

EXHIBIT 24.2

DUKE ENERGY CORPORATION

CERTIFIED RESOLUTIONS

Form 10-K Annual Report Resolutions

FURTHER RESOLVED, That each officer and director who may be required to execute such 2009 Form 10-K or any amendments thereto (whether on behalf of the Corporation or as an officer or director thereof or by attesting the seal of the Corporation or otherwise) be and hereby is authorized to execute a Power of Attorney appointing Lynn J. Good, David S. Maltz and Steven K. Young, and each of them, as true and lawful attorneys and agents to execute in his or her name, place and stead (in any such capacity) such 2009 Form 10-K, as may be deemed necessary and proper by such officers, and any and all amendments thereto and all instruments necessary or advisable in connection therewith, to attest the seal of the Corporation thereon and to file the same with the Securities and Exchange Commission, each of said attorneys and agents to have power to act with or without the others and to have full power and authority to do and perform in the name and on behalf of each of such officers and directors, or both, as the case may be, every act whatsoever necessary or advisable to be done in the premises as fully and to all intents and purposes as any such officer or director might or could do in person.

* * * * * * *

I, MARC E. MANLY, Group Executive, Chief Legal Officer and Corporate Secretary of Duke Energy Corporation, do hereby certify that the foregoing is a full, true and complete extract from the Minutes of the meeting of the Audit Committee of the Board of Directors of said Corporation with full authority delegated to it by the Board of Directors held on February 22, 2010, at which meeting a quorum was present.

IN WITNESS WHEREOF, I have hereunto set my hand and affixed the Corporate Seal of said Duke Energy Corporation, this the 23^rd day of February, 2010.

/s/    MARC E. MANLY        

Marc E. Manly, Group Executive, Chief Legal Officer

and Corporate Secretary

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James E. Rogers, certify that:

1) I have reviewed this annual report on Form 10-K of Duke Energy Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

  a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

  b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

  c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

  d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

  a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

  b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 26, 2010

/S/    JAMES E. ROGERS        

James E. Rogers

Chairman, President and

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Lynn J. Good, certify that:

1) I have reviewed this annual report on Form 10-K of Duke Energy Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

  a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

  b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

  c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

  d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

  a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

  b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 26, 2010

/s/    Lynn J. Good        

Lynn J. Good

Group Executive and

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Duke Energy Corporation (“Duke Energy”) on Form 10-K for the period ending December 31, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James E. Rogers, Chairman, President and Chief Executive Officer of Duke Energy, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

   (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

   (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Duke Energy.

/S/    JAMES E. ROGERS        

James E. Rogers

Chairman, President and Chief Executive Officer

February 26, 2010

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Duke Energy Corporation (“Duke Energy”) on Form 10-K for the period ending December 31, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lynn J. Good, Group Executive and Chief Financial Officer of Duke Energy, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

   (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

   (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Duke Energy.

/s/    Lynn J. Good        

Lynn J. Good

Group Executive and Chief Financial Officer

February 26, 2010