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, 2008 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:

Title of each class	Name of each exchange on which registered
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 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, 2008	$	21,946,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at February 23, 2009.		1,281,151,774

TABLE OF CONTENTS

DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2008

Item		Page
PART I.
1.	BUSINESS	3
	GENERAL	3
	U.S. FRANCHISED ELECTRIC AND GAS	8
	COMMERCIAL POWER	20
	INTERNATIONAL ENERGY	24
	OTHER	25
	ENVIRONMENTAL MATTERS	26
	GEOGRAPHIC REGIONS	27
	EMPLOYEES	27
	EXECUTIVE OFFICERS OF DUKE ENERGY	27
1A.	RISK FACTORS	28
1B.	UNRESOLVED STAFF COMMENTS	35
2.	PROPERTIES	35
3.	LEGAL PROCEEDINGS	37
4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	37
PART II.
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	38
6.	SELECTED FINANCIAL DATA	40
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	42
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	82
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	83
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	196
9A.	CONTROLS AND PROCEDURES	196
PART III.
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	197
11.	EXECUTIVE COMPENSATION	197
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	197
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	197
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	197
PART IV.
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	198
	SIGNATURES	199
	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;

• State, federal and foreign legislative and regulatory initiatives and 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 in Duke Energy Corporation’s (Duke Energy) service territories;

• 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 ratepayers in a timely manner;

• 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 units described below.

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.

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). 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. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 3 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets”). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy hereinafter.

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. The results of operations of these businesses are presented as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the spin-off. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.”

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. The results of operations of the former DENA businesses which Duke Energy exited have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the completion of the exit activities.

Business Segments. At December 31, 2008, Duke Energy operated the following business segments, all of which are considered reportable segments under the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information,”: U.S. Franchised Electric and Gas, Commercial Power and International Energy. Prior to the fourth quarter of 2008, Crescent was a reportable business segment of Duke Energy; however, beginning in the fourth quarter of 2008, Crescent is no longer considered an operating segment of Duke Energy as Duke Energy’s chief operating decision maker no longer reviews Crescent’s operating results in order to make resource allocation decisions and evaluate its performance. Accordingly, the results of Crescent have been included in Other for all periods presented. Prior to Duke Energy’s sale of an effective 50% ownership interest in Crescent in September 2006 (see below), the then Crescent segment represented Duke Energy’s 100% ownership of Crescent Resources, LLC. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business 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.”

3

PART I

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), 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). Substantially all of U.S. Franchised Electric and Gas’ operations are regulated and, accordingly, these operations are accounted for under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71).

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, and the five Midwestern gas-fired non-regulated generation assets that were a portion of the former DENA operations. 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. Most of the generation asset output in Ohio has been contracted through the Rate Stabilization Plan (RSP), which expired on December 31, 2008; effective January 1, 2009 Commercial Power began operating under an Electric Security Plan (ESP), which expires on December 31, 2011. As a result of the approval of the ESP, certain of Commercial Power’s operations are accounted for under SFAS No. 71 effective December 17, 2008. For more information on the RSP and ESP, as well as the reapplication of SFAS No. 71 to certain of its operations, see the “Commercial Power” section below. 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 6,300 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 370 net MW of wind generating capacity in operation as of December 31, 2008. In 2008, DEGS initiated a joint venture with Areva Inc. named ADAGE, LLC, to develop, design, build, and operate wood burning biomass power plants in the U.S.

International Energy. International Energy 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 activities target power generation in Latin America. Additionally, International Energy owns equity investments in Saudi Arabia and Greece.

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, Crescent, DukeNet Communications, LLC (DukeNet) and related telecom businesses and Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned, captive insurance subsidiary. 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 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. Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern U.S. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. On a limited basis, Bison also participates in reinsurance activities with certain third parties.

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

4

PART I

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
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
APB	Accounting Principles Board
ARO	Asset Retirement Obligation
Attiki	Attiki Gas Supply S.A.
Bison	Bison Insurance Company Limited
BPM	Bulk Power Marketing
BREDL	Blue Ridge Environmental Defense League
Bridgeport	Bridgeport Energy LLC
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
Campeche	Compañía de Servicios de Compresión de Campeche, S.A. de C.V.
CAMR	Clean Air Mercury Rule
CC	Combined Cycle
CMT	Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc.
CT	Combustion Turbine
Cinergy	Cinergy Corp.
CO2	Carbon Dioxide
COL	Combined Construction and Operating License
CPCN	Certificate of Public Convenience and Necessity
Crescent	Crescent Resources, LLC
DB	Defined Benefit Pension Plan
DCP Midstream	DCP Midstream, LLC (formerly Duke Energy Field Services, LLC)
DEGS	Duke Energy Generation Services, Inc.
DEI	Duke Energy International, LLC
DEM	Duke Energy Merchants, LLC
DENA	Duke Energy North America
DENR	Department of Environment and Natural Resources
DETM	Duke Energy Trading and Marketing, LLC
DOE	Department of Energy
DOJ	Department of Justice

5

PART I

Term or Acronym	Definition
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.
EITF	Emerging Issues Task Force
EPA	Environmental Protection Agency
EPS	Earnings Per Share
ESP	Electric Security Plan
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FEED	Front End Engineering and Design Study
FERC	Federal Energy Regulatory Commission
FIN	Financial Accounting Standards Board Interpretation
FPP	Fuel and Purchased Power
FSP	Financial Accounting Standards Board Staff Position
FTC	Federal Trade Commission
GAAP	United States Generally Accepted Accounting Principles
GCSA	Gas Compression Services Agreement
IGCC	Integrated Gasification Combined Cycle
IRS	Internal Revenue Service
ISO	Independent Transmission System Operator
IURC	Indiana Utility Regulatory Commission
KPSC	Kentucky Public Service Commission
LIBOR	London Interbank Offered Rate
LS Power	LS Power Equity Partners
MACT	Maximum achievable control technology
MBSSO	Market-Based Standard Service Offer
Mcf	Thousand cubic feet
MMBtu	Million British Thermal
Moody’s	Moody’s Investor Services
Modernization Act	Medicare Prescription Drug Improvement and Modernization Act
MRO	Market Rate Option
MSREF	Morgan Stanley Real Estate Fund V U.S., L.P.
MTBE	Methyl tertiary butyl ether
MW	Megawatt
NCUC	North Carolina Utilities Commission
NDTF	Nuclear Decommissioning Trust Funds

6

PART I

Term or Acronym	Definition
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Council
NMC	National Methanol Company
NOx	Nitrogen oxide
NRC	Nuclear Regulatory Commission
OCC	Office of the Ohio Consumers’ Counsel
OIL	Oil Insurance Limited
ORS	South Carolina Office of Regulatory Staff
OUCC	Indiana Office of Utility Consumer Counselor
PEMEX	Mexican National Oil Company
PSCSC	Public Service Commission of South Carolina
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935, as amended
PV	Photovoltaic
RSP	Rate Stabilization Plan
RTO	Regional Transmission Organization
SAB	Securities and Exchange Commission Staff Accounting Bulletin
SB 221	Ohio Senate Bill 221
sEnergy	sEnergy Insurance Limited
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SO2	Sulfur dioxide
SPE	Special Purpose Entity
Spectra Energy	Spectra Energy Corp.
Spectra Capital	Spectra Energy Capital, LLC (formerly Duke Capital LLC)
SRT	System Reliability Tracker
S&P	Standard & Poor’s
Synfuel	Synthetic Fuel
TEPPCO GP	Texas Eastern Products Pipeline Company, LLC
TEPPCO LP	TEPPCO Partners, L.P.
UBE	United Bridgeport Energy LLC
VIE	Variable Interest Entity
WARN	North Carolina Waste Awareness Reduction Network
Westcoast	Westcoast Energy, 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.”)

7

PART I

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, 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 48,000 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 150,900 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 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 the largest contributor 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, food, electronics and motor vehicle manufacturing industries were the most significant contributors to the area’s manufacturing output. In contrast, the majority of Duke Energy Carolinas’ industrial and commercial electric sales revenue for 2008 came from the textiles industry, which continues to decline, real estate and education services sectors.

Duke Energy Carolinas has business development strategies to leverage the competitive advantages of its service territory to attract and expand advanced manufacturing and data intensive businesses. These competitive advantages, including a quality workforce, strong educational institutions, superior transportation infrastructure and competitive electric rates approximately 30% below the national average were key factors in attracting new businesses. The success in attracting new companies, as well as expanding the operations of existing customers, partially offset the sales declines in the industries like apparel, textile and furniture in 2008.

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 2008. 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.

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

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.

Duke Energy Indiana has business development strategies to leverage the competitive advantages of the Indiana region to attract new advanced manufacturing, logistics, life sciences and data center business to Duke Energy Indiana’s service territory. These advantages, including competitive electric rates, a strong transportation network, excellent institutions of higher learning, and a quality workforce, are key in attracting new customers and encouraging existing customer expansions. This ability to attract business investment in the service territory helped balance the decline in sales in the stone, clay and glass, primary metals and other manufacturing and transportation equipment sector in 2008.

8

PART I

The number of residential and general service customers within the U.S. Franchised Electric and Gas’ service territory continues to increase. As a result, sales to these customers are increasing due to the growth in these sectors, although near-term growth is being hampered by the current economic conditions. As sales to residential and commercial customers are expected to increase over the coming years, the level of sales to industrial customers becomes a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales.

U.S. Franchised Electric and Gas’ costs and revenues are influenced by seasonal patterns. Peak sales 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.

9

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 net capacity of 5,173 MW (including Duke Energy’s approximate 19% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with a combined net capacity of 13,472 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 net capacity of 3,263 MW, fifteen combustion turbine (CT) stations burning natural gas, oil or other fuels with a combined net capacity of 5,245 MW and one combined cycle (CC) station burning natural gas with a net 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, summer reliability, growth, and price. U.S. Franchised Electric and Gas has interconnections and arrangements with its neighboring utilities to facilitate planning, emergency assistance, sale and purchase of capacity and energy, and reliability of power supply.

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 2008, approximately 99.0% of the total generated energy came from U.S Franchised Electric and Gas’ low-cost, efficient nuclear and coal units (66.9% coal and 32.1% 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.

10

PART I

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 significant 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.

William States Lee III Nuclear Station. On December 12, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC) 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 February 25, 2008, Duke Energy Carolinas received confirmation from the NRC that its COL application has been accepted and docketed for the next stage of review. On June 27, 2008, the Blue Ridge Environmental Defense League (BREDL) filed a petition to intervene in the COL proceeding before the NRC. On September 22, 2008, the Atomic Safety and Licensing Board issued a decision denying BREDL’s Petition to Intervene and Request for Hearing. BREDL did not appeal the decision. 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 Carolinas’ 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 pre-construction 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’ Lee 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 denied the environmental intervenor motions. The NRC review of the COL application is ongoing and the current schedule concludes the COL may be granted in early 2012.

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. The NCUC’s Order explained the basis for its decision to approve construction of one unit, with an approved cost estimate of $1.93 billion (including allowance for funds used during construction (AFUDC)), and included certain conditions including providing for updates on construction cost estimates. On February 29, 2008, Duke Energy Carolinas filed its updated cost estimate of $1.8 billion (excluding approximately $600 million 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. 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 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 were filed appealing the final air permit. Duke Energy has intervened in all four cases, which have been consolidated. A hearing is not expected before the end of 2009.

Dan River and Buck Steam Stations. 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, which has resulted in a modification of the construction schedule. Under the revised schedule, the Buck Project is

11

PART I

expected to be delayed for a period of up to one year and is currently anticipated to begin operation in simple cycle mode in summer 2011 and is expected to convert to combined cycle mode in summer 2012. The Dan River Project is expected to begin operation in combined cycle mode in 2012 as originally planned, but without a phased-in simple cycle commercial operation.

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 petition describes the applicants’ need for additional base load generating capacity and requests timely recovery of all construction and operating costs related to the proposed generating station, including financing costs, together with certain incentive ratemaking treatment. In April 2007, Duke Energy Indiana and Vectren filed a Front End Engineering and Design (FEED) Study Report which included an updated estimated cost for the IGCC project of approximately $2 billion (including approximately $120 million of AFUDC). In June 2007, Vectren decided not to proceed with the CPCN petition, and in August 2007, Vectren formally withdrew its participation in the IGCC plant. In June 2007, 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 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 November 2007, which approved the IGCC Project. 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 November 2007 CPCN Order. An evidentiary hearing was conducted on August 25, 2008. 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. On November 3, 2008, Duke Energy Indiana filed its second semi-annual IGCC rider and ongoing review proceeding with the IURC. Duke Energy Indiana was also required to file its plans for studying carbon storage related to the project within 60 days of the order. Under the CPCN order and statutory provisions, Duke Energy Indiana is entitled to recover the costs reasonably incurred in reliance on the CPCN Order. Duke Energy Indiana has begun construction on the Edwardsport IGCC plant and entered into a $200 million engineering, procurement and construction management agreement with Bechtel Power Corporation in December 2008 in connection with the construction of the plant.

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, 2008.

	Generation by Source (Percent)			Cost of Delivered Fuel per Net Kilowatt-hour Generated (Cents)
	2008	2007	2006(e)	2008	2007	2006(e)
Coal(a)	66.9	66.5	63.4	2.59	2.20	2.16
Nuclear(b)	32.1	31.2	35.1	0.44	0.38	0.42
Oil and gas(c)	0.7	1.1	0.6	13.47	9.32	12.67
All fuels (cost-based on weighted average)(a)(b)	99.7	98.8	99.1	1.97	1.71	1.61
Hydroelectric(d)	0.3	1.2	0.9
	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 through December 31, 2008.

(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.

(e) Includes legacy Cinergy regulated operations from the date of acquisition (April 3, 2006) and thereafter.

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 2009 to 2013. U.S. Franchised Electric and Gas expects to renew these contracts or enter into similar contracts with other

12

PART I

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 to fuel its projected 2009 operations and a significant portion of supply to fuel its projected 2010 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 2008, firm supply purchase commitment agreements provided approximately 90% of the natural gas supply, with the remaining gas purchased on the spot market. These firm supply agreements feature two levels of gas supply, specifically (1) baseload, which is a continuous supply to meet normal demand requirements, and (2) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.

U.S. Franchised Electric and Gas 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, 2008, Duke Energy Ohio and Duke Energy Kentucky, combined, had locked in pricing for approximately 24% of their winter 2008/2009 system load requirements.

U.S. Franchised Electric and Gas is 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 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

13

PART I

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 2016. 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.

In 1999, Duke Energy Carolinas entered into a contract with Shaw AREVA MOX Services (MOX Services; formerly Duke COGEMA Stone & Webster, LLC) to purchase mixed-oxide fuel for use in the McGuire and Catawba nuclear reactors. Under this contract, beginning in 2007, MOX Services would fabricate batches of mixed-oxide fuel from stockpiles of plutonium derived from surplus weapons at a facility under construction at the U.S. Department of Energy (DOE) Savannah River site in Aiken, South Carolina. Mixed oxide fuel is similar to conventional uranium fuel. Following review and approval by the NRC, four MOX fuel lead assemblies, fabricated in France, were irradiated for two fuel cycles (approximately three years) in Unit 1 of the Catawba Nuclear Station. In 2008, Duke Energy Carolinas and MOX Services engaged in discussions to renegotiate the terms of the contract prior to its expiration on December 1, 2008. The parties were unable to reach agreement and the contract automatically terminated on December 1, 2008. Duke Energy Carolinas has communicated to MOX Services that it continues to support the objectives of the surplus weapons disposition program and is interested in receiving a future proposal from MOX Services for the use of MOX fuel.

Energy Efficiency. In May 2007, Duke Energy Carolinas filed its Save-A-Watt energy efficiency plan with the NCUC seeking approval to implement new energy efficiency programs, a new regulatory recovery model and a rate rider. The plan recognizes energy efficiency as a reliable, valuable resource that is a “fifth fuel,” that should be part of the portfolio available to meet customers’ growing need for electricity along with coal, nuclear, natural gas, or renewable energy. The plan would compensate Duke Energy Carolinas for verified reductions in energy use and be available to all customer groups. The plan contains proposals for several different energy efficiency programs. Customers would pay for energy efficiency programs with an energy efficiency rider that would be included in their power bill and adjusted annually. The proposed energy efficiency rider would be based on 90% of the avoided capacity and energy cost of generation not needed as a result of the success of Duke Energy Carolinas’ energy efficiency efforts. The plan is consistent with Duke Energy Carolinas’ public commitment to invest 1% of its annual retail revenues from the sale of electricity in energy efficiency programs subject to the appropriate regulatory treatment of Duke Energy Carolinas’ energy efficiency investments. Piedmont Natural Gas Company and Public Service Company of North Carolina, Inc. raised certain concerns regarding the incentives offered to Duke Energy Carolinas’ customers under its proposed portfolio of energy efficiency programs. In June 2008, Duke Energy Carolinas filed settlement agreements resolving all issues with these parties. Duke Energy Carolinas has not reached settlement with any of the other intervenors. The evidentiary hearing occurred the week of July 28, 2008 and concluded on August 18, 2008. Duke Energy Carolinas was unable to reach a settlement with any party to the proceeding. On October 7, 2008 Duke Energy Carolinas filed its proposed order and legal brief with the NCUC. Duke Energy Carolinas is awaiting a decision from the NCUC.

On February 26, 2009, the NCUC issued an order approving the proposed energy efficiency programs as new programs eligible for incentives under North Carolina’s 2009 energy legislation. The NCUC requested additional information regarding the earnings potential under its proposed Save-A-Watt recovery mechanism before ruling on this issue; however, it authorized Duke Energy Carolinas to implement its proposed energy efficiency rider pending final resolution and subject to refund.

On February 25, 2009, the PSCSC issued a directive rejecting Duke Energy Carolinas’ Save-A-Watt energy efficiency plan, which was filed with the PSCSC on September 28, 2007.

On July 11, 2007, the PUCO approved Duke Energy Ohio’s Demand Side Management/ Energy Efficiency Program (DSM). The DSM programs were first proposed in 2006 and were endorsed by the Duke Energy Community Partnership, which is a collaborative group made up of representatives of organizations interested in energy conservation, efficiency and assistance to low-income customers. The program costs will be recouped through a cost recovery mechanism that will be adjusted annually to reflect the previous year’s activity. Duke Energy Ohio is permitted to recover lost revenues, program costs and shared savings (once the programs reach 65% of the targeted savings level) through the cost recovery mechanism based upon impact studies to be provided to the Staff of the PUCO. Duke Energy Ohio filed the Save-A-Watt Energy Efficiency Plan as part of its ESP filed with PUCO on July 31, 2008 (see “Commercial Power” section below). A Stipulation and Recommendation for consideration by the PUCO regarding Duke Energy Ohio’s ESP filing, including implementation of Save-A-Watt, was filed in October 2008. The ESP hearing occurred on November 10, 2008. On December 17, 2008,

14

PART I

the PUCO determined that certain non-residential customers may opt out of Duke Energy Ohio’s energy efficiency initiative. Applications for rehearing of this decision have been filed by environmental groups and a residential customer advocate group. On February 11, 2009 the PUCO issued an Entry denying the rehearing requests.

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. Similar to the plans in North Carolina and South Carolina, 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 avoided cost of generation not needed as a result of the success of Duke Energy Indiana’s energy efficiency programs. A number of parties have intervened in the proceeding. On May 29, 2008, Duke Energy and Vectren Energy Delivery of Indiana, Inc. filed a stipulation and settlement agreement in the proceeding. On August 1, 2008, Duke Energy Indiana reached a settlement agreement with the OUCC resolving all issues in the proceeding. The settlement agreement was filed with the IURC on August 15, 2008. On October 31, 2008, Duke Energy Indiana reached a settlement agreement with Nucor Corporation, Steel Dynamics, Inc. and the Kroger Company resolving all issues in the proceeding. The settlement agreement was filed with the IURC on November 3, 2008. On January 15, 2009, Duke Energy Indiana entered into a settlement that amended the October 31, 2008 settlement, adding two additional intervenors to the settlement – the Indiana Industrial Group and Wal-Mart Stores, Inc. Duke Energy Indiana has not reached a settlement with one intervenor in the proceeding, the Citizens Action Coalition of Indiana, Inc. An evidentiary hearing with the IURC is scheduled to occur in the first quarter of 2009.

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 and applied to reinstitute a low income Home Energy Assistance Program. The KPSC bifurcated the proposed Home Energy Assistance Program from the other energy efficiency programs. On May 14, 2008, the KPSC approved the energy efficiency programs. On September 25, 2008, the KPSC approved Duke Energy Kentucky’s Home Energy Assistance program, making it available for customers at or below 150% of the federal poverty level. 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 and Indiana.

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, the new energy legislation passed in North Carolina in 2007 establishes a renewable portfolio standard for electric utilities at 3% of output by 2012, rising gradually to 12.5% by 2021. 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 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 include an increasing percentage of renewables as part of its generation portfolio. The percentage, beginning in 2009 with 0.25% non-solar and 0.004% solar, increases to 12.5% non-solar and 0.5% solar by 2024. Of these percentages, 50% of the resources must come from within the state of Ohio. To address this legislation, Duke Energy Ohio initiated a comprehensive renewable Request for Proposals (RFP) 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 are focused on meeting the specific near term 2009 and 2010 requirements. Duke Energy Ohio is also working with regulators to seek clarifications on points of the SB 221 renewable guidelines. 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 Senate Bill 3 in North Carolina in 2007, Duke Energy Carolinas was required to include an increasing percentage of renewables as part of its generation portfolio. Senate Bill 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. 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 Senate Bill 3 renewable guidelines. Duke Energy Carolinas will continue its growing renewable efforts with bidders, suppliers and the community in the Carolinas to meet the increasing renewable obligations.

15

PART I

Duke Energy Indiana issued a comprehensive renewable RFP in October 2007. Due to the uncertainty in the financial markets, Duke Energy Indiana has extended its timeline for review of the proposals received from the October 2007 renewable RFP. Duke Energy Indiana will continue its renewable efforts with bidders, suppliers and the community in Indiana to stay involved in developing renewable energy efforts in the state of Indiana.

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, 2008, the inventory balance for U.S. Franchised Electric and Gas was approximately $914 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

Nuclear Insurance and Decommissioning

Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and the Catawba Nuclear Stations 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 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 projection liability, which is approximately $12.5 billion. See Note 18 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, 2008, 2007 and 2006, Duke Energy 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 $1,436 million as of December 31, 2008 and $1,929 million as of December 31, 2007.

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s proportionate ownership in Catawba Nuclear Station at the time, which was 12.5%. The other joint owners of Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. 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.

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. Duke Energy will file these site-specific nuclear decommissioning cost studies with the NCUC and the PSCSC later this year. In addition to the decommissioning cost studies, a new funding study is underway to determine the appropriateness of the annual amounts currently being contributed to the NDTF. The NCUC and the PSCSC will consider the results of the funding study, which could potentially increase the annual required contributions to the NDTF, in the latter part of 2009.

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 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 will continue to safely manage its used nuclear fuel until the DOE accepts it. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial used nuclear fuel by the required date. Damages claimed in the lawsuit were based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional used fuel storage capacity. On March 5, 2007, Duke Energy Carolinas and the U.S. Department of Justice (DOJ) reached a settlement resolving Duke Energy’s used nuclear fuel litigation against the DOE. The agreement provided for an initial payment to Duke Energy of approximately $56 million for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs.

16

PART I

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 18 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 Elec-

17

PART I

tric and Gas’ 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 Rate Case. In June 2007, Duke Energy Carolinas filed an application with the NCUC seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008. This application complied with a condition imposed by the NCUC in approving the Cinergy merger. On October 5, 2007, Duke Energy Carolinas filed an Agreement and Stipulation of Partial Settlement (Partial Settlement) among Duke Energy Carolinas, the North Carolina Public Staff, the North Carolina Attorney General’s Office, Carolina Utility Customers Association Inc., Carolina Industrial Group for Fair Utility Rates III and Wal-Mart Stores East LP, for consideration by the NCUC. The Partial Settlement, which includes Duke Energy Carolinas and all intervening parties to the rate case, reflected agreements on all but a few issues in these matters, including two significant issues. The two significant issues related to the treatment of ongoing merger cost savings resulting from the Cinergy merger and the proposed amortization of Duke Energy Carolinas’ development costs related to GridSouth Transco, LLC (GridSouth), a Regional Transmission Organization (RTO) planned by Duke Energy Carolinas and other utility companies as a result of previous FERC rulemakings, which was suspended in 2002 and discontinued in 2005 as a result of regulatory uncertainty. The Partial Settlement and the remaining disputed issues were presented to the NCUC for a ruling.

The Partial Settlement reflected an agreed to reduction in net revenues and pre-tax cash flows of approximately $210 million and corresponding rate reductions of 12.7% to the industrial class, 5.05%—7.34% to the general class and 3.85% to the residential class of customers with an effective date of January 1, 2008. Under the Partial Settlement, effective January 1, 2008, Duke Energy Carolinas discontinued the amortization of the environmental compliance costs pursuant to North Carolina clean air legislation discussed above and began capitalizing all environmental compliance costs above the cumulative amortization charge of $1.05 billion as of December 31, 2007. Over the past five years, the average annual clean air amortization was $210 million. The Partial Settlement was designed to enable Duke Energy Carolinas to earn a rate of return of 8.57% on a North Carolina retail jurisdictional rate base and an 11% return on the common equity component of the approved capital structure, which consists of 47% debt and 53% common equity. As part of the settlement, Duke Energy Carolinas agreed to alter the then existing bulk power marketing (BPM) profit sharing arrangement that included a provision to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Energy Carolinas’ generating units at market based rates. The Partial Settlement provided that Duke Energy Carolinas share 90% of the North Carolina retail allocation of the profits from BPM transactions beginning January 1, 2008.

The NCUC issued its Order Approving Stipulation and Deciding Non-Settled Issues (Order) on December 20, 2007. The NCUC approved the Partial Settlement in its entirety. The merger savings rider and GridSouth cost matters are discussed in detail below. For the remaining non-settled issues, the NCUC decided in Duke Energy Carolinas’ favor. With respect to the merger savings rider and GridSouth cost matters, the Order required that Duke Energy Carolinas’ test period operating costs reflect an annualized level of the merger cost savings actually experienced in the test period in keeping with traditional principles of ratemaking. The NCUC explained that because rates should be designed to recover a reasonable and prudent level of ongoing expenses, Duke Energy Carolinas’ annual cost of service and revenue requirement should reflect, as closely as possible, Duke Energy Carolinas’ actual costs. However, the NCUC recognized that its treatment of merger savings would not produce a fair result. Therefore, the NCUC preliminarily concluded that it would reconsider certain language in its 2006 merger order in order to allow it to authorize 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. Additionally, the NCUC concluded that approximately $30 million of costs incurred through June 2002 in connection with GridSouth and deferred by Duke Energy Carolinas, were reasonable and prudent and approved a ten-year amortization, retroactive to June 2002. As a result of the retroactive impact of the Order, Duke Energy Carolinas recorded an approximate $17 million charge to write-off a portion of the GridSouth costs in the fourth quarter of 2007. The NCUC did not allow Duke Energy Carolinas a return on the GridSouth investments. As a result of its decision on the non-settled issues, the NCUC ordered an additional reduction in annual revenues of approximately $54 million, offset by its preliminary authorization of a 12-month, $80 million increment rider, as discussed above. 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. On February 18, 2008, the NCUC issued an order confirming their preliminary conclusion regarding the merger savings rider and the $80 million increment rider. Duke Energy Carolinas implemented the rate rider effective January 1, 2008.

Duke Energy Ohio Electric Rate Filing. Prior to the passage of SB 221 in April 2008, as discussed below, electric generation supply service had been deregulated in Ohio. Accordingly, Duke Energy Ohio’s electric generation had been deregulated and Duke Energy Ohio was in a competitive retail electric service market in the state of Ohio. Under applicable legislation governing the deregulation of generation, Duke Energy Ohio implemented a RSP, including a market based standard service offer approved by the PUCO. The RSP, among other things, allowed Duke Energy Ohio to recover increased costs associated with environmental expenditures on its deregulated generating fleet, capacity reserves, and provided for a fuel and emission allowance cost recovery mechanism through 2008.

18

PART I

SB 221 was passed on April 23, 2008 and signed by the Governor of Ohio on May 1, 2008. The new law codifies the PUCO’s authority to approve an electric utility’s standard service offer through an ESP, which would allow for pricing structures similar to the current 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. If a MRO price is approved, the utility would blend in the RSP or ESP price with the MRO price over a six- to ten-year period, subject to the PUCO’s discretion. SB 221 provides for the PUCO to approve non-by-passable charges for new generation, including construction work-in-progress 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 the 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 mandates a reduction of 22% through annual energy savings by 2025. The utility’s earnings under the ESP is 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 asset to an Exempt Wholesale Generator (EWG) absent PUCO approval. Duke Energy Ohio filed an ESP on July 31, 2008, and a settlement with intervening parties was approved by the PUCO on December 17, 2008.

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.

On December 17, 2001 the IURC approved the transfer of functional control of the operation of the Duke Energy Indiana transmission system to the Midwest ISO, an RTO established in 1998. On June 1, 2005, the IURC authorized Duke Energy Indiana to transfer control area operations tasks and responsibilities and transfer dispatch and Day 2 energy markets tasks and responsibilities to the Midwest ISO. 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.

19

PART I

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

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’s 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’s 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 are operating under annual extensions of the current license until FERC issues a new license. Other hydroelectric facilities whose licenses expire between 2009 and 2016 are in various stages of relicensing. Duke Energy expects to receive new licenses for all hydroelectric facilities with the exception of the Dillsboro Project, for which Duke Energy has filed an application to surrender the license. Duke Energy expects to remove this project’s dam and powerhouse, as part of the multi-stakeholder licensing agreement.

U.S. Franchised Electric and Gas is subject to the jurisdiction of the 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 and the five Midwestern gas-fired non-regulated generation assets that were a portion of former DENA. 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. Most of the generation asset output in Ohio has been contracted through the RSP, which expired on December 31, 2008. Effective January 1, 2009, Commercial Power began operating under an ESP, which expires on December 31, 2011, and is described below.

20

PART I

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

21

PART I

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. In support of a strategy to increase its renewable energy portfolio, DEGS acquired the wind power development assets of Energy Investor Funds from Tierra Energy in May 2007 and, in September 2008, acquired Catamount Energy Corporation (Catamount) from Diamond Castle Partners. DEGS currently has approximately 370 net MW of wind energy in operation and over 5,000 MW of wind energy projects in the development pipeline.

The following map show the location of DEGS wind energy generation assets.

In October 2006, Duke Energy completed the sale of Commercial Power’s energy marketing and trading activities, which were acquired in the Cinergy merger. In December 2006, Duke Energy completed the sale of Caledonia Power 1, LLC, which is the project company that operated and managed the Caledonia peaking generation facility in Mississippi. Additionally, Duke Energy completed the sale of Commercial Power’s Brownsville, Tennessee peaking generation facility in April 2008.

Competition

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

Rates and Regulation. Duke Energy Ohio has been charging the RSP to non-residential customers since January 1, 2005 and to residential customers since January 1, 2006. The RSP charge has been updated in conjunction with the ESP, which is effective January 1, 2009, and consists of the following discrete charges:

• Annually Adjusted Component (AAC) Rider- This rider is intended to provide cost recovery primarily for 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

22

PART I

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 the provisions of SFAS No. 71 to any of its operations due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. As described further below, effective December 17, 2008, the PUCO approved Commercial Power’s ESP, which resulted in the reapplication of SFAS No. 71 to certain portions of Commercial Power’s operations as of that date.

From January 1, 2005 through December 31, 2008, Commercial Power had been operating under a RSP, which is 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, upon the expiration of the RSP, there would be a move to full competitive markets. Accordingly, Commercial Power did not apply the provisions of SFAS No. 71 to any of its generation operations prior to December 17, 2008. As discussed further in Item 1 – Business -U.S. Franchised Electric and Gas—Regulation, in April 2008, 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. The MRO 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 ESP became effective on January 1, 2009.

In connection with the approval of the ESP, Duke Energy Ohio reassessed the applicability of SFAS No. 71 to Commercial Power’s generation operations as SB 221 substantially increased the PUCO’s oversight authority over generation in the state of Ohio, including giving the PUCO complete approval of generation rates and the establishment of an earnings test to determine if a utility has earned significantly excessive earnings. Duke Energy Ohio determined that certain costs and related rates (riders) of Commercial Power’s operations related to generation serving native load meet the criteria established by SFAS No. 71 for regulatory accounting treatment as SB 221 and Duke Energy Ohio’s approved ESP solidified the automatic recovery of 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 foreseeable future.

Under the ESP, Commercial Power will bill for its native load generation via numerous riders. SB 221 and the ESP resulted in the approval of the automatic recovery of certain of these riders, which includes, but is not limited to, a FPP rider and certain portions of a cost of an ACC rider. Accordingly, Commercial Power began applying SFAS No. 71 to the corresponding RSP riders granting automatic 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 automatic cost 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 criteria of SFAS No. 71. 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. Duke Energy Ohio 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.

23

Despite certain portions of the Ohio native load operations not being subject to the accounting provisions of SFAS No. 71, all of Commercial Power’s Ohio native load operations’ rates are subject to approval by the PUCO, and thus these operations are referred to 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.)

INTERNATIONAL ENERGY

International Energy operates and manages power generation facilities and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through DEI and its activities target power generation in Latin America. Additionally, International Energy owns equity investments in: National Methanol Company (NMC), located in Saudi Arabia, which is a regional producer of methanol and methyl tertiary butyl ether (MTBE) and Attiki Gas Supply S.A. (Attiki), located in Athens, Greece, which is a natural gas distributor and was acquired in connection with the Cinergy merger.

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.

24

PART I

The following map shows the locations of International Energy’s facilities, including its interest 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 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 baseload 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 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.)

See Item 1A. Risk Factors for a description of certain of the risks associated with the operations of International Energy.

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, Duke Energy’s approximate 50% ownership interest in Crescent, DukeNet and related telecom businesses and Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned, captive insurance subsidiary. 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 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.

25

PART I

Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations.

On September 7, 2006, an indirect wholly-owned subsidiary of Duke Energy closed an agreement to create the Crescent JV with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.21 billion, net of transaction costs, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. A 2% interest in the Crescent JV was also issued by the joint venture to the President and Chief Executive Officer of Crescent, which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this 2% interest can be put back to the Crescent JV after three years, or possibly earlier upon the occurrence of certain events, at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes. Duke Energy’s investment in the Crescent JV has been accounted for as an equity method investment for periods after September 7, 2006. During 2008, Crescent recorded impairment charges on certain of its property holdings, of which Duke Energy recorded its proportionate share of $238 million. As a result of Duke Energy recording its proportionate share of Crescent’s impairment losses, the carrying value of Duke Energy’s investment in Crescent has been reduced to zero at December 31, 2008. Beginning in the fourth quarter of 2008, in accordance with Accounting Principles Board (APB) Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB 18), Duke Energy suspended applying the equity method of accounting to its investment in Crescent since its investment has been reduced to zero. Accordingly, Duke Energy will not record additional losses related to its investment in Crescent. However, should Crescent begin reporting net income in future periods, Duke Energy may resume applying the equity method of accounting after its proportionate share of that net income equals the share of net losses not recognized during the period the equity method was suspended. Duke Energy continues to exercise significant influence over the operations and financial policies of Crescent.

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

Competition and Regulation

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

ENVIRONMENTAL MATTERS

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

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

• 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.

26

PART I

• 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 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.

(For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Notes 4 and 18 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 18 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our various business 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 and Hedging Activities, Credit Risk, and Financial Instruments,” respectively.

EMPLOYEES

On December 31, 2008, Duke Energy had approximately 18,250 employees. A total of approximately 4,260 operating and maintenance employees were represented by unions.

EXECUTIVE OFFICERS OF DUKE ENERGY

STEPHEN G. DE MAY, 46, Senior Vice President, Treasurer and Chief Risk officer. Mr. De May assumed his current position in November 2007. 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, 49, Group Executive and President, Commercial Businesses. Ms. Good assumed her current position in November 2007. 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.

DAVID L. HAUSER, 57, Group Executive and Chief Financial Officer. Mr. Hauser assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Hauser served as Group Vice President and Chief Financial Officer of Duke Energy since March 2004 and as Acting Chief Financial Officer of Duke Energy from December 2003 to March 2004.

DHIAA M. JAMIL, 52, Group Executive and Chief Nuclear Officer. Mr. Jamil assumed his current position in February 2008. Prior to that he served as Senior Vice President, Nuclear Support, Duke Energy Carolinas, LLC since March 2007; and prior to that he served as Vice President, Catawba Nuclear Station, Duke Energy Carolinas, LLC since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Jamil served as Vice President Catawba Nuclear Station, Duke Power from March 2004 to April 2006, and prior to that he served as Nuclear Station Vice President, Duke Power of Duke Energy from September 2003 to March 2004. Prior to that he served as Vice President, McGuire Nuclear Station Duke Power from September 2002 to September 2003.

27

PART I

MARC E. MANLY, 56, 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, 61, Chairman, President and Chief Executive Officer. Mr. Rogers assumed the role of Chief Executive Officer and President in April 2006, upon the merger of Duke Energy and Cinergy and assumed the role of Chairman on January 2, 2007. Until the merger of Duke Energy and Cinergy, Mr. Rogers served as Chairman of the Board of Cinergy since 2000 and as Chief Executive Officer of Cinergy since 1995.

CHRISTOPHER C. ROLFE, 57, Group Executive and Chief Administrative Officer. Mr. Rolfe assumed his current position in November 2006. Prior to that, he served as Group Executive and Chief Human Resources Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Rolfe served as Vice President, Human Resources of Duke Energy since January 2005. Prior to that, Mr. Rolfe served as Senior Vice President, Strategy, Planning & Human Resources of Duke Energy from March 2003 to January 2005.

B. KEITH TRENT, 49, Group Executive and Chief Strategy, Policy and Regulatory Officer. Mr. Trent assumed his current position in 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, 49, 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 and Executive Vice President and Chief Executive Officer, Regulated Business Unit of Cinergy from 2001 to 2004.

STEVEN K. YOUNG, 50, 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.

28

PART I

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 such costs in an untimely manner, which could materially impact Duke Energy’s results of operations, cash flows or financial position.

During the five-year period from 2009 to 2013, Duke Energy anticipates cumulative capital expenditures of approximately $25 billion. 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 these costs in a timely manner could materially impact Duke Energy’s consolidated financial position, results of operations or cash flows.

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

Duke Energy depends on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity Duke Energy sells to the wholesale market. FERC’s power transmission regulations 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 and trading 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 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.

29

PART I

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.

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

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

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

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

30

PART I

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.

Current Levels of Market Volatility are Unprecedented

The capital and credit markets have been experiencing extreme volatility and disruption. In recent months, the volatility and disruption have reached unprecedented levels. In some cases, the markets have exerted downward pressure on stock prices and credit availability for certain companies. A portion of Duke Energy’s borrowings have been issued in the commercial paper markets and, although Duke Energy has continued to issue commercial paper, there can be no assurance that such markets will continue to be a reliable source of short-term financing for Duke Energy. If current levels of market disruption and volatility continue or worsen, Duke Energy may be forced to repay commercial paper as it becomes due or to meet its other liquidity needs by further drawing upon contractually committed lending agreements primarily provided by global banks, although there is no assurance that the commitments made by lenders under Duke Energy’s master credit facility will be available if needed due to the recent turmoil throughout the financial services industry. This could require Duke Energy to seek other funding sources. However, under such extreme market conditions, there can be no assurance other funding sources would be available or sufficient.

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

Duke Energy’s primary foreign currency rate exposure is to the Brazilian Real. A 10% devaluation in the currency exchange rate in all of Duke Energy’s exposure currencies would result in an estimated net after-tax loss on the translation of local currency earnings of approximately $10 million in 2009. The consolidated balance sheets would be negatively impacted by such devaluation by approximately $120 million through cumulative currency translation adjustments.

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

31

PART I

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, 2008, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $1,308 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 clean up costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets. The steps Duke Energy takes to ensure that its facilities are in compliance could be prohibitively expensive. As a result, Duke Energy may be required to shut down or alter the operation of its facilities, which may cause Duke Energy to incur losses. Further, Duke Energy’s regulatory rate structure and Duke Energy’s contracts with customers may not necessarily allow Duke Energy to recover capital costs Duke Energy incurs to comply with new environmental regulations. Also, Duke Energy may not be able to obtain or maintain from time to time all required environmental regulatory approvals for Duke Energy’s operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if Duke Energy fails to obtain and comply with them or if environmental laws or regulations change and become more stringent, then the operation of Duke Energy’s facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on Duke Energy’s financial position, results of operations or cash flows, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

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

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

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect Duke Energy’s financial 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

32

PART I

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 sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond Duke Energy’s control.

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

• general economic conditions, including downturns in the U.S. or other economies which impact energy consumption particularly in which sales to industrial or large commercial customers comprise a significant portion of total sales;

• 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;

33

PART I

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

• natural disasters, acts of terrorism, wars, embargoes and other catastrophic events to the extent they affect Duke Energy’s operations and markets, as well as the cost and availability of insurance covering such risks; and

• federal, state and foreign energy and environmental regulation and legislation.

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

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

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

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

Duke Energy is subject to regulation by FERC and the NRC, by federal, state and local authorities under environmental laws and by state public utility commissions under laws regulating Duke Energy’s businesses. Regulation affects almost every aspect of Duke Energy’s businesses, including, among other things, Duke Energy’s ability to: take fundamental business management actions; determine the terms and rates of Duke Energy’s transmission and distribution businesses’ services; make acquisitions; issue equity or debt securities; engage in transactions between Duke Energy’s utilities and other subsidiaries and affiliates; and 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 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. 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.

34

PART I

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

U.S. FRANCHISED ELECTRIC AND GAS

As of December 31, 2008, U.S. Franchised Electric and Gas operated three nuclear generating stations with a combined net capacity of 5,173 MW (including an approximate 19% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with a combined net capacity of 13,472 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 net capacity of 3,263 MW, fifteen CT stations with a combined net capacity of 5,245 MW and one CC station with a net 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	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	1,145	1,145	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
Riverbend CT	120	120	Natural gas/Fuel oil	NC	100
Buck CT	93	93	Natural gas/Fuel oil	NC	100
Dan River CT	85	85	Natural gas/Fuel oil	NC	100
Lee CT	84	84	Natural gas/Fuel oil	SC	100
Other small hydro (26 plants)	651	651	Hydro	NC/SC	100
Midwest:
Gibson(A)	3,132	2,822	Coal	IN	90
Cayuga(B)	1,005	1,005	Coal/Fuel oil	IN	100
Wabash River(C)	676	676	Coal/Fuel oil	IN	100
East Bend	600	414	Coal	KY	69
Madison CT	596	596	Natural gas	OH	100
Gallagher	560	560	Coal	IN	100
Woodsdale CT	501	501	Natural gas/Propane	OH	100
Wheatland CT	460	460	Natural gas	IN	100
Noblesville CC	285	285	Natural gas	IN	100
Miami Fort (Unit 6)	163	163	Coal/Fuel oil	OH	100
Edwardsport	160	160	Coal/Fuel oil	IN	100
Henry County CT	135	135	Natural gas	IN	100
Cayuga CT	106	106	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	29,757	27,438

(A) Duke Energy Indiana owns and operates Gibson Station Units 1-4 and owns 50.05% of Unit 5, but is the operator

(B) Includes Cayuga Internal Combustion (IC)

(C) Includes Wabash River IC

35

PART I

In addition, as of December 31, 2008, U.S. Franchised Electric and Gas owned approximately 20,900 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 1,800 miles of 345 kilovolts, 3,300 miles of 230 kilovolts, 8,800 miles of 100 to 161 kilovolts, and 6,400 miles of 13 to 69 kilovolts. U.S. Franchised Electric and Gas also owned approximately 150,900 conductor miles of electric distribution lines, including 103,300 miles of overhead lines and 47,600 miles of underground lines, as of December 31, 2008 and approximately 7,200 miles of gas mains and service lines. As of December 31, 2008, 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 and Refunding Mortgage Bonds.

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

COMMERCIAL POWER

The following table provides information about Commercial Power’s generation portfolio as of December 31, 2008. 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	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)(A)	1,000	640	Steam	Coal	OH	64
W.C. Beckjord(A)	1,124	862	Steam	Coal	OH	76.7
W.M. Zimmer(A)	1,300	605	Steam	Coal	OH	46.5
J.M. Stuart(A)	2,340	912	Steam	Coal	OH	39
Killen(A)	600	198	Steam	Coal	OH	33
Conesville(A)	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
Total Renewable Energy	88	88
Total	11,416	7,641

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

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

36

PART I

INTERNATIONAL ENERGY

The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2008.

Name	Total MW Capacity	Owned MW Capacity	Fuel	Location	Approximate Ownership Interest (percentage)
Paranapanema	2,307	2,112	Hydro	Brazil	95	%
Cerros Colorados	576	523	Hydro/Natural Gas	Argentina	91
Egenor	510	510	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	135	Natural Gas	Peru	76
Total	4,373	4,018

International Energy also owns a 25% equity interest in NMC. In 2008, 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 that has an exclusive 30 year license to supply natural gas to residential and commercial customers within the geographical area of Athens, Greece. (For additional information and a map showing International Energy’s properties, see “Business—International Energy” earlier in this section.)

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 18 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.

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 2008.

37

PART II

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 23, 2009, there were approximately 165,931 common stockholders of record.

Common Stock Data by Quarter

	2008						2007
			Stock Price Range(a)						Stock Price Range(a)
	Dividends Per Share		High		Low		Dividends Per Share		High		Low
First Quarter	$	0.22	$	20.60	$	17.00	$	0.21	$	20.62	$	18.40
Second Quarter(b)		0.45		19.20		17.02		0.43		21.30		18.06
Third Quarter		—		19.10		16.77		—		19.90		16.91
Fourth Quarter(b)		0.23		17.99		13.50		0.22		20.78		18.25

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

(b) Dividends paid in September 2008 and December 2008 increased from $0.22 per share to $0.23 per share and dividends paid in September 2007 and December 2007 increased from $0.21 per share to $0.22 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 2008

There were no repurchases of equity securities during the fourth quarter of 2008.

38

PART II

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 2004 through 2008.

This performance chart assumes $100 invested on December 31, 2003 in Duke Energy common stock, in the S&P 500 Stock Index and in the Philadelphia Utility Index and that all dividends are reinvested.

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, 2008. In May 2008, 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.

39

PART II

Item 6. Selected Financial Data.^(a)

	2008			2007			2006		2005			2004
	(in millions, except per-share amounts)
Statement of Operations
Total operating revenues	$	13,207		$	12,720		$	10,607	$	6,906		$	6,357
Total operating expenses		10,765			10,222			9,210		5,586			5,074
Gains on sales of investments in commercial and multi-family real estate		—			—			201		191			192
Gains (losses) on sales of other assets and other, net		69			(5	)		223		(55	)		(435	)
Operating income		2,511			2,493			1,821		1,456			1,040
Total other income and expenses		121			428			354		217			180
Interest expense		741			685			632		381			425
Minority interest (benefit) expense		(4	)		2			13		24			(15	)
Income from continuing operations before income taxes		1,895			2,234			1,530		1,268			810
Income tax expense from continuing operations		616			712			450		375			192
Income from continuing operations		1,279			1,522			1,080		893			618
Income (loss) from discontinued operations, net of tax		16			(22	)		783		935			872
Income before cumulative effect of change in accounting principle and extraordinary items		1,295			1,500			1,863		1,828			1,490
Cumulative effect of change in accounting principle, net of tax and minority interest		—			—			—		(4	)		—
Extraordinary items, net of tax		67			—			—		—			—
Net income		1,362			1,500			1,863		1,824			1,490
Dividends and premiums on redemption of preferred and preference stock		—			—			—		12			9
Earnings available for common stockholders	$	1,362		$	1,500		$	1,863	$	1,812		$	1,481
Ratio of Earnings to Fixed Charges		3.4			3.7			2.6		2.4			1.6
Common Stock Data
Shares of common stock outstanding(b)
Year-end		1,272			1,262			1,257		928			957
Weighted average—basic		1,265			1,260			1,170		934			931
Weighted average—diluted		1,268			1,266			1,188		970			966
Earnings per share (from continuing operations)
Basic	$	1.01		$	1.21		$	0.92	$	0.94		$	0.65
Diluted		1.01			1.20			0.91		0.92			0.64
Earnings (loss) per share (from discontinued operations)
Basic	$	0.02		$	(0.02	)	$	0.67	$	1.00		$	0.94
Diluted		0.01			(0.02	)		0.66		0.96			0.90
Earnings per share (before cumulative effect of change in accounting principle and extraordinary items)
Basic	$	1.03		$	1.19		$	1.59	$	1.94		$	1.59
Diluted		1.02			1.18			1.57		1.88			1.54
Earnings per share (from extraordinary items)
Basic	$	0.05		$	—		$	—	$	—		$	—
Diluted		0.05			—			—		—			—
Earnings per share
Basic	$	1.08		$	1.19		$	1.59	$	1.94		$	1.59
Diluted		1.07			1.18			1.57		1.88			1.54
Dividends per share(c)		0.90			0.86			1.26		1.17			1.10
Balance Sheet
Total assets	$	53,077		$	49,686		$	68,700	$	54,723		$	55,770
Long-term debt including capital leases, less current maturities	$	13,250		$	9,498		$	18,118	$	14,547		$	16,932

40

PART II

(a) Significant transactions reflected in the results above include: 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 (see Note 3 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets”), 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006 (see Note 3 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets”), 2005 DENA disposition, 2005 deconsolidation of DCP Midstream effective July 1, 2005, 2005 DEFS sale of TEPPCO and 2004 sale of the former DENA Southeast plants.

(b) 2006 increase primarily attributable to issuance of approximately 313 million shares in connection with Duke Energy’s merger with Cinergy (see Note 3 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets”).

(c) 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.

41

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, 2008, 2007 and 2006.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas business to shareholders, as discussed below. Accordingly, the results of operations of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DCP Midstream have been reclassified to discontinued operations for all periods presented. Additionally, in April 2006, Duke Energy consummated the merger with Cinergy.

EXECUTIVE OVERVIEW

2008 Financial Results. For the year-ended December 31, 2008, Duke Energy reported net income of $1,362 million and basic and diluted earnings per share (EPS) of $1.08 and $1.07, respectively, as compared to net income of $1,500 million and basic and diluted EPS of $1.19 and $1.18, respectively, for the year-ended December 31, 2007. Income from continuing operations was $1,279 million for 2008 as compared to $1,522 million for 2007. Total reportable segment EBIT (defined below in “Segment Results” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations) increased to $3,073 million in 2008 from $2,971 million in 2007.

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.

2008 Objectives. Planning for future capital expansion and the related regulatory cost recovery structures was a primary focus in 2008. Over the period 2009 through 2013, Duke Energy plans to spend approximately $25 billion on capital expenditures, with approximately $18 billion anticipated to support the U.S. Franchised Electric and Gas segment. During 2008 and early 2009, Duke Energy achieved important milestones with various state and federal regulators related to future capital projects. In the Carolinas, the North Carolina Department of Environment and Natural Resources (DENR) issued the final air permit for Cliffside Unit 6, the state of the art coal generation unit at Duke Energy Carolinas’ existing Cliffside Steam Station and Duke Energy Carolinas entered into an engineering, procurement, construction and commissioning services agreement with an affiliate of The Shaw Group, Inc. related to participation in the construction of Cliffside Unit 6, which has a current cost estimate of approximately $2.4 billion, which includes approximately $0.6 billion of allowance for funds used during construction (AFUDC). On October 14, 2008, Duke Energy Carolinas submitted revised hazardous air pollutant emissions determination documentation including revised emission source information to North Carolina Department 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 hazardous air pollutants. On October 24, 2008, Duke Energy Carolinas filed to amend its air permit to include emission limits to assure the public of the minor source status of Cliffside Unit 6. As of December 31, 2008, the Cliffside Unit 6 project was approximately 30% complete. Duke Energy Carolinas is also continuing to seek all necessary regulatory approvals for the proposed William States Lee III Nuclear Station, including December 2007 filings of a Combined Construction and Operating License (COL) application with the Nuclear Regulatory Commission (NRC), which was approved in February 2008, 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 Indiana, the Indiana Utility Regulatory Commission (IURC) issued an order in November 2007 granting Duke Energy Indiana a Certificate of Public Convenience and Necessity (CPCN) for the proposed 630 megawatt (MW) Integrated Gasification Combined Cycle (IGCC) power plant at the Edwardsport Generating Station, and construction is underway. The order also approved the timely recovery of costs related to the project. On January 7, 2009, the IURC approved Duke Energy Indiana’s first semi-annual IGCC Rider including a new cost estimate for the IGCC Project of $2.35 billion (including approximately $125 million of AFUDC) and cost recovery associated with a study on carbon capture. Duke Energy Indiana has begun construction on the Edwardsport IGCC plant and entered into a $200 million engineering, procurement and construction management agreement with Bechtel Power Corporation in December 2008 in connection with the construction of the plant.

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.

New legislation (SB 221) was passed on April 23, 2008 and signed by the Governor of Ohio on May 1, 2008. The new law codifies the Public Utility Commission of Ohio’s (PUCO) authority to approve an electric utility’s standard service offer through an electric security plan (ESP), which would allow for pricing structures similar to the current rate stabilization plan (RSP) in Ohio. On July 31, 2008, Duke

42

PART II

Energy Ohio filed a new generation pricing formula to be effective January 1, 2009, when the RSP is scheduled to expire. Among other things, the plan provides pricing mechanisms for compensation related to the advanced energy, renewables and energy efficiency portfolio standards established by SB 221. On October 27, 2008 Duke Energy Ohio filed a Stipulation which results in a residential net rate increase of 2% in 2009 and in 2010, and a non-residential rate increase of 2% in 2009, 2010 and 2011. The Stipulation also allows the recovery of expenditures incurred to deploy SmartGrid infrastructure modernization technology on the distribution system. The recovery of such expenditures, net of savings, is subject to an annual residential revenue cap. Further, the Stipulation allows for the implementation of a new energy efficiency compensation model, referred to as Save-A-Watt, to achieve the energy efficiency mandate pursuant to the recent electric energy legislation. On December 17, 2008, the PUCO issued its finding and order, which adopted a modified Stipulation approving Duke Energy Ohio’s ESP. Specifically, 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. Applications for rehearing of the PUCO’s decision have been filed by environmental groups and a residential customer advocate group.

Prior to December 17, 2008, Commercial Power did not apply the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. The approval of the ESP and SB 221 substantially increased the PUCO’s oversight authority over generation in the state of Ohio, including giving the PUCO complete approval of generation rates and the establishment of an earnings test to determine if a utility has earned significantly excessive earnings. Duke Energy Ohio determined that certain costs and related rates (riders) of Commercial Power’s operations related to generation serving native load meet the criteria established by SFAS No. 71 for regulatory accounting treatment. As a result of the reapplication of SFAS No. 71 to certain portions of Commercial Power’s operations, Commercial Power’s future results will be subject to less volatility that had been caused by the timing of under-and-over collections of certain costs, as well as the impacts of mark-to-market activity on certain coal and power derivatives.

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 replacement program and permitted recovery of carrying costs on gas stored underground via its monthly gas cost adjustment filing. Certain rate design issues, which were unresolved at the time of the settlement, are currently under appeal at the Ohio Supreme Court.

On June 25, 2008, Duke Energy Ohio filed notice with the PUCO that it will seek a rate increase for electric delivery service of approximately $86 million, or 4.8% on total electric revenues, to be effective in the second quarter of 2009. Management expects the rate case to be resolved by mid-2009. In addition, Duke Energy intends to file for electric rate increases in North Carolina and South Carolina in 2009, with rates becoming effective in 2010.

Global climate change was another primary focus of management during 2008. Duke Energy’s strategy for meeting customer demand while building a sustainable business that allows our customers and our 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. In order to expand its wind energy operations, Commercial Power, through Duke Energy Generation Services (DEGS), acquired the wind power development assets of Energy Investor Funds from Tierra Energy in May 2007 and, in September 2008, acquired Catamount Energy Corporation (Catamount) from Diamond Castle Partners. DEGS currently has approximately 370 net MW of wind energy in operation and well over 5,000 MW of wind energy projects in the development pipeline. On June 6, 2008, Duke Energy Carolinas filed an application with the NCUC for approval of a Solar Photovoltaic (PV) Distributed Generation Program. The application seeks authorization to invest approximately $100 million to install approximately 850 solar PV facilities on customer rooftops and other customer and company owned property over a two-year period, resulting in a total generating capacity of 20 MW. On October 20, 2008, Duke Energy Carolinas filed rebuttal testimony, agreeing to reduce the size of the program to an investment of approximately $50 million to install a total generating capacity of 10 MW to address concerns raised by other parties to the proceeding. On December 31, 2008, the NCUC issued its Order Granting the CPCN subject to certain conditions.

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 2007, new energy efficiency plans were filed in North Carolina, South Carolina and Indiana and energy efficiency programs were expanded in both Kentucky and Ohio. The energy efficiency plans filed in North Carolina,

43

PART II

South Carolina and Indiana are Save-A-Watt programs that would compensate Duke Energy for verified reductions in energy use and be available to all customer groups. In North Carolina, the NCUC ruled on February 26, 2009 to approve the proposed energy efficiency plan but did not approve cost recovery as the NCUC requested additional information regarding the earnings potential under the proposed Save-A-Watt recovery mechanism. In South Carolina the PSCSC issued a directive rejecting Duke Energy Carolinas’ Save-A-Watt energy efficiency plan on February 25, 2009. In Indiana, a settlement agreement was filed with the IURC between Duke Energy Indiana and several intervenors and an evidentiary hearing is expected to occur in the first quarter of 2009. 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 and Indiana. The ESP approved by the PUCO, as discussed above, includes certain stipulations for Duke Energy Ohio’s energy efficiency programs.

Overall, the regulatory and legislative accomplishments during 2008 have positioned Duke Energy well for 2009 and beyond.

Duke Energy Objectives – 2009 and beyond. Management of Duke Energy continues to focus on the following objectives:

• Pursue a balanced approach to meeting future energy needs by pursuing new supply options, including energy efficiency, coal gasification, advanced pulverized coal, nuclear, natural gas-fired generation and renewable energy, while considering whether they are available, affordable, reliable and clean;

• Pursue low-carbon and no-carbon solutions for meeting future energy needs in anticipation of a carbon-constrained world;

• Control costs, run the businesses efficiently and provide excellent customer service; and

• Meet 2009 financial objectives and, for the long-term, deliver on its promise to shareholders by steadily growing earnings and dividends.

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 28,000 megawatts 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. Commercial Power has net capacity of approximately 7,550 megawatts of regulated and unregulated generation, excluding wind assets, of which approximately 4,000 megawatts serves retail customers under the ESP in Ohio. Approximately 75% of International Energy’s net capacity of approximately 4,000 megawatts of installed generation capacity in Latin America consists of base load hydroelectric capacity that carries a low level of dispatch risk; in addition, for 2009 approximately 90% of International Energy’s contractible capacity in Latin America is either currently contracted or receives a system capacity payment.

As a result of the downturn in the economy, Duke Energy has experienced reductions in sales volumes, most notably with respect to industrial customers. Management anticipates that recessionary pressures will continue in 2009, 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 and achieving constructive regulatory outcomes to reduce regulatory lag.

As mentioned earlier, during the five-year period from 2009 to 2013, Duke Energy anticipates total capital expenditures of approximately $25 billion. Of this amount, approximately 30% is expected to be spent on committed projects, including base load power plants to meet long term growth in customer demand, ongoing environmental projects, and nuclear fuel. Approximately 50% 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 planned capital expenditures 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. Capital expenditures are currently estimated to be approximately $4.8 billion in 2009. These expenditures are principally related to expansion plans, maintenance costs, environmental spending related to Clean Air Act 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 new IGCC plant at Duke Energy Indiana’s Edwardsport Generating Station, a new 825 MW coal unit at Duke Energy Carolinas’ existing Cliffside facility in North Carolina 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. Costs related to environmental spending are expected to decrease over the five-year period as the upgrades to comply with the new environmental regulations are completed.

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

44

PART II

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. Duke Energy does not currently anticipate any additional capital investment related to its investment in the Crescent JV.

With the exception of equity issuances to fund the dividend reinvestment plan and other internal plans, Duke Energy does not currently anticipate funding capital expenditures with the issuance of common equity in the foreseeable future, but rather through the use of available cash and cash equivalents as well as the issuance of incremental debt. Further, at this time, Duke Energy does not believe the recent market developments significantly impact its ability to obtain financing and fully expects to have access to liquidity in the capital markets at reasonable rates and terms. 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, 2008, Duke Energy has available borrowing capacity of approximately $1.2 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 NCUC that the North Carolina allocable portion of development costs associated with the William States Lee III nuclear station will be recoverable through a future rate case proceeding as long as the costs are deemed prudent and reasonable. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state legislators or regulators.

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

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable regulated businesses like U.S. Franchised Electric and Gas and certain portions of Commercial Power’s operations, and the traditionally higher-growth businesses like the unregulated portion of Commercial Power’s operations and International Energy. As was the case throughout 2008, 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 2009 and beyond.

Declines in demand for electricity as a result of economic downturns would reduce overall electricity sales and lessen Duke Energy’s cash flows, especially as industrial customers reduce production and, thus, consumption of electricity. A 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 approval of 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 2009 goals can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in the United States 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. Changes to regulations are ongoing and Duke Energy cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

Duke Energy’s earnings are impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as 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.

45

PART II

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, if current levels of market disruption and volatility continue or worsen, 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 the turmoil throughout 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, 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.

Year Ended December 31, 2007 as Compared to December 31, 2006. Consolidated operating revenues for 2007 increased $2,113 million, compared to 2006. This change was driven primarily by the following:

• An approximate $1,642 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;

• An approximate $550 million increase at Commercial Power. See Operating Revenue discussion within “Segment Results” for Commercial Power below for further information; and

• An approximate $117 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 $194 million decrease at Other. See Operating Revenue discussion within “Segment Results” for Other below for further information.

Consolidated Operating Expenses

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.

46

PART II

Year Ended December 31, 2007 as Compared to December 31, 2006. Consolidated operating expenses for 2007 increased approximately $1,012 million, compared to 2006. This change was driven primarily by the following:

• An approximate $1,169 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; and

• An approximate $326 million increase at Commercial Power. See Operating Expense discussion within “Segment Results” for Commercial Power below for further information.

Partially offsetting these increases were:

• An approximate $400 million decrease in Other. See Operating Expense discussion within “Segment Results” for Other below for further information; and

• An approximate $62 million decrease at International Energy. See Operating Expense discussion within “Segment Results” for International Energy below for further information.

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

Consolidated gains on sales of investments in commercial and multi-family real estate were zero in both 2008 and 2007 as a result of the deconsolidation of Crescent in September 2006 and the subsequent accounting for Duke Energy’s investment in Crescent as an equity method investment. Gains amounted to approximately $201 million in 2006. The gain in 2006 was driven primarily by pre-tax gains from the sale of two office buildings at Potomac Yard in Washington, D.C. and a gain on a land sale at Lake Keowee in northwestern South Carolina.

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 $69 million in 2008, a loss of approximately $5 million for 2007 and a gain of approximately $223 million for 2006. The gain in 2008 relates primarily to Commercial Power’s sales of zero cost basis emission allowances, while the loss in 2007 relates primarily to Commercial Power’s sales of emission allowances acquired in connection with Duke Energy’s merger with Cinergy in April 2006 which were written up to fair value as part of purchase accounting. The gain in 2006 was due primarily to the pre-tax gains resulting from the sale of an effective 50% interest in Crescent, creating a joint venture between Duke Energy and MSREF (approximately $246 million), partially offset by Commercial Power’s losses on sales of emission allowances acquired in connection with Duke Energy’s merger with Cinergy in April 2006 which were written up to fair value as part of purchase accounting (approximately $29 million).

Consolidated Operating Income

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.

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated operating income increased approximately $672 million compared to 2006. Increased operating income was partially driven by an approximate $237 million favorable impact generated during the first quarter of 2007 related to legacy Cinergy operations (reflected in the results for U.S. Franchised Electric and Gas and Commercial Power) for which there was zero in the comparable period of the prior year since the Cinergy merger occurred effective April 2006, as well as factors 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, 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 National Methanol Company (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

47

PART II

in the equity component of 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.

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated other income and expenses increased $74 million, compared to 2006. This increase was primarily driven by an increase in equity earnings of $34 million due primarily to the deconsolidation of Crescent in September 2006 and the subsequent accounting for Crescent as an equity method investment and increased equity earnings from International Energy of approximately $22 million primarily related to its investment in National Methanol Company (NMC) primarily as a result of higher margins, approximately $34 million increase in interest income, largely as a result of increased earnings from higher average invested cash and short-term investment balances during 2007 as compared to 2006 (of which approximately $19 million of the increase relates to interest income of legacy Cinergy in the first quarter 2007 with no comparable amount in 2006), partially offset by lower interest income related to income taxes resulting primarily from favorable income tax settlements in 2006, a $17 million impairment charge at International Energy recorded during the second quarter of 2006, and convertible debt costs of approximately $21 million related to the spin-off of Spectra Energy.

Consolidated Interest Expense

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

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated interest expense increased $53 million, compared to 2006. This increase was due primarily to the debt assumed from the merger with Cinergy, higher interest on debt in Brazil and interest expense recorded on tax items primarily as a result of the adoption of FIN No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48), partially offset by debt reductions and financing activities and an increase in the debt component of AFUDC resulting from increased capital spending.

Consolidated Minority Interest (Benefit) Expense

Year Ended December 31, 2008 as Compared to December 31, 2007. Minority interest (benefit) expense was a benefit of approximately $4 million for 2008 as compared to an expense of approximately $2 million in 2007. This decrease was primarily due to losses at Duke Energy Trading and Marketing, LLC (DETM).

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated minority interest expense decreased $11 million, compared to 2006. This decrease was due primarily to lower earnings at Aguaytia in 2007 and the deconsolidation of Crescent.

Consolidated Income Tax Expense from Continuing Operations

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.

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated income tax expense from continuing operations increased approximately $262 million compared to 2006. The increase is primarily the result of higher pre-tax income in 2007 as compared to 2006. Additionally, the effective tax rate increased for the year ended December 31, 2007 (32%) compared to 2006 (29%), due primarily to prior year favorable tax settlements on research and development costs and nuclear decommissioning costs, and tax benefits related to the impairment of an investment in Bolivia, partially offset by an increase in the manufacturing deduction in 2007 and higher foreign taxes accrued in 2006.

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

Consolidated income (loss) from discontinued operations was income of $16 million for 2008, a loss of $22 million for 2007 and income of $783 million for 2006. 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.

48

PART II

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

The 2006 amount is primarily comprised of after-tax earnings of approximately $953 million related to the natural gas businesses that were spun off to shareholders on January 2, 2007, approximately $140 million of after-tax losses associated with certain contract terminations or sales at former DENA, and the recognition of approximately $17 million of after-tax losses associated with exiting the Cinergy commercial marketing and trading operations.

See Note 14 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” for additional information related to discontinued operations.

Extraordinary Item, net of tax

The reapplication of SFAS No. 71 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, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so 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,
	2008			2007			Variance 2008 vs. 2007			2006			Variance 2007 vs. 2006
	(in millions)
U.S. Franchised Electric and Gas	$	2,398		$	2,305		$	93		$	1,811		$	494
Commercial Power		264			278			(14	)		47			231
International Energy		411			388			23			163			225
Total reportable segment EBIT		3,073			2,971			102			2,021			950
Other(a)(b)		(568	)		(260	)		(308	)		(5	)		(255	)
Total reportable segment EBIT and other		2,505			2,711			(206	)		2,016			695
Interest expense		(741	)		(685	)		56			(632	)		(53	)
Interest income and other(c)		131			208			(77	)		146			62
Consolidated earnings from continuing operations before income taxes	$	1,895		$	2,234		$	(339	)	$	1,530		$	704

(a) Other includes the results of Crescent for all periods presented as, beginning in the fourth quarter of 2008, Crescent is no longer an operating segment of Duke Energy.

(b) In September 2006, Duke Energy completed a joint venture transaction of Crescent. As a result, Other segment data for 2006 includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.

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

49

PART II

Minority interest expense presented below includes only minority interest expense related to EBIT of Duke Energy’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures.

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

U.S. Franchised Electric and Gas

	Years Ended December 31,
	2008		2007		Variance 2008 vs. 2007			2006		Variance 2007 vs. 2006
	(in millions, except where noted)
Operating revenues	$	10,159	$	9,740	$	419		$	8,098	$	1,642
Operating expenses		7,889		7,488		401			6,319		1,169
Gains (losses) on sales of other assets and other, net		6		—		6			—		—
Operating income		2,276		2,252		24			1,779		473
Other income and expenses, net		122		53		69			32		21
EBIT	$	2,398	$	2,305	$	93		$	1,811	$	494
Duke Energy Carolinas’ GWh sales(a)		85,476		86,604		(1,128	)		82,652		3,952
Duke Energy Midwest GWh sales(a)(b)(c)		62,523		64,570		(2,047	)		46,069		18,501
Net proportional MW capacity in operation(d)		27,438		27,586		(148	)		27,590		(4	)

(a) Gigawatt-hours (GWh).

(b) Relates to operations of former Cinergy from the date of acquisition and thereafter.

(c) Duke Energy Ohio Inc. (Duke Energy Ohio), Duke Energy Indiana, Inc. (Duke Energy Indiana) and Duke Energy Kentucky, Inc. (Duke Energy Kentucky) collectively referred to as Duke Energy Midwest.

(d) Megawatt (MW).

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

Increase (decrease) over prior year	2008		2007		2006
Residential sales(a)	(0.5	)%	6.5	%	(1.2	)%
General service sales(a)	(0.5	)%	5.4	%	1.4	%
Industrial sales(a)	(5.5	)%	(2.3	)%	(3.8	)%
Wholesale sales	11.9	%	40.9	%	(38.7	)%
Total Duke Energy Carolinas’ sales(b)	(1.3	)%	4.8	%	(3.1	)%
Average number of customers	1.5	%	2.0	%	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

Increase (decrease) over prior year	2008		Nine Months Ended December 31, 2007
Residential sales(a)	(3.0	)%	6.7	%
General service sales(a)	(1.2	)%	6.3	%
Industrial sales(a)	(6.5	)%	(0.4	)%
Wholesale sales	1.5	%	7.7	%
Total Duke Energy Midwest sales(b)	(3.2	)%	4.5	%
Average number of customers	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.

50

PART II

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.

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/thousand cubic feet (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 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 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.

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

U.S. Franchised Electric and Gas continues to increase the 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 2008, particularly sales to the industrial and residential sector. These trends are expected to continue for some period into 2009, 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 2009, fueled by the expiration of certain import limitations related to foreign textile products.

51

PART II

The North Carolina rate order resulting from the 2007 rate review included a one-time increment rider of approximately $80 million related to merger savings, effective for retail sales in 2008. The expiration of this rider will have an unfavorable impact on 2009 revenue. Various regulatory activities will continue in 2009. Additionally, Duke Energy Carolinas will continue to consider pursuing legislative initiatives that would allow more real-time recovery of costs. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters” for information regarding various regulatory activities that could impact U.S. Franchised Electric and Gas in 2009, including the PUCO’s December 17, 2008 approval of Duke Energy Ohio’s ESP.

U.S. Franchised Electric and Gas evaluates the carrying amount of its recorded goodwill for impairment under the guidance of SFAS No. 142, “Goodwill and Intangible Assets”. For further information on key assumptions that impact U.S. Franchised Electric and Gas’ goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment. As of the date of the 2008 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, 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 U.S. Franchised Electric and Gas reporting units have been impaired. Should any such triggering events or circumstances occur in 2009 that would more likely than not reduce the fair value of a reporting unit below its carrying value, management would perform an interim impairment assessment of U.S. Franchised Electric and Gas’ goodwill and it is possible that goodwill impairment charges could be recorded as a result of these assessments. At December 31, 2008, the U.S. Franchised Electric and Gas segment had goodwill of approximately $3.5 billion.

Year Ended December 31, 2007 as Compared to December 31, 2006

Operating Revenues. The increase was driven primarily by:

• A $1,066 million increase in regulated revenues for the first quarter of 2007 due to the merger with Cinergy;

• A $212 million increase in fuel revenues, including emission allowances, driven by increased fuel rates for retail customers and increased GWh sales to retail customers;

• A $188 million increase in GWh sales to retail customers due to favorable weather conditions. For the Carolinas and Midwest, cooling degree days for 2007 were approximately 27% and 48% above normal, respectively, compared to close to normal in both regions during 2006;

• An $82 million increase in wholesale power revenues, net of sharing, due to increased sales volumes primarily due to additional long-term contracts;

• A $57 million increase in retail rates and rate riders primarily related to the new electric base rates implemented in the first quarter of 2007 for Duke Energy Kentucky and the recovery of environmental compliance costs from retail customers in Indiana; and

• A $40 million increase related to the sharing of anticipated merger savings through rate decrement riders with regulated customers, which was substantially completed prior to the third quarter of 2007.

Operating Expenses. The increase was driven primarily by:

• An $852 million increase in regulated operating expenses for the first quarter of 2007 due to the merger with Cinergy;

• A $137 million increase in operating and maintenance expense primarily due to higher wage and benefit costs, including increased short-term incentive costs, and maintenance costs at fossil and nuclear generating plants, partially offset by a one time $12 million donation in the second quarter 2006 ordered by the NCUC as a condition of the Cinergy merger;

• A $133 million increase in fuel expense (including purchased power) primarily due to increased retail demand resulting from favorable weather conditions. Generation fueled by coal and natural gas, as well as purchases to meet retail customer requirements, increased significantly during the year ended December 31, 2007 compared to the same period in the prior year. These increases were partially offset by a $21 million reimbursement for previously incurred fuel expenses resulting from a settlement between Duke Energy Carolinas and the U.S. Department of Justice resolving Duke Energy’s used nuclear fuel litigation against the Department of Energy (DOE). The settlement between the parties was finalized on March 6, 2007; and

• A $40 million increase in depreciation due primarily to additional capital spending in the Carolinas.

52

PART II

Partially offsetting these increases was:

• A $6 million net decrease in regulatory amortization expense primarily due to decreased amortization of compliance costs related to North Carolina clean air legislation during 2007 as compared to the prior year. Regulatory amortization expenses related to clean air were approximately $187 million for the year ended December 31, 2007 compared to approximately $225 million during the same period in 2006. This decrease was partially offset by the write-off of a portion of the investment in the GridSouth RTO (approximately $17 million) per a rate order from the NCUC and Ohio’s regulatory amortization related to the rate transition charge rider and new demand side management (DSM) rider.

Other Income and Expenses, net. The increase is primarily attributable to the equity component of AFUDC earned from additional capital spending for ongoing construction projects.

EBIT. The increase resulted primarily from the merger with Cinergy, favorable weather conditions, additional long-term wholesale contracts, increase in retail rates and rate riders and the substantial completion of the required rate reductions due to the merger with Cinergy. These increases were partially offset by increased operating and maintenance expenses and additional depreciation as rate base increased during 2007.

Commercial Power

	Years Ended December 31,
	2008		2007			Variance 2008 vs. 2007			2006			Variance 2007 vs. 2006
	(in millions, except where noted)
Operating revenues	$	1,826	$	1,881		$	(55	)	$	1,331		$	550
Operating expenses		1,645		1,618			27			1,292			326
Gains (losses) on sales of other assets and other, net		59		(7	)		66			(29	)		22
Operating income		240		256			(16	)		10			246
Other income and expenses, net		24		22			2			37			(15	)
EBIT	$	264	$	278		$	(14	)	$	47		$	231
Actual plant production, GWh(a)		20,199		23,702			(3,503	)		17,640			6,062
Net proportional megawatt capacity in operation		7,641		8,019			(378	)		8,100			(81	)

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

53

PART II

• 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 RSP valuation.

Matters Impacting Future Commercial Power Results

Commercial Power’s current strategy is focused on 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 prices and weather, as well as dependent upon completion of energy asset construction projects and tax credits on renewable energy production.

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 the provisions of SFAS No. 71 due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. As described further below, effective December 17, 2008, the PUCO approved Duke Energy Ohio’s ESP, which resulted in the reapplication of SFAS No. 71 to certain portions of Commercial Power’s operations as of that date.

From January 1, 2005 through December 31, 2008, Commercial Power had been operating under a RSP, which is 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, upon the expiration of the RSP, there would be a move to full competitive markets. Accordingly, Commercial Power did not apply the provisions of SFAS No. 71 to any of its generation operations prior to December 17, 2008. In connection with the approval of the ESP, Duke Energy Ohio reassessed the applicability of SFAS No. 71 to Commercial Power’s generation operations as SB 221 substantially increased the PUCO’s oversight authority over generation in the state of Ohio, including giving the PUCO complete approval of generation rates and the establishment of an earnings test to determine if a utility has earned significantly excessive earnings. Duke Energy Ohio determined that certain costs and related rates (riders) of Commercial Power’s operations related to generation serving native load meet the criteria established by SFAS No. 71 for regulatory accounting treatment as SB 221 and Duke Energy’s approved ESP solidified the automatic recovery of 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 foreseeable future.

Under the ESP, Commercial Power will bill for its native load generation via numerous riders. SB 221 and the ESP resulted in the approval of the automatic recovery of certain of these riders, which includes, but is not limited to, a fuel and purchased power (FPP) rider and portions of a cost of environmental compliance (AAC) rider. Accordingly, Commercial Power began applying SFAS No. 71 to the corresponding RSP riders granting automatic 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 automatic cost 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 criteria of SFAS No. 71. Moreover, generation remains a competitive market in Ohio and native load customers continue to have the ability to switch to alternative supplier 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. The level of switching to date has been insignificant. Duke Energy Ohio 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.

54

PART II

As a result of the reapplication of SFAS No. 71 to certain portions of Commercial Power’s operations, Commercial Power’s future results will be subject to less volatility that had been caused by the timing of under-and-over collections of certain costs, as well as the impacts of mark-to-market activity on certain coal and power derivatives.

Commercial Power evaluates the carrying amount of its recorded goodwill for impairment under the guidance of SFAS No. 142, “Goodwill and Intangible Assets”. For further information on key assumptions that impact Commercial Power’s goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment. As of the date of the 2008 annual impairment analysis, the fair value of Commercial Power’s reporting units exceeded their respective carrying value, thus no goodwill impairment charges were recorded. However, 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 Commercial Power’s reporting units have been impaired. Should any such triggering events or circumstances occur in 2009 that would more likely than not reduce the fair value of a reporting unit below its carrying value, management would perform an interim impairment assessment of Commercial Power’s goodwill and it is possible that goodwill impairment charges could be recorded as a result of these assessments. At December 31, 2008, the Commercial Power segment had goodwill of approximately $960 million.

Year Ended December 31, 2007 as compared to December 31, 2006

Operating Revenues. The increase was primarily driven by:

• A $387 million increase related to the non-regulated generation assets of former Cinergy, including the impacts of purchase accounting, which reflects the first quarter 2007 operating revenues for which there was zero in the comparable period in the prior year as a result of the merger in April 2006;

• A $185 million increase in retail electric revenues due to higher retail pricing principally related to the time of collections on fuel and purchased power (FPP) rider and increased retail demand resulting from favorable weather in 2007 compared to 2006; and

• A $134 million increase in revenues due to higher generation volumes and capacity revenues from the Midwest gas-fired assets resulting from favorable weather in 2007 compared to 2006.

Partially offsetting these increases were:

• A $111 million decrease in net mark-to-market revenues on non-qualifying power and capacity hedge contracts, consisting of mark-to-market losses of $52 million in 2007 compared to gains of $59 million in 2006; and

• A $35 million decrease in revenues from sales of fuel due to lower volumes in 2007 compared to 2006.

Operating Expenses. The increase was primarily driven by:

• A $327 million increase related to the non-regulated generation assets of former Cinergy, including the impacts of purchase accounting, which reflects the first quarter 2007 operating expenses for which there was zero in the comparable period in the prior year as a result of the merger with Cinergy in April 2006;

• A $116 million increase in fuel expenses for the Midwest gas-fired assets primarily due to increased generation volumes in 2007 compared to 2006; and

• A $36 million increase in operating expenses primarily due to increased plant maintenance in 2007.

Partially offsetting these increases were:

• A $114 million decrease in net mark-to-market expenses on non-qualifying fuel hedge contracts, consisting of mark-to-market gains of $65 million in 2007 compared to losses of $49 million in 2006; and

• A $30 million decrease in expenses associated with sales of fuel due to lower volumes in 2007 compared to 2006.

Gains (Losses) on Sales of Other Assets and Other, net. Decrease in 2007 compared to 2006 is attributable to lower losses on emission allowance sales in 2007 due to lower sales activity in 2007 compared to 2006.

Other Income and Expenses, net. The decrease is driven by lower equity earnings of unconsolidated affiliates.

EBIT. The improvement is primarily attributable to higher retail margins resulting largely from favorable timing of fuel and purchase power recoveries, increased retail demand as a result of favorable weather and improved results from the Midwest gas-fired assets as a result of higher generation volumes and increased capacity revenues. These favorable variances were partially offset by higher expenses from increased plant maintenance in 2007.

55

PART II

International Energy

	Years Ended December 31,
	2008		2007		Variance 2008 vs. 2007		2006			Variance 2007 vs. 2006
	(in millions, except where noted)
Operating revenues	$	1,185	$	1,060	$	125	$	943		$	117
Operating expenses		899		776		123		838			(62	)
Gains (losses) on sales of other assets and other, net		1		—		1		(1	)		1
Operating income		287		284		3		104			180
Other income and expenses, net		146		114		32		76			38
Minority interest expense		22		10		12		17			(7	)
EBIT	$	411	$	388	$	23	$	163		$	225
Sales, GWh		18,066		17,127		939		18,501			(1,374	)
Net proportional megawatt capacity in operation		4,018		3,968		50		3,922			46

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 methyl tertiary butyl ether (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.

Matters Impacting Future International Energy Results

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

56

PART II

The results of International Energy’s earnings from projects accounted for on the equity method are loosely correlated to the price of crude oil and other commodities. As a result of the decline in oil and other commodity prices, International Energy anticipates that earnings from equity projects, which contributed approximately $127 million of EBIT in 2008, will be lower in 2009 than in 2008.

International Energy evaluates the carrying amount of its recorded goodwill for impairment under the guidance of SFAS No. 142, “Goodwill and Intangible Assets”. For further information on key assumptions that impact International Energy’s goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment. As of the date of the 2008 annual impairment analysis, the fair value of International Energy’s reporting units exceeded their respective carrying value, thus no goodwill impairment charges were recorded. However, management is continuing to monitor the impact of recent market and economic events, including the impacts of foreign exchange rates in all jurisdictions, as well as the impacts of commodity prices, such as crude oil, on the results of NMC, to determine if it is more likely than not that the carrying value of International Energy’s reporting units have been impaired. Should any such triggering events or circumstances occur in 2009 that would more likely than not reduce the fair value of a reporting unit below its carrying value, management would perform an interim impairment assessment of International Energy’s goodwill and it is possible that goodwill impairment charges could be recorded as a result of these assessments. At December 31, 2008, the International Energy segment had goodwill of approximately $260 million.

Year Ended December 31, 2007 as Compared to December 31, 2006

Operating Revenues. The increase was driven primarily by:

• An $81 million increase in Brazil due to higher sales prices and favorable exchange rates;

• A $37 million increase in Guatemala due to higher prices and volumes as a result of increased thermal dispatch; and

• A $27 million increase in Peru due to higher spot prices as a result of transmission line congestion.

Partially offsetting these increases were:

• An $18 million decrease in Ecuador due to decreased sales as a result of lower thermal dispatch; and

• A $5 million decrease in Argentina due to lower sales volumes resulting from unfavorable hydrology, partially offset by higher average sales prices.

Operating Expenses. The decrease was driven primarily by:

• A $100 million decrease due to a prior year reserve established as a result of a settlement made in conjunction with the Citrus litigation;

• A $43 million decrease in Mexico due primarily to a $33 million impairment charge on the notes receivable from the Campeche equity investment in 2006; and

• An $11 million decrease in Ecuador due to lower fuel used as a result of lower generation.

Partially offsetting these decreases were:

• A $50 million increase in Brazil primarily due to higher exchange rates and higher regulatory and purchased power costs;

• A $37 million increase in Guatemala due to increased fuel used as a result of higher dispatch and higher maintenance costs as a result of unplanned outages; and

• An $8 million increase in Argentina due to higher maintenance costs.

Other Income and Expenses, net. The increase was driven primarily by a $26 million increase in equity earnings at NMC as a result of higher methanol and methyl tertiary butyl ether (MTBE) margins, as well as the absence of a $17 million impairment of the Campeche equity investment recorded in 2006.

EBIT. The increase in EBIT was primarily due to a prior year reserve established as a result of a settlement made in conjunction with the Citrus litigation, a prior year impairment of the Campeche equity investment and note receivable reserve, favorable prices in Peru due to transmission line congestion, favorable prices and net foreign exchange impacts offset by higher regulatory costs in Brazil and higher equity earnings at National Methanol, partially offset by higher maintenance costs and unfavorable hydrology in Argentina.

57

PART II

Other

	Years Ended December 31,
	2008			2007			Variance 2008 vs 2007			2006			Variance 2007 vs 2006
	(in millions)
Operating revenues	$	134		$	167		$	(33	)	$	361		$	(194	)
Operating expenses		429			467			(38	)		867			(400	)
Gains on sales of investments in commercial and multi-family real estate		—			—			—			201			(201	)
Gains (losses) on sales of other assets and other, net		3			2			1			254			(252	)
Operating income		(292	)		(298	)		6			(51	)		(247	)
Other income and expenses, net		(288	)		37			(325	)		42			(5	)
Minority interest expense (benefit)		(12	)		(1	)		(11	)		(4	)		3
EBIT	$	(568	)	$	(260	)	$	(308	)	$	(5	)	$	(255	)

Prior to the fourth quarter of 2008, Crescent was a reportable business segment of Duke Energy. Beginning in the fourth quarter of 2008, Crescent is no longer considered an operating segment of Duke Energy as Duke Energy’s chief operating decision maker no longer reviews Crescent’s operating results in order to make resource allocation decisions and evaluate its performance. Accordingly, the results of Crescent have been included in Other for all periods presented. As a result of Duke Energy recording its proportionate share of Crescent’s impairment losses, the carrying value of Duke Energy’s investment in Crescent has been reduced to zero at December 31, 2008. Beginning in the fourth quarter of 2008, in accordance with Accounting Principles Bulletin (APB) 18, “The Equity Method of Accounting for Investments in Common Stock,” Duke Energy suspended applying the equity method of accounting to its investment in Crescent since its investment has been reduced to zero. Accordingly, Duke Energy will not record additional losses related to its investment in Crescent. However, should Crescent begin reporting net income in future periods, Duke Energy may resume applying the equity method of accounting after its proportionate share of that net income equals the share of net losses not recognized during the period the equity method was suspended.

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.

58

PART II

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 to reduce the carrying value of investments in debt and equity securities, including certain investments in auction rate debt securities, to their estimated fair value. Duke Energy analyzes all investments in debt and equity securities to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment is other-than-temporary includes, but is not limited to, the length of time over which the market value has been lower than the cost basis of the investment, the percentage decline compared to the cost of the investment and management’s intent and ability to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value.

Duke Energy has guaranteed approximately $100 million of outstanding surety bonds and letters of credit related to projects at Crescent. This amount represents the face value of the guarantees; however, Crescent has already completed a substantial portion of its obligations under these guarantees. As of December 31, 2008, it is reasonably possible that Duke Energy could have exposure of approximately $40 million under these guarantees should Crescent fail to perform under its obligations associated with these projects, which would become more likely should Crescent declare bankruptcy in the near future. See Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions,” for a discussion of impairment losses recorded by Crescent during 2008 and Crescent’s significant debt obligations as of December 31, 2008.

Year Ended December 31, 2007 as Compared to December 31, 2006

Operating Revenues. The decrease was driven primarily by:

• A $221 million decrease due to the deconsolidation of Crescent effective September 7, 2006.

Partially offsetting this decrease was:

• A $15 million increase related to revenues earned for services performed for Spectra Energy, and

• A $14 million increase related to DETM, primarily driven by mark-to-market activity.

Operating Expenses. The decrease was driven primarily by:

• A $160 million decrease due to the deconsolidation of Crescent effective September 7, 2006;

• A $110 million decrease related to contract settlement negotiations. Duke Energy was party to an agreement with a third party service provider related to certain future purchases. The agreement contained certain damage payment provisions if qualifying purchases were not initiated by September 2008. In the fourth quarter of 2006, Duke Energy initiated early settlement discussions regarding this agreement and recorded a reserve of approximately $65 million. During the year ended December 31, 2007, Duke Energy paid the third party service provider approximately $20 million, which directly reduced Duke Energy’s future exposure under the agreement, and further reduced the reserve by $45 million based upon qualifying purchase commitments that fulfilled Duke Energy’s obligations under the agreement.

• A $74 million decrease in costs to achieve related to the Cinergy merger;

• A $50 million decrease at Bison due primarily to lower charges for mutual insurance exit obligations of approximately $76 million, partially offset by higher operating expenses of approximately $26 million;

• A $42 million decrease in governance and other corporate costs, including prior year shared services cost allocations to Spectra Energy not classified as discontinued operations; and

• A $22 million decrease in amortization costs related to Crescent capitalized interest.

Partially offsetting these decreases were:

• A $25 million increase due to a donation to the Duke Foundation, a non-profit organization funded by Duke Energy shareholders that makes charitable contributions to selected non-profits and government subdivisions; and

• A $12 million increase related to employee severance costs.

Gains on sales of investments in Commercial and Multi-family real estate. The decrease was due to the deconsolidation of Crescent effective September 7, 2006.

Gains (Losses) on Sales of Other Assets and Other, net. The decrease was driven primarily by a $246 million pre-tax gain resulting from the sale of and effective 50% interest in Crescent.

59

PART II

Other Income and Expenses, net. The decrease was driven primarily by convertible debt charges of approximately $21 million related to the spin-off of Spectra Energy, partially offset by a $9 million increase due to the deconsolidation of Crescent effective September 7, 2006 and an increase in investment returns related to executive life insurance of $8 million.

EBIT. The decrease was primarily driven by a gain on the sale of ownership interest in Crescent in the third quarter 2006 and lower results due to the downturn in the real estate market, an increase in captive insurance expenses, a donation to the Duke Foundation, convertible debt charges related to the spin-off of Spectra Energy and employee severance charges, partially offset by contract settlement negotiations, lower charges for mutual insurance exit obligations, the reduction of costs to achieve related to the Cinergy merger, lower governance and other corporate costs and a decrease in amortization costs related to Crescent capitalized interest.

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

Duke Energy accounts for certain of its regulated operations (primarily U.S. Franchised Electric and Gas and certain portions of Commercial Power) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. Generally Accepted Accounting Principles (GAAP) for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state 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, nuclear decommissioning costs and amortization of regulatory assets. Total regulatory assets were $4,077 million as of December 31, 2008 and $2,645 million as of December 31, 2007. Total regulatory liabilities were $2,678 as of December 31, 2008 and $2,674 million as of December 31, 2007. For further information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

In order to apply the accounting provisions of SFAS No. 71 and record regulatory assets and liabilities, the scope criteria in SFAS No. 71 must be met. Management makes significant judgments in determining whether the scope criteria of SFAS No. 71 are met for its operations, 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 set forth in SFAS No. 71 when such criteria had not been previously met, SFAS No. 71 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 of SFAS 71.

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

60

PART II

customers (native load), 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 are not accounted for under SFAS No. 71 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 reapplied the provisions of SFAS No. 71 to certain portions of its native load operations due to the passing of SB 221 and the approval of the ESP. However, other portions of Commercial Power’s native load operations continue to not meet the scope criteria of SFAS No. 71, 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 being subject to the accounting provisions of SFAS No. 71, all of Commercial Power’s Ohio native load operations’ rates are such 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.

No other operations within Commercial Power, and no operations within the International Energy business segment, meet the criteria for accounting under SFAS No. 71.

Substantially all of U.S. Franchised Electric and Gas’s operations meet the scope criteria in SFAS No. 71 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, 2008 and 2007, Duke Energy had goodwill balances of $4,720 million and $4,642 million, respectively. Duke Energy evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). The majority of Duke Energy’s goodwill at December 31, 2008 and 2007 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. The remainder relates to International Energy’s Latin American operations. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Duke Energy performs an annual goodwill impairment test and updates the test 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 amount. Duke Energy performs its annual impairment assessment as of August 31 each year. Duke Energy primarily uses a discounted cash flow analysis to determine the fair value of its reporting units. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts, as well as other factors, into its revenue and expense forecasts. Duke Energy did not record any impairment on its goodwill as a result of the 2008, 2007 or 2006 impairment tests required by SFAS No. 142.

One of the most significant assumptions that Duke Energy utilizes in determining the fair value of its reporting units 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. 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. In determining the appropriate WACC for each of Duke Energy’s reporting units, Duke Energy considered current and historical market data for risk free interest rates over a 10-year period and applied an appropriate equity risk premium for the equity component of the WACC, and utilized credit ratings and appropriate risk premiums for the debt component. Duke Energy also considered implied WACC’s for certain peer companies in determining the appropriate WACC rates to use. The discount rates used for calculating the fair values as of August 31, 2008 for each of Duke Energy’s domestic reporting units were commensurate with the risks associated with each reporting unit and ranged from 6.75% to 8%. For Duke Energy’s international operations, a base discount rate of 8% was used, with specific adders used for each separate jurisdiction in which International Energy operates to reflect the differing risk profiles of the jurisdictions. This resulted in discount rates for the August 31, 2008 goodwill impairment test for the international operations ranging from 8.6% to 12.2%.

Additionally, estimated future cash flows are based on Duke Energy’s internal business plan. 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

61

PART II

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.

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.

The impairment analysis as of August 31, 2008 did not indicate that the fair value of any of Duke Energy’s reporting units were less than its book value. 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, 2008. 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, 2008, management did not identify any indicators of potential impairment that required an update to the annual impairment assessment. This reflects the fact that 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 operates to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions. However, management will continue to monitor changes in the business, as well as overall market conditions and economic factors that could require additional impairment assessments.

Revenue Recognition

Revenues on sales of electricity and gas, primarily at U.S. Franchised Electric and Gas, are recognized when either the service is provided or the product is delivered. Unbilled revenues are estimated by applying an average revenue/kilowatt-hour or per thousand cubic feet (Mcf) for all customer classes to the number of estimated kilowatt-hours or Mcf’s delivered but not billed. The amount of unbilled revenues can vary significantly period to period as a result of factors including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are recorded as Receivables in Duke Energy’s Consolidated Balance Sheets at December 31, 2008 and 2007 were approximately $360 million and $380 million, respectively.

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 based on the accounting guidance set forth in SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5), which requires a loss contingency to be recognized 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 $1,031 million and $1,082 million as of December 31, 2008 and 2007, 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 fore-

62

PART II

cast, 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 $1,099 million in excess of the self insured retention. Insurance recoveries of approximately $1,032 million and $1,040 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, 2008 and 2007, 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 18 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Accounting for Income Taxes

Duke Energy accounts for income taxes under SFAS No. 109, “Accounting for Income Taxes,” (SFAS No. 109) and FIN 48. 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. If future utilization of deferred tax assets is uncertain, Duke Energy may record a valuation allowance against certain deferred tax assets.

Prior to the adoption of FIN 48 on January 1, 2007, Duke Energy recorded tax contingencies based on the accounting guidance set forth in SFAS No. 5, which requires a contingency to be both probable and reasonably estimable for a loss to be recorded. Upon adoption of FIN 48, 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. In accordance with FIN 48, Duke Energy records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in the Consolidated Financial Statements. Management reevaluates tax positions each period in which new information about recognition or measurement becomes available.

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. 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 future impacts of various items, including changes in 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.

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

Pension and Other Post-Retirement Benefits

Duke Energy accounts for its defined benefit pension plans using SFAS No. 87, “Employers’ Accounting for Pensions,” (SFAS No. 87) and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” (SFAS No. 158). Under SFAS No. 87, pension income/expense is recognized on an accrual basis over employees’ approximate service periods. Other post-retirement benefits are accounted for using SFAS No. 106, “Employers ‘ Accounting for Postretirement Benefits Other Than Pensions,” (SFAS No. 106).

63

PART II

In accordance with the measurement date provision of SFAS No. 158, in 2007, Duke Energy changed its measurement date from September 30 to December 31.

Funding requirements for defined benefit (DB) plans are determined by government regulations, not SFAS No. 87. Duke Energy made voluntary contributions to its DB retirement plans of zero in 2008, $350 million in 2007 and $124 million in 2006. In the first quarter of 2009, Duke Energy made a voluntary contribution to its DB retirement plans in 2009 of $500 million. Additionally, during 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans.

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

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. 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 $46 million in 2008. In 2009, Duke Energy’s qualified pension cost is expected to be approximately $40 million lower than in 2008 as a result of the aforementioned approximate $500 million 2009 DB retirement plan contribution. Non-qualified pension cost and other post-retirement benefits cost are expected to remain approximately the same as 2008.

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, 2008. 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.

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 3.1% for U.S. equities, 2.8% for Non U.S. equities, 2.5% for fixed income securities, and 0.3% for real estate.

If Duke Energy had used a long-term rate of 8.25% in 2008, pre-tax pension expense would have been higher by approximately $10 million and pre-tax other post-retirement expense would have been higher by less than $1 million. If Duke Energy had used a long-term rate of 8.75% pre-tax pension expense would have been lower by approximately $10 million and pre-tax other post-retirement expense would have been lower by less than $1 million. Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 6.50% as of December 31, 2008.

64

PART II

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, 2008, the medical care trend rates were 8.50%, which grades to 5.00% by 2013. As of December 31, 2008, the prescription drug trend rate was 11.00%, which grades to 5.00% by 2022. If Duke Energy had used health care trend rates one percentage point higher, pre-tax other post-retirement expense would have been higher by $3 million. If Duke Energy had used health care trend rates one percentage point lower, pre-tax other post-retirement expense would have been lower by $2 million.

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

For further information, see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans.”

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

At December 31, 2008, Duke Energy had cash, cash equivalents and short-term investments of approximately $1.0 billion, partially offset by approximately $543 million of short-term notes payable and commercial paper, which includes approximately $279 million of borrowings by Duke Energy Ohio under the master credit facility. To fund its liquidity and capital requirements during 2009, 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, cash equivalents and short-term investments. 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 2009 capital and investment expenditures of approximately $4.8 billion, primarily consisting of:

• $3.8 billion at U.S. Franchised Electric and Gas

• $0.6 billion at Commercial Power

• $0.3 billion at International and

• $0.1 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 with an overall focus on positive net cash generation. Based on this goal, approximately 75 percent of total projected 2009 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2009 capital and investment expenditures include approximately $1.9 billion for system growth, $1.5 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.2 billion of environmental expenditures, and approximately $0.2 billion of nuclear fuel.

With respect to the 2009 capital expenditure plan, Duke Energy has flexibility within its $4.8 billion budget to defer or eliminate certain spending should the broad economy continue to deteriorate. Of the $4.8 billion budget, approximately $2.6 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 2009 irrespective of broader economic factors. Approximately $2.1 billion of projected 2009 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 2009 capital expenditures of approximately $0.1 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.

65

PART II

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

Duke Energy anticipates its debt to total capitalization ratio to remain at approximately 41% in 2009. In January 2009, Duke Energy issued $750 million principal amount of senior notes. Proceeds from the issuance were used to redeem commercial paper and for general corporate purposes. In 2009, Duke Energy currently anticipates issuing approximately $1.4 billion of additional debt at the operating subsidiary level, primarily for the purpose of funding capital expenditures. Due to the flexibility in the timing of projected 2009 capital expenditures, the timing and amount of debt issuances throughout 2009 could be influenced by changes in the timing of capital spending. Additionally, Duke Energy plans to generate approximately $350 million of cash from the issuance of common stock under its DRIP and other internal plans. In February 2009, Duke Energy made an approximate $500 million contribution to its pension plan.

At this time, Duke Energy does not believe the recent market developments significantly impact its ability to obtain financing and fully expects to have access to liquidity in the capital markets at reasonable rates and terms. 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, 2008, Duke Energy has available borrowing capacity of approximately $1.2 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 2009, 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 2009 funding requirements related to capital and investments expenditures, dividend payments and the contribution to the pension plan.

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 2009. 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 $3,328 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

Net cash provided by operating activities was $3,208 million in 2007, compared to $3,748 million in 2006, a decrease in cash provided of $540 million. The decrease in cash provided by operating activities was driven primarily by:

• The spin-off of the natural gas businesses on January 2, 2007,

• The deconsolidation of Crescent in September 2006, and

• A $250 million increase in contributions to Duke Energy’s pension plan and other post retirement benefit plans in 2007, partially offset by

• The impact of a full year of Cinergy operations in 2007 compared to nine months in 2006.

66

PART II

Investing Cash Flows

Net cash used in investing activities was $4,611 million in 2008, $2,151 million in 2007, and $1,328 million in 2006.

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

Capital, Investment and Acquisition Expenditures by Business Segment

	Years Ended December 31,
	2008		2007		2006
	(in millions)
U.S. Franchised Electric and Gas(a)	$	3,650	$	2,613	$	2,381
Natural Gas Transmission(b)		—		—		790
Commercial Power		870		442		209
International Energy		161		74		58
Other(c)		241		153		638
Total consolidated	$	4,922	$	3,282	$	4,076

(a) Amounts include capital expenditures associated with North Carolina clean air legislation of $355 million in 2008, $418 million in 2007 and $403 million in 2006, which are included in Capital Expenditures within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows.

(b) On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses. 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, which was part of the Field Services business segment.

(c) Other includes Crescent and only reflects capital expenditure amounts in 2006 for periods prior to deconsolidation on September 7, 2006. Additionally, amounts include capital expenditures associated with residential real estate of $322 million for the period from January 1, 2006 through the date of deconsolidation, which is included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows.

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 Energy Corporation (approximately $245 million) and the purchase of a portion of Saluda River Electric Cooperative, 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 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.

The increase in cash used in investing activities in 2007 as compared to 2006 is primarily due to the following:

• Approximately $1,600 million in proceeds received from the sale of former DENA assets in 2006,

• Approximately $700 million in proceeds received from the sale of Cinergy commercial marketing and trading operations in 2006,

• Approximately $380 million in proceeds received from the sale of an effective 50% interest in Crescent in 2006,

• An approximate $250 million decrease in proceeds from the sales of commercial and multi-family real estate due to the deconsolidation of Crescent in September 2006, and

• Approximately $150 million of cash received in 2006 as part of the Cinergy merger.

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

An approximate $1,800 million increase in proceeds from available-for sale securities, net of purchases, and

An approximate $470 million decrease in capital and investment expenditures, in part reflecting the spin-off of the natural gas businesses on January 2, 2007.

67

PART II

Financing Cash Flows and Liquidity

Duke Energy’s consolidated capital structure as of December 31, 2008, including short-term debt, was 41% debt and 59% common equity. The fixed charges coverage ratio, calculated using SEC guidelines, was 3.4 times for 2008, 3.7 times for 2007, and 2.6 times for 2006, which includes a pre-tax gain of approximately $250 million on the sale of an effective 50% interest in Crescent.

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.

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.

Net cash used in financing activities was $1,327 million in 2007 compared to $1,961 million in 2006, a decrease of $634 million. The change was due primarily to the following:

• An approximate $500 million decrease in cash used due to the repurchase of common shares in 2006,

• An approximate $400 million decrease in dividends paid as a result of the spin-off of Spectra Energy, and

• An approximate $1,030 million increase in net proceeds in 2007 from the issuance of notes payable and commercial paper.

These increases were partially offset by:

• An approximate $700 million decrease in proceeds from issuances of long-term debt, net of redemptions,

• An approximate $400 million distribution of cash in 2007 as a result of the spin-off of Spectra Energy,

• An approximate $110 million decrease in cash due to the repurchase of senior convertible notes in 2007, and

• An approximate $100 million decrease in proceeds from the Duke Energy Income Fund.

Financing Activities Subsequent to December 31, 2008. In January 2009, Duke Energy issued $750 million principal amount of 6.30% senior unsecured notes due February 1, 2014. The net 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, and $127 million had initial rates of 0.50% reset on a daily basis with $77 million maturing December 2039 and $50 million maturing October 2040.

Significant Financing Activities—Year Ended 2008. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $400 million carries a fixed interest rate of 5.25% and matures January 15, 2018 and $500 million carries a fixed interest rate of 6.00% and matures 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.

In April 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $300 million carries a fixed interest rate of 5.10% and matures April 15, 2018 and $600 million carries a fixed interest rate of 6.05% and matures 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

68

PART II

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 is reset on a weekly basis.

In June 2008, Duke Energy issued $500 million principal amount of senior notes, of which $250 million carries a fixed interest rate of 5.65% and matures June 15, 2013 and $250 million carries a fixed interest rate of 6.25% and matures June 15, 2018. Proceeds from the issuance were used to redeem commercial paper, to fund capital expenditures in Duke Energy’s nonregulated businesses in the U.S. 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 matures 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 October 2008, International Energy issued approximately $153 million of debt in Brazil, of which approximately $112 million matures in September 2013 and carries a variable interest rate equal to the Brazil interbank rate plus 2.15%, and approximately $41 million matures in September 2015 and carries 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 November 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $500 million carries a fixed interest rate of 7.00% and matures November 15, 2018 and $400 million carries a fixed interest rate of 5.75% and matures 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 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.

Significant Financing Activities—Year Ended 2007. 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. Additionally, dividends paid on Duke Energy common stock during 2007 of approximately $1,089 million were less than the 2006 dividends paid of approximately $1,488 million 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.

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.

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 above. The remainder was used for general corporate purposes.

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 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.

69

PART II

Significant Financing Activities—Year Ended 2006. During the year ended December 31, 2006, Duke Energy increased the portion of outstanding commercial paper and pollution control bond balances classified as long-term from $472 million to $929 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

During 2006, Duke Energy repurchased approximately 17.5 million shares of its common stock for approximately $500 million and paid dividends of approximately $1,488 million. Also, during the year ended December 31, 2006, approximately $632 million of convertible senior notes were converted into approximately 27 million shares of Duke Energy Common Stock.

In November 2006, Union Gas Limited (Union Gas) issued 4.85% fixed-rate debenture bonds denominated in 125 million Canadian dollars (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022. This debt was included in the spin-off of the natural gas businesses in January 2007.

In October 2006, Duke Energy Carolinas issued $150 million in tax-exempt floating-rate bonds. The bonds are structured as variable-rate demand bonds, subject to weekly remarketing and bear a final maturity of 2031. The initial interest rate was set at 3.72%. The bonds are supported by an irrevocable 3-year direct-pay letter of credit and were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Marshall and Belews Creek Steam Stations.

In September 2006, prior to the completion of the partial sale of Crescent to the MS Members as discussed in Note 3 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets,” Crescent issued approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a Financing Activity on the Consolidated Statements of Cash Flows. As a result of Duke Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’s Consolidated Balance Sheets.

In September 2006, Union Gas entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%. This debt was included in the spin-off of the natural gas businesses in January 2007.

In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units at a price of 12.15 Canadian dollars per Trust Unit for total proceeds of 104 million Canadian dollars, net of commissions and expenses of other expenses of issuance. The sale of approximately 9 million Trust Units reduced Duke Energy’s ownership interest in the Income Fund to approximately 46% at December 31, 2006. The Income Fund was included in the spin-off of the natural gas businesses in January 2007.

In August 2006, Duke Energy Kentucky issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio. Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

In June 2006, Duke Energy Indiana issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.

Available Credit Facilities and Restrictive Debt Covenants. In June 2007, Duke Energy closed the syndication of an amended and restated credit facility, which replaced existing credit facilities, with a 5-year, $2.65 billion master credit facility. Duke Energy, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky all have borrowing capacity under the terms of the master credit facility.

In March 2008, Duke Energy entered into an amendment to its $2.65 billion master credit facility whereby the borrowing capacity was increased by $550 million to $3.2 billion. In October 2008, Duke Energy terminated the participation of one of the financial institutions supplying approximately $63 million of credit commitment under its master credit facility. The total credit facility capacity under the master credit facility subsequent to this termination is approximately $3.14 billion. Duke Energy has the unilateral ability under the master credit facility to increase or decrease the borrowing sublimits of each borrower, subject to 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 pollution control bonds. At December 31, 2008, Duke Energy had available capacity of approximately $1.2 billion under the master credit facility. For further information on Duke Energy’s credit facilities as of December 31, 2008, see Note 16 to the Consolidated Financial Statements, “Debt and Credit Facilities.”

70

PART II

In September 2008, 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) borrowed a total of approximately $1 billion under Duke Energy’s master credit facility. In the fourth quarter of 2008, Duke Energy Carolinas used the proceeds from a debt issuance to repay in full the approximately $260 million borrowed under the master credit facility. At December 31, 2008, outstanding borrowings of approximately $750 million under Duke Energy’s master credit facility were as follows:

	Amounts Borrowed Under Master Credit Facility
	(in millions)
Duke Energy Corporation	$	274
Duke Energy Ohio		279
Duke Energy Indiana		123
Duke Energy Kentucky		74
Total	$	750

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 24 basis points. The loan for Duke Energy has a stated maturity of June 2012, while the loans for all of the other borrowers have stated maturities of September 2009; however, the borrowers have the ability under the master credit facility to renew the loans due in September 2009 up through the date the master credit facility matures in June 2012. Except for Duke Energy Ohio, all of the borrowers 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, borrowings of $471 million are reflected as Long-Term Debt on the Consolidated Balance Sheets at December 31, 2008. As Duke Energy Ohio does not have the intent to refinance its borrowings on a long-term basis, the $279 million outstanding at December 31, 2008 is reflected in Notes Payable and Commercial Paper within current liabilities on the Consolidated Balance Sheets.

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, 2008, 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 S&P and Moody’s Investors Service (Moody’s).

In September 2008, S&P revised the outlook on Duke Energy and its rated subsidiaries from stable to positive and affirmed the credit ratings of Duke Energy and its rated subsidiaries.

In January 2008, Moody’s changed the rating outlook on Duke Energy, Duke Energy Carolinas, Cinergy, Duke Energy Ohio and Duke Energy Kentucky to stable from positive, while affirming the existing ratings in the below table of each of these entities. In January 2009, Moody’s changed the rating on Duke Energy Ohio to positive from stable. The outlooks for all other rated entities remain as stable.

Duke Energy’s corporate credit rating and issuer credit rating from S&P and Moody’s, respectively, as of February 1, 2009 is A- and Baa2, respectively. The following table summarizes the February 1, 2009 unsecured credit ratings from the rating agencies retained by Duke Energy and its principal funding subsidiaries.

71

PART II

Senior Unsecured Credit Ratings Summary as of February 1, 2009

	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 Standard & Poor’s (S&P) or Moody’s Investors Service (Moody’s). As of December 31, 2008, Duke Energy had approximately $8 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 $19 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s.

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

Duke Energy has paid quarterly cash dividends for 83 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. It is currently anticipated that dividends per share will increase $0.01 per share beginning in the third quarter of 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. Duke Energy currently anticipates issuing up to an aggregate of approximately $600 million of common stock associated with these programs. Approximately $100 million of common stock was issued during the fourth quarter of 2008 associated with these 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, $50 million in 2007 and approximately $127 million in 2006.

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, 2008, 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 $10.7 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.

72

PART II

Off-Balance Sheet Arrangements

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, guarantees of debt, surety bonds and indemnifications. In contemplation of the spin-off of the natural gas businesses on January 2, 2007, certain guarantees that had been issued by Spectra Energy Capital were transferred to Duke Energy prior to the consummation of the spin-off. This resulted in Duke Energy recording an immaterial liability for certain guarantees that were previously grandfathered under the provisions of FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others,” and, therefore, had not been recognized in the Consolidated Balance Sheets. Guarantees issued by Spectra Energy Capital or its subsidiaries on or prior to December 31, 2006 remained with Spectra Energy 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 Energy Capital against any losses incurred under these guarantee obligations. See Note 19 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.

Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy, either on its own or on behalf of Spectra Energy Capital through the aforementioned indemnification agreements, 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.

Due to the continued downturn in the overall economic environment, Duke Energy performed an assessment of its guarantee obligations as of December 31, 2008 to determine whether any SFAS No. 5 liabilities have been triggered as a result of potential increased non-performance risk by parties for which Duke Energy has issued guarantees. Based on the results of this analysis, as of December 31, 2008 management determined, with the exception of some insignificant amounts, that it is not probable that Duke Energy will have to perform under any guarantee obligations. However, management will continue to monitor the financial condition of the third parties or non-wholly owned entities for whom Duke Energy has issued guarantees on behalf of, including certain obligations related to Crescent, to determine whether performance under these guarantees becomes probable in the future. As of December 31, 2008, it is reasonably possible that Duke Energy could have exposure of approximately $40 million under these guarantees should Crescent fail to perform under its obligations associated with these projects, which would become more likely should Crescent declare bankruptcy in the near future. See Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions,” for a discussion of impairment losses recorded by Crescent during 2008 and Crescent’s significant debt obligations as of December 31, 2008.

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 Company LLC (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 (SPE). 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, pursuant to SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” For a more detailed discussion of the sale of certain accounts receivable, see Note 23 to the Consolidated Financial Statements, “Variable Interest Entities.”

Duke Energy also holds interests in variable interest entities (VIEs), consolidated and unconsolidated, as defined by FIN No. 46R, “Consolidation of Variable Interest Entities.” For further information, see Note 23 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 18 to the Consolidated Financial Statements, “Commitments and Contingencies.”

73

PART II

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 2009.

Contractual Obligations as of December 31, 2008

	Payments Due By Period
	Total		Less than 1 year (2009)		2-3 Years (2010 & 2011)		4-5 Years (2012 & 2013)		More than 5 Years (Beyond 2013)
	(in millions)
Long-term debt(a)	$	24,080	$	1,387	$	2,653	$	4,606	$	15,434
Capital leases(a)		173		28		52		43		50
Operating leases(b)		622		101		164		105		252
Purchase Obligations:(h)
Firm capacity payments(c)		567		64		138		11		354
Energy commodity contracts(d)		8,457		2,694		3,752		1,172		839
Other purchase obligations(e)		3,627		2,059		1,200		51		317
Other funding obligations(f)		480		48		96		96		240
Total contractual cash obligations(g)	$	38,006	$	6,381	$	8,055	$	6,084	$	17,486

(a) See Note 16 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount includes interest payments over life of debt or capital lease. Payment amounts exclude $750 million of debt issued by Duke Energy in January 2009. 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 18 to the Consolidated Financial Statements, “Commitments and Contingencies”.

(c) Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity, and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some power locations throughout North America.

(d) Includes contractual obligations to purchase physical quantities of electricity, coal and nuclear fuel, certain normal purchases, energy derivatives and hedges per SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2008. 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, and commitments to buy wind and CT turbines. Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase can not be determined.

(f) Primarily relates to future annual funding obligations to the 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. Asset retirement obligations recognized on the Consolidated Balance Sheets total $2,567 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,436 million at December 31, 2008. The table above excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 18 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 18 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of pension and other post-retirement benefit plans (see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also, the table above excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. 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.

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 Treasurer and other members of management on market risk positions, corporate exposures, credit exposures and overall risk management activities. The Treasurer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.

74

PART II

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. 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 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”

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 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 normal purchases and sales exception described in paragraph 10 of SFAS No. 133, as amended and interpreted by Derivatives Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” On a limited basis, U.S. Franchised Electric and Gas and Commercial Power apply the normal purchase and normal sales exception to certain contracts. 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 scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract unless the contract is designated as the hedged item in a fair value hedge. Recognition of the contracts in the Consolidated Statements of Operations will be the same regardless of whether the contracts are accounted for as cash flow hedges or as normal purchases and sales, unless designated as the hedged item in a fair value hedge, assuming no hedge ineffectiveness.

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. Derivatives related to regulated businesses reflect changes in the fair value of the derivative instruments as a regulatory asset or liability on the Consolidated Balance Sheets. Derivatives related to unregulated businesses are marked-to-market each period, with changes in the fair value of the derivative instruments reflected in earnings. These instruments are referred to as undesignated contracts (see Undesignated Contracts below).

Generation Portfolio Risks for 2009. 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, 2008 and 2007, it was estimated that a ten percent price change per megawatt hour in forward wholesale power prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $10 million in 2009 and would have had a $24 million impact in 2008, 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, 2008 and 2007, it was estimated that a ten percent change in

75

PART II

the forward price per ton of coal would have a corresponding effect on Duke Energy’s pre-tax income of approximately $10 million in 2009 and would have had a $4 million impact in 2008, 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, 2008 and 2007, it was estimated that a ten percent price change per Million British Thermal (MMBtu) in natural gas prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $5 million in 2009 and would have had a $9 million impact in 2008, 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 2009. Derivative contracts executed to manage generation portfolio risks for delivery periods beyond 2009 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, 2008 and 2007, it was estimated that a ten percent price change in the forward price per megawatt hour of wholesale power would have a corresponding effect on Duke Energy’s pre-tax income of approximately $11 million in 2009 and would have had a $16 million impact in 2008, 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, 2008 and 2007, it was estimated that a ten percent change in the forward price per ton of coal would have a corresponding effect on Duke Energy’s pre-tax income of approximately $10 million in 2009 and would have had a $14 million impact in 2008, 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.

Comparability of sensitivity analysis. As Commercial Power began reapplying the provisions of SFAS No. 71 on December 17, 2008 to portions of its operations, certain derivative contracts that historically resulted in earnings volatility receive regulatory deferral of gains and losses. Accordingly, the mark-to-market associated with these contracts will not impact earnings. However, to achieve comparability of sensitivity information between periods, the portion of the derivative contracts that receive regulatory treatment have been included in the sensitivity amounts for both periods presented. Since certain derivative contracts included in the sensitivity analysis for 2009 will not result in earnings impacts, the forecasted sensitivities for 2009 are less than the pre-tax income amounts disclosed above.

Other Commodity Risks. At December 31, 2008 and 2007, pre-tax income in 2009 and 2008 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

76

PART II

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 $1,099 million in excess of the self insured retention. Insurance recoveries of approximately $1,032 million and $1,040 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, 2008 and 2007, 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 19 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further information on guarantees issued by Duke Energy or its subsidiaries.

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 16 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” “Fair Value of Financial Assets and Liabilities,” and “Debt and Credit Facilities.”

Based on a sensitivity analysis as of December 31, 2008, it was estimated that if market interest rates average 1% higher (lower) in 2009 than in 2008, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $28 million. Comparatively, based on a sensitivity analysis as of December 31, 2007, had interest rates averaged 1% higher (lower) in 2008 than in 2007, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $22 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, 2008 and 2007. The increase in interest rate sensitivity is primarily due to borrowings outstanding under the master credit facility. 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.

Equity Price Risk

As described further in Note 10 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” Duke Energy invests in 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 nuclear decommissioning trust fund and assets of the various pension and other post-retirement benefit plans.

Nuclear Decommissioning Trust Funds (NDTF). As required by the NRC and the NCUC, Duke Energy maintains trust funds to fund the costs of nuclear decommissioning (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations”). As of December 31, 2008, 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 in equity securities are exposed to price fluctuations in 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 pursuant to an Order by the NCUC. Earnings or losses of the fund will ultimately impact the amount of costs recovered through U.S. Franchised Electric and Gas’ rates.

77

PART II

In 2005, the NCUC and PSCSC collectively approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2008, 2007 and 2006, Duke Energy expensed approximately $48 million and contributed cash of approximately $48 million to the NDTF for decommissioning costs. Estimated site-specific nuclear decommissioning costs $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s proportionate ownership in the Catawba Nuclear Station, which was 12.5% at the time the study was completed. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. 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 is based on Duke Energy’s current ownership share of Catawba Nuclear Station of approximately 19%. Duke Energy will file these site-specific nuclear decommissioning cost studies with the NCUC and the PSCSC later this year. In addition to the decommissioning cost studies, a new funding study is underway to determine the appropriateness of the annual amounts currently being contributed to the NDTF. The NCUC and the PSCSC will consider the results of the funding study, which could potentially increase the annual required contributions to the NDTF, in the latter part of 2009.

The following table provides the fair value of investments held in the NDTF at December 31, 2008:

	Fair Value at December 31, 2008
	(in millions)
Equity Securities	$	831
Corporate Debt Securities		88
U.S. Government Bonds		272
Municipal Bonds		120
Other		125
Total	$	1,436

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 expense required to be recorded in future periods, which could adversely affect Duke Energy’s results of operations in those periods. In February 2009, Duke Energy made an approximate $500 million contribution to its pension plan. See Note 22 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 2009, 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, 2008 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 $10 million to Duke Energy’s Consolidated Statements of Operations in 2009. The Consolidated Balance Sheet would be negatively impacted by approximately $120 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2008 as a result of a 10% devaluation in the currency exchange rates. As of December 31, 2007, a 10% devaluation in the currency exchange rates in all of Duke Energy’s exposure currencies was expected to

78

PART II

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 $145 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2007.

Other Issues

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

Global Climate Change. A body of scientific evidence now accepted by a growing majority of the public and policymakers suggests that the Earth’s climate is changing, caused in part by greenhouse gases emitted into the atmosphere from human activities. 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 emissions with the aim of stabilizing the atmospheric concentration of greenhouse gases at a level that avoids the potentially worst-case effects of climate change.

Greenhouse gas (GHG) emissions are produced from a wide variety of human activities. The U.S. EPA publishes an inventory of these emissions annually. Carbon dioxide (CO₂), an essential trace gas, is a by product of fossil fuel combustion and currently accounts for about 85% of U.S. greenhouse gas emissions. Duke Energy currently accounts for about 1.5% of total U.S. CO₂ emissions, and about 1.3% of total U.S. GHG emissions.

Duke Energy is making long-term decisions for how best to meet its customers’ growing demand for electricity. Duke Energy’s strategy for meeting customer demand while building a sustainable business that allows our customers and our shareholders to prosper in a carbon-constrained environment includes significant commitments to customer energy efficiency, renewable energy, advanced nuclear power, advanced clean-coal and high-efficiency natural gas electric generating plants, and retirement of older less efficient coal-fired power plants. Each of these actions will or has the potential to reduce Duke Energy’s CO₂ emissions and therefore its exposure to the costs of future GHG regulation.

Duke Energy’s cost of complying with any federal GHG emissions law that may be enacted will depend on the design details of the program. If potential future GHG legislation adopts a cap-and-trade approach, the design elements of such a program that will have the greatest influence on Duke Energy’s compliance costs include (1) the required levels and timing of the cap, which will drive emission allowance prices, (2) the emission sources covered under the cap, (3) the number of allowances that Duke Energy might be allocated at no cost on a year-to-year basis, (4) the type and effectiveness of any cost control mechanisms included in the program, (5) the role of emission offsets, which will also influence allowance prices, and (6) the availability and cost of technologies that Duke Energy can deploy to lower its emissions. While Duke Energy believes it is very 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.

While there were many bills introduced in both houses of Congress during the 110^th Congress that proposed mandatory limits on GHG emissions, S. 2191—America’s Climate Security Act of 2007 (commonly referred to as the Lieberman-Warner bill after the sponsors Senators Joseph Lieberman of Connecticut and John Warner of Virginia) became the primary climate change related legislative vehicle. The bill was approved by the Senate Environment and Public Works Committee in December 2007, but failed to advance on the Senate floor in June 2008 when the bill fell considerably short of the 60 votes necessary to invoke cloture and cut off debate. No subsequent action was taken in the 110^th Congress related to mandatory federal GHG legislation.

Numerous bills mandating reductions in GHG emissions are expected to be introduced in both houses of Congress in 2009. The leadership in both the House and Senate has publicly stated it is their intent to proceed with climate legislation. President Obama, in his presidential campaign and after the election, indicated passage of climate change legislation is a priority. Still, as the Senate debate in 2008 revealed, there are wide-ranging views in Congress regarding what constitutes acceptable GHG legislation. The current condition of the U.S. economy could add a degree of uncertainty, and there are indications that, in the 111^th Congress multiple committees will be involved in crafting GHG legislation, which will make the process of developing GHG legislation potentially more challenging.

79

PART II

Duke Energy supports the enactment of federal GHG cap-and-trade legislation. Due to Duke Energy’s concern about patchwork policies focused on a single industrial sector or particular region of the country, Duke Energy believes this legislation should establish a program that applies to all parts of the economy, including power generation, industrial and commercial sources, and motor vehicles. 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 non-emitting technologies are developed and become available for wide-scale deployment. Legislation should also include adequate cost-containment measures to protect the U.S. economy from grave and unintended impacts of the policy.

Duke Energy is unable to estimate the potential cost of complying with currently unspecified and unknowable future GHG legislation or any indirect costs that might result. Compliance costs are sensitive to numerous policy design details, allowance prices, and technology availability and cost. During the Senate debate on the Lieberman-Warner legislation in 2007 and 2008, Duke Energy attempted to estimate its cost of complying with that legislation over a range of potential allowance prices. Duke Energy estimated its compliance costs under the Lieberman- Warner model to be between approximately $930 million to $2.8 billion in the first year of the program (2012), which represented the cost to purchase emission allowances needed for compliance over and above what might be allocated to Duke Energy at zero-cost. Duke Energy would have continued to incur similar or greater annual compliance costs in subsequent years for continued allowance purchases until such time as new lower-and zero-emitting technologies could be deployed to reduce emissions. Duke Energy’s compliance costs at that time would then include the cost of purchasing and deploying new generation technologies. Duke Energy would only be able to reduce its allowance purchase costs after new technologies were actually deployed.

There is no way to know how similar or different the requirements of the Lieberman-Warner legislation might be to any future GHG legislation that Congress may eventually adopt, so it is uncertain whether these costs are at all representative of compliance costs that Duke Energy might incur as a result of any potential future GHG legislation. 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.

At the state level, the Midwestern Governors Association has an initiative under way called the Midwestern Greenhouse Gas Reduction Accord. One of the ongoing activities of the initiative is the design of a regional GHG cap-and-trade system, with the anticipated end product to be a Model Rule for implementing a GHG cap-and-trade system. Once complete, the Model Rule would go to participating states for their consideration and possible adoption. The states of Ohio and Indiana are currently only observers to the accord process. The outcome of this initiative is highly uncertain and Duke Energy is unable to determine at this time whether there might be direct or indirect cost impacts from any new regulations that might result from the initiative.

While Duke Energy’s near-term compliance strategy associated with any potential future GHG legislation that incorporates a cap-and-trade mechanism will likely be focused on allowance purchases, it is expected that at some point in the future Duke Energy would begin reducing emissions by replacing existing coal-fired generation with new lower-and zero-emitting generation technologies, and/or installing new carbon capture and sequestration technology on existing coal-fired generating plants when the technologies become available and cost-effective. It is not possible at this time, however, to predict with certainty what new technologies might be developed, when they will be ready to be deployed, or what their costs will be. There is also uncertainty as to how or when certain non-technical issues, such as legal and liability questions, that could affect the cost and availability of new technologies might be resolved by regulators. Duke Energy currently is focused on advanced nuclear generation, integrated gasification combined cycle generation with carbon capture and sequestration, and capture and storage retrofit technology for existing pulverized coal-fired generation as promising new technologies for generating electricity with lower or no CO₂ emissions.

Duke Energy has begun the regulatory process to construct a new 2,234-megawatt nuclear power plant (William States Lee III Nuclear Station) in South Carolina, petitioning the U.S. Nuclear Regulatory Commission in 2007 for a combined construction and operating license. If constructed, this facility would produce virtually no GHG’s and could begin operation in the 2018 timeframe.

With regard to advanced clean-coal, Duke Energy is in the process of constructing a 630-megawatt integrated gasification combined cycle (IGCC) power plant in Indiana. One of the key features of the IGCC technology is that it has great potential to support the capture of its CO₂ emissions, with subsequent underground storage of the captured CO₂. Indiana’s geology gives all indications of being conducive to permanent underground storage of CO₂. Although the IGCC plant, scheduled to be completed in 2012, is not currently being equipped with the technology to capture carbon emissions, space is being reserved for it to be added later. In January 2009, Duke Energy was given permission by the IURC to proceed with a CO₂ capture front-end engineering and design study. Duke Energy has also submitted an application to the Department of Energy for up to a 50% sharing of the cost of installing and operating a pilot-scale CO₂ capture and storage project at Duke Energy’s IGCC facility.

80

PART II

Duke Energy has regulatory requirements in North Carolina and Ohio to meet increasing percentages of customer demand for electricity with renewable energy. In North Carolina the requirement reaches 12.5% in 2021 and in Ohio it reaches a minimum of 12.5% in 2024. Duke Energy also anticipates the Congress will consider a federal renewable portfolio standard in 2009. Previous attempts have passed in the House but fallen short in the Senate. Duke Energy believes, however, chances of passage in the 111^th Congress have increased.

In addition to relying on new technologies to reduce its CO₂ emissions, Duke Energy has filed for regulatory approval in each of the states in which it operates (Duke Energy has received approval in Ohio) for a first-of-its-kind innovative approach in the utility industry to help meet growing customer demand with new and creative ways to increase energy efficiency, thereby reducing demand (Save-A-Watt) instead of relying almost exclusively on new power plants to generate electricity.

Each of these activities has the potential to reduce Duke Energy’s future CO₂ emissions which will reduce Duke Energy’s exposure to future GHG regulation.

Duke Energy recognizes the potential for more frequent and severe extreme weather events as a result of climate change and the possibility that these weather events could have a material impact on its 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) and the long period of time over which any changes might take place make estimating any potential future financial risk to Duke Energy’s operations that may be caused by the physical risks of climate change extremely challenging. 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.

(For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 18 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of December 31, 2008:

SFAS No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). In December 2007, the FASB issued SFAS No. 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R retains the fundamental requirements in SFAS No. 141 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 establishes 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, SFAS No. 141R must be applied prospectively to business combinations for which the acquisition date occurs on or after January 1, 2009. The impact to Duke Energy of applying SFAS No. 141(R) for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of SFAS No. 141(R). SFAS No. 141R changes the accounting for income taxes related to prior business combinations, such as Duke Energy’s merger with Cinergy. Subsequent to the effective date of SFAS No. 141R, the resolution of any tax contingencies relating to Cinergy that existed as of the date of the merger will be 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.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS No. 160). In December 2007, the FASB issued SFAS No. 160, which amends ARB No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies 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 statement also changes 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, SFAS No. 160 establishes 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, SFAS No. 160 is effective as of January 1, 2009, and must be applied prospectively, except for certain presentation and disclosure requirements which must be applied retrospectively. The adoption of SFAS No. 160 will impact the presentation of noncontrolling interests in Duke Energy’s Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income, as well as the calculation of Duke Energy’s effective tax rate.

81

PART II

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment to FASB Statement No. 133” (SFAS No. 161). In March 2008, the FASB issued SFAS No. 161, which amends and expands the disclosure requirements for derivative instruments and hedging activities prescribed by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, 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 will adopt SFAS No. 161 as of January 1, 2009 and SFAS No. 161 encourages, but does not require, comparative disclosure for earlier periods at initial adoption. The adoption of SFAS No. 161 will not have any impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1). In May 2008, the FASB issued FSP APB 14-1, which addresses the accounting for convertible debt securities that, upon conversion, may be settled by the issuer fully or partially in cash. FSP APB 14-1 does not change the accounting for more traditional types of convertible debt securities that do not have a cash settlement feature and FSP APB 14-1 does not apply if, under existing GAAP for derivatives, the embedded conversion feature must be accounted for separately from the rest of the instrument. For Duke Energy, FSP APB 14-1 is applicable as of January 1, 2009 and must be applied retrospectively to all prior periods presented, even if the instrument has matured, has been converted, or has otherwise been extinguished as of the effective date of FSP APB 14-1. Duke Energy is currently evaluating the impact of adopting FSP APB 14-1 on its historical results of operations as, in 2003, Duke Energy issued $770 million of convertible debt with a cash settlement option that was fully converted to common stock during the years ended December 31, 2005, 2006 and 2007; however, Duke Energy does not anticipate the retrospective application of FSP APB 14-1 will have a material impact on Duke Energy’s historical results of operations, cash flows or financial position. Future impacts of FSP APB 14-1 will be determined by whether Duke Energy issues convertible debt with cash settlement options.

FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). In June 2008, the FASB issued FSP EITF 03-6-1 to address whether instruments granted in share-based payment transactions may be participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing basic EPS pursuant to the two-class method described in SFAS No. 128. The FASB concluded that rights to dividends or dividend equivalents (whether paid or unpaid) on unvested share-based payment awards that provide a noncontingent transfer of value (such as a nonforfeitable right to receive cash when dividends are paid to common stockholders, irrespective of whether the award ultimately vests) to the holder of the share-based payment award constitute participation rights and, therefore, should be included in the computation of basic EPS using the two-class method. Duke Energy issues certain share-based payment awards under which rights to dividends during the vesting period are nonforfeitable. For Duke Energy, FSP EITF 03-6-1 is effective as of January 1, 2009 and all prior-period EPS data is required to be adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1. Duke Energy is currently evaluating the impact of adoption of FSP No. EITF 03-6-1 on its EPS; however, Duke Energy does not currently anticipate the adoption of FSP EITF 03-6-1 will have a material impact on its calculated future or historical EPS amounts.

FSP FAS 132(R)-1, “Employers’ Disclosure about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1). In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132(R) 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 SFAS No. 157 (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, FASP FAS 132(R)-1 is effective for Duke Energy’s Form 10-K for the year ended December 31, 2009. The adoption of FSP FAS 132(R)-1 will not have any impact on Duke Energy’s results of operations, cash flows or financial position.

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.”

82

PART II

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, 2008 and 2007, and the related consolidated statements of operations, common stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008, based on 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, 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 the 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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, 2008, 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 27, 2009

83

PART II

DUKE ENERGY CORPORATION

Consolidated Statements of Operations

(In millions, except per-share amounts)

	Years Ended December 31,
	2008			2007			2006
Operating Revenues
Regulated electric	$	9,325		$	8,976		$	7,678
Non-regulated electric, natural gas, and other		3,092			3,024			2,542
Regulated natural gas		790			720			387
Total operating revenues		13,207			12,720			10,607
Operating Expenses
Fuel used in electric generation and purchased power—regulated		3,007			2,602			2,270
Fuel used in electric generation and purchased power—non-regulated		1,400			1,344			1,102
Cost of natural gas and coal sold		613			557			339
Operation, maintenance and other		3,351			3,324			3,420
Depreciation and amortization		1,670			1,746			1,545
Property and other taxes		639			649			534
Impairment charges		85			—			—
Total operating expenses		10,765			10,222			9,210
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		—			—			201
Gains (Losses) on Sales of Other Assets and Other, net		69			(5	)		223
Operating Income		2,511			2,493			1,821
Other Income and Expenses
Equity in earnings (loss) of unconsolidated affiliates		(102	)		157			123
Losses on sales and impairments of equity investments		(9	)		—			(20	)
Other income and expenses, net		232			271			251
Total other income and expenses		121			428			354
Interest Expense		741			685			632
Minority Interest (Benefit) Expense		(4	)		2			13
Income From Continuing Operations Before Income Taxes		1,895			2,234			1,530
Income Tax Expense from Continuing Operations		616			712			450
Income From Continuing Operations		1,279			1,522			1,080
Income (Loss) From Discontinued Operations, net of tax		16			(22	)		783
Income Before Extraordinary Items		1,295			1,500			1,863
Extraordinary Items, net of tax		67			—			—
Net Income	$	1,362		$	1,500		$	1,863
Common Stock Data
Weighted-average shares outstanding
Basic		1,265			1,260			1,170
Diluted		1,268			1,266			1,188
Earnings per share (from continuing operations)
Basic	$	1.01		$	1.21		$	0.92
Diluted	$	1.01		$	1.20		$	0.91
Earnings (loss) per share (from discontinued operations)
Basic	$	0.02		$	(0.02	)	$	0.67
Diluted	$	0.01		$	(0.02	)	$	0.66
Earnings per share (before extraordinary items)
Basic	$	1.03		$	1.19		$	1.59
Diluted	$	1.02		$	1.18		$	1.57
Earnings per share (from extraordinary items)
Basic	$	0.05		$	—		$	—
Diluted	$	0.05		$	—		$	—
Earnings per share
Basic	$	1.08		$	1.19		$	1.59
Diluted	$	1.07		$	1.18		$	1.57
Dividends per share	$	0.90		$	0.86		$	1.26

See Notes to Consolidated Financial Statements

84

PART II

DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(In millions)

	December 31,
	2008		2007
ASSETS
Current Assets
Cash and cash equivalents	$	986	$	678
Short-term investments		51		437
Receivables (net of allowance for doubtful accounts of $42 at December 31, 2008 and $67 at December 31, 2007)		1,653		1,767
Inventory		1,135		1,012
Assets held for sale		—		2
Other		1,448		1,020
Total current assets		5,273		4,916
Investments and Other Assets
Investments in unconsolidated affiliates		473		696
Nuclear decommissioning trust funds		1,436		1,929
Goodwill		4,720		4,642
Intangibles, net		680		720
Notes receivable		134		153
Assets held for sale		—		115
Other		2,577		2,944
Total investments and other assets		10,020		11,199
Property, Plant and Equipment
Cost		50,304		46,056
Less accumulated depreciation and amortization		16,268		14,946
Net property, plant and equipment		34,036		31,110
Regulatory Assets and Deferred Debits
Deferred debt expense		257		255
Regulatory assets related to income taxes		625		552
Other		2,866		1,654
Total regulatory assets and deferred debits		3,748		2,461
Total Assets	$	53,077	$	49,686

See Notes to Consolidated Financial Statements

85

PART II

DUKE ENERGY CORPORATION

Consolidated Balance Sheets—(Continued)

(In millions, except per-share amounts)

	December 31,
	2008			2007
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,477		$	1,585
Notes payable and commercial paper		543			742
Taxes accrued		362			383
Interest accrued		187			145
Liabilities associated with assets held for sale		—			114
Current maturities of long-term debt		646			1,526
Other		1,130			1,203
Total current liabilities		4,345			5,698
Long-term Debt		13,250			9,498
Deferred Credits and Other Liabilities
Deferred income taxes		5,117			4,751
Investment tax credit		148			161
Liabilities associated with assets held for sale		—			3
Asset retirement obligations		2,567			2,351
Other		6,499			5,844
Total deferred credits and other liabilities		14,331			13,110
Commitments and Contingencies
Minority Interests		163			181
Common Stockholders’ Equity
Common Stock, $0.001 par value, 2 billion shares authorized; 1,272 million and 1,262 million shares outstanding at December 31, 2008 and December 31, 2007, respectively		1			1
Additional paid-in capital		20,106			19,933
Retained earnings		1,607			1,398
Accumulated other comprehensive loss		(726	)		(133	)
Total common stockholders’ equity		20,988			21,199
Total Liabilities and Common Stockholders’ Equity	$	53,077		$	49,686

See Notes to Consolidated Financial Statements

86

PART II

DUKE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(In millions)

	Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,362		$	1,500		$	1,863
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)		1,834			1,888			2,215
Extraordinary items, net of tax		(67	)		—			—
Gains on sales of investments in commercial and multi-family real estate		—			—			(201	)
(Gains) losses on sales of other assets		(95	)		10			(365	)
Impairments and other charges		94			—			48
Deferred income taxes		485			669			250
Minority Interest		(4	)		2			61
Equity in loss (earnings) of unconsolidated affiliates		102			(157	)		(732	)
Contributions to company-sponsored pension and other post-retirement benefit plans		—			(412	)		(172	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(33	)		—			(134	)
Receivables		189			(240	)		844
Inventory		(209	)		(36	)		(24	)
Other current assets		(449	)		(22	)		1,276
Increase (decrease) in
Accounts payable		(136	)		(172	)		(1,524	)
Taxes accrued		47			(134	)		(69	)
Other current liabilities		(88	)		(321	)		(594	)
Capital expenditures for residential real estate		—			—			(322	)
Cost of residential real estate sold		—			—			143
Other, assets		236			739			1,005
Other, liabilities		60			(106	)		180
Net cash provided by operating activities		3,328			3,208			3,748
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(4,386	)		(3,125	)		(3,381	)
Investment expenditures		(147	)		(91	)		(89	)
Acquisitions, net of cash acquired		(389	)		(66	)		(284	)
Cash acquired from acquisition of Cinergy		—			—			147
Purchases of available-for-sale securities		(7,353	)		(23,639	)		(33,436	)
Proceeds from sales and maturities of available-for-sale securities		7,454			24,613			32,596
Net proceeds from the sales of other assets, and sales of and collections on notes receivable		92			154			2,861
Proceeds from the sales of commercial and multi-family real estate		—			—			254
Settlement of net investment hedges and other investing derivatives		—			(10	)		(163	)
Distributions from equity investments		—			—			152
Purchases of emission allowances		(62	)		(103	)		(228	)
Sales of emission allowances		104			52			194
Change in restricted cash		115			68			47
Other		(39	)		(4	)		2
Net cash used in investing activities		(4,611	)		(2,151	)		(1,328	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		4,794			823			2,369
Issuance of common stock related to employee benefit plans		133			50			127
Payments for the redemption of:
Long-term debt		(2,130	)		(1,248	)		(2,098	)
Preferred stock of a subsidiary		—			—			(12	)
Convertible Notes		—			(110	)		—
Decrease in cash overdrafts		—			(2	)		(2	)
Notes payable and commercial paper		(73	)		617			(412	)
Distributions to minority interests		(2	)		(52	)		(304	)
Contributions from minority interests		6			68			247
Cash distributed to Spectra Energy		—			(395	)		—
Dividends paid		(1,143	)		(1,089	)		(1,488	)
Repurchase of common shares		—			—			(500	)
Proceeds from Duke Energy Income Fund		—			—			104
Other		6			11			8
Net cash provided by (used in) financing activities		1,591			(1,327	)		(1,961	)
Changes in cash and cash equivalents included in assets held for sale		—			—			(22	)
Net increase (decrease) in cash and cash equivalents		308			(270	)		437
Cash and cash equivalents at beginning of period		678			948			511
Cash and cash equivalents at end of period	$	986		$	678		$	948
Supplemental Disclosures:
Cash paid for interest, net of amount capitalized	$	677		$	827		$	1,154
Cash paid for income taxes	$	322		$	367		$	460
Significant non-cash transactions:
Distribution of Spectra Energy to shareholders	$	—		$	5,219		$	—
Conversion of convertible notes to stock	$	—		$	—		$	632
Accrued capital expenditures	$	378		$	570		$	308
Acquisition of Cinergy Corp.
Fair value of assets acquired	$	—		$	—		$	17,304
Liabilities assumed	$	—		$	—		$	12,709
Issuance of common stock	$	—		$	—		$	8,993

See Notes to Consolidated Financial Statements

87

PART II

DUKE ENERGY CORPORATION

Consolidated Statements of Common Stockholders' 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			Minimum Pension Liability Adjustment			Other			Pension and OPEB Related Adjustments to AOCI			Total
Balance December 31, 2005	928		$	10,446		$	—		$	5,277		$	846		$	(87	)	$	(60	)	$	17		$	—		$	16,439
Net income	—			—			—			1,863			—			—						—			—			1,863
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			103			—			—			—			—			103
Net unrealized gains on cash flow hedges(a)	—			—			—			—			—			6			—			—			—			6
Reclassification into earnings from cash flow hedges (b)	—			—			—			—			—			36			—			—			—			36
Minimum pension liability adjustment(c)	—			—			—			—			—			—			(1	)		—			—			(1	)
Other(d)	—			—			—			—			—			—			—			(15	)		—			(15	)
Total comprehensive income																												1,992
Retirement of old Duke Energy shares	(927	)		(10,399	)		—			—			—			—			—			—			—			(10,399	)
Issuance of new Duke Energy shares	927			1			10,398			—			—			—			—			—			—			10,399
Common stock issued in connection with Cinergy merger	313			—			8,993			—			—			—			—			—			—			8,993
Conversion of Cinergy options to Duke Energy options	—			—			59			—			—			—			—			—			—			59
Dividend reinvestment and employee benefits	6			22			172			—			—			—			—			—			—			194
Stock repurchase	(17	)		(69	)		(431	)		—			—			—			—			—			—			(500	)
Common stock dividends	—			—			—			(1,488	)		—			—			—			—			—			(1,488	)
Conversion of debt to equity	27			—			632			—			—			—			—			—			—			632
Tax benefit due to conversion of debt to equity	—			—			34			—			—			—			—			—			—			34
SFAS No. 158 funded status provision(e)	—			—			—			—			—			—			61			—			(311	)		(250	)
Other capital stock transactions, net	—			—			(3	)		—			—			—			—			—			—			(3	)
Balance December 31, 2006	1,257		$	1		$	19,854		$	5,652		$	949		$	(45	)	$	—		$	2		$	(311	)	$	26,102
Net income	—			—			—			1,500			—			—			—			—			—			1,500
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			200			—			—			—			—			200
Net unrealized losses on cash flow hedges(a)	—			—			—			—			—			(14	)		—			—			—			(14	)
Reclassification into earnings from cash flow hedges(b)	—			—			—			—			—			(1	)		—			—			—			(1	)
SFAS No. 158 amortization	—			—			—			—			—			—			—			—			14			14
SFAS No. 158 net actuarial gain(f)	—			—			—			—			—			—			—			—			96			96
Other(d)	—			—			—			—			—			—			—			—			1			1
Total comprehensive income																												1,796
Adoption of FIN 48	—			—			—			(25	)		—			—			—			—			—			(25	)
Adoption of SFAS No. 158—measurement date provision	—			—			—			(28	)		—			—			—			—			(22	)		(50	)
Distribution of Spectra Energy to shareholders	—			—			—			(4,612	)		(1,156	)		6			—			—			148			(5,614	)
Dividend reinvestment and employee benefits	5			—			79			—			—			—			—			—			—			79
Common stock dividends	—			—			—			(1,089	)		—			—			—			—			—			(1,089	)
Balance December 31, 2007	1,262		$	1		$	19,933		$	1,398		$	(7	)	$	(54	)	$	—		$	2		$	(74	)	$	21,199
Net income	—			—			—			1,362			—			—			—			—			—			1,362
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			(299	)		—			—			—			—			(299	)
Net unrealized gains on cash flow hedges(a)	—			—			—			—			—			10			—			—			—			10
Reclassification into earnings from cash flow hedges(b)	—			—			—			—			—			3			—			—			—			3
Pension and OPEB related adjustments to AOCI	—			—			—			—			—			—			—			—			3			3
SFAS No. 158 net actuarial loss(g)	—			—			—			—			—			—			—			—			(280	)		(280	)
Unrealized loss on investments in auction rate securities(h)	—			—			—			—			—			—			—			(28	)		—			(28	)
Reclassification of losses on investments in auction rate securities and other available-for-sale securities into earnings(i)	—			—			—			—			—			—			—			8			—			8
Unrealized loss on investments in available-for-sale securities(j)	—			—			—			—			—			—			—			(10	)		—			(10	)
Total comprehensive income																												769
Common stock issuances	7			—			103			—			—			—			—			—			—			103
Dividend reinvestment and employee benefits	3			—			70			—			—			—			—			—			—			70
Common stock dividends	—			—			—			(1,143	)		—			—			—			—			—			(1,143	)
Additional amounts related to the spin-off of Spectra Energy	—			—			—			(10	)		—			—			—			—			—			(10	)
Balance December 31, 2008	1,272		$	1		$	20,106		$	1,607		$	(306	)	$	(41	)	$	—		$	(28	)	$	(351	)	$	20,988

(a) Net unrealized gains (losses) on cash flow hedges, net of $6 tax expense in 2008, $9 tax benefit in 2007 and $3 tax expense in 2006.

(b) Reclassification into earnings from cash flow hedges, net of $2 tax expense in 2008, zero in 2007 and $19 tax expense in 2006. Reclassification into earnings from cash flow hedges in 2006 is due primarily to the recognition of former Duke Energy North America’s (DENA) unrealized net gains related to hedges on forecasted transactions which did not occur as a result of the sale to LS Power of substantially all of former DENA’s assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets.

(c) Minimum pension liability adjustment, net of zero tax benefit in 2006.

(d) Net of zero tax expense in 2007 and $9 tax benefit in 2006.

(e) SFAS No. 158 adjustment, net of $144 tax benefit in 2006. Excludes $595 reflected as regulatory assets.

(f) SFAS No. 158 net actuarial gain net of $54 tax expense in 2007. Excludes $204 reflected as regulatory assets.

(g) SFAS No. 158 actuarial loss net of $159 tax benefit in 2008. Excludes $767 reflected as regulatory assets.

(h) Net of $18 tax benefit in 2008.

(i) Net of $5 tax expense in 2008.

(j) Net of $8 tax benefit in 2008.

See Notes to Consolidated Financial Statements

88

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements

For the Years Ended December 31, 2008, 2007 and 2006

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. 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.

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

Shares of common stock of New Duke Energy carry a stated par value of $0.001, while shares of common stock of Old Duke Energy had been issued at no par. In April 2006, as a result of the conversion of all outstanding shares of Old Duke Energy common stock to New Duke Energy common stock, the par value of the shares issued was recorded in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets and the excess of issuance price over stated par value was recorded in Additional Paid-in Capital within Common Stockholders’ Equity in the Consolidated Balance Sheets. Prior to the conversion of common stock from shares of Old Duke Energy to New Duke Energy, all proceeds from issuances of common stock were solely reflected in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets.

On September 7, 2006, Duke Energy deconsolidated Crescent Resources, LLC (Crescent) due to a reduction in ownership causing an inability to exercise control over Crescent (see Note 3). Crescent has been accounted for as an equity method investment since the date of deconsolidation. See Note 12 for a discussion of the suspension of application of the equity method of accounting related to Duke Energy’s investment in Crescent beginning in the fourth quarter of 2008.

On January 2, 2007, Duke Energy completed the spin-off to shareholders of its natural gas businesses. The new natural gas business, which is named Spectra Energy Corp. (Spectra Energy), consists principally of certain operations of Spectra Energy Capital, LLC (Spectra Energy Capital, formerly Duke Capital LLC), primarily Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former Field Services business segment, which represented Duke Energy’s 50% ownership interest in DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) (DCP Midstream). Excluded from the spin-off were certain operations which were transferred from Spectra Energy Capital to Duke Energy in December 2006, primarily International Energy and Duke Energy’s effective 50% interest in the Crescent Resources joint venture (Crescent JV), which is discussed further in Note 3. Subsequent to the spin-off, the results of operations of the spun off businesses are presented as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the spin-off. 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, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV. 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 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

89

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. Additionally, cash flows related to the businesses included in the spin-off are included in the Consolidated Statements of Cash Flows for the year ended December 31, 2006.

Use of Estimates. To conform to generally accepted accounting principles (GAAP) in the United States (U.S.), 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.

Reapplication of SFAS No. 71 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 the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. As described further below, effective December 17, 2008, the Public Utilities Commission of Ohio (PUCO) approved Commercial Power’s Electric Security Plan (ESP), which resulted in the reapplication of SFAS No. 71 to certain portions of Commercial Power’s operations as of that date.

From January 1, 2005 through December 31, 2008, Commercial Power had been operating 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, upon the expiration of the RSP, there would be a move to full competitive markets. Accordingly, Commercial Power did not apply the provisions of SFAS No. 71 to any of its generation operations prior to December 17, 2008. As discussed further in Note 4, 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 Market Rate Option (MRO). The MRO is a price determined through a competitive bidding process. On July 31, 2008, Duke Energy Ohio, Inc. (Duke Energy Ohio) filed an ESP, and with certain amendments, the ESP was approved by the PUCO on December 17, 2008. The ESP became effective on January 1, 2009.

In connection with the approval of the ESP, Duke Energy reassessed the applicability of SFAS No. 71 to Commercial Power’s generation operations as SB 221 substantially increased the PUCO’s oversight authority over generation in the state of Ohio, including giving the PUCO complete approval of generation rates and the establishment of an earnings test to determine if a utility has earned significantly excessive earnings. Duke Energy determined that certain costs and related rates (riders) of Commercial Power’s operations related to generation serving native load meet the criteria established by SFAS No. 71 for regulatory accounting treatment as SB 221 and Duke Energy’s approved ESP solidified the automatic recovery of 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 foreseeable future.

Under the ESP, Commercial Power will bill for its native load generation via numerous riders. SB 221 and the ESP resulted in the approval of the automatic recovery of certain of these riders, which includes, but is not limited to, a fuel and purchased power (FPP) rider and certain portions of a cost of environmental compliance (AAC) rider. Accordingly, Commercial Power began applying SFAS No. 71 to the corresponding RSP riders granting automatic 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 automatic cost 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 criteria of SFAS No. 71. 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. 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.

Despite certain portions of the Ohio native load operations not being subject to the accounting provisions of SFAS No. 71, 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.

90

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Extraordinary item. The reapplication of SFAS No. 71 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 FPP rider. There were no other immediate income statement impacts on the date of reapplication of SFAS No. 71. 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, 2008 and 2007, Duke Energy had approximately $85 million and $166 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. This amount is reflected in Other Current Assets and Other Investments and Other Assets on the Consolidated Balance Sheets.

Inventory. Inventory consists primarily of materials and supplies and coal held for electric generation 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,
	2008		2007
	(in millions)
Materials and supplies	$	661	$	555
Coal held for electric generation		471		388
Natural gas		3		69
Total inventory	$	1,135	$	1,012

Effective November 1, 2008, Duke Energy Ohio and Duke Energy Kentucky, Inc. (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 will be stored and managed for Duke Energy Ohio and Duke Energy Kentucky and will be delivered on demand. The gas storage agreements will expire on October 31, 2009, unless extended by the third party for an additional 12 months. 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 has been classified as Other within Current Assets on the Consolidated Balance Sheets.

Accounting for Risk Management and 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, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS No. 133), are recorded on the Consolidated Balance Sheets at their fair value. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net investment hedges and other investing activities, are presented as a component of operating cash flows in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are presented as a component of financing cash flows in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows related to net investment hedges and derivatives related to other investing activities are presented as a component of investing cash flows in the accompanying Consolidated Statements of Cash Flows.

91

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Duke Energy has designated all energy commodity derivatives as non-trading subsequent to the October 2006 sale of Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (collectively CMT), which is discussed further in Note 14. Gains and losses for all derivative contracts that do not represent physical delivery contracts are reported on a net basis in the Consolidated Statements of Operations. For each of Duke Energy’s physical delivery contracts that are derivatives, the accounting model and presentation of gains and losses, or revenue and expense in the Consolidated Statements of Operations is shown below.

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

(a) An accounting term used by Duke Energy to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is generally recognized in the Consolidated Statements of Operations for the non-regulated businesses and the Consolidated Balance Sheets within regulatory assets or regulatory liabilities for the regulated businesses. This term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within GAAP, Duke Energy’s application of this term could differ from that of other companies.

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

On January 1, 2008, Duke Energy adopted FASB Staff Position (FSP) No. FIN 39-1, “Amendment of FASB Interpretation No 39, Offsetting of Amounts Related to Certain Contracts” (FSP No. FIN 39-1). In accordance with FSP No. FIN 39-1, 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. Prior to the adoption of FSP No. FIN 39-1, Duke Energy offset the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting agreement in accordance with FIN 39, “Offsetting of Amounts Related to Certain Contracts,” but presented cash collateral on a gross basis within the Consolidated Balance Sheets. At December 31, 2008 and 2007, Duke Energy had receivables related to the right to reclaim cash collateral of approximately $86 million and $5 million, respectively, and had payables related to obligations to return cash collateral of an insignificant amount at each balance sheet date that have been offset against net derivative positions in the Consolidated Balance Sheets. Additionally, Duke Energy had cash collateral receivables of approximately $53 million and $15 million under master netting arrangements that have not been offset against net derivative positions at December 31, 2008 and 2007, respectively, as these amounts primarily represent initial margin deposits related to New York Mercantile Exchange (NYMEX) futures contracts. Duke Energy had insignificant cash collateral payables under master netting arrangements that have not been offset against net derivative positions at December 31, 2008 and December 31, 2007.

Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all contracts accounted for as a hedge, Duke Energy prepares formal documentation of the hedge in accordance with SFAS No. 133. 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).

92

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

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

Normal Purchases and Normal Sales (NPNS). On a limited basis, Duke Energy applies the NPNS exception to certain contracts. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for prospectively using the MTM Model unless immediately designated as a cash flow or fair value hedge.

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

Investments in Debt and Equity Securities. Duke Energy accounts for investments in debt and equity securities pursuant to SFAS No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” (SFAS No. 115). Accordingly, Duke Energy has classified investments in debt and equity securities into two categories – trading and available-for-sale. Certain investments in debt and equity securities held in grantor trusts associated with certain deferred compensation plans are classified as trading securities in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested.” These investments are reported at fair value in the Consolidated Balance Sheets with net realized and unrealized gains and losses included in earnings each period to effectively offset the corresponding earnings impact associated with the change in the fair value of the deferred compensation liability to which the investments relate. 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 included in AOCI or a regulatory asset or liability, 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 is included in earnings, unless deferred in accordance with a regulatory order. 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.

Duke Energy analyzes all securities classified as available-for-sale to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment is other-than-temporary includes, but is not limited to, the length of time over which the market value has been lower than the cost basis of the investment, the percentage decline compared to the cost of the investment and management’s intent and ability to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. If a decline in fair value is determined to be other-than-temporary, the investment is written down to its fair value. See Note 13 for a discussion of other-than-temporary impairments recorded during the year ended December 31, 2008.

Duke Energy holds investments in debt and equity securities in a Nuclear Decommissioning Trust Fund (NDTF), which are considered available-for-sale securities and are reported at fair value on Duke Energy’s Consolidated Balance Sheets. Since Duke Energy does not have day-to-day oversight of the investments in the NDTF, management does not have the ability to demonstrate the intent and ability to hold investments for a period of time sufficient to allow for any anticipated recovery in market value. Accordingly, management considers all securities held in the NDTF with market values below their respective original or adjusted cost basis to be other-than-temporarily impaired any time the original or adjusted cost basis exceeds the market value of the investment. However, realized and unrealized gains and losses, net of tax, on the NDTF holdings are deferred and reflected as regulatory assets or liabilities on Duke Energy’s Consolidated

93

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Balance Sheets as Duke Energy expects to recover all costs for decommissioning its nuclear generation assets through regulated rates pursuant to a regulatory order by the North Carolina Utilities Commission (NCUC).

See Note 10 for further information on the investments in debt and equity securities, including investments held in the NDTF.

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

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the determined fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.

Duke Energy primarily uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate, estimated future cash flows and 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. See Note 11 for further information.

Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Duke Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction (see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” 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 3.11% for 2008, 3.19% for 2007, and 3.51% for 2006. 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 15 for further information on the components and estimated useful lives of Duke Energy’s property, plant and equipment balance.

Asset Retirement Obligations. Duke Energy recognizes asset retirement obligations in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations” (SFAS No. 143), for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), for conditional asset retirement obligations. The term conditional asset retirement obligation as used in SFAS No. 143 and FIN 47 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. Both SFAS No. 143 and FIN 47 require that the present value of the projected liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The 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.

Investments in Residential, Commercial, and Multi-Family Real Estate. Prior to the deconsolidation of Crescent in September 2006, investments in residential, commercial and multi-family real estate were carried at cost, net of any related depreciation. However, any properties meeting the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (SFAS No. 144), to

94

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

be presented as Assets Held for Sale, were carried at lower of cost or fair value less costs to sell in the Consolidated Balance Sheets. Proceeds from sales of residential properties prior to September 2006 are presented within Operating Revenues and the costs of properties sold prior to the date of deconsolidation are included in Operation, Maintenance and Other in the Consolidated Statements of Operations. Cash flows related to the acquisition, development and disposal of residential properties prior to the date of deconsolidation are included in Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Gains and losses on sales of commercial and multi-family properties as well as “legacy” land sales prior to the date of deconsolidation are presented as such in the Consolidated Statements of Operations, and cash flows related to these activities are included in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

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

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

Duke Energy uses the criteria in SFAS No. 144 and Emerging Issues Task Force (EITF) 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (EITF 03-13), to determine whether components of Duke Energy that are being disposed of, are classified as held for sale or have been wound down are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Energy must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the operations being disposed of must have been eliminated from Duke Energy’s ongoing operations (i.e. Duke Energy does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected within discontinued operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded as a component of continuing operations in the Consolidated Statements of Operations. Impairments for all other long-lived assets are recorded as Impairments Charges in the Consolidated Statements of Operations. See Note 14 for discussion of discontinued operations.

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 workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred but not yet reported (IBNR), as well as provisions for known claims which have been estimated on a claims-incurred basis. IBNR reserve estimates involve the use of assumptions and are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience.

95

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. Duke Energy is involved in certain legal and environmental matters that arise in the normal course of business. Loss contingencies are accounted for under SFAS No. 5, “Accounting for Contingencies,” (SFAS No. 5). Under SFAS No. 5, 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. See Note 18 for further information.

Environmental Expenditures. Duke Energy expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded 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.

Severance and Special Termination Benefits. Duke Energy has an ongoing severance plan that is accounted for primarily under SFAS No. 112, “Employers’ Accounting for Postemployment Benefits” (SFAS No. 112). In general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits under this ongoing severance plan. Under SFAS No. 112, Duke Energy records a liability for severance once a plan is committed to by management, or sooner if severances are probable and the related severance benefits can be reasonably estimated. Duke Energy accounts for involuntary severance benefits that are incremental to its ongoing severance plan benefits in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS No. 146). Under SFAS No. 146, Duke Energy measures the obligation when all the criteria of SFAS No. 146 are met 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. These voluntary severance programs may or may not include severance payments accounted for under the ongoing severance plan. Special termination benefits are accounted for under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (SFAS No. 88). Under SFAS No. 88, 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. See Note 13 for further information on Duke Energy’s severance programs.

Cost-Based Regulation. Duke Energy accounts for certain of its regulated operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers 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. Duke Energy periodically

96

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, 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 the accounting provisions of SFAS No. 71 and record regulatory assets and liabilities, the scope criteria in SFAS No. 71 must be met. Management makes significant judgments in determining whether the scope criteria of SFAS No. 71 are met for its operations, 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 set forth in SFAS No. 71 when such criteria had not been previously met, SFAS No. 71 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 of SFAS 71. Refer to the above section titled, “Reapplication of SFAS No. 71 to Portions of Generation in Ohio.”

Guarantees. Duke Energy accounts for guarantees and related contracts, for which it is the guarantor, under FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Duke Energy recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee, 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 under FIN 45 is accounted for and recognized in accordance with SFAS No. 5 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 19 for further information.

Stock-Based Compensation. Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). SFAS No. 123(R) establishes accounting for stock-based awards, including stock options, exchanged for employee and certain non-employee services. Accordingly, 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 21 for further information.

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. Unbilled revenues are estimated by applying an average revenue per kilowatt-hour or per thousand cubic feet (Mcf) for all customer classes to the number of estimated kilowatt-hours or Mcfs delivered but not billed. The amount of unbilled revenues can vary significantly period to period as a result of factors including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are recorded as Receivables in Duke Energy’s Consolidated Balance Sheets at December 31, 2008 and 2007, were approximately $360 million and $380 million, respectively.

Prior to the deconsolidation of Crescent in September 2006, profit from the sale of residential developed lots was recognized at closing under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs were allocated to land sold based on relative sales values. Crescent recognized revenues from commercial and multi-family project sales at closing, or later using a deferral method when the criteria for sale accounting had not been met. Profit was recognized based on the difference between the sales price and the carrying cost of the project. Revenue was recognized under the completed contract method for condominium units that Crescent developed and sold in Florida.

97

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

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.

Deferred Returns and AFUDC. Deferred returns, recorded in accordance with SFAS No. 71, represent the estimated financing costs associated with funding certain regulatory assets or liabilities of the U.S. Franchised Electric and Gas segment. The amount of deferred return expense included in Other Income and Expenses, net was $11 million in 2008, $15 million in 2007, and $14 million in 2006.

In accordance with regulatory treatment, 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. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $205 million in 2008, which consisted of an after-tax equity component of $148 million and a before-tax interest expense component of $57 million. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $109 million in 2007, which consisted of an after-tax equity component of $69 million and a before-tax interest expense component of $40 million. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $75 million in 2006, which consisted of an after-tax equity component of $46 million and a before-tax interest expense component of $29 million. The 2006 amount excludes AFUDC and capitalized interest of approximately $22 million for the year ended December 31, 2006, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

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.

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 and recognizes the allowances in earnings as they are consumed or sold. Gains or losses on sales of emission allowances for 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. For regulated businesses that do not provide for direct recovery of emission allowances through a cost tracking mechanism, gains and losses on sales of emission allowances are included in Gains (Losses) on Sales of Other Assets and Other, net in the Consolidated Statements of Operations, or are deferred, depending on level of regulatory certainty. Purchases and sales of emission allowances are presented gross as investing activities on the Consolidated Statements of Cash Flows. See Note 13 for discussion regarding the impairment of the carrying value of certain emission allowances in 2008.

98

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

Management evaluates and records uncertain tax positions in accordance with FIN 48, “Accounting For Uncertainty in Income Taxes—an Interpretation of FASB Statement 109,” (FIN 48), which was adopted by Duke Energy on January 1, 2007. 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. In accordance with FIN 48, 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.

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.

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 revenues in the accompanying Consolidated Statements of Operations were approximately $278 million, $277 million and $221 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131), establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. There is no aggregation within Duke Energy’s reportable business segments. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, including products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Energy’s reportable segments, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, is presented in Note 2.

Foreign Currency Translation. The local currencies of Duke Energy’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation, in accordance with SFAS No. 52, “Foreign Currency Translation.” Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at 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 24 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. Deferred taxes are not provided on translation gains and losses where Duke Energy expects earnings of a foreign operation to be permanently reinvested. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in foreign currency translation as a separate component of AOCI.

99

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Statements of Consolidated Cash Flows. Duke Energy has made certain classification elections within its Consolidated Statements of Cash Flows related to discontinued operations, cash received from insurance proceeds, debt restricted for qualified capital and maintenance expenditures and cash overdrafts. 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. Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds (for example, general liability insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities). Proceeds from debt issued with restrictions to fund future capital and maintenance expenditures are presented on a gross basis, with the debt proceeds classified as a financing cash inflow and the changes in the restricted funds held in trust presented as a component of investing activities. With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts are included within financing cash flows.

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

Dividend Restrictions and Unappropriated Retained Earnings. Duke Energy does not have any legal, regulatory or other restrictions on paying common stock dividends to shareholders. As further described in Note 4, certain wholly-owned subsidiaries have restrictions on paying dividends or otherwise advancing funds to Duke Energy. At December 31, 2008 and 2007, 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, 2008 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). Refer to Note 9 for a discussion of Duke Energy’s adoption of SFAS No. 157.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities- including an amendment of FASB Statement No. 115” (SFAS No. 159). Refer to Note 9 for a discussion of Duke Energy’s adoption of SFAS No. 159.

FSP No. FIN 39-1. Refer to “Accounting for Risk Management and Hedging Activities and Financial Instruments” above for a discussion of Duke Energy’s adoption of FSP No. FIN 39-1.

EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11). In June 2007, the EITF reached a consensus that would require realized income tax benefits from dividends or dividend equivalents that are charged to retained earnings and paid to employees for equity-classified nonvested equity shares, nonvested equity share units, and outstanding equity share options to be recognized as an increase to additional paid-in capital. In addition, EITF 06-11 requires that dividends on equity-classified share-based payment awards be reallocated between retained earnings (for awards expected to vest) and compensation cost (for awards not expected to vest) each reporting period to reflect current forfeiture estimates. For Duke Energy, EITF 06-11 has been applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning January 1, 2008, as well as interim periods within those fiscal years. The adoption of EITF 06-11 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interest in Variable Interest Entities” (FSP FAS 140-4 and FIN 46(R)-8). In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, which amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” (SFAS No. 140) to require public entities to provide additional disclosures about transfers of financial assets and, FIN No. 46(R), to require public enterprises to provide additional disclosures about their involvement with variable interest entities. Additionally, this FSP requires certain disclosures to be provided by a public enterprise that is (a) a sponsor that has a variable interest in a variable interest entity and (b) an enterprise that holds a significant variable interest in a qualifying special-purpose entity (SPE) but was not the transferor (nontransferor enterprise) of financial assets to the qualifying SPE. The disclosures required by this FSP 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 variable interest entities. The disclosure requirements of this FSP were effective for Duke Energy beginning December 31, 2008. The adoption of FSP FAS 140-4 and FIN 46(R)-8 did not have any impact on Duke Energy’s consolidated results of operations, cash flows or financial position. See Note 23 for additional information.

100

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

FSP EITF 99-20-1, “Amendments to the Impairment Guidance of EITF Issue No. 99-20” (FSP EITF 99-20-1). In January 2009, the FASB issued FSP EITF 99-20-1, which amends EITF Issue No. 99-20, “Recognition of Interest Income and Impairment on Purchased Beneficial Interests and Beneficial Interests That Continue to Be Held by a Transferor in Securitized Financial Assets,” to achieve more consistent determinations of whether an other-than-temporary impairment has occurred for debt securities that are beneficial interests in securitized financial assets. FSP EITF 99-20-1 eliminates the requirement that a holder’s best estimate of cash flows be based upon those that a market participant would use and establishes that an other-than-temporary impairment on a debt security that is a beneficial interest in a securitized financial asset would be recognized as a realized loss through earnings when it is probable that there has been an adverse change in the holder’s estimated cash flows from the cash flows previously projected, which is consistent with the impairment model is SFAS No. 115. FSP EITF 99-20-1 also retains and emphasizes the objective of an other-than-temporary impairment assessment and the related disclosure requirements in SFAS No. 115 and other related guidance. For Duke Energy, FSP EITF 99-20-1 was effective beginning December 15, 2008. The adoption of FSP EITF 99-20-1 did not have any impact on the carrying value of Duke Energy’s note receivable from Cinergy Receivables, which is considered a retained beneficial interest in a securitized financial asset. See Note 23 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:

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133 and SFAS No. 140. SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 was effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that had been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. The adoption of SFAS No. 155 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140” (SFAS No. 156). In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 was effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. The adoption of SFAS No. 156 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement 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. SFAS No. 158 does 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 SFAS No. 158 recognition and disclosure provisions resulted in an increase in total assets of approximately $211 million (consisting of an increase in regulatory assets of $595 million, an increase in deferred tax assets of $144 million, offset by a decrease in pre-funded pension costs of $522 million and a decrease in intangible assets of $6 million), an increase in total liabilities of approximately $461 million and a decrease in AOCI, net of tax, of approximately $250 million as of December 31, 2006. The adoption of SFAS No. 158 did not have a material impact on Duke Energy’s consolidated results of operations or cash flows.

101

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Under the measurement date requirements of SFAS No. 158, 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 has 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 SFAS No. 158. See Note 22.

FIN 48. In July 2006, the FASB issued FIN 48, which provides 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. FIN 48 prescribes 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 FIN 48 effective January 1, 2007. See Note 6 for additional information.

FSP No. FIN 48-1, Definition of “Settlement” in FASB Interpretation No. 48 (FSP No. FIN 48-1). In May, 2007, the FASB staff issued FSP No. FIN 48-1 which clarifies the conditions under FIN 48 that should be met for a tax position to be considered effectively settled with the taxing authority. Duke Energy’s adoption of FIN 48 as of January 1, 2007 was consistent with the guidance in this FSP.

FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230–A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable GAAP. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP was effective for Duke Energy as of January 1, 2007. As discussed in Note 21, effective with the spin-off of Spectra Energy on January 2, 2007, all previously granted Duke Energy long-term incentive plan equity awards were modified to equitably adjust the awards. As the modifications to the equity awards were made solely to reflect the spin-off, no change in the recognition or the measurement (due to a change in classification) of those instruments resulted.

The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2006 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

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

Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Duke Energy is required to recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. 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.

102

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The adoption of SFAS No. 123(R) did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. See Note 21.

SAB No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006 the Securities and Exchange Commission (SEC) issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement—including the reversing effect of prior year misstatements—but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

SAB No. 108 was effective for Duke Energy’s year ending December 31, 2006. SAB No. 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been used or (ii), under certain circumstances, recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. Duke Energy has historically used a dual approach for quantifying identified financial statement misstatements. Therefore, the adoption of SAB No. 108 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of December 31, 2008:

SFAS No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). In December 2007, the FASB issued SFAS No. 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R retains the fundamental requirements in SFAS No. 141 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 establishes 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, SFAS No. 141R must be applied prospectively to business combinations for which the acquisition date occurs on or after January 1, 2009. The impact to Duke Energy of applying SFAS No. 141R for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of SFAS No. 141R. SFAS No. 141R changes the accounting for income taxes related to prior business combinations, such as Duke Energy’s merger with Cinergy. Subsequent to the effective date of SFAS No. 141R, the resolution of tax contingencies relating to Cinergy that existed as of the date of the merger will be 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.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS No. 160). In December 2007, the FASB issued SFAS No. 160, which amends ARB No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies 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 statement also changes 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, SFAS No. 160 establishes 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, SFAS No. 160 is effective as of January 1, 2009, and must be applied prospectively, except for certain presentation and disclosure requirements which must be applied retrospectively. The adoption of SFAS No. 160 will impact the presentation of noncontrolling interests in Duke Energy’s Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income, as well as the calculation of Duke Energy’s effective tax rate.

103

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment to FASB Statement No. 133” (SFAS No. 161). In March 2008, the FASB issued SFAS No. 161, which amends and expands the disclosure requirements for derivative instruments and hedging activities prescribed by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, 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 will adopt SFAS No. 161 as of January 1, 2009 and SFAS No. 161 encourages, but does not require, comparative disclosure for earlier periods at initial adoption. The adoption of SFAS No. 161 will not have any impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1). In May 2008, the FASB issued FSP APB 14-1, which addresses the accounting for convertible debt securities that, upon conversion, may be settled by the issuer fully or partially in cash. FSP APB 14-1 does not change the accounting for more traditional types of convertible debt securities that do not have a cash settlement feature and FSP APB 14-1 does not apply if, under existing GAAP for derivatives, the embedded conversion feature must be accounted for separately from the rest of the instrument. For Duke Energy, FSP APB 14-1 is applicable as of January 1, 2009 and must be applied retrospectively to all prior periods presented, even if the instrument has matured, has been converted, or has otherwise been extinguished as of the effective date of FSP APB 14-1. Duke Energy is currently evaluating the impact of adopting FSP APB 14-1 on its historical results of operations as, in 2003, Duke Energy issued $770 million of convertible debt with a cash settlement option that was fully converted to common stock during the years ended December 31, 2005, 2006 and 2007; however, Duke Energy does not anticipate the retrospective application of FSP APB 14-1 will have a material impact on Duke Energy’s historical results of operations, cash flows or financial position. Future impacts of FSP APB 14-1 will be determined by whether Duke Energy issues convertible debt with cash settlement options.

FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). In June 2008, the FASB issued FSP EITF 03-6-1 to address whether instruments granted in share-based payment transactions may be participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing basic EPS pursuant to the two-class method described in SFAS No. 128. The FASB concluded that rights to dividends or dividend equivalents (whether paid or unpaid) on unvested share-based payment awards that provide a noncontingent transfer of value (such as a nonforfeitable right to receive cash when dividends are paid to common stockholders, irrespective of whether the award ultimately vests) to the holder of the share-based payment award constitute participation rights and, therefore, should be included in the computation of basic EPS using the two-class method. Duke Energy issues certain share-based payment awards under which rights to dividends during the vesting period are nonforfeitable. For Duke Energy, FSP EITF 03-6-1 is effective as of January 1, 2009 and all prior-period EPS data is required to be adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1. Duke Energy does not currently anticipate the adoption of FSP EITF 03-6-1 will have a material impact on its calculated future or historical EPS amounts.

FSP FAS 132(R)-1, “Employers’ Disclosure about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1). In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132(R) 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 SFAS No. 157 (i.e., Level 1, 2, and 3 of fair value hierarchy) along with a roll-forward of the Level 3 values each year. For Duke Energy, FSP FAS 132(R)-1 is effective for Duke Energy’s Form 10-K for the year ended December 31, 2009. The adoption of FSP FAS 132(R)-1 will not have any impact on Duke Energy’s 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 under SFAS No. 131: 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. Prior to the fourth quarter of 2008, Crescent was a reportable business segment of Duke Energy. Beginning in the fourth quarter of 2008, Crescent is no longer considered an operating segment of Duke Energy as Duke Energy’s chief operating decision maker no longer reviews Crescent’s operating results in order to make resource allocation decisions and evaluate its performance. Accordingly, the results of Crescent have been included in Other for all periods presented.

104

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, which primarily consisted of Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former Field Services business segment, which represented Duke Energy’s 50% ownership interest in DCP Midstream. Accordingly, results of operations for these former business segments are included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for the year ended December 31, 2006.

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, Inc. (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 NCUC, the Public Service Commission of South Carolina (PSCSC), the PUCO, the Indiana Utility Regulatory Commission (IURC) and the Kentucky Public Service Commission (KPSC). Substantially all of U.S. Franchised Electric and Gas’ operations are regulated and, accordingly, these operations are accounted for under the provisions of SFAS No. 71.

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 megawatts (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. Most of the generation asset output in Ohio was contracted through the RSP through December 31, 2008. As discussed further in Note 1 and Note 4, beginning on December 17, 2008, Commercial Power reapplied the provisions of SFAS No. 71 to certain portions of its operations due to the passing of SB 221 and the approval of the ESP. 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 6,300 megawatts 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 370 net MW of wind energy generating capacity in commercial operation, approximately 150 MW of wind energy under construction and more than 5,000 megawatts of wind energy projects in development.

International Energy 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 activities target power generation in Latin America. Additionally, International Energy owns equity investments in National Methanol Company (NMC), located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE), and Attiki Gas Supply S.A. (Attiki), which is a natural gas distributor located in Athens, Greece.

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, Crescent and DukeNet Communications, LLC (DukeNet) and related telecommunications. Additionally, Other includes Duke Energy Trading and Marketing, LLC (DETM), which 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 workers compensation, 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 develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North Carolina and South Carolina. As

105

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

discussed further in Note 3, on September 7, 2006, Duke Energy deconsolidated Crescent due to a reduction in ownership and its inability to exercise control over Crescent and has accounted for Crescent as an equity method investment since the date of deconsolidation. See Note 12 for discussion of the suspension of the application of the equity method of accounting related to Duke Energy’s investment in Crescent beginning in the fourth quarter of 2008. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations.

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, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. 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.

106

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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, 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(d)		75		59			134			(568	)		86		241		2,605
Eliminations and reclassifications		—		(97	)		(97	)		—			—		—		140
Interest expense		—		—			—			(741	)		—		—		—
Interest income and other(c)		—		—			—			131			—		—		—
Total consolidated	$	13,207	$	—		$	13,207		$	1,895		$	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(d)		75		92			167			(260	)		61		153		3,176
Eliminations and reclassifications		—		(128	)		(128	)		—			—		—		27
Interest expense		—		—			—			(685	)		—		—		—
Interest income and other(c)		—		—			—			208			—		—		—
Total consolidated	$	12,720	$	—		$	12,720		$	2,234		$	1,746	$	3,282	$	49,686
Year Ended December 31, 2006
U.S. Franchised Electric and Gas	$	8,077	$	21		$	8,098		$	1,811		$	1,280	$	2,381	$	34,346
Natural Gas Transmission(f)		—		—			—			—			—		790		19,002
Field Services(f)		—		—			—			—			—		—		1,233
Commercial Power		1,325		6			1,331			47			140		209		6,826
International Energy		943		—			943			163			73		58		3,332
Total reportable segments		10,345		27			10,372			2,021			1,493		3,438		64,739
Other(d)(e)		262		99			361			(5	)		52		638		3,990
Eliminations and reclassifications		—		(126	)		(126	)		—			—		—		(29	)
Interest expense		—		—			—			(632	)		—		—		—
Interest income and other(c)		—		—			—			146			—		—		—
Total consolidated	$	10,607	$	—		$	10,607		$	1,530		$	1,545	$	4,076	$	68,700

107

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

(d) In September 2006, Duke Energy completed a joint venture transaction of Crescent (see Note 3). As a result, Other includes the results of Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006. As discussed in Note 12, Duke Energy suspended accounting for Crescent as an equity method investment beginning in the fourth quarter of 2008.

(e) Capital expenditures for Crescent’s residential real estate are included in operating cash flows and were $322 million for the period from January 1, 2006 through the date of deconsolidation of Crescent (September 7, 2006).

(f) Both the former Natural Gas Transmission business segment and former Field Services business segment were included in the spin-off of Spectra Energy on January 2, 2007. The results of operations for these former business segments are presented as a component of Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations for the year ended December 31, 2006.

Geographic Data

	U.S.		Canada		Latin America		Consolidated
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
2006
Consolidated revenues	$	9,664	$	—	$	943	$	10,607
Consolidated long-lived assets		34,934		10,541		2,173		47,648

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. Assets acquired and liabilities assumed are recorded at estimated fair values on the purchase date. The purchase price minus the estimated fair value of the acquired tangible and identifiable intangible assets and liabilities meeting the definition of a business as defined in EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional, requested information is received during the allocation period, which generally does not exceed one year from the consummation date; however, it may be longer for certain income tax items. As discussed in Note 1, effective January 1, 2009, Duke Energy adopted SFAS No. 141(R) and will apply the provisions of this standard to any future acquisitions.

Cinergy Merger. On April 3, 2006, the merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). For accounting purposes, the effective date of the merger was April 1, 2006. The merger combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger was accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes. As a result, the assets and liabilities of Cinergy were recorded at their respective fair values as of April 3, 2006 and the results of Cinergy’s operations are included in the Duke Energy consolidated financial statements beginning as of the effective date of the merger.

Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction was valued at approximately $9.1 billion and resulted in goodwill of approximately $4.5 billion, none of which was deductible for tax purposes. Approximately $135 million of the goodwill was allocated to CMT, which was sold in October 2006, as described further in Note 14.

108

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following unaudited consolidated pro forma financial results are presented as if the Cinergy merger had occurred at the beginning of the year ended December 31, 2006:

Unaudited Consolidated Pro Forma Results

	Year Ended December 31, 2006
	(in millions, except per share amounts)
Operating revenues	$	12,093
Income from continuing operations		1,080
Net income		1,854
Earnings available for common stockholders		1,854
Earnings per share (from continuing operations)
Basic	$	0.86
Diluted	$	0.85
Earnings per share
Basic	$	1.48
Diluted	$	1.46

Pro forma results for the year ended December 31, 2006 include approximately $128 million of charges related to costs to achieve the merger and related synergies, which are recorded within Operating Expenses on the Consolidated Statements of Operations. Pro forma results for the year ended December 31, 2006 do not reflect the pro forma effects of any significant transactions completed by Duke Energy that are not reflected in the historical amounts other than the merger with Cinergy.

Other Acquisitions. 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. As the acquisition occurred on September 30, 2008, Duke Energy began recording earnings associated with the additional acquired interest beginning October 1, 2008. See Note 4 for discussion of Duke Energy’s filing of a petition with the PSCSC requesting an accounting order to defer incremental costs incurred from the purchase of this additional ownership interest.

In June 2008, Duke Energy announced the execution of a definitive agreement to acquire Catamount Energy Corporation (Catamount) from Diamond Castle Partners. Catamount is a leading wind power company located in Rutland, Vermont. The acquisition closed in September 2008 and expanded Duke Energy’s renewable energy portfolio to include 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. The acquisition 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 recorded upon acquisition primarily 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 Note 11 for further discussion of the goodwill and intangible assets recorded as a result of this transaction.

On February 4, 2009, Duke Energy completed the sale of Mark Hill Wind Power Ltd., which was a United Kingdom wind project acquired in the Catamount acquisition. No gain or loss was recognized on the sale. Additionally, Duke Energy has entered into an agreement to sell another United Kingdom wind project acquired in the Catamount acquisition. This transaction is expected to close in 2009. No gain or loss is expected to be recognized on the sale. As these projects do not meet the definition of a disposal group as defined by SFAS No. 144, these projects are not reflected as held-for-sale on the Consolidated Balance Sheets at December 31, 2008.

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 anticipated to be in commercial operation in 2009.

109

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

During the first quarter of 2006, International Energy closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). In December 2007, International Energy closed on a transaction to acquire an additional 10% interest in Aguaytia for approximately $16 million, which consisted of approximately $8 million of cash and a short-term note payable of approximately $8 million. The acquisitions during 2006 increased International Energy’s ownership in Aguaytia to 66% and resulted in Duke Energy accounting for Aguaytia as a consolidated entity. Prior to the acquisition of the additional interest in 2006, Aguaytia was accounted for as an equity method investment. The December 2007 acquisition of an additional interest in Aguaytia increased Duke Energy’s ownership interest to 76% at December 31, 2007. The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas and natural gas liquids (NGL) and the generation, transmission and sale of electricity from a 177 MW power plant. No goodwill was recorded in connection with these transactions.

In the fourth quarter of 2006, Duke Energy acquired an 825 MW power plant located in Rockingham County, North Carolina, from Dynegy for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 MW combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy’s plan to meet customers’ electric needs for the foreseeable future. The transaction required approvals by the NCUC, the FERC and the U.S. Federal Trade Commission (FTC). No goodwill was recorded as a result of this acquisition.

The pro forma results of operations for Duke Energy as if those acquisitions discussed above (other than the Cinergy merger) which closed prior to December 31, 2008 occurred as of the beginning of the periods presented do not materially differ from reported results.

See Note 14 for acquisitions related to discontinued operations.

Dispositions. In December 2006, Duke Energy Indiana agreed to sell one unit of its Wabash River Power Station (Unit 1) to Wabash Valley Power Association Inc. (WVPA). The sale was approved by the IURC, the FERC, the FTC and the U.S. Department of Justice (DOJ) during 2007. On December 31, 2007, Duke Energy Indiana received proceeds of approximately $114 million, which was equivalent to the net book value of Unit 1 at the time of sale. Since, pursuant to the terms of the purchase and sale agreement, the effective date of the sale was January 1, 2008, the assets of Unit 1 were reflected as Assets Held for Sale within Investments and Other Assets on the Consolidated Balance Sheets at December 31, 2007 and a corresponding liability equal to the cash received was included in Liabilities Associated with Assets Held for Sale within Current Liabilities on the Consolidated Balance Sheets at December 31, 2007. Since the sales price was equal to the net book value of Unit 1 at the transaction date, no gain or loss was recognized on the sale. The sale was completed on January 1, 2008.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses. See Note 1 and Note 14 for additional information. Additionally, see Note 14 for dispositions related to discontinued operations.

Other Asset Sales. 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 zero cost basis 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 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.

For the year ended December 31, 2006, the sale of other assets and businesses resulted in approximately $2 billion in proceeds and net pre-tax gains of approximately $223 million recorded in Gains (Losses) on Sales of Other Assets and Other, net in the Consolidated Statements of Operations. Proceeds and pre-tax gains during 2006 relate primarily to transactions related to Crescent and Commercial Power as discussed further below.

On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create the Crescent JV with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent, which had an enterprise value of approximately $2.1 billion as of December 31, 2005, to a newly-formed joint venture. The enterprise value was determined primarily by discounted cash flow analyses, but also incorporated multiple-to-book value approaches, as well as per acre valu-

110

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

ations for certain types of properties. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.21 billion, net of transaction costs, of which approximately $1.19 billion was immediately distributed to Duke Energy. These proceeds were classified as Proceeds from the issuance of long-term debt within Financing Activities on the Consolidated Statements of Cash Flows. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million, which represented 50% of the fair value of the net assets of Crescent based on a $2.1 billion enterprise value of Crescent less debt of approximately $1.3 billion. A 2% interest in the Crescent JV was also issued by the joint venture to the President and Chief Executive Officer of Crescent, which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three-year period. Additionally, this 2% interest can be put back to the Crescent JV after three years, or possibly earlier upon the occurrence of certain events, at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV has been accruing this obligation related to the put as a liability over the three-year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes. Since, subsequent to this transaction, Duke Energy no longer controlled the Crescent JV, Duke Energy deconsolidated its investment in Crescent as of the transaction date and subsequently accounted for its investment in the Crescent JV under the equity method of accounting. See Note 12 for discussion surrounding Duke Energy suspending the equity method of accounting for its investment in Crescent beginning in the fourth quarter of 2008.

Immediately prior to the Crescent JV transaction, Duke Energy’s basis in 100% of Crescent’s net assets was approximately $340 million. As Duke Energy received proceeds from the sale of approximately $415 million as compared to the approximate $170 million book basis in the 50% interest in the underlying net assets of Crescent, Duke Energy recognized a pre-tax gain on the sale of approximately $246 million, which has been classified as a component of Gains (Losses) on Sales of Other Assets and Other, net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006. In accordance with appropriate accounting literature, including APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB 18) and AICPA Statement of Position 78-9, “Accounting for Investments in Real Estate Ventures,” Duke Energy concluded that recognition of the gain was appropriate as the cash received of approximately $415 million exceeded the economic gain of approximately $246 million and there was no significant uncertainties regarding the realization of the gain. Specifically, Duke Energy is not committed or required to make future capital contributions to Crescent. Proceeds of approximately $380 million, which represents cash received from the MS Members, net of cash held by Crescent as of the transaction date, were classified as Net proceeds from the sales of other assets, and sales of and collections on notes receivable within Investing Activities on the Consolidated Statements of Cash Flows.

For the period from January 1, 2006 to September 7, 2006, Crescent commercial and multi-family real estate sales resulted in $254 million of proceeds and $201 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales primarily consisted of two office buildings at Potomac Yard in Washington, D.C. for a pre-tax gain of $81 million and land at Lake Keowee in Northwestern South Carolina for a pre-tax gain of $52 million, as well as several other large land tract sales.

During 2006, Commercial Power’s sale of emission allowances resulted in proceeds of $136 million and pre-tax losses on sales of approximately $29 million, which was recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. These losses primarily relate to Commercial Power’s sales of emission allowances that were written up to fair value in purchase accounting in connection with Duke Energy’s merger with Cinergy in April 2006.

The transactions and amounts discussed above exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 14.

111

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

4. Regulatory Matters

Regulatory Assets and Liabilities.

Substantially all of U.S. Franchised Electric and Gas’ operations and certain portions of Commercial Power’s operations apply the provisions of SFAS No. 71. 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.

Duke Energy’s Regulatory Assets and Liabilities:

	As of December 31,
	2008		2007		Recovery/Refund Period Ends(s)
	(in millions)
Regulatory Assets(a)
Net regulatory asset related to income taxes(c)	$	625	$	552	(o	)
Accrued pension and post retirement(d)		1,261		539	(b	)
ARO costs(d)		1,016		489	2043
Regulatory Transition Charges (RTC)(d)		138		239	2011
Gasification services agreement buyout costs(d)		175		194	2018
Deferred debt expense(c)		160		175	2039
Vacation accrual(e)		137		128	2009
Post-in-service carrying costs and deferred operating expense(d)		101		100	2067
Under-recovery of fuel costs(f)		163		97	2010
Regional Transmission Organization (RTO) costs(g)(h)		20		22	(g	)
Hedge costs and other deferrals(h)(r)		107		5	2009
Storm cost deferrals(d)		36		—	(b	)
Forward contracts to purchase emission allowances(h)		33		—	(b	)
Other(h)		105		105	(b	)
Total Regulatory Assets	$	4,077	$	2,645
Regulatory Liabilities(a)
Removal costs(c)(i)	$	2,162	$	2,173	(q	)
Nuclear property and liability reserves(c)(i)		184		179	2043
Demand-side management costs(j)(k)		134		99	(p	)
Purchased capacity costs(j)(k)		13		90	(n	)
Accrued pension and post retirement(i)		—		27	—
Deferred emission allowance revenue(l)		15		5	(b	)
Gas purchase costs(l)		14		4	2009
Over-recovery of fuel costs(m)		60		1	2009
Other(i)		96		96	(b	)
Total Regulatory Liabilities	$	2,678	$	2,674

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

(b) Recovery/Refund period 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 $10 million to be recovered in rates through 2012. See “Duke Energy Carolinas Rate Case” discussion below. South Carolina portion to be recovered through future rates, although ultimate recovery period is currently unknown.

(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) Earns a negative return.

(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) Refund period will be determined by the volume of sales as U.S. Franchised Electric and Gas is currently refunding the liability through retail sales.

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

112

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

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

(r) Approximately $95 million of the balance at December 31, 2008 relates to mark-to-market deferrals associated with open hedge positions at Commercial Power as a result of the reapplication of SFAS No. 71.

(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.

Regulatory Merger Approvals.

On April 3, 2006, the merger between Duke Energy and Cinergy was consummated to create a newly-formed company, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the PUCO, the KPSC, the PSCSC and the NCUC required that certain merger related savings be shared with consumers in Ohio, Kentucky, South Carolina, and North Carolina, respectively. The commissions also required Duke Energy Holding Corp., Cinergy, Duke Energy Ohio, Duke Energy Kentucky and/or Duke Energy Carolinas to meet additional conditions. Although the merger itself was not subject to approval by the IURC, the IURC approved certain affiliate agreements in connection with the merger subject to similar conditions. Key elements of these conditions include:

• The PUCO required that Duke Energy Ohio provide (i) a rate reduction of approximately $15 million for one year to facilitate economic development in a time of increasing rates and market prices and (ii) a reduction of approximately $21 million to its gas and electric consumers in Ohio for one year, with both credits beginning January 1, 2006. During the first quarter of 2007, Duke Energy Ohio completed its merger related rate reductions and filed a report with the PUCO to terminate the merger credit riders. Approximately $2 million and $34 million of these rate reductions were passed through to customers during the years ended December 31, 2007 and 2006, respectively.

• The KPSC required that Duke Energy Kentucky provide $8 million in rate reductions to its customers over five years, ending when new rates are established in the next rate case after January 1, 2008. Approximately $2 million of the rate reduction was passed through to customers during the years ended December 31, 2008, 2007 and 2006, respectively.

• The PSCSC required that Duke Energy Carolinas provide a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing (BPM) profit sharing arrangement. The rate reduction ended May 31, 2007. Approximately $16 million and $23 million of the rate reduction was passed through to customers during the years ended December 31, 2007 and 2006, respectively.

• The NCUC required that Duke Energy Carolinas provide (i) a rate reduction of approximately $118 million for its North Carolina customers through a credit rider to existing base rates for a one-year period following the close of the merger and (ii) $12 million to support various low income, environmental, economic development and educationally beneficial programs, the cost of which was incurred in the second quarter of 2006. The rate reduction ended June 30, 2007. Approximately $63 million and $54 million of the rate reduction was passed through to customers during the years ended December 31, 2007 and 2006, respectively.

• In its order approving Duke Energy’s merger with Cinergy, the NCUC stated that the merger will result in a significant change in Duke Energy’s organizational structure which constitutes a compelling factor that warrants a general rate review. Therefore, as a condition of its merger approval and no later than June 1, 2007, Duke Energy Carolinas was required to file a general rate case or demonstrate that Duke Energy Carolinas’ existing rates and charges should not be changed (see discussion under “Duke Energy Carolinas’ 2007 Rate Case” below).

• The IURC required that Duke Energy Indiana provide a rate reduction of $40 million to its customers over a one year period and $5 million over a five year period for low-income energy assistance and clean coal technology. In April 2006, Citizens Action Coalition of Indiana, Inc., an intervenor in the merger proceeding, filed a Verified Petition for Rehearing and Reconsideration claiming that Duke Energy Indiana should be ordered to provide an additional $5 million in rate reduction to customers to be consistent with the terms of the NCUC’s order approving the merger. In May 2006, the IURC denied the petition for rehearing and reconsideration. As of April 30, 2007, Duke Energy Indiana had completed its merger related reductions and filed a notice with the IURC to terminate the merger credit rider. Approximately $13 million and $27 million of the rate reduction was passed through to customers during the years ended December 31, 2007 and 2006, respectively.

• The FERC approved the merger without conditions.

113

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Restrictions on the Ability of Certain Subsidiaries to Make Dividends, Advances and Loans to Duke Energy Corporation. As discussed above, on April 3, 2006, the merger between Duke Energy and Cinergy was consummated. As a condition to the 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.

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, 2008, Duke Energy’s consolidated subsidiaries had restricted net assets of approximately $10.7 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.

Used Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the Department of Energy (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 will continue to safely manage its used nuclear fuel until the DOE accepts it. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial used nuclear fuel by the required date. Damages claimed in the lawsuit were based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional used fuel storage capacity. Payments made to the DOE for expected future disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. On March 5, 2007, Duke Energy Carolinas and the DOJ reached a settlement resolving Duke Energy’s used nuclear fuel litigation against the DOE. The agreement provided for an initial payment to Duke Energy of approximately $56 million for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs. The settlement agreement resulted in a pre-tax earnings impact of approximately $26 million during the year ended December 31, 2007, of which approximately $19 million and $7 million were recorded as an offset to Fuel Used in Electric Generation and Purchased Power, and Operation, Maintenance and Other, respectively, in the Consolidated Statements of Operations, with the remaining impact reflected within Inventory and Property, Plant and Equipment in the Consolidated Balance Sheets.

114

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

North Carolina Clean Air Act Compliance. In 2002, the state of North Carolina passed 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 Carolinas, to significantly reduce emissions of SO₂ and NO_x from coal-fired power plants in the state. The legislation allowed electric utilities, including Duke Energy Carolinas, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). The legislation provided for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). As discussed further below, under the Partial Settlement of the Duke Energy Carolinas’ 2007 rate case, effective January 1, 2008, Duke Energy Carolinas discontinued the amortization of environmental compliance costs incurred pursuant to the North Carolina clean air legislation and began capitalizing all environmental compliance costs above the cumulative amortization charge of $1.05 billion recorded by Duke Energy Carolinas associated with the North Carolina clean air legislation from inception through December 31, 2007. Of this amount, Duke Energy Carolinas’ recorded amortization expense related to this clean air legislation of approximately $187 million and $225 million during the years ended December 31, 2007 and 2006, respectively. As of December 31, 2008, cumulative expenditures totaled approximately $1,601 million, with approximately $355 million, $418 million and $403 million incurred during the years ended December 31, 2008, 2007 and 2006, respectively, which are included within capital expenditures in Net Cash Used In Investing Activities on the Consolidated Statements of Cash Flows. In filings with the NCUC, Duke Energy Carolinas estimated the costs to comply with the legislation as approximately $1.8 billion (excluding any AFUDC). Actual costs may be higher or lower than the estimate based on changes in construction costs and Duke Energy Carolinas’ continuing analysis of its overall environmental compliance plan. As required by the legislation, the NCUC considered the reasonableness of Duke Energy Carolinas’ environmental compliance plan and the method for recovery of the remaining costs in a proceeding it initiated and consolidated with a review of Duke Energy Carolinas’ 2007 base rates (see “Duke Energy Carolinas’ 2007 Rate Case” below). Additionally, federal and state environmental regulations, including, among other things, the Clean Air Interstate Rule (CAIR), (see Note 18), and a likely federal mercury rule, could result in additional costs to reduce emissions from Duke Energy’s coal-fired power plants.

Duke Energy Carolinas’ 2007 Rate Case. In June 2007, Duke Energy Carolinas filed an application with the NCUC seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008. This application complied with a condition imposed by the NCUC in approving the Cinergy merger. On October 5, 2007, Duke Energy Carolinas filed an Agreement and Stipulation of Partial Settlement (Partial Settlement) among Duke Energy Carolinas, the North Carolina Public Staff, the North Carolina Attorney General’s Office, Carolina Utility Customers Association Inc., Carolina Industrial Group for Fair Utility Rates III and Wal-Mart Stores East LP, for consideration by the NCUC. The Partial Settlement, which included all parties to the case, reflected agreements on all but a few issues in these matters, including two significant issues. The two significant issues related to the treatment of ongoing merger cost savings resulting from the Cinergy merger and the proposed amortization of Duke Energy Carolinas’ development costs related to GridSouth Transco, LLC (GridSouth), a RTO planned by Duke Energy Carolinas and other utility companies as a result of previous FERC rulemakings, which was suspended in 2002 and discontinued in 2005 as a result of regulatory uncertainty. The Partial Settlement and the remaining disputed issues were presented to the NCUC for a ruling.

The Partial Settlement reflected an agreed to reduction in net revenues and pre-tax cash flows of approximately $210 million and corresponding rate reductions of 12.7% to the industrial class, 5.05%—7.34% to the general class and 3.85% to the residential class of customers with an effective date of January 1, 2008. Under the Partial Settlement, effective January 1, 2008, Duke Energy Carolinas discontinued the amortization of the environmental compliance costs pursuant to North Carolina clean air legislation discussed above and began capitalizing all environmental compliance costs above the cumulative amortization charge of $1.05 billion as of December 31, 2007. Over the past five years, the average annual clean air amortization was $210 million. The Partial Settlement was designed to enable Duke Energy Carolinas to earn a rate of return of 8.57% on a North Carolina retail jurisdictional rate base and an 11% return on the common equity component of the approved capital structure, which consists of 47% debt and 53% common equity. As part of the settlement, Duke Energy Carolinas agreed to alter the then existing BPM profit sharing arrangement that included a provision to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Energy Carolinas’ generating units at market based rates. The Partial Settlement provided for Duke Energy Carolinas to share 90% of the North Carolina retail allocation of the profits from BPM transactions beginning January 1, 2008.

The NCUC issued its Order Approving Stipulation and Deciding Non-Settled Issues (Order) on December 20, 2007. The NCUC approved the Partial Settlement in its entirety. The merger savings rider and GridSouth cost matters are discussed in detail below. For the

115

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

remaining non-settled issues, the NCUC decided in Duke Energy Carolinas’ favor. With respect to the merger savings rider and GridSouth cost matters, the Order 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 in keeping with traditional principles of rate making. The NCUC explained that because rates should be designed to recover a reasonable and prudent level of ongoing expenses, Duke Energy Carolinas’ annual cost of service and revenue requirement should reflect, as closely as possible, Duke Energy Carolinas’ actual costs. However, the NCUC recognized that its treatment of merger savings would not produce a fair result. Therefore, the NCUC preliminarily concluded that it would reconsider certain language in its 2006 merger order in order to allow it to authorize 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. Additionally, the NCUC concluded that approximately $30 million of costs incurred through June 2002 in connection with GridSouth and deferred by Duke Energy Carolinas, were reasonable and prudent and approved a ten-year amortization, retroactive to June 2002. As a result of the retroactive impact of the Order, Duke Energy Carolinas recorded an approximate $17 million charge to write-off a portion of the GridSouth costs in the fourth quarter of 2007. The NCUC did not allow Duke Energy Carolinas a return on the GridSouth investments. As a result of its decision on the non-settled issues, the NCUC ordered an additional reduction in annual revenues of approximately $54 million, offset by its preliminary authorization of a 12-month, $80 million increment rider, as discussed above. 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. On February 18, 2008, the NCUC issued an order confirming their preliminary conclusion regarding the merger savings rider and the $80 million increment rider. Duke Energy Carolinas implemented the rate rider effective January 1, 2008 and terminated the rider effective January 1, 2009.

On December 12, 2007, the PSCSC directed the South Carolina Office of Regulatory Staff (ORS) to provide a written report concerning the NCUC’s resolution of Duke Energy Carolinas’ rate application and its relevance to Duke Energy Carolinas’ rates in South Carolina. On January 31, 2008, the ORS filed its report with the PSCSC, which concluded that the outcome of the North Carolina rate case had no bearing on Duke Energy Carolinas’ rates in South Carolina. The PSCSC took no action with respect to the report filed by the ORS.

At the request of the NCUC, the Public Staff performed a review of Duke Energy Carolinas’ pension and other post-retirement benefit plan costs, as well as Duke Energy’s funding of the plans. The Public Staff filed its report on February 23, 2009 recommending no change in Duke Energy Carolinas’ methodology for expensing pension and other post-retirement benefit costs.

Duke Energy Ohio Electric Rate Filings. Duke Energy Ohio operated under a RSP, a market-based standard service offer approved by the PUCO in November 2004, from January 1, 2005 through December 31, 2008. In March 2005, the Office of the Ohio Consumers’ Counsel (OCC) appealed the PUCO’s approval of the RSP to the Supreme Court of Ohio, which issued its decision in November 2006. It upheld the RSP in virtually every respect but remanded to the PUCO on two issues. The Supreme Court of Ohio ordered the PUCO to support a certain portion of its order with reasoning and record evidence and to require Duke Energy Ohio to disclose certain confidential commercial agreements with other parties previously requested by the OCC. Duke Energy Ohio has complied with the disclosure order.

In October 2007, the PUCO issued its ruling affirming the RSP, with certain modifications, and maintained the then current price. The ruling provided for continuation of the existing rate components, including the recovery of costs related to new pollution control equipment and capacity costs associated with power purchase contracts to meet customer demand, but provided customers an enhanced opportunity to avoid certain pricing components if they are served by a competitive supplier. The ruling also attempted to modify the statutory requirement that Duke Energy Ohio transfer its generating assets to an exempt wholesale generator (EWG) and ordered Duke Energy Ohio to retain ownership for the remainder of the RSP period. The ruling also incorrectly implied that Duke Energy Ohio’s non-residential regulatory transition charge (RTC) will terminate at the end of 2008. On November 23, 2007, Duke Energy Ohio filed an application for rehearing on the portions of the PUCO’s ruling relating to whether certain pricing components may be avoided by customers, the right to transfer generating assets, and the termination date of the RTC. On December 19, 2007, the PUCO issued its Entry on Rehearing granting in part and denying in part Duke Energy Ohio’s Application for Rehearing. Among other things, the PUCO modified and clarified the applicability of various rate riders during customer shopping situations. It also clarified that the residential RTC terminates at the end of 2008 and that the non-residential RTC terminates at the end of 2010 and agreed to give further consideration to whether Duke Energy Ohio may transfer its generating assets to an EWG.

On February 15, 2008, Duke Energy Ohio filed a notice of appeal with the Ohio Supreme Court challenging a portion of the PUCO’s decision on remand regarding Duke Energy Ohio’s RSP. The October 2007 order permits non-residential customers to avoid certain charges associated with the costs of Duke Energy Ohio standing ready to serve such customers if they return after being served by

116

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

another supplier. Duke Energy Ohio believes the PUCO exceeded its authority in modifying the charges that may be avoided, resulting in Duke Energy Ohio having to subsidize Ohio’s competitive electric market. Duke Energy Ohio asked the Ohio Supreme Court to reverse the PUCO ruling and require that non-residential customers pay the charges associated with Duke Energy Ohio standing ready to serve them should they return from a competitive supplier. On March 28, 2008, Duke Energy Ohio voluntarily withdrew its appeal. The OCC filed a notice of appeal challenging the PUCO’s October 2007 decision as unlawful and unreasonable. The OCC and Ohio Partners for Affordable Energy (OPAE) also filed appeals from the PUCO’s November 20, 2007 order approving Duke Energy Ohio’s RSP riders. Duke Energy Ohio intervened in each appeal. Pending the Ohio Supreme Court’s consideration of its initial appeal, the OCC requested that the PUCO stay implementation of the Infrastructure Maintenance Fund charge to be collected from customers approved in the October 2007 order. The Commission denied the OCC’s request and the OCC filed a similar request with the Ohio Supreme Court. On July 9, 2008, the court denied the OCC’s request to stay implementation of the Infrastructure Maintenance Fund. On April 30, 2008, the Ohio Supreme Court granted Duke Energy Ohio’s motion to intervene in the OCC’s appeal. Oral arguments were conducted on November 18, 2008. On January 2, 2009, the PUCO filed a motion to dismiss the action as moot. The PUCO argued that the rates at issue in this matter expired on January 1, 2009, with the implementation of Duke Energy Ohio’s ESP. On February 19, 2009, the Ohio Supreme Court issued its decision on OCC’s appeal. The Ohio Supreme Court granted the PUCO’s motion to dismiss ruling that because the challenged rate structure is no longer in effect, it can neither order lower prospective rates nor order a refund.

New legislation (SB 221) was passed on April 23, 2008 and signed by the Governor of Ohio on May 1, 2008. The new law codifies the PUCO’s authority to approve an electric utility’s standard service offer through an ESP, which would allow for pricing structures similar to the current 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. If a MRO price is approved, the utility would blend in the RSP or ESP price with the MRO price over a six- to ten-year period, subject to the PUCO’s discretion. SB 221 provides for the PUCO to approve non-by-passable 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 the 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 22% of a utility’s load by 2025. The utility’s earnings under the ESP can be 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 EWG absent PUCO approval.

On July 31, 2008 Duke Energy Ohio filed a new generation pricing formula to be effective January 1, 2009, when the current RSP expired. Among other things, the plan provides pricing mechanisms for compensation related to the advanced energy, renewables and energy efficiency portfolio standards established by SB 221.

On October 27, 2008 Duke Energy Ohio filed a Stipulation and Recommendation (Stipulation) for consideration by the PUCO regarding Duke Energy Ohio’s July 31, 2008 ESP filing. The Stipulation reflected agreement on all but two issues and was filed with the support of most of the parties to this proceeding. In addition to the Stipulation, the ability for residential governmental aggregation customers to avoid certain charges and to receive a shopping credit was presented to the PUCO for a ruling. Parties to this proceeding who did not support the Stipulation were free to litigate any, or all, issues.

The Stipulation agrees to a net increase in base generation revenues of approximately $36 million, $74 million and $98 million in 2009, 2010 and 2011, respectively, including termination of the residential and non-residential RTC. Such amounts result in a residential net rate increase of 2% in 2009 and in 2010, and a non-residential rate increase of 2% in 2009, 2010 and 2011. The Stipulation also allows the recovery of expenditures incurred to deploy SmartGrid infrastructure modernization technology on the distribution system. The recovery of such expenditures, net of savings, is subject to an annual residential revenue cap. Further, the Stipulation allows for the implementation of a new energy efficiency compensation model, referred to as Save-A-Watt, to achieve the energy efficiency mandate pursuant to the recent electric energy legislation. The criteria customers must meet to be exempt from Duke Energy Ohio’s program was also presented to the PUCO for a ruling in this case. Also under the Stipulation, Duke Energy Ohio may defer up to $50 million of certain operation and maintenance costs incurred at the W.C. Beckjord generating station and amortize such costs over a three-year period.

The ESP hearing occurred on November 10, 2008. On December 17, 2008, the PUCO issued its finding and order resolving the two litigated issues and adopting a modified Stipulation. Specifically, 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

117

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Duke Energy Ohio’s system to avoid some charges. Applications for rehearing of the PUCO’s decision have been filed by environmental groups and a residential customer advocate group. On February 11, 2009 the PUCO issued an Entry denying the rehearing requests.

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 SFAS No. 71 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. Duke Energy Ohio sought an increase of approximately $34 million in revenue, or approximately 5.7%, to be effective in the spring of 2008. The application also requested approval to continue tracker recovery of costs associated with the accelerated gas main replacement program. The staff of the PUCO issued a Staff Report in December 2007 recommending an increase of approximately $14 million to $20 million in revenue. The Staff Report also recommended approval for Duke Energy Ohio to continue tracker recovery of costs associated with the accelerated gas main 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 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 the proposed rate design. On June 28, 2008, the OCC and OPAE filed Applications for Rehearing opposing the rate design. On July 23, 2008 the Ohio Commission issued an Entry denying the rehearing requests of OCC and OPAE. On September 16 and 19, 2008 respectively, OCC and OPAE filed their notices of appeal to the Ohio Supreme Court opposing the residential rate design issue. At this time, Duke Energy Ohio cannot predict whether the Ohio Supreme Court will reverse the PUCO’s decision of May 28, 2008.

Duke Energy Ohio Electric Distribution Rate Case. On June 25, 2008, Duke Energy Ohio filed notice with the PUCO that it will seek a rate increase for electric delivery service of approximately $86 million, or 4.8% on total electric revenues, to be effective in the second quarter of 2009. Among other things, the rate request includes a proposal to increase the monthly residential customer charge from $4.50 to $10, with an offsetting reduction in the usage-based charge. This change in rate design will make customer bills more even throughout the year. Duke Energy Ohio also proposes a distribution modernization tracker that would allow smaller annual increases to reflect increased investment in the delivery system. 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. On January 14, 2009, the PUCO granted Duke Energy Ohio’s deferral request. Accordingly, a regulatory asset was recorded as of December 31, 2008 for $31 million. The staff of the PUCO issued a Staff Report in January 2009 recommending an increase of approximately $54 million to $62 million associated with the Ohio distribution rate case. The staff report did not recommend approval of the distribution modernization tracker. The report also recommended approval of a rider to recover the deferred storm costs from the September 14, 2008 windstorm and recommended a future hearing be established to evaluate the windstorm related costs and implement a rider. An evidentiary hearing with PUCO is scheduled to begin on March 31, 2009.

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 is 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 of $8 million 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

118

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 were 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 is filing a motion for discretionary review to the Kentucky Supreme Court on or about March 6, 2009.

Energy Efficiency. In May 2007, Duke Energy Carolinas filed its Save-A-Watt energy efficiency plan with the NCUC seeking approval to implement new energy efficiency programs, a new regulatory recovery model and a rate rider. The plan recognizes energy efficiency as a reliable, valuable resource that is a “fifth fuel”, that should be part of the portfolio available to meet customers’ growing need for electricity along with coal, nuclear, natural gas, or renewable energy. The plan would compensate Duke Energy Carolinas for verified reductions in energy use and be available to all customer groups. The plan contains proposals for several different energy efficiency programs. Customers would pay for energy efficiency programs with an energy efficiency rider that would be included in their power bill and adjusted annually. The energy efficiency rider would be based on 90% of the avoided capacity and energy cost of generation not needed as a result of the success of Duke Energy Carolinas’ energy efficiency efforts. The plan is consistent with Duke Energy Carolinas’ public commitment to invest 1% of its annual retail revenues from the sale of electricity in energy efficiency programs subject to the appropriate regulatory treatment of Duke Energy Carolinas’ energy efficiency investments. Piedmont Natural Gas Company and Public Service Company of North Carolina, Inc. raised certain concerns regarding the incentives offered to Duke Energy Carolinas’ customers under its proposed portfolio of energy efficiency programs. In June 2008, Duke Energy Carolinas filed settlement agreements resolving all issues with these parties. Duke Energy Carolinas has not reached settlement with any of the other intervenors. The evidentiary hearing occurred the week of July 28, 2008 and concluded on August 18, 2008. Duke Energy Carolinas was unable to reach a settlement with any party to the proceeding. On October 7, 2008 Duke Energy Carolinas filed its proposed order and legal brief with the NCUC.

On February 26, 2009, the NCUC issued an order approving the proposed energy efficiency programs as new programs eligible for incentives under North Carolina’s 2009 energy legislation. The NCUC requested additional information regarding the earnings potential under its proposed Save-A-Watt recovery mechanism before ruling on this issue; however, it authorized Duke Energy Carolinas to implement its proposed energy efficiency rider pending final resolution and subject to refund.

On February 25, 2009, the PSCSC issued a directive rejecting Duke Energy Carolinas’ Save-A-Watt energy efficiency plan, which was filed with the PSCSC on September 28, 2007.

On July 11, 2007, the PUCO approved Duke Energy Ohio’s Demand Side Management/Energy Efficiency Program (DSM Program). The DSM programs were first proposed in 2006 and were endorsed by the Duke Energy Community Partnership, which is a collaborative group made up of representatives of organizations interested in energy conservation, efficiency and assistance to low-income customers. The program costs are recouped through a cost recovery mechanism that will be adjusted annually to reflect the previous year’s activity. Duke Energy Ohio is permitted to recover lost revenues, program costs and shared savings (once the programs reach 65% of the targeted savings level) through the cost recovery mechanism based upon impact studies to be provided to the Staff of the PUCO. Duke Energy Ohio filed the Save-A-Watt Energy Efficiency Plan as part of its ESP filed with PUCO on July 31, 2008 (discussed above). A Stipulation and Recommendation for consideration by the PUCO regarding Duke Energy Ohio’s ESP filing, including implementation of Save-A-Watt, was filed on October 27, 2008. The ESP hearing occurred on November 10, 2008. On December 17, 2008, the PUCO approved the ESP, 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 decision have been filed by environmental groups and a residential customer advocate group.

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. Similar to the plans in North Carolina and South Carolina, 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 avoided cost of generation not needed as a result of the success of Duke Energy Indiana’s energy efficiency programs. A number of parties have

119

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

intervened in the proceeding. On May 29, 2008 Duke Energy and Vectren Energy Delivery of Indiana, Inc. filed a stipulation and settlement agreement in the proceeding. On August 1, 2008, Duke Energy Indiana reached a settlement agreement with the OUCC resolving all issues in the proceeding. The settlement agreement was filed with the IURC on August 15, 2008. On October 31, 2008, Duke Energy Indiana reached a settlement agreement with Nucor Corporation, Steel Dynamics, Inc. and the Kroger Company resolving all issues in the proceeding. The settlement agreement was filed with the IURC on November 3, 2008. On January 15, 2009, Duke Energy Indiana entered into a settlement that amended the October 31, 2008 settlement, adding two additional intervenors to the settlement – the Indiana Industrial Group and Wal-Mart Stores, Inc. Duke Energy Indiana has not reached a settlement with one intervenor in the proceeding, the Citizens Action Coalition of Indiana, Inc. An evidentiary hearing with the IURC is scheduled to occur in the first quarter of 2009.

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 and applied to reinstitute a low income Home Energy Assistance Program. The KPSC bifurcated the proposed Home Energy Assistance Program from the other energy efficiency programs. On May 14, 2008, the KPSC approved the energy efficiency programs. On September 25, 2008, the KPSC approved Duke Energy Kentucky’s Home Energy Assistance program, making it available for customers at or below 150% of the federal poverty level. 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 and Indiana. An evidentiary hearing with the KPSC is expected to occur in the third quarter of 2009.

2007 North Carolina and South Carolina Legislation. South Carolina passed new energy legislation (S 431) which became effective May 3, 2007. A key element of the legislation include expansion of the annual fuel clause mechanism to include recovery of costs of reagents (e.g., ammonia, limestone, etc.) that are consumed in the operation of Duke Energy Carolinas’ environmental control technologies. The cost of reagents for Duke Energy Carolinas in 2008 was $24 million and is expected to be approximately $40 million in 2009. With the enactment of this legislation, Duke Energy Carolinas will be allowed to recover the South Carolina portion of these costs, incurred on or after May 3, 2007, through the fuel clause. The legislation also 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 (SB 3) in July 2007 that was signed into law by the Governor on August 20, 2007. The North Carolina legislation allows utilities to recover the costs of reagents and certain purchased power costs through the annual fuel clause. 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. The North Carolina legislation also establishes a renewable energy and energy efficiency portfolio standard (REPS) for electric utilities at 3% of energy output in 2012, rising gradually to 12.5% by 2021, and grants 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. On February 29, 2008, the NCUC adopted new rules and modified existing rules to implement the legislation.

Renewable Resources. On June 6, 2008, Duke Energy Carolinas filed an application with the NCUC for approval of a Solar Photovoltaic (PV) Distributed Generation Program. The application seeks authorization to invest approximately $100 million to install approximately 850 solar PV facilities on customer rooftops and other customer and company owned property over a two-year period, resulting in a total generating capacity of 20 MW. If approved, the program would enable Duke Energy Carolinas to partially satisfy the Renewable Energy Portfolio Standard (REPS) established by SB 3. 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, the NCUC must issue a Certificate of Public Convenience and Necessity (CPCN) to Duke Energy Carolinas before it may proceed. On October 20, 2008, Duke Energy Carolinas filed rebuttal testimony, agreeing to reduce the size of the program to an investment of approximately $50 million to install a total generating capacity of 10 MW to address concerns raised by other parties to the proceeding. The NCUC held a hearing on this matter on October 23, 2008. On December 31, 2008, the NCUC issued its Order Granting CPCN Subject to Conditions. The conditions are (1) reduction of the program size from 20 MWs to 10 MWs (as previously agreed by Duke Energy Carolinas); and (2) limiting program costs recoverable through the REPS rider program costs equivalent to the cost of the third place bid in Duke Energy Carolinas’ 2007 request for proposal for renewable

120

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

energy. The Order leaves open the opportunity to recover the excess costs through other recovery mechanisms. On January 29, 2009, Duke Energy Carolinas filed a motion for reconsideration asking the NCUC to either eliminate the condition limiting recovery of the program costs through the REPS rider or provide Duke Energy Carolinas with assurance that all costs of the program can be recovered through a combination of the REPS rider and base rates. The NCUC has agreed to hold oral arguments on March 23, 2009 regarding reconsideration of the cost recovery conditions of the order.

Deferral of Costs. On February 4, 2009, Duke Energy Carolinas filed petitions with the NCUC and the PSCSC requesting an accounting order to defer certain environmental compliance costs and the incremental costs incurred from the purchase of a portion of Saluda River’s ownership interest in the Catawba Nuclear Station. Duke Energy Carolinas is requesting approval to defer in a regulatory asset account 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 and the purchase in September 2008 of a portion of Saluda’s ownership interest in the Catawba Nuclear Station. The costs Duke Energy Carolinas is seeking 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, the PSCSC approved the deferral of these costs.

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) 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 February 25, 2008, Duke Energy Carolinas received confirmation from the NRC that its COL application has been accepted and docketed for the next stage of review. On June 27, 2008, the Blue Ridge Environmental Defense League (BREDL) filed a petition to intervene in the COL proceeding before the NRC. On September 22, 2008, the Atomic Safety and Licensing Board issued a decision denying BREDL’s Petition to Intervene and Request for Hearing. BREDL did not appeal the decision. 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’ Lee 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 denied the environmental intervenor motion. The NRC review of the COL application is ongoing and the current schedule concludes the COL may be granted in early 2012. Duke Energy Carolinas filed with the DOE for a federal loan guarantee. Duke Energy Carolinas filed Part 1 applications in September 2008 and a Part II application in December 2008. If obtained, a federal loan guarantee has the potential to significantly lower financing costs associated with the proposed William States Lee III Nuclear Station.

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. The NCUC’s Order explained the basis for its decision to approve construction of one unit, with an approved cost estimate of $1.93 billion (including AFUDC), and included certain conditions including providing for updates on construction cost estimates. A group of environmental intervenors filed a motion and supplemental motion for reconsideration in April 2007 and May 2007, respectively. The NCUC denied the motions for reconsideration in June 2007. On February 29, 2008, Duke Energy Carolinas filed its latest updated cost estimate of $1.8 billion (excluding 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 approx-

121

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

imately $125 million in federal advanced clean coal tax credits, as discussed further below. 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 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 were filed appealing the final air permit. Duke Energy intervened in all four cases which have been consolidated. A hearing is not expected before the end of 2009. See Note 18 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 11, 2007, the environmental group N.C. Waste Awareness Reduction Network (WARN) and two individual N.C. WARN members filed a petition against the DENR contesting the issuance of a wastewater discharge permit to Duke Energy Carolinas for the Cliffside Steam Station. This matter has been settled and the dismissal and settlement document was filed with the Office of Administrative Hearings on March 4, 2008.

On October 14, 2008, Duke Energy Carolinas submitted revised hazardous air pollutant 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 hazardous air pollutants. On October 24, 2008, Duke Energy Carolinas filed to amend its air permit to include emission limits to assure the public of the minor source status of Cliffside Unit 6. DAQ held public hearings on January 15, 2009, in Forest City, North Carolina and January 22, 2009 in Statesville, North Carolina to allow public comment on DAQ’s proposal to find Cliffside Unit 6 as a minor source of hazardous air pollutants. The meeting notices were accompanied with a draft permit that includes the minor source limits and monitoring requirements that make the limits enforceable. A final permit with minor source limits is expected in the first quarter of 2009.

Dan River Steam Station and Buck Steam Station. 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, which has resulted in a modification of the construction schedule. Under the revised schedule, the Buck Project is expected to be delayed for a period of up to one year and is currently anticipated to begin operation in single cycle mode in summer 2011 and convert to combined cycle mode in Summer 2012. The Dan River Project is expected to begin operation in combined cycle mode in 2012 as originally planned, but without a phased-in simple cycle commercial operation.

The combined cycle natural gas-fired generating facility at the existing Buck Steam Station will affect an isolated wetland, and Duke Energy Carolinas applied for a state permit. DENR issued the permit with an unacceptable condition requiring submission of a storm water plan before engineering and project siting have determined the location of the facilities. Duke Energy Carolinas challenged the permit and the matter has been resolved; DENR has issued a new permit acceptable to Duke Energy Carolinas. On October 15, 2008 DENR issued a final construction permit authorizing construction of the Buck combined cycle natural gas-fired generating units.

Edwardsport Integrated Gasification Combined Cycle 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 petition describes the applicants’ need for additional base load generating capacity and requests timely recovery of all construction and operating costs related to the proposed generating station, including financing costs, together with certain incentive ratemaking treatment. In April 2007, Duke Energy Indiana and Vectren filed a Front End Engineering and Design Study Report which included an updated estimated cost for the IGCC project of approximately $2 billion (including approximately $120 million of AFUDC). In June 2007, Vectren decided not to

122

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

proceed with the CPCN petition, and in August 2007, Vectren formally withdrew its participation in the IGCC plant. In June 2007, 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. The IURC also approved Duke Energy Indiana’s proposal to initiate a proceeding in May 2008 concerning proposals for the study of partial carbon capture, sequestration and/or enhanced oil recovery for the Edwardsport IGCC 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 IURC Order to the Indiana Court of Appeals and also appealed the air permit. The Joint Brief of the Appellants in the appeal of the CPCN case was filed on May 30, 2008 and the Duke Energy Indiana Brief of Appellee was filed on July 23, 2008 in the appeal of the IURC CPCN Order. On October 16, 2008, the Indiana Court of Appeals affirmed the IURC’s grant of Duke Energy Indiana’s CPCN petition. On November 17, 2008, the same parties filed for a rehearing before the Indiana Court of Appeals, which was denied on December 17, 2008. The time for additional appeals has passed and this proceeding is now concluded.

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 November 2007, which approved the IGCC Project. 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 November 2007 CPCN Order. An evidentiary hearing was conducted on August 25, 2008. 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. The OUCC filed a motion of clarification of this order concerning a ratemaking issue related to deferred taxes. The order was not otherwise appealed. The IURC is anticipated to rule on the motion for clarification of the ratemaking issue by the end of the first quarter of 2009. On November 3, 2008, Duke Energy Indiana filed its second semi-annual IGCC rider and ongoing review proceeding with the IURC. Duke Energy Indiana was also required to file its plans for studying carbon storage related to the project within 60 days of the order. Under the CPCN order and statutory provisions, Duke Energy Indiana is entitled to recover the costs reasonably incurred in reliance on the CPCN Order. Duke Energy Indiana has begun construction on the Edwardsport IGCC plant and entered into a $200 million engineering, procurement and construction management agreement with Bechtel Power Corporation in December 2008 in connection with the construction of the plant.

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 provide for Duke Energy’s Cliffside 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 U.S. Department of Energy and the U.S. Department of the Treasury. On November 10, 2008, the District Court dismissed the case, finding that plaintiffs lacked standing to pursue their claims. Duke Energy anticipates that plaintiffs will appeal this decision.

Other U.S. Franchised Electric and Gas Matters.

Ohio Riser Leak Investigation. In April 2005, the PUCO issued an order opening a statewide investigation into riser leaks in gas pipeline systems throughout Ohio. The investigation followed four explosions since 2000 caused by gas riser leaks, including an April 2000 explosion in Duke Energy Ohio’s service area. In November 2006, the PUCO Staff released the expert report, which concluded that certain types of risers are prone to leaks under various conditions, including over-tightening during initial installation. The PUCO Staff recommended that natural gas companies continue to monitor the situation and study the cause of any further riser leaks to determine whether further remedial action is warranted. As of January 1, 2008, Duke Energy Ohio had approximately 87,000 of these risers on its distribution system. If the PUCO orders natural gas companies to replace all of these risers, Duke Energy Ohio estimates a replacement cost of approximately $40 million. As part of the rate case filed in July 2007 (see “Duke Energy Ohio Gas Rate Case” above), Duke Energy Ohio requested approval from the PUCO to accelerate its riser replacement program. The riser replacement program is contained in the settlement reached with all intervenors and is expected to be completed at the end of 2012.

City of Orangeburg, South Carolina Wholesale Sales. On June 20, 2008, Duke Energy Carolinas filed notice with the NCUC that it intends to sell electricity at wholesale under a Power Purchase Agreement dated May 23, 2008 to the City of Orangeburg, South Caro-

123

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

lina, at the same level of firmness or reliability as it provides to its retail customers (i.e. native load priority). This notice is required by a condition imposed by the NCUC in approving the Cinergy merger. Duke Energy Carolinas requested that the NCUC accept and acknowledge the purchase power agreement without conditions. Together with the advance notice, Duke Energy Carolinas and Orangeburg filed a joint petition for a declaratory ruling that Duke Energy Carolinas’ new wholesale contracts with native load priority will be treated for ratemaking and reporting purposes in the same manner as existing wholesale contracts with native load priority. This would mean that revenues from those contracts will be allocated to the wholesale jurisdiction and costs will be allocated to the wholesale jurisdiction based on average system costs. The NCUC Public Staff has filed its objection to the advance notice and joint petition. The NCUC held a hearing on this matter on November 5, 2008. Briefs and proposed orders were filed on December 30, 2008. Duke Energy Carolinas is awaiting an order from the NCUC. Duke Energy Carolinas has also filed advance notices of its intent to serve additional wholesale customers, the City of Greenwood, South Carolina and Haywood Electric Membership Corp., at native load priority.

SmartGrid and Distributed Renewable Generation Demonstration Project. On May 23, 2008, Duke Energy Indiana filed a petition with the IURC requesting approval for SmartGrid and Distributed Renewable Generation Demonstration Project investments and related costs along with a request to annually update distribution rates and include a lost revenue recovery mechanism. Hearings are anticipated to be held in April 2009.

Gibson Unit 4 Outage. In a 2008 fuel clause proceeding, the IURC granted a motion by the Industrial Group and Nucor Corporation to establish a subdocket to examine whether imprudence in Duke Energy Indiana’s maintenance practices led to a forced outage at Gibson Station Unit 4 during January-March 2008. The outage contributed to notably higher fuel and purchased power costs during the outage. A hearing on this subdocket proceeding was held in January 2009. The IURC authorized Duke Energy Indiana to collect through rates the costs for which it sought recovery in the subdocket proceeding subject to refund (similar to prior subdockets) pending the outcome of this new subdocket related to maintenance practices for Gibson Station Unit 4.

Commercial Power.

As discussed in Note 1, effective December 17, 2008, Commercial Power reapplied the provisions of SFAS No. 71 to certain portions of its operations due to the passing of SB 221 and the PUCO’s approval of the ESP. However, since certain portions of Commercial Power’s operations are not subject to regulatory accounting pursuant to SFAS No. 71, reported results for Commercial Power are subject to volatility due to the over- or under-collection of certain costs for which recovery is not automatic under the ESP. Commercial Power may be impacted by certain of the regulatory matters discussed above, including the Duke Energy Ohio electric rate filings.

FERC 203 Application. On April 23, 2008 (supplemented on May 6, 2008), Duke Energy Ohio and certain affiliates filed an application with the FERC requesting approval to transfer Duke Energy Ohio’s electric generating facilities, some of which are designated to serve Ohio customers, to affiliate companies. The FERC filing, if approved, does not obligate Duke Energy to make the transfer of the electric generating facilities, and does not impact Duke Energy Ohio’s current rates. On October 10, 2008, Duke Energy Ohio and affiliates filed a notice with the FERC reporting that Duke Energy Ohio was in settlement discussions with all parties in the Ohio proceeding regarding Duke Energy Ohio’s application to establish an ESP, as discussed above. Duke Energy Ohio advised the FERC that it believed that in light of those discussions good cause existed for the FERC to extend the time to consider Duke Energy Ohio’s Section 203 application. On October 17, 2008, the FERC issued an order extending the time for the FERC to act on the application by 180 additional days, and ordered Duke Energy Ohio to inform the FERC of the status of settlement discussions by November 16, 2008. As part of the settlement that was approved by the PUCO on December 17, 2008 (see discussion above) Duke Energy Ohio agreed to withdraw that portion of its application for approval related to the transfer of its generating facilities designated to serve Ohio customers and the PUCO approved of the transfer for the remaining generating facilities. Duke Energy Ohio filed a new application requesting FERC approval to transfer to affiliate companies only the remaining generating facilities not designated to serve Ohio customers, which was approved by the FERC on February 19, 2009.

PJM Interconnection Reliability Pricing Model (RPM) Buyers’ Complaint. On May 30, 2008, a group of public utility commissions, state consumer counsels, industrial power customers and load serving entities, known collectively as the RPM Buyers, filed a complaint at FERC. The complaint asks FERC to find that the results of the three transitional base residual auctions conducted by PJM to procure capacity for its RPM capacity market during the years 2008-2011 are unjust and unreasonable because, allegedly, they have produced excessive capacity prices, have failed to prevent suppliers from exercising market power, and have not produced benefits commensurate with costs. In their complaint, the RPM Buyers propose revised, administratively determined auction clearing prices. Certain Duke Energy Ohio revenues during the years 2008—2011 are at risk, as Duke Energy Ohio planned to supply capacity to this mar-

124

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

ket. On July 11, 2008, Duke Energy Ohio filed a response to the complaint with the FERC. On September 19, 2008, the FERC issued an Order denying the Buyer’s complaint. The FERC dismissed the RPM Buyers’ complaint, finding that, for the transition auctions, no party violated PJM’s tariff and the prices determined during the auctions were in accordance with the tariff provisions governing the auctions. On October 20, 2008, the RPM buyers filed a Request for Rehearing with the FERC that raised the same issues as in the initial complaint that was denied by the FERC.

Other Matters.

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-kilovolt (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 and filed for rate approval for the project from the FERC in the fourth quarter of 2008, and will make a filing with the IURC in the second quarter of 2009. The earliest possible in-service date for the project is in 2014 or 2015.

Application for the Establishment of a Regulatory Asset. On November 14, 2008, Duke Energy Kentucky petitioned the KPSC for permission to create a regulatory asset to defer for future recovery approximately $5 million for its expenses incurred to repair damage and restore service to its customers following extensive storm-related damage caused by Hurricane Ike on September 14, 2008. The KPSC approved the requested accounting order on January 7, 2009.

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 completed the purchase of a portion of Saluda’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy paid approximately $150 million for an additional approximate 7 percent 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 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.

125

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Duke Energy’s share of jointly-owned plant or facilities included on the December 31, 2008 Consolidated Balance Sheet were 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)(c)(d)	19.2	%	$	782	$	332	$	10
Duke Energy Ohio
Production:
Miami Fort Station (Units 7 and 8)(b)	64.0			591		160		4
W.C. Beckjord Station (Unit 6)(b)	37.5			55		31		1
J.M. Stuart Station(a)(b)	39.0			426		200		342
Conesville Station (Unit 4)(a)(b)	40.0			82		56		174
W.M. Zimmer Station(b)	46.5			1,321		509		10
Killen Station(a)(b)	33.0			207		128		96
Vermillion(b)	75.0			197		47		—
Transmission(c)	Various			90		51		—
Duke Energy Indiana
Production:
Gibson Station (Unit 5)(c)	50.1			322		153		1
Transmission and local facilities(c)	Various			3,007		1,260		—
Duke Energy Kentucky
Production:
East Bend Station(c)	69.0			423		219		5
International Energy
Production:
Brazil – Canoas I & II	47.4			261		56		—

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

(b) Included in Commercial Power segment.

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

(d) Property, Plant and Equipment includes approximately $145 million that represents the net amount for the additional portion of Catawba purchased from Saluda in September 2008. Accumulated Depreciation includes approximately $1 million, which represents estimated depreciation from the effective date of the purchase of the additional ownership in Catawba through December 31, 2008.

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.

126

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

6. Income Taxes

The following details the components of income tax expense:

Income Tax Expense

	For the Years Ended December 31,
	2008			2007			2006
	(in millions)
Current income taxes
Federal	$	60		$	(59	)	$	651
State		17			24			60
Foreign		68			64			48
Total current income taxes		145			29			759
Deferred income taxes
Federal		388			627			(304	)
State		50			37			(20	)
Foreign		46			32			27
Total deferred income taxes		484			696			(297	)
Investment tax credit amortization		(13	)		(13	)		(12	)
Total income tax expense from continuing operations		616			712			450
Total income tax expense (benefit) from discontinued operations		(3	)		(88	)		379
Total income tax expense from extraordinary item		37			—			—
Total income tax expense included in Consolidated Statements of Operations(a)	$	650		$	624		$	829

(a) Included in the “Total current income taxes” line above is a FIN 48 benefit relating primarily to certain temporary differences of approximately $46 million for 2008 and $245 million for 2007.

Income from Continuing Operations before Income Taxes

	For the Years Ended December 31,
	2008		2007		2006
	(in millions)
Domestic	$	1,575	$	1,894	$	1,333
Foreign		320		340		197
Total income from continuing operations before income taxes	$	1,895	$	2,234	$	1,530

127

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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,
	2008			2007			2006
	(in millions)
Income tax expense, computed at the statutory rate of 35%	$	663		$	782		$	536
State income tax, net of federal income tax effect		43			40			26
Tax differential on foreign earnings		3			(23	)		6
Employee stock ownership plan dividends		(20	)		(20	)		(29	)
Other items, net		(73	)		(67	)		(89	)
Total income tax expense from continuing operations	$	616		$	712		$	450
Effective tax rate		32.5	%		31.9	%		29.4	%

During 2008, Duke Energy had tax benefits related to depreciation and other property, plant and equipment related differences, such as AFUDC equity, of approximately $30 million, certain foreign restructuring of approximately $25 million and a manufacturing deduction of approximately $18 million. These benefits are reflected in the above table in Other items, net.

During 2007, Duke Energy had tax benefits related to the manufacturing deduction of approximately $35 million, which is reflected in the above table in Other items, net. During the year ended December 31, 2007, the manufacturing deduction increased from 3% to 6% on qualified production activities.

During 2006, Duke Energy had favorable tax settlements on research and development costs and nuclear decommissioning costs of approximately $30 million, tax benefits related to the impairment of an investment in Bolivia of approximately $25 million and the tax benefits related to manufacturing deduction of approximately $13 million. 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. During the year ended December 31, 2006, the Act provided for a 3% deduction on qualified production activities. These benefits are reflected in the above table in Other items, net.

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,
	2008			2007
	(in millions)
Deferred credits and other liabilities	$	995		$	1,206
Total deferred income tax assets		995			1,206
Valuation allowance		(94	)		(90	)
Net deferred income tax assets		901			1,116
Investments and other assets		(764	)		(695	)
Accelerated depreciation rates		(4,125	)		(3,769	)
Regulatory assets and deferred debits		(856	)		(953	)
Other		(30	)		(22	)
Total deferred income tax liabilities		(5,775	)		(5,439	)
Net deferred income tax liabilities	$	(4,874	)	$	(4,323	)

128

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

Deferred Tax Liabilities

	December 31,
	2008			2007
	(in millions)
Current deferred tax assets, included in other current assets	$	158		$	312
Non-current deferred tax assets, included in other investments and other assets		97			133
Current deferred tax liabilities, included in other current liabilities		(12	)		(17	)
Non-current deferred tax liabilities		(5,117	)		(4,751	)
Total net deferred income tax liabilities	$	(4,874	)	$	(4,323	)

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 permanently reinvested. The cumulative undistributed earnings as of December 31, 2008 on which Duke Energy has not provided deferred income taxes and foreign withholding taxes is approximately $734 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

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

At December 31, 2008 and December 31, 2007, Duke Energy had approximately $294 million and $114 million, respectively, of unrecognized tax benefits that, if recognized, may affect the effective tax rate or a regulatory liability. At this time, Duke Energy is unable to estimate the specific effect to either. At December 31, 2008 and December 31, 2007, Duke Energy had approximately $14 million and $16 million, respectively, that, if recognized, would affect Income (Loss) From Discontinued Operations, net of tax. At December 31, 2007, Duke Energy had approximately $9 million that, if recognized, would have affected Goodwill. In accordance with SFAS No. 141R, which is effective January 1, 2009, Duke Energy has approximately $6 million identified as Goodwill at December 31, 2008 that, if recognized, would affect the effective tax rate.

It is reasonably possible that Duke Energy will reflect an approximate $60 million reduction in unrecognized tax benefits within the next twelve months due to expected settlements.

During the years ending December 31, 2008, and December 31, 2007, Duke Energy recognized approximately $2 million and $38 million of net interest income, respectively, related to income taxes. At December 31, 2008, and December 31, 2007, Duke Energy’s Consolidated Balance Sheets included approximately $29 million and $27 million, respectively, of interest receivable, which reflects all interest related to income taxes, and approximately $2 million related to accruals for the payment of penalties.

129

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 2000 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, 2008 and 2007, approximately $490 million and $122 million, respectively, of federal income tax receivables were included in Other within Current Assets on the Consolidated Balance Sheets. At December 31, 2008 this balance 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. This additional carrying amount is then depreciated over the 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 adoption of SFAS No. 143 had no impact on the earnings of Duke Energy’s regulated electric operations in North Carolina and South Carolina as the effects of the recognition and subsequent accounting for an asset retirement obligation are offset by the establishment of regulatory assets and liabilities as Duke Energy received approval from both the NCUC and PSCSC to defer all cumulative and future income statement impacts related to SFAS No. 143. However, the PUCO, IURC and KPSC do not allow Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky, respectively, to defer costs associated with asset retirement obligations, thus the subsequent accounting for asset retirement obligations recorded in those jurisdictions impacts earnings.

Asset retirement obligations at 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. In accordance with SFAS No. 143, Duke Energy identified certain assets that have an indeterminate life, and thus the fair value of the retirement obligation is not reasonably estimable. These assets included distribution facilities and some gas-fired power plants. 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, 2008 and 2007:

	Years Ended December 31,
	2008			2007
	(in millions)
Balance as of January 1,	$	2,351		$	2,301
Spin-off to Spectra Energy(a)		—			(85	)
Liabilities incurred due to new acquisitions (b)		44			—
Accretion expense(c)		164			153
Liabilities settled		(2	)		(20	)
Liabilities incurred in the current year		10
Liabilities added due to regulatory requirements		—			2
Balance as of December 31,	$	2,567		$	2,351

(a) As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses.

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

(c) Accretion expense for the years ended December 31, 2008 and 2007 included approximately $163 million and $153 million, respectively, related to Duke Energy’s regulated electric operations which have been deferred as regulatory assets and liabilities in accordance with SFAS No. 71, as discussed above.

130

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 under SFAS No. 71. 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 $2,162 million and $2,173 million as of December 31, 2008 and 2007, respectively.

Nuclear Decommissioning Costs. In 2005, the NCUC and PSCSC collectively approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2008, 2007 and 2006, 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 Cash Flows from 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. The balance of the external nuclear decommissioning trust funds, which are reflected as Nuclear Decommissioning Trust Funds within Investments and Other Assets in the Consolidated Balance Sheets, was approximately $1,436 million as of December 31, 2008 and $1,929 million as of December 31, 2007. The decrease in the value of the NDTF during 2008 is due to the overall decline in the value of the investments held in the NDTF as a result of the impacts of the current economic condition on 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 $1,194 million as of December 31, 2008 and $1,551 million as of December 31, 2007. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s proportionate ownership in the Catawba Nuclear Station, which was 12.5% at the time the study was completed. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station.

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. Duke Energy will file these site-specific nuclear decommissioning cost studies with the NCUC and the PSCSC later in 2009. In addition to the decommissioning cost studies, a new funding study is underway to determine the appropriateness of the annual amounts currently being contributed to the NDTF to fund the cost of future decommissioning of Duke Energy’s nuclear units. The NCUC and the PSCSC will consider the results of the funding study, which could potentially increase the annual required contributions to the NDTF, in the latter part of 2009.

Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Management believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, will be sufficient to provide for the cost of future decommissioning.

The operating licenses for Duke Energy’s nuclear units are subject to extension. In December 2003, Duke Energy was granted renewed operating licenses for 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 and Hedging Activities and Credit 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. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including swaps, futures, forwards, options and swaptions.

131

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As discussed in Note 1, on January 1, 2008, Duke Energy adopted FSP No. FIN 39-1. In accordance with FSP No. FIN 39-1, 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. Amounts presented in the table below exclude cash collateral amounts which are disclosed separately in Note 1.

Net Derivative Portfolio Assets (Liabilities) reflected in the Consolidated Balance Sheets:

	Years Ended December 31,
	2008			2007
	(in millions)
Hedging	$	(10	)	$	(34	)
Undesignated		(80	)		39
Total	$	(90	)	$	5

The amounts in the table above represent the combination of amounts included in the Consolidated Balance Sheets as a component of Other within Current Assets, Other within Investments and Other Assets, Other within Current Liabilities and Other within Deferred Credits and Other Liabilities.

Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their power generating and natural gas sales and transportation activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for electricity and natural gas transactions. Duke Energy is hedging exposures to the price variability of these commodities for a maximum period of 2 years.

The ineffective portion of commodity cash flow hedges resulted in an insignificant amount in 2008 and 2007 and a pre-tax gain of approximately $5 million in 2006 and is reported primarily in Income (Loss) From Discontinued Operations, net of tax in the Consolidated Statements of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges, which is classified in Income (Loss) From Discontinued Operations, net of tax in the Consolidated Statements of Operations, resulted in an insignificant amount in 2008 and 2007 and a loss of approximately $67 million in 2006.

As of December 31, 2008, approximately $24 million of pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheets in AOCI and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur.

Commodity Fair Value Hedges. Some Duke Energy subsidiaries may be exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. In the former DENA business, now classified as discontinued operations, Duke Energy evaluated changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, used various instruments to hedge its market risk. Those commodity instruments, such as swaps, futures and forwards, served as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in no gain or loss in 2008 and 2007, and a pre-tax gain of $7 million in 2006, and is reported primarily in Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Operations. At December 31, 2008, Duke Energy did not have any open commodity fair value hedges.

Normal Purchases and Normal Sales (NPNS) Exception. Duke Energy has applied the NPNS scope exception, as provided in SFAS No. 133, interpreted by Derivatives Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 13 years, are not included in the table above.

132

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Energy to risk as a result of its issuance of variable 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, but is not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Duke Energy’s existing interest rate derivative instruments and related ineffectiveness were insignificant to its consolidated results of operations, cash flows or financial position in 2008, 2007, and 2006.

As of December 31, 2008, approximately $5 million of pre-tax deferred net losses on terminated interest rate hedges were accumulated on the Consolidated Balance Sheets in AOCI and are expected to be recognized in earnings during the next twelve months as the hedge transactions occur.

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be 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. Duke Energy did not enter into or have any open foreign currency derivatives or net investment hedges during 2008, 2007 or 2006. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

Other Derivative Contracts. Trading. Duke Energy has been exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of proprietary trading activities. During 2003, Duke Energy prospectively discontinued proprietary trading. As a result of the Cinergy merger, Duke Energy acquired natural gas and power marketing and trading operations, conducted primarily through CMT, the results of which have been reflected in Income (Loss) from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to the date of sale. As discussed further in Note 14, in October 2006, the CMT sale transaction was completed and Duke Energy entered into a series of Total Return Swaps (TRS) with Fortis. As of December 31, 2008, all of the underlying contracts that were part of the TRS had been transferred to Fortis and, as a result, Duke Energy has no future exposure associated with these TRS.

Undesignated. In addition, Duke Energy uses derivative contracts to manage the market risk exposures that arise from energy supply, structured origination, marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies, and to manage interest rate and foreign currency exposures. This category includes changes in fair value for derivatives that no longer qualify for the NPNS scope exception and disqualified hedge contracts, unless the derivative contract is subsequently re-designated as a hedge. The contracts in this category as of December 31, 2008 are primarily associated with forward power sales and coal purchases, as well as forward contracts to purchase SO₂ emission allowances, for the Commercial Power and U.S. Franchised Electric and Gas operations. Duke Energy’s exposure to price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.

During the years ended December 31, 2008 and 2007, Duke Energy included in earnings approximately $75 million of pre-tax losses and approximately $13 million of pre-tax gains, respectively, related to mark-to-market adjustments within Commercial Power which are reported primarily in Non-regulated electric, natural gas, and other and Fuel used in electric generation and purchased power-non-regulated on the Consolidated Statements of Operations. As discussed in Note 1 and Note 4, beginning on December 17, 2008, Commercial Power reapplied the provisions of SFAS No. 71 to certain portions of its operations due to the passing of SB 221 and the approval of the ESP. The reapplication of SFAS No. 71 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 hedge contracts, which the ESP allows to be recovered through an FPP rider. Subsequent to December 17, 2008, mark-to-market gains and losses on certain open hedge positions related to native load generation will be deferred as regulatory assets or liabilities and recovered through the FPP rider.

In connection with the exiting of the DENA business in 2005, Duke Energy entered into a series of 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, 2008 is an asset of approximately $30 million, which offsets the net fair value of the underlying contracts, which is a liability of approximately $30 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.

133

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 in its risk management operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

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.

9. Fair Value of Financial Assets and Liabilities

On January 1, 2008, Duke Energy adopted SFAS No. 157. Duke Energy’s adoption of SFAS No. 157 is currently limited to financial instruments and to non-financial derivatives as, in February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157 Date Posted: February 12, 2008,” (FSP FAS 157-2) which delayed the effective date of SFAS No. 157 until January 1, 2009 for non-financial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. There was no cumulative effect adjustment to retained earnings for Duke Energy as a result of the adoption of SFAS No. 157. In accordance with FSP FAS 157-2, the provisions of SFAS No. 157 were not applied to the 2008 annual goodwill impairment test (see Note 11) or to certain non-financial assets acquired from Catamount (see Note 3).

SFAS No. 157 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 SFAS No. 157, 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 under SFAS No. 157 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 SFAS No. 157 does not require additional fair value measurements, it applies to other accounting pronouncements that require or permit fair value measurements. In October 2008, the FASB issued FSP FAS 157-3, which illustrated key considerations in determining the fair value of a financial asset when the market for that asset is not active. The application of FSP FAS 157-3 did not change the way Duke Energy determined fair value of its financial assets and liabilities.

Duke Energy determines fair value of financial assets and liabilities based on the following fair value hierarchy, as prescribed by SFAS No. 157, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 inputs—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 inputs for any blockage factor.

Level 2 inputs—inputs other than quoted market prices included in Level 1 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.

Level 3 inputs—unobservable inputs for the asset or liability.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities- including an amendment of FASB Statement No. 115” (SFAS No. 159), which permits entities to elect to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 was effective as of January 1, 2008 and had no impact on amounts

134

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

presented for periods prior to the effective date. Duke Energy does not currently have any financial assets or financial liabilities for which the provisions of SFAS No. 159 have been elected. However, in the future, Duke Energy may elect to measure certain financial instruments at fair value in accordance with this standard.

The following table provides the fair value measurement amounts for financial assets and liabilities recorded on Duke Energy’s Consolidated Balance Sheets at fair value at December 31, 2008:

	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)	$	224		$	—		$	—		$	224
Nuclear decommissioning trust fund		1,436			853			583			—
Other long-term available for sale securities(b)		314			74			240			—
Derivative assets(c)		251			9			70			172
Total Assets	$	2,225		$	936		$	893		$	396
Derivative liabilities(d)		(341	)		(88	)		(115	)		(138	)
Net Assets	$	1,884		$	848		$	778		$	258

(a) Approximately $173 million of auction rates 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) Included in Other within Investments and Other Assets on the Consolidated Balance Sheets.

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

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

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
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:
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, settlements and other		(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 gains (losses) included in the Consolidated Statements of Operations related to Level 3 measurements outstanding at December 31, 2008:
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

135

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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, NYSE, NYMEX and Chicago Board of Trade, as well as pink sheets, which is an electronic quotation system that displays quotes for broker-dealers for many over-the-counter securities. 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 does not adjust 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: As of December 31, 2008, Duke Energy has approximately $270 million par value (approximately $224 million fair value) of auction rate securities for which an active market does not currently exist. All of these securities were valued as of December 31, 2008 using measurements appropriate for Level 3 investments. The methods and significant assumptions used to determine the fair values of Duke Energy’s investment in auction rate debt securities represented a combination of broker-provided quotations and estimations of fair value using validation of such quotations through internal discounted cash flow models which incorporated primarily Duke Energy’s own assumptions as to the term over which such investments will be recovered at par, the current level of interest rates, and the appropriate risk-adjusted (for liquidity and credit) discount rates when relevant observable inputs are not available to determine present value of such cash flows. Valuations were determined based on a combination of broker quotes, where available, internal modeling of comparable instruments or discounted cash flow analyses. In preparing the valuations, all significant value drivers were considered, including the underlying collateral. Refer to Notes 10 and 13 for additional information on Duke Energy’s investments in auction rate securities.

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 NYMEX contracts, which Duke Energy classifies as Level 1 measurements.

Fair Value Disclosures Required Under SFAS No. 107, “Disclosures About Fair Value of Financial Instruments”. The fair value of financial instruments, excluding financial assets included in the scope of FAS 157 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, 2008 and 2007, are not necessarily indicative of the amounts Duke Energy could have realized in current markets.

	As of December 31,
	2008				2007
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term debt, including current maturities	$	13,896	$	13,981	$	11,024	$	11,154

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.

10. Investments in Debt and Equity Securities

Duke Energy applies SFAS No. 115 to its investments in debt and equity securities and classifies its investments primarily into two categories – trading and available-for-sale. As discussed in Note 1, certain investments in debt and equity securities held in grantor trusts associated with certain deferred compensation plans are classified as trading securities, which are reported at fair value in the Consolidated Balance Sheets with net realized and unrealized gains and losses included in earnings each period. Substantially all other

136

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. Except for certain investments in debt and equity securities, primarily those held in the NDTF, which are discussed separately below, unrealized gains and losses on investments classified as available-for-sale are included in AOCI, 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 is included in earnings. 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.

Duke Energy analyzes all securities classified as available-for-sale to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment is other-than-temporary includes, but is not limited to, the length of time over which the market value has been lower than the cost basis of the investment, the percentage decline compared to the cost of the investment and management’s intent and ability to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. 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. During the year ended December 31, 2008, Duke Energy recorded pre-tax other-than-temporary impairment charges of approximately $13 million within Other Income and Expenses, net on the Consolidated Statements of Operations to write down the carrying value of certain investments in debt and equity securities to their estimated fair values, including investments in auction rate debt securities as discussed in Note 13.

Short-term investments. At December 31, 2008 and 2007, Duke Energy had $51 million and $437 million, respectively, of short-term investments, which consisted primarily of investments in auction rate debt securities that are considered available-for-sale securities under SFAS No. 115. As discussed further in Note 13, at December 31, 2007, Duke Energy held approximately $430 million of investments in auction rate debt securities and all but approximately $15 million of these investments were sold at auction in January 2008 at full principal amounts. During the first quarter of 2008, Duke Energy made additional investments of approximately $285 million in auction rate debt securities. At December 31, 2008, Duke Energy holds approximately $270 million par value of investments in auction rate debt securities that have a carrying value of approximately $224 million. Of this amount, approximately $55 million par value (approximately $51 million carrying value) of investments in auction rate debt securities are classified as short-term investments at December 31, 2008 as these investments either have a stated maturity within the next 12 months or Duke Energy believes the investments are reasonably expected to be refunded within the next 12 months based on notification of a refunding plan by the issuer. The remaining balance of investments in auction rate debt securities are included in long-term investments and are discussed further below. During the years ended December 31, 2008, 2007 and 2006, Duke Energy purchased short-term investments of approximately $4,277 million, $21,661 million and $31,521 million, respectively, and received proceeds on sales of approximately $4,424 million, $22,685 million and $30,692 million, respectively.

Other Long-term investments. Duke Energy invests in debt and equity securities that are held in the NDTF (see Note 7 for further information), in grantor trusts for investments primarily related to certain deferred compensation plans and in the captive insurance investment portfolio. Additionally, as discussed above and further in Note 13, approximately $215 million par value (approximately $173 million carrying value) of investments in auction rate debt securities have been classified as long-term at December 31, 2008 due to market illiquidity factors as a result of continued failed auctions. All of these investments are classified as available-for-sale under SFAS No. 115 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. As of December 31, 2008 and 2007, Duke Energy’s other long-term investments had a fair market value of $1,855 million and $2,274 million, respectively.

As of December 31, 2008 and 2007, Duke Energy’s NDTF held investments with a fair market value of approximately $1,436 million and $1,929 million, respectively. The NDTF is managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreement. Therefore, Duke Energy has limited oversight of the day-to-day management of the NDTF investments. Since day-to-day investment decisions are not made by management of Duke Energy, the ability to hold investments in unrealized loss positions is outside the control of Duke Energy since buy and sell decisions are made by the investment manager of the NDTF. Accordingly, other-than-temporary impairment losses are recorded immediately when the fair value of individual investments held in the NDTF is less than the cost basis of the investment. However, pursuant to an order from the NCUC, all losses associated with investments in the NDTF are deferred as a regulatory asset, thus there is no impact on the earnings of Duke Energy as a result of these other-than-temporary impairment write-downs.

137

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The cost of securities sold is determined using the specific identification method. During the years ended December 31, 2008, 2007 and 2006, Duke Energy purchased long-term investments of approximately $3,076 million, $1,978 million and $1,915 million, respectively, and received proceeds on sales of approximately $3,030 million, $1,928 million and $1,904 million, respectively. The majority of these purchases and sales relate to activity within the NDTF, including annual contributions to the NDTF of approximately $48 million pursuant to an order by the NCUC (see Note 7).

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

	As of December 31,
	2008							2007
	Gross Unrealized Holding Gains		Gross Unrealized Holding Losses(a)			Estimated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses(a)			Estimated Fair Value
Short-term Investments	$	—	$	(4	)	$	51	$	—	$	—		$	437
Total short-term investments	$	—	$	(4	)	$	51	$	—	$	—		$	437
Equity Securities	$	161	$	(20	)	$	880	$	510	$	(1	)	$	1,458
Corporate Debt Securities		5		—			124		2		—			86
Municipal Bonds		2		—			150		3		—			251
U.S. Government Bonds		18		—			292		10		—			269
Auction Rate Securities		—		(42	)		173		—		—			—
Other		3		(1	)		236		2		(1	)		210
Total long-term investments	$	189	$	(63	)	$	1,855	$	527	$	(2	)	$	2,274

(a) Losses of approximately $190 million and $24 million as of December 31, 2008 and 2007, respectively, associated with investments held in the NDTF have been excluded from the table since, as discussed above, day-to-day investment decisions are not made by management of Duke Energy, thus the ability to hold investments in unrealized loss positions is outside the control of Duke Energy since buy and sell decisions are made by the investment manager of the NDTF. Accordingly, other-than-temporary impairment losses are recorded immediately when the fair value of individual investments held in the NDTF is less than the cost basis of the investment.

For the years ended December 31, 2008, 2007, and 2006, a loss of approximately $1 million, a gain of less than $1 million, and a gain of approximately $57 million (including $51 million reclassified to Income (Loss) from Discontinued Operations, net of tax), respectively, were reclassified out of AOCI into earnings.

Debt securities held, which includes auction rate securities based on the stated maturity date, at December 31, 2008 mature as follows: $18 million in less than one year, $106 million in one to five years, $130 million in six to ten years and $646 million thereafter.

138

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The fair values and gross unrealized losses of available-for-sale equity and debt 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, 2008 and 2007.

	As of December 31, 2008
	Fair Value		Unrealized Loss Position >12 months			Unrealized Loss Position <12 months
	(in millions)
Equity Securities	$	47	$	(2	)	$	(18	)
Auction Rate Securities		224		—			(46	)
Other		32		—			(1	)
Total	$	303	$	(2	)	$	(65	)

	As of December 31, 2007
	Fair Value		Unrealized Loss Position >12 months			Unrealized Loss Position <12 months
	(in millions)
Equity Securities	$	6	$	(1	)	$	—
Other		55		(1	)		—
Total	$	61	$	(2	)	$	—

11. Goodwill and Intangible Assets

Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142. There were no goodwill impairment charges in 2008, 2007 or 2006 as a result of the annual impairment tests required by SFAS No. 142. As discussed further in Note 3, in April 2006, Duke Energy and Cinergy consummated the previously announced merger, which resulted in Duke Energy recording goodwill and intangible assets of approximately $5.6 billion. The following table shows the components of goodwill at December 31, 2008:

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2007		Changes			Balance December 31, 2008
	(in millions)
U.S. Franchised Electric and Gas	$	3,478	$	22		$	3,500
Commercial Power(a)		871		89			960
International Energy(b)		293		(33	)		260
Total consolidated	$	4,642	$	78		$	4,720
	Balance December 31, 2006		Changes			Balance December 31, 2007
U.S. Franchised Electric and Gas	$	3,500	$	(22	)	$	3,478
Natural Gas Transmission(c)		3,523		(3,523	)		—
Commercial Power		885		(14	)		871
International Energy(b)		267		26			293
Total consolidated	$	8,175	$	(3,533	)	$	4,642

(a) As discussed in Note 3, the increase in goodwill in the Commercial Power segment primarily relates to the acquisition of Catamount in September 2008.

(b) The change in the goodwill balance at International Energy relates to the impacts of foreign exchange rates on the translation of the goodwill balance into U.S. dollars.

(c) As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, including the former Natural Gas Transmission business segment.

139

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Intangible Assets

The carrying amount and accumulated amortization of intangible assets as of December 31, 2008 and December 31, 2007, which primarily related to the intangible assets acquired as a part of the merger with Cinergy, are as follows:

	December 31, 2008			December 31, 2007
	(in millions)
Emission allowances	$	300		$	426
Gas, coal and power contracts		296			296
Wind development rights(a)		161			48
Other		68			68
Total gross carrying amount		825			838
Accumulated amortization—gas, coal and power contracts		(117	)		(94	)
Accumulated amortization—other		(28	)		(24	)
Total accumulated amortization		(145	)		(118	)
Total intangible assets, net	$	680		$	720

(a) As discussed further below, the increase in wind development rights primarily relates to the acquisition of Catamount in September 2008.

Emission allowances in the table above include emission allowances acquired by Duke Energy as part of the merger with Cinergy, which were recorded at fair value on the date of the merger, 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, 2008 and December 31, 2007 are as follows:

	December 31, 2008			December 31, 2007
	(in millions)
Gross carrying value at beginning of period	$	426		$	587
Purchases of emission allowances		62			103
Sales and consumption of emission allowances (a)(b)		(116	)		(271	)
Impairment of emission allowances (c)		(82	)		—
Other changes		10			7
Gross carrying value at end of period	$	300		$	426

(a) Carrying value of emission allowances are recognized via a charge to expense when consumed. Carrying value of emission allowances sold or consumed during the years ended December 31, 2008, 2007 and 2006 were $116 million, $271 million and $428 million, respectively.

(b) See Note 3 for a discussion of gains and losses on sales of emission allowances by Commercial Power during the years ended December 31, 2008, 2007 and 2006.

(c) See Note 13 for discussion of impairments of the carrying value of emission allowances during the year ended December 31, 2008.

Amortization expense for gas, coal and power contracts and other intangible assets for the years ended December 31, 2008, 2007 and 2006 was approximately $27 million, $57 million and $56 million, respectively.

The table below shows the expected amortization expense for the next five years for intangible assets as of December 31, 2008. The expected amortization expense includes estimates of emission allowances consumption and estimates of consumption of commodities such as gas and coal under existing contracts. The table below does not include any estimated amortization related to the wind development projects acquired from Catamount, discussed below, as those projects have not yet commenced commercial operations. The amortization amounts discussed below are estimates. 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, additional intangible acquisitions and other events.

	2009		2010		2011		2012		2013
	(in millions)
Amortization expense	$	155	$	39	$	36	$	35	$	32

140

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 has plans to dispose of through sale; however, these assets do not meet the criteria for assets held-for-sale treatment under SFAS No. 144. 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.

Intangible Liabilities

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. The carrying amount of this intangible liability was zero and approximately $67 million at December 31, 2008 and 2007, respectively. Duke Energy also recorded approximately $56 million of intangible liabilities associated with other power sale contracts in connection with the merger with Cinergy. The carrying amount of these intangible liabilities was approximately $16 million and $22 million at December 31, 2008 and 2007, respectively. During the years ended December 31, 2008, 2007 and 2006, Duke Energy amortized approximately $73 million, $45 million and $35 million, respectively, to income related to these intangible liabilities. The remaining balance of approximately $16 million will be amortized to income as follows: approximately $6 million in each of the years 2009 through 2010, and approximately $4 million in 2011. Intangible liabilities are classified as Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

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. As of December 31, 2008 and 2007, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets. Significant investments in affiliates are as follows:

Commercial Power. As of December 31, 2008, investments 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.

At December 31, 2007, investments primarily included a 50% interest in South Houston Green Power, L.P. (SHGP). SHGP 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 under FIN 46(R). 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. The wind assets are currently anticipated to be in commercial operation in 2009. This transaction, which will be considered a non-monetary exchange of productive assets with commercial substance, is subject to the accounting guidance in APB Opinion No. 29, “Accounting for Nonmonetary Transactions’ and SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29”. 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 accounted for under APB 18. 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

141

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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.

International Energy. As of both December 31, 2008 and 2007, investments primarily included 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. Through August 2007, Duke Energy held a 50% investment interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues were generated from a gas compression services agreement (GCSA) with the Mexican National Oil Company (PEMEX). Upon the expiration of the GCSA with PEMEX in August 2007, the operations of Campeche were transferred to PEMEX and International Energy had no subsequent involvement with Campeche. See Note 13 for discussion of other than temporary impairment charges recorded during the year ended December 31, 2006 against the carrying value of the Campeche investment and related notes receivable.

Other. As of December 31, 2008 and 2007, investments primarily include telecommunications investments and Duke Energy’s effective 50% interest in Crescent. As described further in Note 2, effective in the fourth quarter of 2008, Crescent is no longer a reportable business segment of Duke Energy and all historical results of Crescent have been reflected in Other. Additionally, as described further in Note 3, Duke Energy deconsolidated Crescent as of September 7, 2006 as a result of a reduction in ownership to an effective 50% interest and subsequently accounted for the investment using the equity method of accounting up through September 30, 2008.

Crescent has long-term debt of approximately $1.4 billion, all of which is non-recourse to Duke Energy. Prior to the June 2008 debt amendments discussed below, approximately $1.2 billion of the long-term debt balance was term debt due in September 2012 with only very minor amounts due prior to that date. Crescent’s debt agreements had certain financial covenants that were required to be met on a quarterly basis. Due to the sustained downturn in overall economic conditions, including the real estate markets in areas in which Crescent holds properties, Crescent management determined that it could be in violation of one or more of its debt covenants in the near-term absent amendments to its debt agreements. In June 2008, Crescent renegotiated amendments to its debt agreements, including modifications to certain financial covenants. Under the terms of the amended debt agreements, Crescent is still obligated to pay down the entire term loan amount of $1.2 billion by September 2012, with cumulative repayments of $225 million through December 31, 2011, ($50 million, $75 million, and $100 million to be paid in the periods ending December 31, 2009, 2010, and 2011 respectively), with the remainder due in 2012. Under the terms of the new debt agreement, Crescent was required to have its properties appraised by an independent third party no later than February 28, 2009. Had the appraisals indicated that Crescent’s Loan-to-Value Ratio (Total Indebtedness/ Qualifying Assets Value) was greater than 80%, Crescent would be in violation of certain debt covenants. All of the property appraisals were completed prior to February 28, 2009 and Crescent’s Loan-to-Value Ratio was less than 80%. As of December 31, 2008, Crescent maintained an overall debt balance of approximately $1.4 billion, of which approximately $230 million relates to a revolving credit facility.

In connection with the renegotiation of the debt agreements in the second quarter of 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 and reduce debt, in an environment which favors buyers. Crescent’s management continues to view a significant portion of its real estate projects as strategic assets. The new focus in accelerating cash flows from certain of its non-strategic assets in 2008 and 2009 may enable Crescent to meet its new and accelerated debt service obligations and ultimately improve its capitalization. Crescent’s objective with this strategy is to ultimately allow it greater financial flexibility in maximizing the long-term value of its strategic assets.

As a result of its revised business strategy to accelerate certain cash flows resulting from the June 2008 amendments to its debt agreements and the continued deterioration of the real estate and credit markets, Crescent prepared its recoverability assessments for its real estate projects as required under SFAS No. 144. Under SFAS No. 144, 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 assets, it was determined that projected undiscounted cash flows did not exceed the carrying value of the projects based on the revised business strategy assumptions, and impairment losses were 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 independent third party appraisals and 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 years ended December 31, 2008 and 2007, 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 and $32 million, respectively. Duke Energy’s proportionate share of Crescent’s impairment charges are recorded in Equity in Earnings (Loss) of Unconsolidated Affiliates in Duke Energy’s Consolidated Statements of Operations.

142

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As a result of Duke Energy recording its proportionate share of Crescent’s impairment losses, the carrying value of Duke Energy’s investment in Crescent was reduced to zero at September 30, 2008. Beginning in the fourth quarter of 2008, in accordance with APB 18, Duke Energy suspended applying the equity method of accounting to its investment in Crescent since its investment has been reduced to zero. Accordingly, Duke Energy did not record any additional losses during the fourth quarter of 2008. However, should Crescent begin reporting net income in future periods, Duke Energy may resume applying the equity method of accounting after its proportionate share of that net income equals the share of net losses not recognized during the period the equity method was suspended since Duke Energy continues to exercises significant influence over the operations and financial policies of Crescent.

See Note 19 for discussion of certain guarantees Duke Energy has issued on behalf of Crescent.

Investments in Equity Method Unconsolidated Affiliates

	As of:
	December 31, 2008						December 31, 2007
	Domestic		International		Total		Domestic		International		Total
	(in millions)
U.S. Franchised Electric and Gas	$	3	$	—	$	3	$	2	$	—	$	2
Commercial Power		226		—		226		201		—		201
International Energy		—		161		161		—		181		181
Other(a)(b)		73		10		83		301		11		312
Total	$	302	$	171	$	473	$	504	$	192	$	696

(a) Other includes Duke Energy’s effective 50% interest in Crescent. As discussed above, Duke Energy’s investment in Crescent was written down to zero during 2008.

(b) During the year ended December 31, 2008, Duke Energy recorded pre-tax impairment charges to write-down the carrying value of certain equity method investments to their estimated fair value. These impairment charges are included in Losses on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations.

Equity in Earnings (Losses) of Equity Method Unconsolidated Affiliates

	For the Years Ended:
	December 31, 2008								December 31, 2007								December 31, 2006
	Domestic			International		Total			Domestic			International		Total			Domestic			International		Total
	(in millions)
U.S. Franchised Electric and Gas	$	(16	)	$	—	$	(16	)	$	(2	)	$	—	$	(2	)	$	(2	)	$	—	$	(2	)
Commercial Power		16			—		16			17			—		17			21			—		21
International Energy		—			127		127			—			102		102			—			80		80
Other(a)(b)		(230	)		1		(229	)		38			2		40			21			3		24
Total(c)	$	(230	)	$	128	$	(102	)	$	53		$	104	$	157		$	40		$	83	$	123

(a) Other includes equity earnings and losses of Crescent for all periods. For the year ended December 31, 2006, approximately $15 million represents Duke Energy’s effective 50% interest in Crescent earnings subsequent to deconsolidation in September 2006.

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

(c) Excludes equity in earnings of approximately $609 million for the year ended December 31, 2006 included in Income (Loss) From Discontinued Operations, net of tax, primarily related to equity method investments held by the natural gas businesses and included in Duke Energy’s spin-off of Spectra Energy on January 2, 2007.

Duke Energy’s share of net earnings from these unconsolidated affiliates is reflected in the Consolidated Statements of Operations as Equity in Earnings of Unconsolidated Affiliates. During the years ended December 31, 2008, 2007 and 2006, Duke Energy received distributions from equity investments of approximately $195 million, $147 million and $893 million, respectively. Of these amounts, approximately $195 million, $147 million and $741 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006, respectively, and approximately $152 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2006.

143

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Summarized Combined Financial Information of Equity Method Unconsolidated Affiliates

	As of December 31,
	2008			2007
	(in millions)
Balance Sheet
Current assets	$	1,399		$	1,348
Non-current assets		4,072			3,900
Current liabilities		(1,489	)		(1,297	)
Non-current liabilities		(2,038	)		(2,015	)
Net assets	$	1,944		$	1,936

	For the Years Ended December 31,
	2008		2007		2006
	(in millions)
Income Statement(a)
Operating revenues	$	2,683	$	2,284	$	14,259
Operating expenses		2,407		1,634		12,365
Net income		58		462		1,657

(a) Amounts for the year ended December 31, 2006 include equity investments related to the natural gas businesses that were included in the spin-off to shareholders on January 2, 2007 for which equity earnings are included in Income (Loss) From Discontinued Operations, net of tax, for periods prior to the spin-off. Additionally, amounts for Crescent are included from the date of deconsolidation (September 7, 2006) and thereafter.

Related Party Transactions. Notes receivable from unconsolidated affiliates, which are included in Receivables on the Consolidated Balance Sheets, were $292 million and $299 million as of December 31, 2008 and 2007, respectively, which represents Duke Energy Ohio’s and Duke Energy Indiana’s notes receivable from Cinergy Receivables Company LLC (Cinergy Receivables). See Note 23 for additional information.

Duke Energy Ohio and Duke Energy Indiana sell their receivables to Cinergy Receivables. During 2008, Duke Energy Ohio and Duke Energy Indiana collectively sold approximately $5.7 billion of receivables to Cinergy Receivables and received approximately $5.7 billion in proceeds from the sales, including the notes receivable. During 2007, Duke Energy Ohio and Duke Energy Indiana collectively sold approximately $5.3 billion of receivables to Cinergy Receivables and received approximately $5.1 billion in proceeds from the sales, including the notes receivable. See Note 23 for further information.

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, $8 million and $24 million to the unconsolidated subsidiary during the years ended December 31, 2008, 2007 and 2006, respectively. Additionally, at both December 31, 2008 and 2007, U.S. Franchised Electric and Gas had a trade payable to Advance SC LLC of approximately $11 million.

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 in accordance with SOP 78-9, “Accounting for Investments in Real Estate Ventures.”

144

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Prior to August 2007, International Energy loaned money to Campeche to assist in the costs to build. International Energy received principal and interest payments of approximately $28 million and $11 million from Campeche during 2007 and 2006, respectively.

The following related party transactions relate to activity with and among businesses included in the spin-off of the natural gas businesses in January 2007 and are included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, except where noted:

In December 2005, Duke Energy completed a 140 million Canadian dollars initial public offering on its Canadian income trust fund (the Income Fund) and sold 14 million Trust Units at an offering price of 10 Canadian dollars per Trust Unit. In January 2006, a subsequent greenshoe sale of 1.4 million additional Trust Units, pursuant to an overallotment option, were sold at a price of 10 Canadian dollars per Trust Unit. Subsequent to the January 2006 sale of additional Trust Units, Duke Energy held an approximate 58% ownership interest in the businesses of the Income Fund. Proceeds of approximately 14 million Canadian dollars are included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units at a price of 12.15 Canadian dollars per Trust Unit for total proceeds of 104 million Canadian dollars, net of commissions and expenses of other expenses of issuance, which is included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. The sale of approximately 9 million Trust Units reduced Duke Energy’s ownership interest in the businesses of the Income Fund to approximately 46% at December 31, 2006. The Income Fund was included in the spin-off of the natural gas businesses on January 2, 2007. As a result of the sale of additional Trust Units, Duke Energy recognized an approximate $15 million pre-tax gain on the sale of subsidiary stock during the year ended December 31, 2006. The proceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. There were no deferred taxes recorded as a result of this transaction.

For the year ended December 31, 2006, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DCP Midstream of approximately $137 million, $41 million and $12 million, respectively. Additionally, Duke Energy received approximately $725 million for its share of distributions paid by DCP Midstream in 2006. Of these distributions $573 million was included in Other, assets within Cash Flows from Operating Activities for the year ended 2006, and approximately $152 million was included in Distributions from Equity Investments within Cash Flows from Investing Activities for the year ended 2006 within the accompanying Consolidated Statements of Cash Flows.

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.

Accordingly, summarized financial information for Crescent, which has been accounted for under the equity method since September 7, 2006 is as follows:

	Year Ended December 31, 2008			Year Ended December 31, 2007		September 7 through December 31, 2006
	(in millions)
Operating revenues	$	407		$	536	$	179
Operating expenses	$	754		$	415	$	152
Operating income	$	(347	)	$	121	$	27
Net income(a)	$	(420	)	$	76	$	30

(a) 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			December 31, 2007
	(in millions)
Current assets	$	77		$	99
Non-current assets	$	1,685		$	2,059
Current liabilities	$	471		$	306
Non-current liabilities	$	1,341		$	1,486
Minority interest	$	(1	)	$	13

145

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Summarized financial information for DCP Midstream, which had equity earnings of approximately $574 million included in Income (Loss) from Discontinued Operations, net of tax, on the Consolidated Statements of Operations during the year ended December 31, 2006 and was included in the spin-off of the natural gas businesses on January 2, 2007, is as follows:

	Year Ended December 31, 2006
Operating revenues	$	12,335
Operating expenses	$	11,063
Operating income	$	1,272
Net income	$	1,139

Also see Notes 3, 19 and 23 for additional related party information.

13. Impairments, Severance, and Other Charges

Auction Rate Security Investments. At December 31, 2007, Duke Energy held approximately $430 million of investments in auction rate debt securities and all but approximately $15 million of these investments were sold at auction in January 2008 at full principal amounts. During the first quarter of 2008, Duke Energy made additional investments of approximately $285 million in auction rate debt securities, which primarily consisted of investments in AAA rated student loan securities that are viewed as having minimal credit risk as substantially all values are ultimately backed by the U.S. government. These securities are treated as available-for-sale securities under SFAS No. 115. At the end of the first quarter of 2008, Duke Energy reclassified its approximate $300 million par value of investments in auction rate debt securities from short-term to long-term as an active market for these investments did not exist. During the year ended December 31, 2008, approximately $30 million of auction rate debt security investments were refunded by the issuer and the proceeds received by Duke Energy represented full principal and interest amounts. As of the end of each quarter throughout 2008, management of Duke Energy performed valuations of its investment in auction rate debt securities (consistent with provisions of SFAS No. 157—see Note 9 for further information on the methods utilized to determine fair value) to determine if the carrying value of these investments exceeded their estimated fair value and, if so, whether the decline in fair value was considered temporary or other-than-temporary. As of December 31, 2008, the fair value of the investments in auction rate debt securities was determined to be lower than the par value of the securities by approximately $46 million. Based on an analysis of specific facts and circumstances, management believes that the majority of these investments are viewed as having minimal credit risk (as discussed above) and Duke Energy has the intent and ability to hold these securities until the credit markets regain liquidity, the instruments are refunded by the issuer at their stated par values or maturity. Accordingly, approximately $43 million of the decline in value was considered temporary and recorded as a component of Other Comprehensive Income. The remaining $3 million reduction in carrying value was charged to expense as management had concluded this impairment to be other-than-temporary. This conclusion was based in part on a loss in value in the underlying collateral supporting the par value of these securities, which is not supported by insurance or backed by the U.S. government. At December 31, 2008, the par value and carrying value of Duke Energy’s investments in auction rate debt securities was approximately $270 million and $224 million, respectively.

At December 31, 2008, approximately $51 million of the fair value of investments in auction rate debt securities are classified as Short-Term Investments within current assets on the Consolidated Balance Sheets, with the remaining approximately $173 million classified as long-term investments in Other within Investments and Other Assets on the Consolidated Balance Sheets. The investments classified as short-term either have a stated maturity within the next 12 months or Duke Energy believes the investments are reasonably expected to be refunded within the next 12 months based on a notification of a refunding plan by the issuer.

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. See Note 1 for Duke Energy’s policy on reviewing the carrying value of investments to determine if an other-than-temporary impairment exists.

Emission Allowances. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia issued a decision vacating the CAIR. In December 2008, a federal appeals court reinstated the CAIR while the EPA develops a new clean air program (see Note 18 for additional information). 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, pursuant to SFAS No. 144, Duke Energy evaluated the carrying value of emission allowances held by its regulated and non-regulated businesses for impairment during the third quarter of 2008.

146

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

At the time of its 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 the 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 decision to vacate the 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 in the third quarter of 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, during the third quarter of 2008, Commercial Power recorded pre-tax impairment charges of approximately $77 million related to forecasted excess SO₂ allowances held. Additionally, Commercial Power recorded pre-tax impairment charges of approximately $5 million in the third quarter of 2008 related to annual NO_x allowances as these were also affected by the decision to vacate the CAIR. These impairment charges are recorded in Impairments Charges within Operating Expenses on the Consolidated Statements of Operations.

Additionally, U.S. Franchised Electric and Gas had emission allowances and certain commitments to purchase emission allowances that, based on management’s best estimate in the third quarter of 2008 due to the vacation of the CAIR, 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 vacating of the CAIR, these forward contracts, which primarily settle in the fourth quarter of 2008 and 2009, qualified for the NPNS exception under SFAS No. 133, as amended. However, since certain of these forward contracts were no longer considered probable of use in the normal course of operations at the time the impairment analysis was performed due to the excess over forecasted needs, in the third quarter of 2008, U.S. Franchised Electric and Gas determined that these contracts no longer qualified for the NPNS exception under SFAS No. 133. 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. The fair value of these contracts at December 31, 2008 was approximately $32 million. These forward contracts will continue to be marked-to-market, with an offset to a regulatory asset or liability balance, until ultimate settlement.

As a result of the reinstatement of the CAIR, as discussed above, all emission allowances and certain commitments to purchase emission allowances held by Commercial Power and U.S. Franchised Electric and Gas as of December 31, 2008 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.

See Note 11 for further information regarding the carrying value of emission allowances.

International Energy. During the year ended December 31, 2006, International Energy recorded other than temporary impairment charges of approximately $50 million related to an investment in Campeche. Campeche project revenues were generated from a GCSA with PEMEX. The charges consist of a $17 million impairment of the carrying value of the equity method investment, which has been classified within Losses on Sales and Impairments of Equity Investments in the accompanying Consolidated Statements of Operations and a $33 million reserve against notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the accompanying Consolidated Statements of Operations.

The GCSA expired in August 2007 and ownership of the facility transferred to PEMEX.

Discontinued Operations. See Note 14 for impairments related to discontinued operations.

Severance and Other Charges. During the years ended December 31, 2008, 2007 and 2006, Duke Energy recorded severance charges of approximately $1 million, $20 million and $134 million, respectively, primarily under its ongoing severance plan. Of the amount for the year ended December 31, 2007, approximately $12 million related to a voluntary termination program whereby eligible employees were provided a window during which to accept termination benefits. A total of 117 employees accepted the termination benefits during the voluntary window period, which closed in June 2007. Future severance costs under Duke Energy’s ongoing severance plan, if any, are not currently estimable. The liabilities recorded during the year ended December 31, 2006 related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 3), of which approximately $89 million was charged to expense

147

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

within income from continuing operations and approximately $45 million was recorded as a component of goodwill. Additionally, in connection with Duke Energy’s spin-off of Spectra Energy, Duke Energy recognized approximately $12 million of severance costs under its ongoing severance plan, which is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

Severance Reserve	Balance at January 1, 2008		Provision(b)		Non-cash Adjustments			Cash Reductions			Balance at December 31, 2008
	(in millions)
Other	$	24	$	1	$	—		$	(16	)	$	9
	Balance at January 1, 2007		Provision(b)		Non-cash Adjustments			Cash Reductions			Balance at December 31, 2007
Spectra Energy(a)	$	2	$	—	$	(2	)	$	—		$	—
Other		60		20		(4	)		(52	)		24
Total	$	62	$	20	$	(6	)	$	(52	)	$	24
	Balance at January 1, 2006		Provision(b)		Non-cash Adjustments			Cash Reductions			Balance at December 31, 2006
Spectra Energy(c)	$	3	$	—	$	—		$	(1	)	$	2
Other(c)		28		146		(11	)		(103	)		60
Total	$	31	$	146	$	(11	)	$	(104	)	$	62

(a) Liability was transferred as part of the spin-off of the natural gas businesses on January 2, 2007.

(b) Severance provisions are expected to be paid within one year from the date that the provision was recorded.

(c) Severance expense included in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations was approximately $3 million for 2006.

Post-Retirement Benefits. In July 2007, Duke Energy offered a voluntary early retirement incentive plan to approximately 1,100 eligible employees. The special termination benefit that was offered was a healthcare reimbursement account that could be used by participants for reimbursement of qualifying medical expenses. There were no severance benefits offered in connection with this plan. The window for acceptance of these voluntary termination benefits closed on August 15, 2007. During the three months ended September 30, 2007, approximately 170 employees accepted the offer and, pursuant to SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Duke Energy recorded a charge of approximately $8 million pre-tax related to this voluntary plan.

14. Discontinued Operations and Assets Held for Sale

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, to Duke Energy shareholders. The results of operations of these businesses are presented in the accompanying Consolidated Statements of Operations as discontinued operations for all periods prior to the spin-off. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. 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 includes approximately $8.6 billion of debt) and $5.6 billion of common stockholders’ equity (which includes approximately $1.0 billion of accumulated other comprehensive income) were distributed from Duke Energy as of the date of the spin-off.

Income (Loss) From Discontinued Operations, net of tax, for the year ended December 31, 2006 includes pre-tax interest expense of approximately $600 million associated with the debt distributed in the spin-off of Spectra Energy, as well as losses of approximately $19 million, which were previously classified in Other, resulting from mark-to-market movements in discontinued hedges at DCP Midstream.

148

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Additionally, Income (Loss) From Discontinued Operations, net of tax, for the years ended December 31, 2007 and 2006 includes pre-tax amounts of approximately $18 million and $60 million, respectively, related to costs to achieve the Spectra Energy spin-off, primarily fees to outside service providers. In the table below, these amounts are included in Other for the year ended December 31, 2007 and in Spectra Energy for the year ended December 31, 2006.

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

Additionally, effective with the spin-off, Duke Energy and Spectra Energy entered into various reinsurance and other related agreements that allocated certain assets to Spectra Energy and DCP Midstream created under insurance coverage provided prior to the spin-off by Duke Energy’s captive insurance subsidiary and third party reinsurance companies. Under these agreements, Spectra Energy’s captive insurance subsidiary reinsured 100% of Duke Energy’s retained risk under the insurance coverage provided prior to the spin-off. Consistent with the terms of the reinsurance agreement entered into while all parties were under the common control of Duke Energy, Duke Energy paid approximately $95 million in cash to Spectra Energy’s captive insurance company, which was placed in a grantor trust to secure Spectra Energy’s obligation to Duke Energy under the Spectra Energy reinsurance agreements. This transfer is reflected in Cash distributed to Spectra Energy within financing activities on the Consolidated Statements of Cash Flows. As of December 31, 2008, Duke Energy had a total liability to Spectra Energy and DCP Midstream related to these agreements of approximately $85 million, which is reflected in both Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. This liability is offset by a corresponding receivable, of which approximately $20 million was due from Spectra Energy’s captive insurance subsidiary under the Spectra Energy reinsurance agreement and approximately $65 million was due from third party reinsurance companies. These amounts are reflected in both Other Current Assets and Other 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, 2008 and 2007, Duke Energy had an approximate $49 million and $44 million receivable, respectively, from Spectra Energy related to certain income tax items.

Also refer to Notes 2, 7, 11, 12, 13, 19, 21 and 22 for additional information related to the spin-off transaction.

The following table summarizes the results classified as Income (Loss) from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

149

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Discontinued Operations (in millions)

	Operating Income (Loss)											Net Gain (Loss) on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax			Income (Loss) from Discontinued Operations, Net of Tax
Year Ended December 31, 2008
Commercial Power	$	4	$	—		$	(8	)	$	8		$	23		$	8		$	15		$	23
International Energy		—		(8	)		(3	)		(5	)		—			—			—			(5	)
Other		1		(2	)		—			(2	)		—			—			—			(2	)
Total consolidated	$	5	$	(10	)	$	(11	)	$	1		$	23		$	8		$	15		$	16
Year Ended December 31, 2007
Commercial Power	$	414	$	(94	)	$	(118	)	$	24		$	(1	)	$	8		$	(9	)	$	15
International Energy		—		8			3			5			—			—			—			5
Other		—		(30	)		16			(46	)		7			3			4			(42	)
Total consolidated	$	414	$	(116	)	$	(99	)	$	(17	)	$	6		$	11		$	(5	)	$	(22	)
Year Ended December 31, 2006
Spectra Energy	$	4,514	$	1,383		$	430		$	953		$	—		$	—		$	—		$	953
Commercial Power		106		(33	)		(36	)		3			33			50			(17	)		(14	)
International Energy		18		(29	)		(3	)		(26	)		(10	)		(3	)		(7	)		(33	)
Other		748		(55	)		(13	)		(42	)		(127	)		(46	)		(81	)		(123	)
Total consolidated	$	5,386	$	1,266		$	378		$	888		$	(104	)	$	1		$	(105	)	$	783

Amounts for Spectra Energy and Other for the year ended December 31, 2006 in the table above are net of insignificant intercompany eliminations.

The following table presents the carrying values of the major classes of Assets Held for Sale and related Liabilities Associated with Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2007, which primarily relate to Duke Energy Indiana’s Wabash River Power Station, the sale of which was completed in January 2008 (see Note 3). There were no Assets Held for Sale and related Liabilities Associated with Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2008.

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale

	December 31, 2007
	(in millions)
Current assets	$	2
Property, plant and equipment, net		115
Total assets held for sale	$	117
Current liabilities	$	114
Deferred credits and other liabilities		3
Total liabilities associated with assets held for sale	$	117

150

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

As discussed above, the results of operations for all of the businesses transferred to Spectra Energy are presented as discontinued operations for all periods presented. Significant transactions occurring during the year ended December 31, 2006 related to the operations transferred to Spectra Energy and significant transactions occurring during the years ended December 31, 2008, 2007 and 2006 within the other operations of Duke Energy that resulted in discontinued operations presentation are discussed below. Transactions under Spectra Energy primarily include transactions at Duke Energy’s former Natural Gas Transmission and Field Services business segments.

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, which was subject to FERC approval, closed in April 2008. This transaction 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 (see Note 18), Duke Energy ceased all synthetic fuel (synfuel) operations as of December 31, 2007. Accordingly, the results of operations for synfuel have been reclassified to discontinued operations for all periods presented. 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-percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International. As discussed below, 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 and the results of operations for Bolivia have been reclassified to discontinued operations for all periods presented.

Year Ended December 31, 2006

Spectra Energy

As a result of the transfer of 19.7% interest in DCP Midstream to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DCP Midstream, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. After discontinuance of hedge accounting, these contracts were marked-to-market in the Consolidated Statements of Operations. As a result, approximately $19 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy for the year ended December 31, 2006. Cash settlements on these contracts of approximately $163 million are classified as a component of Net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2006.

The sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million. In addition, the sale of shares of stock, received as consideration for the settlement of a customer’s transportation contract, resulted in proceeds of approximately $29 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain equivalent to the proceeds received from the sale of stock.

As a result of a settlement of a property insurance claim, proceeds of approximately $30 million were received and a pre-tax gain of $10 million was recognized.

151

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Commercial Power

In June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as certain Duke Energy Ohio trading contracts, to Fortis, a Benelux-based financial services group. In October 2006, the sale transaction was completed. Under the purchase and sale agreement, Fortis purchased CMT at a base price of approximately $210 million. In addition, Fortis paid approximately $200 million for the portfolio of contracts and an amount equal to the estimated net working capital associated with these companies at the time of close. In October 2006, Duke Energy received total pre-tax cash proceeds of approximately $700 million and recorded an approximate $25 million pre-tax gain on the sale. Income tax expense recorded as a result of this transaction relates to the approximate $135 million of goodwill that was not deductible for tax purposes, thus creating a taxable gain that was greater than the gain for book purposes. Results of operations for CMT, as well as certain Duke Energy Ohio trading contracts, have been reflected in Income (Loss) from Discontinued Operations, net of tax, from the date of the Cinergy merger through the date of sale.

In October 2006, in connection with this transaction, Duke Energy entered into a series of TRS with Fortis, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Fortis. The TRS will be cancelled for each underlying contract as each is transferred to Fortis. All economic and credit risk associated with the contracts has been transferred to Fortis as of the date of the sale through the TRS.

As discussed above, due to the expiration of certain tax credits, Duke Energy ceased all synfuel operations as of December 31, 2007. Accordingly, the results of operations for synfuel have been reclassified to discontinued operations for all periods presented. For the year ended December 31, 2006, synfuel operations had after-tax earnings of approximately $3 million, which includes tax benefits of approximately $20 million.

International Energy

International Energy had a receivable from Norsk Hydro ASA (Norsk) that related to purchase price adjustments on the 2003 sale of International Energy’s European business. During the first quarter of 2006, International Energy recorded an allowance of approximately $19 million pre-tax ($12 million after-tax) against this receivable. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million pre-tax (approximately $5 million after-tax) write-up of the receivable through a reduction in the valuation allowance. This receivable was collected in July 2006.

As discussed above, in December 2006, International Energy engaged in discussions with a potential buyer of its assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, as discussed above, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International for approximately $20 million. Based upon the agreed selling price of the assets, in December 2006, International Energy recorded a pre-tax impairment charge of approximately $28 million. The impairment charge reduced the carrying value of the assets to the estimated selling price pursuant to the aforementioned agreement. International Energy recorded an approximate $25 million income tax benefit associated with the impairment charge, which was recorded within continuing operations as prescribed by SFAS No. 109, “Accounting for Income Taxes.”

Other

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Approximately $700 million was incurred from the announcement date through December 31, 2006, of which approximately $230 million was incurred during the year ended December 31, 2006. As of December 31, 2006 the former DENA exit activities had been substantially complete and no additional material charges were incurred.

In January 2006, Duke Energy signed an agreement to sell to LS Power former DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 megawatts of power generation located in the Western and Northeastern United States. In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments. Additional proceeds of up to approximately $40 million were subject to LS Power obtaining certain state regulatory approvals. On July 20, 2006 the Public Utilities Commission of the State of California approved a toll arrangement related

152

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

to the Moss Landing facility previously sold to LS Power. In August 2006, LS Power made an additional payment to Duke Energy of approximately $40 million, which was recorded as an additional gain on the sale of assets.

During the first quarter of 2006, Duke Energy acquired the remaining 33 1/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC for approximately $71 million. The assets and liabilities of Bridgeport were included as part of former DENA’s power generation assets, which were sold to a subsidiary of LS Power, as discussed above.

15. Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2008			2007
	(Years)	(in millions)
Land	—	$	687		$	673
Plant—Regulated
Electric generation, distribution and transmission(a)	8 –125		34,005			31,605
Natural gas transmission and distribution	12 –60		1,566			1,436
Other buildings and improvements(a)	25 –100		564			569
Plant—Unregulated
Electric generation, distribution and transmission(a)	8 –100		3,989			3,923
Natural gas transmission and distribution	—		—			4
Gathering and processing facilities	—		—			3
Other buildings and improvements(a)	30 –90		1,698			1,777
Nuclear fuel	—		966			864
Equipment(a)	3 – 33		658			633
Vehicles	5 – 26		81			64
Construction in process	—		4,379			2,712
Other(a)	5 – 33		1,711			1,793
Total property, plant and equipment			50,304			46,056
Total accumulated depreciation—regulated(b), (c)			(14,681	)		(13,590	)
Total accumulated depreciation—unregulated(c)			(1,587	)		(1,356	)
Total net property, plant and equipment		$	34,036		$	31,110

(a) Includes capitalized leases of approximately $208 million for 2008 and $183 million for 2007.

(b) Includes accumulated amortization of nuclear fuel: $484 million for 2008 and $485 million for 2007.

(c) Includes accumulated amortization of capitalized leases: $37 million for 2008 and $38 million for 2007.

Capitalized interest, which includes the interest expense component of AFUDC, amounted to $93 million for 2008, $71 million for 2007, and $56 million for 2006.

153

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

16. Debt and Credit Facilities

Summary of Debt and Related Terms

	Weighted- Average Rate		Year Due	December 31,
				2008			2007
				(in millions)
Unsecured debt	6.8	%	2009 – 2037	$	6,360		$	6,801
Secured debt	4.7	%	2009 – 2017		737			589
First and refunding mortgage bonds	6.0	%	2009 – 2038		4,165			1,507
Capital leases	6.0	%	2009 – 2025		137			108
Other debt(a)	2.0	%	2009 – 2041		2,084			1,744
Notes payable and commercial paper(b)(c)	4.0	%			993			1,042
Fair value hedge carrying value adjustment					25			28
Unamortized debt discount and premium, net					(62	)		(53	)
Total debt(d)					14,439			11,766
Current maturities of long-term debt					(646	)		(1,526	)
Short-term notes payable and commercial paper(e)					(543	)		(742	)
Total long-term debt				$	13,250		$	9,498

(a) Includes $1,569 million of Duke Energy pollution control bonds as of both December 31, 2008 and 2007. As of December 31, 2008 and 2007, $404 million and $361 million, respectively, was secured by first and refunding mortgage bonds and $494 million and $344 million, respectively was secured by a letter of credit.

(b) Includes $450 million and $300 million as of December 31, 2008 and 2007, respectively, 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, for the commercial paper balance of approximately $714 million, was 10 days as of December 31, 2008 and 17 days as of December 31, 2007.

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

(d) As of December 31, 2008 and 2007, $414 million and $571 million, respectively, of debt was denominated in Brazilian Reals.

(e) Weighted-average rates on outstanding short-term notes payable and commercial paper was 3.4% and 5.3% as of December 31, 2008 and December 31, 2007, respectively.

Unsecured and Other 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 is reset on a weekly basis.

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

In October 2008, International Energy issued approximately $153 million of debt in Brazil, of which approximately $112 million matures in September 2013 and carries a variable interest rate equal to the Brazil interbank rate plus 2.15%, and approximately $41 million matures in September 2015 and carries 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 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 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 0.50% reset on a daily basis with $77 million maturing December 2039 and $50 million maturing October 2040.

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.

154

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 outstanding $249 million 6.6% Insured Quarterly Senior Notes due 2022 on April 30, 2007, and approximately $110 million of convertible senior notes discussed below. The remainder was used for general corporate purposes.

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 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.

Auction Rate Debt. As of December 31, 2008, Duke Energy had auction rate pollution control bonds outstanding of approximately $730 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 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. Duke Energy has plans to refund and refinance its remaining 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 effect 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, as a result of the market price of Duke Energy common stock achieving a specified threshold, approximately 27 million shares of common stock were issued related to conversions by holders of the convertible senior notes, which resulted in the retirement of approximately $632 million of convertible senior notes. At December 31, 2006, unsecured debt included approximately $110 million of these convertible senior notes, which were potentially convertible into approximately 4.7 million shares of common stock and included as outstanding shares in the diluted EPS calculation (see Note 20). On May 15, 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 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, which resulted in the redemption of the remainder of the outstanding convertible senior notes.

In connection with the spin-off of Spectra Energy on January 2, 2007 (see Note 1), Duke Energy distributed approximately 2 million shares of Spectra Energy common stock to the holders of the convertible senior notes pursuant to the antidilution provisions of the indenture agreement, resulting in a pre-tax charge of approximately $21 million during the three months ended March 31, 2007, which is recorded in Other Income and Expenses, net in the Consolidated Statements of Operations.

Secured Debt and First and Refunding Mortgage Bonds. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $400 million carries a fixed interest rate of 5.25% and matures January 15, 2018 and $500 million carries a fixed interest rate of 6.00% and matures 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.

155

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

In April 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $300 million carries a fixed interest rate of 5.10% and matures April 15, 2018 and $600 million carries a fixed interest rate of 6.05% and matures 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 August 2008, Duke Energy Indiana issued $500 million principal amount of first mortgage bonds, which carry a fixed interest rate of 6.35% and matures 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 November 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $500 million carries a fixed interest rate of 7.00% and matures November 15, 2018 and $400 million carries a fixed interest rate of 5.75% and matures 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.

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 Citicorp North America, Inc., which terminates in September 2010. 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, 2008 and 2007, the interest rate associated with the credit facility, which is based on commercial paper rates, was 4.7% and 5.3%, respectively and $300 million was outstanding under the credit facility as of both December 31, 2008 and 2007. The securitization transaction was not structured to meet the criteria for sale treatment under SFAS No. 140 and accordingly is reflected as a secured borrowing in the Consolidated Balance Sheets. As of December 31, 2008 and 2007, the $300 million outstanding balance of the credit facility was secured by approximately $518 million and $532 million, respectively, of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy.

Other Assets Pledged as Collateral. As of December 31, 2008, 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.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $3.2 billion and $2.4 billion of floating-rate debt as of December 31, 2008 and 2007, respectively, which excludes approximately $300 million and $571 million of Brazilian debt at December 31, 2008 and 2007, 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 a London Interbank Offered Rate for debt denominated in U.S. dollars. As of December 31, 2008 and 2007, the average interest rate associated with floating-rate debt was approximately 3.2% and 4.9%, respectively.

156

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Maturities, Call Options and Acceleration Clauses.

Annual Maturities as of December 31, 2008

	(in millions)
2009	$	646
2010		1,004
2011		294
2012		2,313
2013		1,193
Thereafter		8,446
Total long-term debt, including current maturities(a)	$	13,896

(a) Excludes short-term notes payable and commercial paper of $543 million.

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, 2008, Duke Energy had approximately $8 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $19 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 1, 2009, Duke Energy Carolinas’ senior unsecured credit rating was A- at S&P and A3 at Moody’s.

Available Credit Facilities.

In June 2007, Duke Energy closed the syndication of an amended and restated credit facility, which replaced existing credit facilities, with a 5-year, $2.65 billion master credit facility. Duke Energy, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky all have borrowing capacity under the terms of the master credit facility.

In March 2008, Duke Energy entered into an amendment to its $2.65 billion master credit facility whereby the borrowing capacity was increased by $550 million to $3.2 billion. In October 2008, Duke Energy terminated the participation of one of the financial institutions supplying approximately $63 million of credit commitment under its master credit facility. The total credit facility capacity under the master credit facility subsequent to this termination is approximately $3.14 billion. Duke Energy has the unilateral ability under the master credit facility to increase or decrease the borrowing sublimits of each borrower, subject to maximum cap limitations, at any time. See table below for the borrowing sublimits at December 31, 2008 for each of the Duke Energy entities with borrowing capacity under this credit facility. 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 pollution control bonds.

Master Credit Facility Summary as of December 31, 2008 (in millions)^(d)

	Credit Facility Capacity		Commercial Paper		Draw Down on Credit Facility		Letters of Credit		Pollution Control Bonds		Total Amount Utilized		Available Credit Facility Capacity
Duke Energy Corporation
$3,137 multi-year syndicated(a), (b), (c)	$	3,137	$	715	$	750	$	155	$	340	$	1,960	$	1,177

(a) Credit facility expires June 2012. 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.

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

(c) Contains sublimits at December 31, 2008 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.

(d) 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 pollution control bonds.

157

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

In September 2008, 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) borrowed a total of approximately $1 billion under Duke Energy’s master credit facility. In the fourth quarter of 2008, Duke Energy Carolinas used the proceeds from a debt issuance to repay in full the approximately $260 million borrowed under the master credit facility. At December 31, 2008, outstanding borrowings of approximately $750 million under Duke Energy’s master credit facility as follows:

	Amounts Borrowed Under Master Credit Facility
	(in millions)
Duke Energy Corporation	$	274
Duke Energy Ohio		279
Duke Energy Indiana		123
Duke Energy Kentucky		74
Total	$	750

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 24 basis points. The loan for Duke Energy has a stated maturity of June 2012, while the loans for all of the other borrowers have stated maturities of September 2009; however, the borrowers have the ability under the master credit facility to renew the loans due in September 2009 up through the date the master credit facility matures in June 2012. Except for Duke Energy Ohio, all of the borrowers 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, borrowings of $471 million are reflected as Long-Term Debt on the Consolidated Balance Sheets at December 31, 2008. As Duke Energy Ohio does not have the intent to refinance its borrowings on a long-term basis, amounts outstanding at December 31, 2008 of $279 million are reflected as current liabilities in Notes Payable and Commercial Paper on the Consolidated Balance Sheets.

At December 31, 2008 and December 31, 2007, approximately $779 million and $629 million, respectively, of pollution control 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 $440 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 credit facilities separate from the master credit facility. Additionally, at December 31, 2008 and December 31, 2007 approximately $450 million and $300 million, respectively, of commercial paper issuances were classified as Long-Term Debt on the Consolidated Balance Sheets. These pollution control 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, 2008, 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.

158

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other Loans. During 2008 and 2007, 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 $384 million as of December 31, 2008 and $367 million as of December 31, 2007. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other Assets on the Consolidated Balance Sheets.

17. Preferred and Preference Stock at Duke Energy

As of December 31, 2008 and 2007, there were 44 million authorized shares of preferred stock, par value $0.001 per share, with no such preferred shares outstanding.

Preferred and Preference Stock of Duke Energy’s Subsidiaries. In connection with the Westcoast Energy, Inc. (Westcoast) acquisition in 2002, Duke Energy assumed approximately $411 million of authorized and issued redeemable preferred and preference shares at Westcoast and Union Gas. The approximate $225 million remaining obligation associated with these preferred and preference shares was transferred to Spectra Energy in connection with the spin-off of the natural gas businesses on January 2, 2007.

Additionally, in May 2006, Duke Energy redeemed, at par plus accrued and unpaid dividends, approximately $11 million of authorized and issued Duke Energy Indiana preferred stock, which had been acquired by Duke Energy in connection with the Cinergy merger in April 2006.

18. 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 (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Energy’s operations; (2) workers’ compensation liability coverage to statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Duke Energy’s by-laws and (5) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and extra expense. All coverage is subject to certain deductibles or retentions, terms and conditions common for companies with similar types of operations.

In 2006, Bison was a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provided property and business interruption reinsurance coverage respectively for Duke Energy’s non-nuclear facilities. Duke Energy accounts for these memberships under the cost method, as it did not have the ability to exert significant influence over these investments. Bison terminated its membership in OIL effective December 31, 2006 and paid a withdrawal premium during 2007 as a result of this decision. 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 continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Nuclear Insurance

Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses

159

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 projection liability. The Price-Anderson Act provides for an inflation adjustment at least every five years. Effective October 2008, this adjustment increased the maximum total financial projection liability from approximately $10.8 billion to approximately $12.5 billion.

Primary Liability Insurance. Duke Energy has purchased the maximum reasonably available private primary liability insurance as required by law, which is $300 million.

Excess Liability Program. As discussed above, effective October 2008, this program provides approximately $12.5 billion of coverage through the Price-Anderson Act’s mandatory industry-wide excess secondary financial protection program of risk pooling. The $12.5 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.

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 ten times its annual premiums. The current potential maximum assessments are: Primary Property Insurance—$38 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 an accident, and second, to decontaminate before any proceeds can be used for decommissioning, plant repair or restoration.

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

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

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.

160

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. 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.

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 January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) et. al. (2d Cir. 2007) remanding most aspects of the EPA’s rule back to the agency. The court effectively disallowed those portions of the rule most favorable to industry, and the decision creates a great deal of uncertainty regarding future requirements and their timing. On April 14, 2008, the U.S. Supreme Court issued an order granting review of the case and briefs were filed on July 14, 2008. Oral argument occurred on December 2, 2008. A decision is expected in 2009. If the Supreme Court upholds the lower court decision, it is expected that costs will increase as a result of the court’s decision, however, Duke Energy is unable to estimate at this time its costs to comply.

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 begins in 2009 for NO_x and 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 court did not impose a deadline or schedule on the EPA. 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 (see Note 4). Additionally, Duke Energy plans to spend approximately $120 million between 2009 and 2013 (approximately $85 million in Ohio and $35 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 (see below) in Indiana. Duke Energy Ohio received partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its RSP.

See Note 13 for a discussion of the impacts of the D.C. Circuit Court’s July 11, 2008 decision to vacate the CAIR on the carrying value of emission allowances.

Clean Air Mercury Rule (CAMR). The EPA finalized its CAMR in May 2005. The CAMR was to have limited total annual mercury emissions from coal-fired power plants across the U.S. through a two-phased cap-and-trade program beginning in 2010. On February 8, 2008, the D.C. Circuit issued its opinion in New Jersey v. EPA, No. 05-1097 vacating the CAMR. Requests for rehearing were denied. The U.S. EPA and the Utility Air Regulatory Group have requested that the U.S. Supreme Court review the D.C. Circuit’s decision. The D.C. Circuit’s decision creates uncertainty regarding future mercury emission reduction requirements and their timing, but makes it fairly certain that there will be a delay in the implementation of federal mercury requirements for existing coal-fired power plants. On January 29, 2009, the EPA requested the U.S. Department of Justice withdraw its Petition for Writ of Certiorari filed on October 17, 2008. On Febru-

161

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

ary 23, 2009, the Supreme Court denied the Utility Air Regulatory Group’s petition. The EPA will not develop emission standards for utility units under section 112 of the Clean Air Act, thus abiding by the D.C. Circuit’s decision. At this point, Duke Energy is unable to estimate the costs to comply with any future mercury regulations that might result from the D.C. Circuit’s decision.

Coal Combustion Product (CCP) Management. Duke Energy currently estimates that it will spend approximately $365 million over the period 2009-2013 to install synthetic caps and liners at existing and new CCP landfills and to convert CCP handling systems from wet to dry systems.

Extended Environmental Activities and Accruals. Included in Other within Deferred Credits and Other Liabilities and Other Current Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $55 million and $52 million as of December 31, 2008 and December 31, 2007, 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.

Litigation

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

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

In November 1999, the U.S. brought a lawsuit in the U.S. Federal District Court for the Southern District of Indiana against Cinergy, Duke Energy Ohio, and Duke Energy Indiana alleging various violations of the CAA for various projects at six Duke Energy owned and co-owned generating stations in the Midwest. Three northeast states and two environmental groups have intervened in the case. A jury trial commenced on May 5, 2008 and jury verdict was returned on May 22, 2008. The jury found in favor of Cinergy, Duke Energy Ohio and Duke Energy Indiana on all but three units at Wabash River. Also, the judge previously granted summary judgment against Duke Energy with respect to plaintiffs’ claim 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 (SIP) provisions governing particulate matter at Duke Energy Ohio’s W.C. Beckjord Station.

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. In a subsequent order rendered on January 12, 2009, the Court also ordered Duke Energy to pay plaintiffs’ costs incurred in preparing and filing the motion for a new trial. A new liability trial is scheduled to begin on May 11, 2009. The remedy trial for violations already established at the Wabash River Station and W.C. Beckjord Station began on February 2, 2009. Based on previous rulings by the judge in this case, the Wabash River units are not subject to civil penalties; and therefore, the remedy trial in February addressed only the appropriate injunctive relief. Plaintiffs are seeking numerous types of injunctive relief including installation of monitoring equipment, ceasing operations and remediation of alleged excess emissions from the Wabash River units.

162

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Cinergy and Duke Energy Ohio have been informed by Dayton Power and Light (DP&L) that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of CAA requirements at a station operated by DP&L and jointly-owned by DP&L, Columbus Southern Power Company (CSP), and Duke Energy Ohio. The NOV indicated the EPA may issue an order requiring compliance with the requirements of the Ohio SIP, or bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against Duke Energy Ohio, DP&L and CSP for alleged violations of the CAA at this same generating station. The parties reached an agreement to settle this matter in the form of a consent decree which was submitted for comment to the EPA and ultimately approved and entered by the court on October 23, 2008. The consent decree will not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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 claiming NSR violations at the Edwardsport generating station in Knox County, Indiana. Sierra Club claims that Duke Energy violated the CAA when it undertook various unnamed maintenance projects at Edwardsport without obtaining permits and installing the best available emission controls. Sierra Club further states that it intends to file suit for additional alleged violations of the CAA and the Indiana State Implementation Plan. 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 and the case will proceed to discovery.

It is not possible to estimate the damages, if any, that Duke Energy might incur in connection with these matters. 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.

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 June 2008, Duke Energy Carolinas announced that it would voluntarily perform a MACT assessment of air emission controls planned for Cliffside Unit 6. In July 2008, Duke Energy Carolinas submitted the results of the assessment to the DENR. On August 8, 2008 the plaintiffs filed a motion for summary judgment and on August 11, 2008 Duke Energy Carolinas filed a motion to dismiss. Both motions were argued on October 16, 2008. 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 Clean Air Act and submitting a MACT determination application. DAQ held public hearings on January 15, 2009 in Forest City, North Carolina and January 22, 2009 in Statesville, North Carolina to allow public comment on DAQ’s proposal to find Cliffside Unit 6 is a minor source of hazardous air pollutants. The meeting notices were accompanied with a draft permit that includes the minor source limits and monitoring requirements that make the limits enforceable. A final permit with minor source limits is expected in the first quarter of 2009. 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. 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’ need for power through other resources. In addition, Duke Energy Carolinas will seek appropriate regulatory treatment for the investment in the plant.

Carbon Dioxide (CO₂) Litigation. In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin and the City of New York brought a lawsuit in the U.S. District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. A similar lawsuit was filed in the U.S. District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO₂ from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while

163

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. 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. Oral argument on the motion is scheduled for May 2009. 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. The plaintiffs have filed their appeal to the Fifth Circuit Court of Appeals and oral argument was heard on August 6, 2008. Due to the late recusal of one of the judges on the Fifth Circuit panel, the court held a new oral argument on November 3, 2008. 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.

San Diego Price Indexing Cases. Duke Energy and several of its affiliates, as well as other energy companies, have been parties to 13 lawsuits which have been coordinated as the “Price Indexing Cases” in San Diego, California. The plaintiffs allege that the defendants conspired to manipulate the price of natural gas in violation of state and/or federal antitrust laws, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information, resulted in artificially high energy prices. In December 2007, Duke Energy reached a settlement in principle to settle the 13 cases. A settlement agreement was executed in February 2008 and amended and restated in July 2008. The settlement did not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Other Price Reporting Cases. A total of 12 lawsuits have been filed against Duke Energy affiliates and other energy companies. Ten of these cases have been consolidated into a single proceeding. 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 four of the cases. One case was filed in Tennessee state court, which dismissed the case on filed rate and preemption grounds. That case was appealed to the Tennessee Court of Appeals, where oral argument was heard in November 2007. The Tennessee Court of Appeals reversed this lower court ruling in October 2008 and on December 23, 2008, Defendants filed an application for permission to appeal together with a brief to the Tennessee Supreme Court. 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. 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. In October 2008, a settlement in principle was reached with the class plaintiffs in five of the cases. The settlement is subject to execution of definitive settlement documents and approval by the court. The settlement, as currently structured, will 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.

164

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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.

Trading Related Investigations. Beginning in February 2004, Duke Energy has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Energy has cooperated with the government in this investigation and is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to this matter at this time.

ExxonMobil Disputes. In March 2007, Duke Energy and Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (together with MNGI and ExxonMobil) executed a settlement agreement for global settlement of both parties’ claims raised in arbitration proceedings relating to DETM and Duke Energy Marketing Limited Partnership (DEMLP). In the arbitration brought in Canada by DEMLP, the arbitrators held that ExxonMobil was not required to take assignment of certain gas supply and transportation agreements with other parties, under which DEMLP continues to remain obligated. These contracts are currently estimated to result in losses of up to approximately $10 million through 2009; based on the currently estimated in-service dates for certain gas infrastructure facilities. As Duke Energy has an ownership interest of approximately 60% in DEMLP, only 60% of any losses would impact pre-tax earnings for Duke Energy. However, these losses are subject to change in the future in the event of changes in market conditions and underlying assumptions.

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. The plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. Duke Energy 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. No trial date has been set. At mediation, 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 in federal court in the Southern District of Ohio. Plaintiffs allege that Duke Energy (then Cinergy and 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 denies the allegations made in the lawsuit. Following Duke Energy’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. 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.

Duke Energy International Paranapanema Lawsuit. In June 2007, the Brazilian electricity regulatory agency (ANEEL) issued resolution 497/2007 (the Resolution) which purports to impose additional assessments (retroactive to July 1, 2004) on generation

165

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 proportional usage by each generator. Pursuant to the Resolution, Duke Energy International Geracao Paranapanema S.A. (Paranapanema) was assessed approximately $32 million, inclusive of interest. Following various failed administrative challenges, on July 16, 2008, Paranapanema filed a lawsuit in the Brazilian federal court challenging the merits of the assessment. On July 29, 2008 the court granted Paranapanema’s request to enjoin its payment obligation while the legal challenge on the merits remains pending before the Brazilian court. That injunction was appealed and reversed on January 28, 2009. On February 3, 2009, Paranapanema filed a motion for reconsideration of the appellate court’s ruling against the injunction. Paranapanema also filed a brief on the merits. A final decision on both the injunction ruling and the merits is pending before the appellate court.

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 $1,031 million and $1,082 million as of December 31, 2008 and 2007, 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 $1,099 million in excess of the self insured retention. Insurance recoveries of approximately $1,032 million and $1,040 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, 2008 and 2007, 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.

EI UK Holdings, Inc. In March, 2004, EI UK Holdings, Inc., a subsidiary of FirstEnergy Corp, filed a complaint in Ohio State Court. The complaint alleged that Cinergy, and an affiliate, had breached certain agreements and sought indemnification from Cinergy. The case went to trial and on February 14, 2008, the jury returned a verdict in favor of EI UK Holdings and against Cinergy and its affiliate and awarded EI UK Holdings $15 million, plus interest. Post judgment motions were denied and Cinergy paid the verdict and prejudgment interest in June 2008.

166

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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, 2008 and 2007, Duke Energy has recorded reserves, including reserves related to the aforementioned asbestos-related injuries and damages claims, of approximately $1.1 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5. As of December 31, 2008 and 2007, Duke Energy recognized approximately $1,032 million and $1,040 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

Synfuel. Commercial Power produced synfuel from facilities that qualified for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code if certain requirements were satisfied. Section 29/45K provided for a phase-out of the credit if the average price of crude oil during a calendar year exceeded a specified threshold. The phase-out was based on a prescribed calculation and definition of crude oil prices. The exposure to synfuel tax credit phase-out was monitored as Duke Energy was able to reduce or cease synfuel production based on the expectation of any potential tax credit phase-out. The objective of these activities was to reduce potential losses incurred if the reference price in a year exceeded a level triggering a phase-out of synfuel tax credits.

These credits reduced Duke Energy’s income tax liability and, therefore, Duke Energy’s tax expense recorded in Income (Loss) from Discontinued Operations, net of tax. Commercial Power’s sale of synfuel had generated $339 million in tax credits through December 31, 2005. After reducing for the possibility of phase-out, the amount of additional credits generated during the years ended December 31, 2007 and 2006 were approximately $84 million and $20 million, respectively. Duke Energy ceased production of synfuel upon the expiration of the tax credits at the end of 2007.

The Internal Revenue Service (IRS) has completed the audit of Cinergy for the 2002, 2003, and 2004 tax years, including the synfuel facility owned during that period, which represents $222 million of tax credits generated during the aforementioned audit period. The IRS has not proposed any adjustment that would disallow the credits claimed during that period. Subsequent periods are still subject to audit. Duke Energy believes that it operated in conformity with all the necessary requirements to be allowed such credits under Section 29/45K.

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. 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.

Other Matters. Duke Energy was party to an agreement with a third party service provider related to certain future purchases. The agreement contained certain damage payment provisions if qualifying purchases were not initiated by September 2008. In the fourth quarter of 2006, Duke Energy initiated early settlement discussions regarding this agreement and recorded a reserve of approximately $65 million. During the third quarter of 2007, Duke Energy paid the third party service provider approximately $20 million, which directly reduced Duke Energy’s future exposure under the agreement, and further reduced the reserve by $20 million based upon qualifying purchase commitments that, once satisfied, will fulfill Duke Energy’s obligations under the agreement. As a result of additional adjustments to this reserve during the fourth quarter of 2007, there was no remaining reserve associated with this agreement at December 31, 2007.

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 19.

167

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 $164 million in 2008, $138 million in 2007 and $110 million in 2006 which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Income (Loss) From Discontinued Operations, net of tax, in 2006 included rental expense for operating leases of approximately $36 million. 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, 2008:

	Operating Leases		Capital Leases
	(in millions)
2009	$	101	$	20
2010		96		21
2011		68		19
2012		57		18
2013		48		17
Thereafter		252		42
Total future minimum lease payments	$	622	$	137

19. Guarantees and Indemnifications

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

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 originally 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 originally issued by Spectra Energy Capital or its affiliates prior to the spin-off remained with Spectra Energy Capital subsequent to the spin-off, except for certain guarantees discussed below that are in the process of being assigned to Duke Energy. During this assignment period, Duke Energy has indemnified Spectra Energy Capital against any losses incurred under these guarantee obligations.

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 payment on the obligation 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, 2008 was approximately $510 million. Of this amount, approximately $200 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 $314 million of the guarantees expire between 2009 and 2039, with the remaining performance guarantees having no contractual expiration. In addition, as discussed above, Spectra Energy Capital is in the process of assigning to Duke Energy performance guarantees with maximum potential amounts of future payments of approximately $320 million. During the assignment period, Duke Energy has indemnified Spectra Energy Capital for any losses incurred as a result of these guarantees.

168

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Included in the amounts discussed above is approximately $63 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 2009 to 2019, with others having no specific term. The maximum potential amount of future payments under these guarantees as of December 31, 2008 was approximately $63 million.

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 to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly-owned entity to perform according to the terms of its underlying contract. As of December 31, 2008, Duke Energy has guaranteed approximately $100 million of outstanding surety bonds and letters of credit related to obligations of non-wholly-owned entities, substantially all of which relates to projects at Crescent. This amount represents the face value of the guarantees; however, Crescent has already completed a substantial portion of its obligations under these guarantees. As of December 31, 2008, it is reasonably possible that Duke Energy could have exposure of approximately $40 million under these guarantees should Crescent fail to perform under its obligations associated with these projects which would become more likely should Crescent declare bankruptcy in the near future. See Note 12 for further information.

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, 2008, the amounts of the fair value recorded for the guarantees and indemnifications mentioned above are approximately $19 million, which is recorded in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. Due to the continued downturn in the overall economic environment, Duke Energy performed an assessment of its guarantee obligations as of December 31, 2008 to determine whether any FAS 5 liabilities have been triggered as a result of potential increased non-performance risk by parties for which Duke Energy has issued guarantees. Based on the results of this analysis, as of December 31, 2008 management determined, with the exception of some insignificant amounts, that it is not probable that Duke Energy will have to perform under any guarantee obligations. However, management will continue to monitor the financial condition of the third parties or non-wholly owned entities for whom Duke Energy has issued guarantees on behalf of, including its obligations related to Crescent discussed above, to determine whether performance under these guarantees becomes probable in the future.

20. Earnings Per Share

Basic EPS is computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing earnings available for 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, stock-based performance unit awards, contingently convertible debt and phantom stock awards, were exercised, settled or converted into common stock.

169

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following tables illustrate Duke Energy’s basic and diluted EPS calculations and reconcile the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2008, 2007, and 2006.

(in millions, except per share data)	Income		Average Shares	EPS
2008
Income from continuing operations—basic	$	1,279	1,265	$	1.01
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock			3
Income from continuing operations—diluted	$	1,279	1,268	$	1.01
2007
Income from continuing operations—basic	$	1,522	1,260	$	1.21
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock			5
Contingently convertible bond		—	1
Income from continuing operations—diluted	$	1,522	1,266	$	1.20
2006
Income from continuing operations—basic	$	1,080	1,170	$	0.92
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock			4
Contingently convertible bond		4	14
Income from continuing operations—diluted	$	1,084	1,188	$	0.91

The increase in weighted-average shares outstanding for the year ended December 31, 2007 compared to the same period in 2006 was due primarily to the April 2006 issuance of approximately 313 million shares in conjunction with the merger with Cinergy (see Note 1), the conversion of debt into approximately 27 million shares of Duke Energy common stock during the year ended December 31, 2006 (see Note 16), and the repurchase and retirement of approximately 17.5 million shares of Duke Energy common stock during the year ended December 31, 2006.

Beginning in the fourth quarter of 2008, Duke Energy began issuing authorized but unissued shares of common stock to fulfill obligations under its Dividend Reinvestment Plan and other internal plans, including 401(k) plans. Duke Energy currently anticipates issuing up to an aggregate of approximately $600 million of common stock associated with these programs. Approximately $100 million of common stock was issued during the fourth quarter of 2008 associated with these plans.

As of December 31, 2008, 2007 and 2006, approximately 15 million, 13 million and 14 million, respectively, of options, unvested stock, performance awards and phantom stock 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.

As discussed further in Note 1, effective January 1, 2009, Duke Energy adopted the provisions of FSP EITF 03-6-1, which requires Duke Energy to compute basic EPS using the two-class method described in SFAS No.128 as Duke Energy has certain share-based payment awards that meet the definition of participating securities.

21. Stock-Based Compensation

Duke Energy accounts for stock-based compensation under the provisions of SFAS No. 123(R). SFAS No. 123(R) established accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, 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.

170

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Duke Energy’s 2006 Long-term Incentive Plan (the 2006 Plan), approved by shareholders in October 2006, reserved 60 million shares of common stock for awards to employees and outside directors. The 2006 Plan superseded Duke Energy’s 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 2009, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards which are exercised or vested. 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.

Payments for cash settled awards during the year ended December 31, 2008 were immaterial.

Impact of Spin-off on Equity Compensation Awards

As discussed in Note 1, on January 2, 2007, Spectra Energy was spun off by Duke Energy to its shareholders. In connection with this transaction, Duke Energy distributed substantially all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock.

Effective with the spin-off, all previously granted Duke Energy long-term incentive plan equity awards were split into Duke Energy and Spectra Energy equity-related awards, consistent with the spin-off conversion ratio. Each equity award (stock option, phantom share, performance share and restricted stock award) was split into two awards: a Duke Energy award (issued by Duke Energy in Duke Energy shares) and a Spectra Energy award (issued by Spectra Energy in Spectra Energy shares). The number of shares covered by the adjusted Duke Energy award equals the number of shares covered by the original award, and the number of shares covered by the Spectra Energy award equals the number of shares that would have been received in the spin-off by a non-employee shareholder (which reflected the one-half share of Spectra Energy common stock for every share of Duke Energy common stock distribution ratio for Spectra Energy shares).

Stock option exercise prices were adjusted using a formula approved by the Duke Energy Compensation Committee that was designed to preserve the exercise versus market price spread (whether “in the money” or “out of the money”) of each option. All equity award adjustments were designed to equalize the fair value of each award before and after the spin-off. Accordingly, no material incremental compensation expense was recognized as a result of the equity award adjustments.

Duke Energy’s future stock-based compensation expense will not be significantly impacted by the equity award adjustments that occurred as a result of the spin-off. Stock-based compensation expense recognized in future periods will correspond to the unrecognized compensation expense as of the date of the spin-off. Unrecognized compensation expense as of the date of the spin-off reflects the unamortized balance of the original grant date fair value of the equity awards held by Duke Energy employees (regardless of whether those awards are linked to Duke Energy stock or Spectra Energy stock). No future compensation cost will be recognized by Duke Energy for equity awards held by Spectra Energy employees.

Stock-Based Compensation Expense

Duke Energy recorded pre-tax stock-based compensation expense included in Income From Continuing Operations for the years ended December 31, 2008, 2007 and 2006 as follows, the components of which are further described below:

	For the Years Ended December 31,
	2008		2007		2006
	(in millions)
Stock Options	$	2	$	5	$	7
Stock Appreciation Rights		—		—		1
Phantom Stock		17		20		30
Performance Awards		23		12		24
Other Stock Awards		1		2		2
Total	$	43	$	39	$	64

171

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The tax benefit associated with the recorded expense in Income from Continuing Operations for the years ended December 31, 2008, 2007 and 2006 was approximately $17 million, $15 million and $24 million, respectively. As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to its shareholders, and the results of these businesses are presented as discontinued operations. Accordingly, pre-tax stock-based compensation expense of approximately $18 million and a corresponding tax benefit of approximately $7 million for the year ended December 31, 2006 is included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

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, 2007	22,317		$	17
Exercised	(2,221	)		13
Forfeited or expired	(306	)		20
Outstanding at December 31, 2008	19,790		$	17	3.4	$	26
Exercisable at December 31, 2008	18,619		$	17	3.2	$	26
Options Expected to Vest	1,140		$	16	7.0	$	—

On December 31, 2007 and 2006, Duke Energy had approximately 20 million and 22 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, 2008, 2007 and 2006 was approximately $11 million, $26 million and $46 million, respectively. Cash received from options exercised during the years ended December 31, 2008, 2007 and 2006 was approximately $30 million, $50 million and $127 million, respectively, with a related tax benefit of approximately $4 million, $10 million and $17 million, respectively. At December 31, 2008, Duke Energy had less than $1 million of future compensation cost associated with unvested stock options which is expected to be recognized over a weighted-average period of less than one year.

There were no options granted by Duke Energy during the years ended December 31, 2008 or 2007. Duke Energy granted 1,877,646 options (fair value of approximately $10 million based on a Black-Scholes model valuation) during the year ended December 31, 2006. Remaining compensation expense to be recognized for unvested converted Cinergy options was determined using a Black-Scholes model.

Weighted-Average Assumptions for Option Pricing

	2006
Risk-free interest rate(1)	4.78%
Expected dividend yield(2)	4.40%
Expected life(3)	6.29 yrs.
Expected volatility(4)	24%

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

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

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

(4) Volatility is based upon 50% historical and 50% implied volatility. Historic volatility is based on the weighted average between Duke Energy and Cinergy 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 outstanding under the 2006 Plan generally vest over periods from immediate to three years. Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 973,515 shares (fair value of approximately $17 million based on the market price of Duke Energy’s common stock on the grant date) during the year ended December 31, 2008, 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) in the year ended December 31, 2007, and 1,181,370 shares (fair value of approximately $34 million based on the market price of Duke Energy common stock on the grant date) in the year ended December 31, 2006.

172

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The following table summarizes information about phantom stock awards outstanding at December 31, 2008:

	Shares (in thousands)		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2007	2,390		$	24
Granted	974			18
Vested	(842	)		24
Forfeited	(76	)		25
Outstanding at December 31, 2008	2,446		$	22
Phantom Stock Awards Expected to Vest	2,341		$	22

The total fair value of the shares vested during the years ended December 31, 2008, 2007 and 2006 was approximately $20 million, $31 million and $23 million, respectively. As of December 31, 2008, Duke Energy had approximately $12 million of future compensation cost associated with unvested phantom stock awards which is expected to be recognized over a weighted-average period of 1.7 years.

Performance Awards

Stock-based awards outstanding under both the 2006 Plan and the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2008, 2007 and 2006 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 with the adoption of SFAS No. 123(R). 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 2008 and 2007. The performance goal for these awards is Duke Energy’s compounded annual growth rate (CAGR) of annual diluted EPS over a three year period. These awards are measured at grant date price. Duke Energy awarded 2,407,755 shares (fair value of approximately $37 million based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2008, 1,534,510 shares (fair value of approximately $23 million based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2007, and 1,610,350 shares (fair value of approximately $32 million based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2006.

The following table summarizes information about stock-based performance awards outstanding at December 31, 2008:

	Shares (in thousands)		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2007	3,911		$	20
Granted	2,408			15
Vested	(739	)		28
Forfeited	(600	)		25
Outstanding at December 31, 2008	4,980		$	16
Stock-based Performance Awards Expected to Vest	4,767		$	16

The total fair value of the shares vested during the years ended December 31, 2008, 2007 and 2006 was approximately $20 million, $34 million and $3 million, respectively. As of December 31, 2008, Duke Energy had approximately $27 million of future compensation cost associated with unvested performance awards which is expected to be recognized over a weighted-average period of 1.2 years.

173

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other Stock Awards

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. There were no other stock awards issued during the years ended December 31, 2008 or 2007. Duke Energy awarded 279,000 shares (fair value of approximately $8 million based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2006.

The following table summarizes information about other stock awards outstanding at December 31, 2008:

	Shares (in thousands)		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2007	324		$	28
Vested	(60	)		25
Forfeited	(45	)		29
Outstanding at December 31, 2008	219		$	29
Other Stock Awards Expected to Vest	207		$	29

The total fair value of the shares vested during the years ended December 31, 2008, 2007 and 2006 was approximately $2 million in each year. As of December 31, 2008, Duke Energy had approximately $2 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.7 years.

22. Employee Benefit Plans

Duke Energy 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 benefits to be paid to plan participants. Duke Energy did not make any contributions to its defined benefit retirement plans in 2008. Duke Energy made contributions of approximately $350 million and $124 million to the legacy Cinergy qualified pension plans during the years ended December 31, 2007 and 2006, respectively. In February 2009, Duke Energy made an approximate $500 million contribution to its qualified pension plans.

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 10 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 pension costs disclosed in the tables below for the qualified, non-qualified and other-postretirement benefit plans represent the cost of the respective pension plan for the periods presented. However, portions of the net periodic pension costs disclosed in the tables have been capitalized as a component of property, plant and equipment.

Duke Energy adopted the funded status disclosure and recognition provisions of SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158), effective December 31, 2006. Duke Energy adopted the change in measurement date transition requirements of SFAS No. 158 effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date. Previously, Duke Energy used a September 30 measurement date for its defined benefit and other post-retirement plans. Additionally, as discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. As a result, the Westcoast Canadian retirement plans and Westcoast other post-retirement benefit plans were transferred to Spectra Energy. The benefit obligation for the Westcoast Canadian retirement plans and Westcoast other post-retirement benefit plans was $832 million at December 31, 2006. The fair value of plan assets for the Westcoast Canadian retirement plans and Westcoast other post-retirement benefit plans was $525 million at December 31, 2006.

174

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The remaining pension and other post-retirement plan assets and liabilities distributed to Spectra Energy as part of the spin-off are disclosed in the table below.

As a result of the change in measurement date, net periodic benefit cost of approximately $28 million for the three month period between September 30, 2006 and December 31, 2006 was recognized, net of tax, as a separate reduction of retained earnings as of January 1, 2007. In addition, as reflected in the table below, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost were recognized, net of tax, as an adjustment to AOCI and regulatory assets.

The table below identifies significant changes to the individual line items in Duke Energy’s Consolidated Balance Sheets during the year ended December 31, 2007 due to the factors above, for the Duke Energy retirement and other post-retirement plans (amounts in brackets represent credits).

	December 31, 2006			Adoption of SFAS No. 158 measurement date provisions and other			Spin-off of the natural gas businesses(a)			January 2, 2007
	(in millions)
Accrued pension and other post-retirement benefit costs	$	(1,947	)	$	(67	)	$	187		$	(1,827	)
Pre-funded pension costs		175			118			(60	)		233
Regulatory Assets		595			(129	)		(58	)		408
Deferred income tax assets (liabilities)		115			28			(25	)		118
Accumulated other comprehensive loss (income), net of tax(b)		197			22			(39	)		180
Retained earnings, net of tax		—			28			(5	)		—

(a) These amounts are in addition to the assets and liabilities of the Westcoast plans that were also distributed to Spectra Energy, as discussed above.

(b) Amounts in the “Spin-off of the natural gas businesses” column exclude approximately $109 million, net of tax, related to accumulated other comprehensive losses of Westcoast that were transferred in connection with the spin-off.

Qualified Pension Plans

Components of Net Periodic Pension Costs: Qualified Pension Plans

	For the Years Ended December 31,
	2008(a)			2007(a)			2006(a)(b)
	(in millions)
Service cost	$	92		$	96		$	76
Interest cost on projected benefit obligation		254			246			190
Expected return on plan assets		(340	)		(319	)		(243	)
Amortization of prior service cost (credit)		7			5			(1	)
Amortization of actuarial losses		13			32			49
Other		20			20			10
Net periodic pension costs	$	46		$	80		$	81

(a) These amounts exclude approximately $13 million, $17 million and $14 million for the years ended December 31, 2008, 2007 and 2006, respectively, of regulatory asset amortization resulting from purchase accounting.

(b) These amounts exclude pre-tax qualified pension cost of approximately $21 million for the year ended December 31, 2006 primarily related to the Westcoast plans transferred to Spectra Energy, which is included in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

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

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

	For the year ended December 31, 2008
	(in millions)
Regulatory assets, net increase	$	770
Regulatory liabilities, net decrease		27
Accumulated other comprehensive (income)/loss
Deferred income tax asset		(181	)
Actuarial losses arising during 2008		492
Amortization of prior year actuarial losses		(3	)
Amortization of prior year prior service cost		(4	)
Net amount recognized in Accumulated other comprehensive (income)/loss	$	304

(a) Excludes actuarial gains recognized in other accumulated comprehensive income of approximately $6 million, net of tax, associated with a Brazilian retirement plan.

175

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	4,301		$	4,823
Adoption of SFAS No. 158 measurement date provisions		—			93
Spin-off of the natural gas businesses		—			(476	)
Service cost		92			96
Interest cost		254			246
Actuarial gains		(182	)		(165	)
Benefits paid		(304	)		(316	)
Obligation at measurement date	$	4,161		$	4,301

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	4,321		$	4,324
Adoption of SFAS No. 158 measurement date provisions		—			173
Spin-off of the natural gas businesses		—			(525	)
Actual return on plan assets		(1,164	)		315
Benefits paid		(304	)		(316	)
Employer contributions		—			350
Plan assets at measurement date	$	2,853		$	4,321

The accumulated benefit obligation was $3,823 million at December 31, 2008 and $4,004 million at December 31, 2007.

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

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Accrued pension liability	$	(1,308	)	$	(240	)
Pre-funded pension costs		—			260
Net amount recognized	$	(1,308	)	$	20

The following table provides the amounts related to Duke Energy’s qualified pension plans that are reflected in Other Regulatory Assets and Deferred Debits, Deferred Credits and Other Liabilties and AOCI on the Consolidated Balance Sheets at December 31, 2008 and 2007:

	As of December 31,
	2008			2007
	(in millions)
Regulatory assets	$	931		$	161
Regulatory liabilities		—			(27	)
Accumulated other comprehensive income
Deferred income tax asset		(215	)		(34	)
Prior service cost		38			42
Net actuarial loss		537			48
Net amount recognized—Accumulated other comprehensive income	$	360		$	56

176

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Of the amounts above, approximately $3 million of unrecognized losses and approximately $7 million of unrecognized prior service cost will be recognized in net periodic pension costs in 2009.

Additional Information:

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

	As of December 31,
	2008		2007
	(in millions)
Projected benefit obligation	$	4,161	$	1,619
Accumulated benefit obligation		3,823		1,444
Fair value of plan assets		2,853		1,392

Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting

Benefit Obligations	2008	2007	2006
	(percentages)
Discount rate	6.50	6.00	5.75
Salary increase	4.50	5.00	5.00
Determined Expense	2008	2007	2006
Discount rate	6.00	5.75	5.50–6.00
Salary increase	5.00	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 pension obligation is based on AA bond yields. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used in 2006 to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.

Qualified Pension Plan Assets

			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2008		2007
U.S. equity securities	34	%	31	%	46	%
Non-U.S. equity securities	30		27		18
Debt securities	32		36		32
Real estate and cash	4		6		4
Total	100	%	100	%	100	%

Assets for both the pension and other post retirement benefits 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 targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.

177

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

The long-term rate of return of 8.5% as of December 31, 2008 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 3.0% for U.S. equities, 2.7% for Non-U.S. equities, 2.5% for fixed income securities, and 0.3% for real estate.

Non-Qualified Pension Plans

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

	For the Years Ended December 31,
	2008		2007		2006(a)
	(in millions)
Service cost	$	2	$	2	$	2
Interest cost on projected benefit obligation		10		10		7
Amortization of prior service cost		3		2		1
Amortization of actuarial losses		1		—		—
Net periodic pension costs	$	16	$	14	$	10

(a) These amounts exclude pre-tax non-qualified pension cost of approximately $7 million for the year ended December 31, 2006 primarily related to the Westcoast plans transferred to Spectra Energy, which is included in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

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

Recognized in Accumulated Other Comprehensive Income

	For the year ended December 31, 2008
	(in millions)
Accumulated other comprehensive (income)/loss
Deferred income tax asset	$	3
Prior service cost arising during 2008		1
Actuarial gains arising during 2008		(4	)
Amortization of prior year actuarial losses		(1	)
Amortization of prior year prior service cost		(3	)
Net amount recognized in accumulated other comprehensive income	$	(4	)

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

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	172		$	199
Adoption of SFAS No. 158 measurement date provisions		—			(1	)
Spin-off of the natural gas businesses		—			(18	)
Service cost		2			2
Interest cost		10			10
Actuarial gains		(4	)		(2	)
Plan amendments		—			1
Benefits paid		(14	)		(19	)
Obligation at measurement date	$	166		$	172

178

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Change in Fair Value of Plan Assets
Benefits paid	$	(14	)	$	(19	)
Employer contributions		14			19
Plan assets at measurement date	$	—		$	—

The accumulated benefit obligation was $154 million at December 31, 2008 and $160 million at December 30, 2007.

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

Consist of:

	As of December 31,
	2008			2007
	(in millions)
Accrued pension liability(a)	$	(166	)	$	(172	)
Net amount recognized	$	(166	)	$	(172	)

(a) Includes approximately $20 million and $15 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2008 and 2007, 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, 2008 and 2007:

	As of December 31,
	2008			2007
	(in millions)
Accumulated other comprehensive income (loss)
Deferred income tax asset	$	(3	)	$	(6	)
Prior service cost		15			16
Net actuarial gain		(6	)		—
Net amount recognized- Accumulated other comprehensive income	$	6		$	10

Of the amounts above, approximately $2 million of unrecognized prior service cost will be recognized in net periodic pension costs in 2009.

Additional Information:

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

	As of December 31,
	2008		2007
Projected benefit obligation	$	166	$	172
Accumulated benefit obligation		154		160
Fair value of plan assets		—		—

179

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

Benefit Obligations	2008	2007	2006
	(percentages)
Discount rate	6.50	6.00	5.75
Salary increase	4.50	5.00	5.00
Determined Expense	2008	2007	2006
Discount rate	6.00	5.75	5.50-6.00
Salary increase	5.00	5.00	5.00

The discount rate used to determine the pension obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used in 2006 to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.

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.

During the year ended December 31, 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans. Duke Energy did not make any contributions to its other post-retirement benefit plans in 2008 or 2006.

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,
	2008(a)			2007(a)			2006(a)(b)
	(in millions)
Service cost	$	7		$	11		$	9
Interest cost on accumulated post-retirement benefit obligation		44			57			50
Expected return on plan assets		(16	)		(9	)		(13	)
Amortization of prior service (credit) cost		(8	)		2			2
Amortization of net transition liability		11			10			12
Amortization of actuarial (gain) loss		(2	)		6			7
Special termination benefit cost		—			8			—
Prior period accounting true-up adjustment(c)		(55	)		—			—
Net periodic other post-retirement benefit costs	$	(19	)	$	85		$	67

(a) These amounts exclude approximately $9 million, $10 million and $5 million for the years ended December 31, 2008, 2007 and 2006, respectively, of regulatory asset amortization resulting from purchase accounting.

(b) These amounts exclude pre-tax qualified pension cost of approximately $21 million for the year ended December 31, 2006 primarily related to the Westcoast plans transferred to Spectra Energy, which is included in Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

(c) 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.

180

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other Post-Retirement Benefit Plans—Other Changes in Plan Assets and Projected Benefit Obligations

Recognized in Accumulated Other Comprehensive Income and Regulatory Assets

	For the year ended December 31, 2008
	(in millions)
Regulatory assets, net decrease	$	(25	)
Accumulated other comprehensive (income)/loss
Deferred income tax liability		14
Actuarial gains arising during 2008		(57	)
Prior service cost arising during 2008		(5	)
Prior period retiree medical accounting true-up adjustment		23
Amortization of prior year prior service credit		2
Amortization of prior year actuarial gains		1
Amortization of prior year net transition liability		(1	)
Net amount recognized in accumulated other comprehensive (income)/loss	$	(23	)

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

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	905		$	1,264
Adoption of SFAS No. 158 measurement date provisions		—			43
Spin-off of the natural gas businesses		—			(279	)
Service cost		7			11
Interest cost		44			57
Plan participants’ contributions		22			32
Actuarial gain		(170	)		(92	)
Plan amendments		(10	)		(59	)
Benefits paid		(65	)		(88	)
Accrued retiree drug subsidy		5			8
Special termination benefit cost		—			8
Accumulated post-retirement benefit obligation at measurement date	$	738		$	905

	As of and for the Years Ended December 31,
	2008			2007
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	224		$	237
Adoption of SFAS No. 158 measurement date provisions		—			8
Spin-off of the natural gas businesses		—			(89	)
Actual return on plan assets		(49	)		10
Benefits paid		(65	)		(88	)
Employer contributions		37			114
Plan participants’ contributions		22			32
Plan assets at measurement date	$	169		$	224

For measurement purposes, plan assets were valued as of December 31 for Duke Energy’s U.S. plan.

181

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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

	As of December 31,
	2008			2007
	(in millions)
Accrued other post-retirement liability(a)	$	(569	)	$	(681	)
Net amount recognized	$	(569	)	$	(681	)

(a) Includes approximately $2 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of both December 31, 2008 and 2007, respectively.

The following table provides the amounts related to Duke Energy’s other post-retirement benefit plans that are reflected in Other Regulatory Assets and Deferred Debits and AOCI on the Consolidated Balance Sheets at December 31, 2008 and 2007:

	As of December 31,
	2008			2007
	(in millions)
Regulatory assets	$	7		$	32
Accumulated other comprehensive (income)/loss:
Deferred income tax liability (asset)		4			(10	)
Net transition obligation		6			7
Prior service credit		(16	)		(13	)
Net actuarial (gain) loss		(1	)		32
Net amount recognized—Accumulated other comprehensive (income)/loss	$	(7	)	$	16

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 2009.

In May 2004, the FASB staff issued FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2). The Modernization Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. FSP FAS 106-2 provides guidance on the accounting for the subsidy. Duke Energy adopted FSP FAS 106-2 and retroactively applied this FSP as of the date of issuance. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $3 million in 2008, $3 million in 2007 and $8 million in 2006. Duke Energy has recognized an approximate $8 million subsidy receivable as of December 31, 2008, which is included in Receivables on the Consolidated Balance Sheets.

Assumptions Used for Other Post-Retirement Benefits Accounting

Determined Benefit Obligations	2008	2007	2006
	(percentages)
Discount rate	6.50	6.00	5.75
Determined Expense	2008	2007	2006
Discount rate	6.00	5.75	5.50-6.00
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 post-retirement obligation is based on AA bond yields. The yield is selected based on bonds with cash flows that are similar to the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used to determine expense in 2006 reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.

182

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Other Post-Retirement Plan Assets

Asset Category (held in the Master Trust)	Target Allocation		Percentage of Plan Assets at December 31
			2008		2007
U.S. equity securities	34	%	31	%	46	%
Non-U.S. equity securities	30		27		18
Debt securities	32		36		32
Real estate and cash	4		6		4
Total	100	%	100	%	100	%

Assets for both the pension and other post-retirement benefits are maintained in a Master Trust. The investment objective of the trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate. The long-term rate of return of 8.5% as of December 31, 2008 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 3.0% for U.S. equities, 2.7% for Non-U.S. equities, 2.5% for fixed income securities, and 0.3% for real estate.

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 VEBA’s is to achieve sufficient returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBA trusts are passively managed. VEBA I has a target allocation of 30% U.S. equities, 45% fixed income securities and 25% cash. VEBA II has a target allocation of 50% U.S. equities and 50% fixed income securities.

Assumed Health Care Cost Trend Rates^(a)

	Medicare Trend Rate				Prescription Drug Trend Rate
	2008		2007		2008		2007
Health care cost trend rate assumed for next year	8.50	%	8.00	%	11.00	%	12.50	%
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	2013		2013		2022		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		41		(37	)

Duke Energy expects to make the future benefit payments, which reflect expected future service, as appropriate. Duke Energy expects to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.

183

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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. 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,
2009	$	349	$	20	$	61	$	430
2010		364		15		64		443
2011		379		15		66		460
2012		388		15		67		470
2013		381		14		69		464
2014 – 2018		1,931		62		359		2,352

(a) Duke Energy expects to receive future subsidies under Medicare Part D of approximately $4 million in each of the years 2009 – 2010, approximately $5 million in each of the years 2011-2013 and a total of approximately $27 million during the years 2014-2018.

Employee Savings Plans

Duke Energy also 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 expensed employer matching contributions of $78 million in 2008, $68 million in 2007 and $67 million in 2006. These amounts exclude pre-tax expenses of $8 million for the year ended 2006 related to Spectra Energy, which is included in Income (Loss) from Discontinued Operations, net of tax, in the Consolidated Statements of Operations. 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.

23. Variable Interest Entities

Power Sale Special Purpose Entities (SPEs). In accordance with FIN 46R, 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, ending in 2009, and 35 MW of capacity, ending in 2016. In addition, these SPEs have individual power purchase agreements with Cinergy Capital & Trading, Inc. (Capital & Trading), a wholly owned subsidiary of Duke Energy, to supply the power. Capital & Trading 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 Bank (3% holder) and 10% by Cinergy Capital and Trading (CCT). 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 through August 2009. CinCap IV also executed a power purchase agreement with CCT (Supply PPA) that contains virtually identical terms, except for the aforementioned reservation payment and a $3 less per MWh energy charge. Cinergy guarantees the performance of CCT under this PPA (with market-based liquidated damages), but does not guarantee the payment by CinCap IV on its debt obligations.

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 Cinergy Capital and Trading (CCT). The capitalization (along with certain miscellaneous fees) of CinCap V is to be 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

184

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

months) of capacity and energy to CMP through December 2016. CinCap V also executed a power purchase agreement with CCT (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 CCT 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 definition of a variable interest entity (VIE) under FIN 46R and are subject to that guidance 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. In accordance with FIN 46R, Duke Energy consolidates these SPEs and, as such, the transactions between Capital & Trading and the two SPEs are eliminated in consolidation.

As a result of the consolidation of these two SPEs, approximately $117 million and $146 million of notes receivable is included on the Consolidated Balance Sheets at December 31, 2008 and 2007, respectively. Of these amounts, $24 million and $29 million are included in Receivables on the Consolidated Balance Sheets and $93 million and $117 million are included in Notes Receivable on the Consolidated Balance Sheets at December 31, 2008 and 2007, respectively. Approximately $108 million and $136 million of non-recourse debt is included on the Consolidated Balance Sheets, of which $19 million and $28 million is included in Current Maturities of Long-Term Debt on the Consolidated Balance Sheets and $89 million and $108 million is included in Long-Term Debt on the Consolidated Balance Sheets at December 31, 2008 and 2007, respectively. In addition, miscellaneous other assets and liabilities are included on Duke Energy’s Consolidated Balance Sheets at December 31, 2008 and 2007. 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, with a balance of $17 million and $40 million at December 31, 2008 and 2007, respectively, bears an effective interest rate of 7.81% and matures in August 2009. The second note receivable, with a balance of $100 million and $106 million at December 31, 2008 and 2007, 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, 2008:

Notes Receivable Maturities

	(in millions)
2009	$	24
2010		8
2011		10
2012		11
2013		13
Thereafter		51
Total	$	117

Subsidiary Trust Preferred Securities. In 2001, Cinergy issued approximately $316 million notional amount of 6.9% trust preferred securities, due February 2007. The trust preferred securities were issued through a trust whose common stock was 100% owned by Cinergy. The trust loaned the proceeds from the issuance of the securities to Cinergy in exchange for a note payable to the trust. Each trust preferred security unit received quarterly cash payments of 6.9% per annum of the notional amount, which represented a trust preferred security dividend. The trust’s ability to pay dividends on the trust preferred securities was solely dependent on its receipt of interest payments from Cinergy on the note payable. However, Cinergy had fully and unconditionally guaranteed the trust preferred securities. The trust preferred securities were not included in Duke Energy’s Balance Sheets. In February 2007, these trust preferred securities were redeemed on their scheduled maturity date and the note payable was settled.

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, special purpose entity. Cinergy Receivables is a wholly-owned limited liability company of Cinergy and was formed in 2002 through a $5 million

185

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

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 related collections. The securitization transaction was structured to meet the criteria for sale treatment under SFAS No. 140 and, accordingly, Duke Energy does not consolidate Cinergy Receivables and the transfers of receivables are accounted for as sales.

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 $292 million and $299 million at December 31, 2008 and 2007, 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 SFAS No. 140 and is classified within Receivables in the accompanying Consolidated Balance Sheets at December 31, 2008 and 2007. In addition, Duke Energy’s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the retained interests held by Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky.

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.

As of December 2008, Cinergy has not provided Cinergy Receivables with any additional financial support. However, per the governing purchase and sale agreement, Cinergy Receivables is required to maintain a minimum net worth of $3 million. As described below, 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. In 2009, Cinergy plans to infuse equity into Cinergy Receivables to remedy the net worth deficiency.

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 2008 were an anticipated credit loss ratio of 0.6%, a discount rate of 5.3% and a receivable turnover rate of 11.4%. The key assumptions used in estimating the fair value for 2007 were an anticipated credit loss ratio of 0.6%, a discount rate of 7.7% and a receivable turnover rate of 11.7%. Because (a) the receivables generally turnover in less than two months, (b) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration, and (c) 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 is recorded against the carrying value of both the retained interests and purchased beneficial interest whenever it is determined that an other-than-temporary impairment has occurred.

186

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

In December 2008, Cinergy Receivables recorded a $15 million increase in its provision for uncollectible accounts due primarily to the increasing amount of receivables greater than 90 days in arrears for Duke Energy Ohio and Duke Energy Kentucky. The greater amount of receivables in arrears is partially attributable to the economic downturn 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 will continue to monitor arrearages to determine whether an other-than-temporary impairment has occurred.

The following table shows the gross and net receivables sold, retained interests, purchased beneficial interest, sales, and cash flows during the years ended December 31, 2008 and 2007:

	2008		2007
	(in millions)
Receivables sold as of December 31,	$	748	$	637
Less: Retained interests		292		299
Net receivables sold as of December 31,	$	456	$	338
Purchased beneficial interest	$	—	$	17
Sales
Receivables sold	$	5,717	$	5,309
Loss recognized on sale		60		72
Cash flows
Cash proceeds from receivables sold	$	5,664	$	5,148
Collection fees received		3		3
Return received on retained interests		37		42

Cash flows from the sale of receivables for the years ended December 31, 2008 and 2007 are reflected within Operating Activities on the Consolidated Statements of Cash Flows.

Collection fees received in connection with the servicing of transferred accounts receivable for the years ended December 31, 2008 and 2007, respectively, 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%.

24. 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, 2008, 2007 and 2006 are as follows:

	For the years ended December 31,
	2008			2007		2006
	(in millions)
Income/(Expense)
Interest income	$	130		$	192	$	158
Foreign exchange (losses) gains(a)		(20	)		14		9
AFUDC equity and deferred returns(b)		137			54		32
Impairments of available-for-sale securities(c)		(13	)		—		—
Other		(2	)		11		52
Total	$	232		$	271	$	251

(a) Losses for the year ended December 31, 2008 primarily relate to International Energy’s remeasurement of certain cash and debt balances into the functional currency.

(b) The increase in 2008 is primarily related to increased capital spending primarily within the U.S. Franchised Electric and Gas segment. See Note 4 for further information.

(c) See Note 10 for additional information.

187

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

25. Subsequent Events

For information on subsequent events related to acquisitions and dispositions of businesses and sales of other assets, regulatory matters, debt and credit facilities, commitments and contingencies and employee benefit plans, see Notes 3, 4, 16, 18 and 22, respectively.

26. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(In millions, except per share data)
2008
Operating revenues	$	3,337	$	3,229	$	3,508	$	3,133	$	13,207
Operating income		751		683		577		500		2,511
Income before extraordinary item		465		351		215		264		1,295
Net income		465		351		215		331		1,362
Earnings per share (before extraordinary item):
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
2007
Operating revenues	$	3,035	$	2,966	$	3,688	$	3,031	$	12,720
Operating income		588		491		930		484		2,493
Net income		357		293		607		243		1,500
Earnings per share:
Basic(a)	$	0.28	$	0.23	$	0.48	$	0.19	$	1.19
Diluted(a)	$	0.28	$	0.23	$	0.48	$	0.19	$	1.18

(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 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 14); and an approximate $4 million charge related to other-than-temporary impairment of investments in auction rate securities (see Note 13).

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 13).

During the fourth quarter of 2008, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $67 million after-tax (approximately $103 million pre-tax) extraordinary gain related to the reapplication of SFAS No. 71 to certain operations of Commercial Power (see Note 1).

During the first quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $21 million pre-tax charge related to convertible debt (see Note 16) and a $22 million reduction in income tax expense due to a reduction in the unitary tax rate.

During the second quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $12 million pre-tax charge related to a voluntary severance program (see Note 13).

During the third quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $20 million pre-tax benefit associated with contract settlement negotiations (see Note 18).

During the fourth quarter of 2007, 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 $32 million (see Note 12), income tax expense of approximately $31 million related to an additional phase-out of the tax credits associated with the synfuel operations (see Notes 14 and 18), an approximate $25 million pre-tax gain related to reserves for contract settlement negotiations (see Note 18) and an approximate $21 million pre-tax charge related to the settlement of an outstanding litigation matter (see Note 18).

188

DUKE ENERGY CORPORATION

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

CONDENSED STATEMENTS OF OPERATIONS

(In millions, except per-share amounts)

	Years Ended December 31,
	2008			2007			2006
Operating Revenues	$	—		$	15		$	—
Operating Expenses		(4	)		(1	)		79
Operating Income		4			16			(79	)
Equity in earnings of subsidiaries		1,275			1,421			1,099
Other Income and Expenses, net		(8	)		52			15
Interest Expense		42			23			1
Income Before Income Taxes		1,229			1,466			1,034
Income Tax Benefit		(50	)		(56	)		(46	)
Income From Continuing Operations		1,279			1,522			1,080
Income (Loss) From Discontinued Operations, net of tax		16			(22	)		783
Income Before Extraordinary Items		1,295			1,500			1,863
Extraordinary Items, net of tax		67			—			—
Net Income	$	1,362		$	1,500		$	1,863
Common Stock Data
Weighted-average shares outstanding
Basic		1,265			1,260			1,170
Diluted		1,268			1,266			1,188
Earnings per share (from continuing operations)
Basic	$	1.01		$	1.21		$	0.92
Diluted	$	1.01		$	1.20		$	0.91
Earnings (loss) per share (from discontinued operations)
Basic	$	0.02		$	(0.02	)	$	0.67
Diluted	$	0.01		$	(0.02	)	$	0.66
Earnings per share (before extraordinary items)
Basic	$	1.03		$	1.19		$	1.59
Diluted	$	1.02		$	1.18		$	1.57
Earnings per share (from extraordinary items)
Basic	$	0.05		$	—		$	—
Diluted	$	0.05		$	—		$	—
Earnings per share
Basic	$	1.08		$	1.19		$	1.59
Diluted	$	1.07		$	1.18		$	1.57
Dividends per share	$	0.90		$	0.86		$	1.26

See Notes to Condensed Parent Company Financial Statements

189

DUKE ENERGY CORPORATION

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

CONDENSED BALANCE SHEETS

(In millions, except per-share amounts)

	December 31, 2008			December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents	$	5		$	25
Short-term investments		5			437
Receivables		894			679
Other		175			64
Total current assets		1,079			1,205
Investments and Other Assets
Notes receivable		450			—
Investment in consolidated subsidiaries		21,814			20,658
Other		1,106			712
Total investments and other assets		23,370			21,370
Total Assets	$	24,449		$	22,575
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	102		$	20
Notes payable and commercial paper		264			578
Taxes accrued		27			132
Other		92			36
Total current liabilities		485			766
Long-term debt		1,224			—
Other Long-Term Liabilities
Deferred income taxes		35			62
Other		1,717			548
Total other long-term liabilities		1,752			610
Commitments and Contingencies
Common Stockholders' Equity
Common Stock, $0.001 par value, 2 billion shares authorized; 1,272 million and 1,262 million shares outstanding at December 31, 2008 and December 31, 2007, respectively		1			1
Additional paid-in capital		20,106			19,933
Retained earnings		1,607			1,398
Accumulated other comprehensive loss		(726	)		(133	)
Total common stockholders' equity		20,988			21,199
Total Liabilities and Common Stockholders' Equity	$	24,449		$	22,575

See Notes to Condensed Parent Company Financial Statements

190

DUKE ENERGY CORPORATION

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

CONDENSED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,362		$	1,500		$	1,863
Adjustments to reconcile net income to net cash provided by operating activities		(748	)		(1,164	)		(869	)
Net cash provided by operating activities		614			336			994
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of available-for-sale securities		(1,117	)		(14,881	)		(6,948	)
Proceeds from sales and maturities of available-for-sale securities		1,367			15,740			5,651
Distributions from wholly-owned subsidiaries		—			—			2,361
Investment in wholly-owned subsidiary		—			(204	)		(200	)
Notes receivable from affiliates, net		(765	)		(548	)		—
Other		(19	)		(7	)		25
Net cash (used in) provided by investing activities		(534	)		100			889
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		771			—			—
Issuance of common stock related to employee benefit plans		133			50			127
Notes payable and commercial paper		112			561			—
Dividends paid		(1,143	)		(1,089	)		(1,488	)
Repurchase of common shares		—			—			(500	)
Other		27			21			24
Net cash used in financing activities		(100	)		(457	)		(1,837	)
Net (decrease) increase in cash and cash equivalents		(20	)		(21	)		46
Cash and cash equivalents at beginning of period		25			46			—
Cash and cash equivalents at end of period	$	5		$	25		$	46
Supplemental Disclosures
Significant non-cash transactions:
Forgiveness of advances payable to wholly-owned subsidiary	$	—		$	—		$	602
Forgiveness of advances receivable from wholly-owned subsidiary	$	—		$	—		$	496

See Notes to Condensed Parent Company Financial Statements

191

DUKE ENERGY CORPORATION

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, 2008.

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 Rate		Year Due	December 31,
				2008			2007
				(in millions)
Unsecured debt	4.6	%	2012 – 2018	$	774		$	—
Commercial paper(a)	4.7	%			714			578
Total debt					1,488			578
Short-term notes payable and commercial paper					(264	)		(578	)
Total long-term debt				$	1,224		$	—

(a) Includes $450 million as of December 31, 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 10 days as of December 31, 2008.

In June 2008, Duke Energy issued $500 million principal amount of senior notes, of which $250 million carries a fixed interest rate of 5.65% and matures June 15, 2013 and $250 million carries a fixed interest rate of 6.25% and matures June 15, 2018. Proceeds from the issuance were used to redeem commercial paper, to fund capital expenditures in Duke Energy’s non-regulated businesses in the U.S. 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, 2008. For additional information on Duke Energy’s master credit facility, see Note 16 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 January 2009, Duke Energy issued $750 million principal amount of senior notes which carries a fixed interest rate of 6.30% and matures February 2014. Proceeds from the issuance were used to redeem commercial paper and for general corporate purposes.

At December 31, 2008, Duke Energy has guaranteed approximately $2.6 billion of debt issued by Duke Energy Carolinas, LLC, one of Duke Energy’s wholly-owned operating subsidiaries.

192

DUKE ENERGY CORPORATION

SCHEDULE I—CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

Annual Maturities as of December 31, 2008

	(in millions)
2009	$	—
2010		—
2011		—
2012		274
2013		250
Thereafter		700
Total long-term debt, including current maturities(a)	$	1,224

(a) Excludes short-term notes payable and commercial paper of $264 million.

3. Commitments and Contingencies

Duke Energy and its subsidiaries are a party to litigation, environmental and other matters. For further information, see Note 18 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 a commercial transaction with a third party 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, 2008 was approximately $4.2 billion. Of this amount, approximately $4 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 2008 and 2033, with the remaining performance guarantees having no contractual expiration. See Note 19 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, 2008 and 2007 are as follows:

	December 31,
Assets (Liabilities)	2008			2007
	(in millions)
Current assets due from affiliated companies(a)(b)	$	8		$	123
Current liabilities due to affiliated companies(c)	$	(100	)	$	(2	)
Non-current liabilities due to affiliated companies(d)	$	(766	)	$	—

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

(b) The balances at December 31, 2008 and 2007 are classified as Receivables on the Balance Sheets.

(c) The balances at December 31, 2008 and 2007 are classified as Accounts Payable on the Balance Sheets.

(d) The balance at December 31, 2008 is classified as 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 $863 million and $548 million as of December 31, 2008 and 2007, 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 December 31, 2008. The $765 million increase in money pool receivables during 2008 and the $548 million increase during 2007 are reflected as Notes Receivable from Affiliates, net within Net Cash Used in Investing Activities on the Condensed Statements of Cash Flows. In conjunction with the money pool arrangement, Duke Energy recorded interest income of $23 million in 2008 and $16 million in 2007, which is included in Other Income and Expenses, net on the Statements of Operations. Duke Energy did not record any money pool interest income during 2006.

193

DUKE ENERGY CORPORATION

SCHEDULE I—CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

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 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 Statement of Operations.

During 2007, Duke Energy contributed $204 million of capital to its wholly owned subsidiary, Cinergy Corp and in 2006 contributed $200 million to its wholly-owned subsidiary, Duke Energy Carolinas, LLC. Additionally, Duke Energy received $200 million in 2008 and $135 million of dividends from Cinergy Corp in 2007, which is reflected within Net Cash Provided by Operating Activities on the Condensed Statements of Cash Flows. During 2006, Spectra Energy Capital, LLC distributed $2,361 million to Duke Energy, which was primarily obtained from the proceeds received on Spectra Energy Capital, LLC’s sale of 50% of Crescent Resources.

194

PART IV

DUKE ENERGY CORPORATION

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

	Balance at Beginning of Period		Additions(c):				Deductions(a)(c)		Balance at End of Period(c)
			Charged to Expense		Charged to Other Accounts
	(In millions)
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
December 31, 2006:
Injuries and damages	$	1,216	$	7	$	10	$	49	$	1,184
Allowance for doubtful accounts		127		38		21		92		94
Other(b)		896		468		268		527		1,105
	$	2,239	$	513	$	299	$	668	$	2,383

(a) Principally cash payments and reserve reversals. For 2007, this also includes the effects of amounts included in the spin-off of Spectra Energy on January 2, 2007 and the impacts of adoption of FIN 48.

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

(c) Amounts for the year ended December 31, 2006 and thereafter include balances and activity related to Duke Energy’s merger with Cinergy in April 2006.

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

195

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, 2008, 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, 2008 and have concluded that no change has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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. 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, 2008 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, 2008.

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.

196

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 2009 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 2009 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 2009 annual meeting of shareholders.

This table shows information about securities to be issued upon exercise of outstanding options, warrants and rights under Duke Energy’s equity compensation plans, along with the weighted-average exercise price of the outstanding options, warrants and rights and the number of securities remaining available for future issuance under the plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights(1) (a)		Weighted-average exercise price of outstanding options, warrants and rights(1) (b)		Number of securities remaining available under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	13,770,122	(2)	$	18.49	53,899,040	(3)
Equity compensation plans not approved by security holders	1,877,646	(4)		16.60	None
Total	15,647,768		$	18.26	53,899,040

(1) Duke Energy has not granted any warrants or rights under any equity compensation plans. Amounts do not include 4,141,968 outstanding options with a weighted average exercise price of $13.82 assumed in connection with various mergers and acquisitions.

(2) Does not include 7,298,070 shares of Duke Energy Common Stock to be issued upon vesting of phantom stock and performance share awards outstanding as of December 31, 2008.

(3) Includes 8,899,040 shares remaining available for issuance for awards of restricted stock, performance shares or phantom stock under the Duke Energy Corporation 2006 Long-Term Incentive Plan.

(4) Does not include 127,645 shares of Duke Energy Common Stock to be issued upon vesting of phantom stock and performance share awards outstanding as of December 31, 2008.

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 2009 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 2009 annual meeting of shareholders.

197

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, 2008, 2007 and 2006

Consolidated Balance Sheets as of December 31, 2008 and 2007

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income for the Years ended December 31, 2008, 2007 and 2006

Notes to the Consolidated Financial Statements

Quarterly Financial Data, as revised (unaudited, included in Note 26 to the Consolidated Financial Statements)

Consolidated Financial Statement Schedule I—Condensed Parent Company Financial Information for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2008, 2007 and 2006

Report of Independent Registered Public Accounting Firm

Separate Financial Statements of Subsidiaries not Consolidated Pursuant to Rule 3-09 of Regulation S-X:

DCP Midstream, LLC. (formerly Duke Energy Field Services, LLC):

Independent Auditors’ Report

Consolidated Balance Sheets as of December 31, 2006 and 2005

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2006 and 2005

Consolidated Statements of Cash Flows for the Years Ended December 31, 2006 and 2005

Consolidated Statements of Members’ Equity for the Years Ended December 31, 2006 and 2005

Notes to Consolidated Financial Statements

Consolidated Financial Statement Schedule II of DCP Midstream, LLC—Consolidated Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2006 and 2005

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

198

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 27, 2009

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/ David L. Hauser

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

Ann Maynard Gray*

Director

James H. Hance, Jr.*

Director

James T. Rhodes*

Director

Dudley S. Taft*

Director

Date: February 27, 2009

David L. Hauser, by signing his 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/    DAVID L. HAUSER
	Attorney-In-Fact

199

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of DCP Midstream, LLC Denver, Colorado

We have audited the accompanying consolidated balance sheets of DCP Midstream, LLC and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for the years then ended. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DCP Midstream, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

March 7, 2008

F-1

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Consolidated Balance Sheets

As of December 31, 2006 and 2005

(millions)

	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	68		$	59
Short-term investments		437			627
Accounts receivable:
Customers, net of allowance for doubtful accounts of $3 million and $4 million, respectively		933			1,237
Affiliates		283			340
Other		56			59
Inventories		87			110
Unrealized gains on mark-to-market and hedging instruments		242			252
Other		23			22
Total current assets		2,129			2,706
Property, plant and equipment, net		3,869			3,836
Restricted investments		102			364
Investments in unconsolidated affiliates		204			169
Intangible assets:
Commodity sales and purchases contracts, net		58			66
Goodwill		421			421
Total intangible assets		479			487
Unrealized gains on mark-to-market and hedging instruments		29			60
Deferred income taxes		4			3
Other non-current assets		33			86
Other non-current assets—affiliates		47			—
Total assets	$	6,896		$	7,711
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,490		$	2,035
Affiliates		92			42
Other		42			42
Current maturities of long-term debt		—			300
Unrealized losses on mark-to-market and hedging instruments		216			244
Distributions payable to members		127			185
Accrued interest payable		47			45
Accrued taxes		27			46
Other		136			129
Total current liabilities		2,177			3,068
Deferred income taxes		17			—
Long-term debt		2,115			1,760
Unrealized losses on mark-to-market and hedging instruments		33			54
Other long-term liabilities		226			224
Non-controlling interests		71			95
Commitments and contingent liabilities
Members’ equity:
Members’ interest		2,107			2,107
Retained earnings		153			411
Accumulated other comprehensive loss		(3	)		(8	)
Total members’ equity		2,257			2,510
Total liabilities and members’ equity	$	6,896		$	7,711

See Notes to Consolidated Financial Statements.

F-2

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Consolidated Statements of Operations and Comprehensive Income

Years Ended December 31, 2006 and 2005

(millions)

	2006			2005
Operating revenues:
Sales of natural gas and petroleum products	$	9,137		$	10,011
Sales of natural gas and petroleum products to affiliates		2,813			2,785
Transportation, storage and processing		308			253
Trading and marketing gains (losses)		77			(15	)
Total operating revenues		12,335			13,034
Operating costs and expenses:
Purchases of natural gas and petroleum products		9,322			10,133
Purchases of natural gas and petroleum products from affiliates		789			830
Operating and maintenance		462			447
Depreciation and amortization		284			287
General and administrative		234			195
Gain on sale of assets		(28	)		(2	)
Total operating costs and expenses		11,063			11,890
Operating income		1,272			1,144
Gain on sale of general partner interest in TEPPCO		—			1,137
Equity in earnings of unconsolidated affiliates		20			22
Non-controlling interest in (income) loss		(15	)		1
Interest income		26			26
Interest expense		(145	)		(154	)
Income from continuing operations before income taxes		1,158			2,176
Income tax expense		(23	)		(9	)
Income from continuing operations		1,135			2,167
Income from discontinued operations, net of income taxes		—			3
Net income		1,135			2,170
Other comprehensive income (loss):
Foreign currency translation adjustment		—			(8	)
Canadian business distributed to Duke Energy		—			(70	)
Net unrealized gains on cash flow hedges		5			—
Reclassification of cash flow hedges into earnings		—			1
Total other comprehensive income (loss)		5			(77	)
Total comprehensive income	$	1,140		$	2,093

See Notes to Consolidated Financial Statements.

F-3

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Consolidated Statements of Cash Flows

Years Ended December 31, 2006 and 2005

(millions)

	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,135		$	2,170
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		—			(3	)
Gain from sale of equity investment in TEPPCO		—			(1,137	)
Gain on sale of assets		(28	)		(2	)
Depreciation and amortization		284			287
Equity in earnings of unconsolidated affiliates, net of distributions		—			15
Deferred income tax expense (benefit)		17			(2	)
Non-controlling interest in income (loss)		15			(1	)
Other, net		(3	)		2
Changes in operating assets and liabilities which provided (used) cash:
Accounts receivable		314			(432	)
Inventories		23			(37	)
Net unrealized (gains) losses on mark-to-market and hedging instruments		(1	)		9
Accounts payable		(495	)		910
Accrued interest payable		1			(14	)
Other		(16	)		(12	)
Net cash provided by continuing operations		1,246			1,753
Net cash provided by discontinued operations		—			11
Net cash provided by operating activities		1,246			1,764
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital and acquisition expenditures		(325	)		(212	)
Investments in unconsolidated affiliates		(44	)		(24	)
Distributions received from unconsolidated affiliates		2			—
Purchases of available-for-sale securities		(19,666	)		(17,986	)
Proceeds from sales of available-for-sale securities		20,121			17,260
Proceeds from sales of assets		81			53
Proceeds from sale of general partner interest in TEPPCO		—			1,100
Other		—			9
Net cash provided by continuing operations		169			200
Net cash used in discontinued operations		—			(13	)
Net cash provided by investing activities		169			187
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends and distributions to members		(1,451	)		(2,313	)
Proceeds from issuance of equity securities of a subsidiary, net of offering costs		—			206
Contribution received from ConocoPhillips		—			398
Payment of debt		(320	)		(607	)
Proceeds from issuing debt		378			408
Loans made to Duke Capital LLC and ConocoPhillips		—			(1,100	)
Repayment of loans by Duke Capital LLC and ConocoPhillips		—			1,100
Net cash (paid to) received from non-controlling interests		(10	)		3
Other		(3	)		(2	)
Net cash used in continuing operations		(1,406	)		(1,907	)
Net cash used in discontinued operations		—			(44	)
Net cash used in financing activities		(1,406	)		(1,951	)
Net increase in cash and cash equivalents		9			—
Cash and cash equivalents, beginning of year		59			59
Cash and cash equivalents, end of year	$	68		$	59
Supplementary cash flow information:
Cash paid for interest (net of amounts capitalized)	$	141		$	163

See Notes to Consolidated Financial Statements.

F-4

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Consolidated Statements of Members’ Equity

Years Ended December 31, 2006 and 2005

(millions)

	Members’ Interest		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, January 1, 2005	$	1,709	$	909		$	69		$	2,687
Dividends and distributions		—		(2,414	)		—			(2,414	)
Distribution of Canadian business		—		(254	)		(70	)		(324	)
Contributions		398		—			—			398
Net income		—		2,170			—			2,170
Foreign currency translation adjustment		—		—			(8	)		(8	)
Reclassification of cash flow hedges into earnings		—		—			1			1
Balance, December 31, 2005		2,107		411			(8	)		2,510
Dividends and distributions		—		(1,393	)		—			(1,393	)
Net income		—		1,135			—			1,135
Net unrealized gains on cash flow hedges		—		—			5			5
Balance, December 31, 2006	$	2,107	$	153		$	(3	)	$	2,257

See Notes to Consolidated Financial Statements.

F-5

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements

Years Ended December 31, 2006 and 2005

1. General and Summary of Significant Accounting Policies

Basis of Presentation—DCP Midstream, LLC, formerly Duke Energy Field Services, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Duke Energy Corporation, or Duke Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. The Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.

To support and facilitate our continued growth, we formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. In September 2005, DCP Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission, or SEC, to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. We own approximately 41% of the limited partnership interests in DCP Partners and a 2% general partnership interest. As the general partner of DCP Partners, we have responsibility for its operations. DCP Partners is accounted for as a consolidated subsidiary.

In July 2005, Duke Energy transferred a 19.7% interest in our Company to ConocoPhillips in exchange for direct and indirect monetary and non-monetary consideration, effectively decreasing Duke Energy’s membership interest in our Company to 50% and increasing ConocoPhillips’ membership interest in our Company to 50%, referred to as “the 50-50 Transaction.” Included in this transaction, we distributed to Duke Energy substantially all of our Canadian business, made a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO and paid a $245 million proportionate distribution to Duke Energy and ConocoPhillips. In addition, ConocoPhillips contributed cash of $398 million to our Company. Under the terms of the amended and restated LLC Agreement, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. At December 31, 2006, there was no remaining restricted investment balance related to this contribution.

On June 28, 2006, Duke Energy’s board of directors approved a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses, including its 50% ownership interest in us, to Duke Energy shareholders. This transaction occurred on January 2, 2007. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy Corp, or Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For the historical periods included in this report, references to Spectra Energy are interchangeable with Duke Energy. On a prospective basis, Spectra Energy refers to the newly formed public company.

We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.

The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

Use of Estimates—Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

Acquisitions—We consolidate assets and liabilities from acquisitions as of the purchase date, and include earnings from acquisitions in consolidated earnings subsequent to the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. If the acquisition constitutes a business, any excess purchase price over the estimated fair value of the acquired assets and liabilities is recorded as goodwill.

F-6

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Reclassifications—Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.

Cash and Cash Equivalents—Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.

Short-Term and Restricted Investments—We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale under Statement of Financial Accounting Standards, or SFAS, No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheets as accumulated other comprehensive income (loss), or AOCI. No such gains or losses were deferred in AOCI at December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.

Inventories—Inventories consist primarily of natural gas and NGLs held in storage for transportation and processing and sales commitments. Inventories are valued at the lower of weighted average cost or market. Transportation costs are included in inventory on the consolidated balance sheets.

Accounting for Risk Management and Hedging Activities and Financial Instruments—Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS 133, as amended, is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.

We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statements of operations and comprehensive income are as follows:

Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-market methoda	Net basis in trading and marketing gains (losses)
Non-Trading Derivatives:
Cash Flow Hedge	Hedge methodb	Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item
Fair Value Hedge	Hedge methodb	Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item
Normal Purchase or Normal Sale	Accrual methodc	Gross basis upon settlement in the corresponding consolidated statements of operations and comprehensive income category based on purchase or sale
Non-Trading Derivatives	Mark-to-market methoda	Net basis in trading and marketing gains (losses)

^a Mark-to-market—An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations and comprehensive income in trading and marketing gains (losses) during the current period.

^b Hedge method—An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations and comprehensive income for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the changes in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations and comprehensive income in the same category as the related hedged item.

^c Accrual method—An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations and comprehensive income for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings.

Cash Flow and Fair Value Hedges—For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge in accordance with SFAS 133. In addition, we formally assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

F-7

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as AOCI and the ineffective portion is recorded in the consolidated statements of operations and comprehensive income. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations and comprehensive income in the same accounts as the item being hedged. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting changes in value of the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the consolidated statements of operations and comprehensive income.

Valuation—When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

Property, Plant and Equipment—Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability for conditional asset retirement obligations as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity.

Impairment of Unconsolidated Affiliates—We evaluate our unconsolidated affiliates for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether any impairment has occurred. Management assesses the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.

Intangible Assets—Intangible assets consist of goodwill, and commodity sales and purchases contracts. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Commodity sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 25 years.

We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.

F-8

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Impairment of Long-Lived Assets, Assets Held for Sale and Discontinued Operations—We evaluate whether the carrying value of long-lived assets, excluding goodwill, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:

• A significant adverse change in legal factors or business climate;

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

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

• Significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;

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

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

If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but 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 the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

We use the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” or SFAS 144, to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the consolidated balance sheets.

If an asset held for sale or sold (1) has clearly distinguishable operations and cash flows, generally at the plant level, (2) has direct cash flows of the held for sale or sold component that will be eliminated (from the perspective of the held for sale or sold component), and (3) if we are unable to exert significant influence over the disposed component, then the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales are reflected as income from discontinued operations in the consolidated statements of operations and comprehensive income. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statements of operations and comprehensive income.

Unamortized Debt Premium, Discount and Expense—Premiums, discounts and expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These premiums and discounts are recorded on the consolidated balance sheets as an offset to long-term debt. These expenses are recorded on the consolidated balance sheets as other non-current assets.

Distributions—Under the terms of the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each members’ tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. Prior to January 2, 2007, the capital accounts were maintained at 50% for both Duke Energy and ConocoPhillips, and prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the years ended December 31, 2006 and 2005, we paid distributions of $650 million and $389 million, respectively, based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.

Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. During the years ended December 31, 2006 and 2005, we paid total dividends of $801 million and $1,925 million, respectively. The $1,925 million paid during the year ended December 31, 2005, is comprised of a disproportionate cash distribution of approximately $1,100 million to Duke Energy

F-9

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

using the proceeds from the sale of our general partner interest in TEPPCO as part of the 50-50 Transaction, a $245 million proportionate distribution to Duke Energy and ConocoPhillips as part of the 50-50 Transaction, and $580 million in proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The $801 million paid during the year ended December 31, 2006, is comprised of proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The LLC Agreement restricts payment of dividends except with the approval of both members.

DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our 41% limited partner interest in DCP Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period will end on December 31, 2010 if certain distribution tests are met and earlier if certain more stringent tests are met. At such time that the subordination period ends, the subordinated units will be converted to common units. During the year ended December 31, 2006, DCP Partners paid distributions of approximately $13 million to its public unitholders. We hold general partner incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.

Foreign Currency Translation—We translated assets and liabilities of our Canadian operations, where the Canadian dollar was the functional currency, at the period-end exchange rates. Revenues and expenses were translated using average monthly exchange rates during the period, which approximates the exchange rates at the time of each transaction during the period. Foreign currency translation adjustments are included in the consolidated statements of comprehensive income. In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. As a result, there were no translation gains or losses in AOCI at December 31, 2006 and 2005.

Revenue Recognition—We generate the majority of our revenues from natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as trading and marketing of natural gas and NGLs.

We obtain access to raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.

• Fee-based arrangements—Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, or transporting of natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase raw natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of raw natural gas from the wellhead location to the delivery point. The revenue we earn is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced.

• Percent-of-proceeds/index arrangements—Under percentage-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs at index prices based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Under these types of arrangements, our revenues correlate directly with the price of natural gas and NGLs.

• Keep-whole arrangements—Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, market the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas received. Under these types of contracts, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices.

F-10

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Our trading and marketing of natural gas and NGLs, consists of physical purchases and sales, as well as derivative instruments.

We recognize revenue for sales and services under the four revenue recognition criteria, as follows:

Persuasive evidence of an arrangement exists—Our customary practice is to enter into a written contract, executed by both us and the customer.

Delivery—Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

The fee is fixed or determinable—We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

Collectability is probable—Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, cash position and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.

We generally report revenues gross in the consolidated statements of operations and comprehensive income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statements of operations and comprehensive income as trading and marketing gains (losses). These activities include mark-to-market gains and losses on energy trading contracts, and the financial or physical settlement of energy trading contracts.

Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. There are no material differences between the actual amounts and the estimated amounts of revenues and purchases recorded at December 31, 2006 and 2005.

Gas and NGL Imbalance Accounting—Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable—other as of December 31, 2006 and 2005 were imbalances totaling $45 million and $59 million, respectively. Included in the consolidated balance sheets as accounts payable—other, as of December 31, 2006 and 2005 were imbalances totaling $42 million at both periods.

Significant Customers—ConocoPhillips, an affiliated company, was a significant customer in both of the past two years. Sales to ConocoPhillips, including its 50% owned equity method investment, ChevronPhillips Chemical Company LLC, or CP Chem, totaled approximately $2,677 million during 2006 and $2,513 million during 2005.

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2006 and 2005, included in the consolidated balance sheets, totaled $6 million for both periods recorded as other current liabilities, and totaled $6 million and $7 million, respectively, recorded as other long-term liabilities.

Stock-Based Compensation—Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPU’s, Strategic Performance Units, or SPU’s, and Phantom Units. Prior to January 2, 2007, each of the above units constitutes a notional unit equal to the weighted average fair value of a common share or unit of ConocoPhillips, Duke Energy and DCP Partners, weighted 45%, 45% and 10%, respectively. Upon the Spectra spin, the 45% weighting attributable to Duke Energy will be valued as one common share of Duke Energy and one-half of one common share of Spectra Energy. The 2006 Plan also provides for the grant of DCP Partners’ Phantom Units, which constitute a notional unit equal to the fair value of DCP Partners’ common units. Each unit provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006.

F-11

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, equity instruments may be granted to DCP Partners’ key employees. DCP Midstream GP, LLC adopted the DCP Partners’ Plan for employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ Plan provides for the grant of unvested units, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. DCP Partners first granted awards under this plan during the first quarter of 2006.

Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board, or APB, Opinion No. 25, or APB 25, “Accounting for Stock Issued to Employees,” and Financial Accounting Standards Board, or FASB, Interpretation No. 44, or FIN 44, “Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion No. 25.” Under that method, compensation expense was measured as the intrinsic value of an award at the measurement dates. The intrinsic value of an award is the amount by which the quoted market price of the underlying stock exceeds the amount, if any, an employee would be required to pay to acquire the stock. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation expense has historically been recognized in the accompanying consolidated statements of operations and comprehensive income. Compensation expense for phantom stock awards and other stock awards was recorded from the date of grant over the required vesting period based on the market value of the awards at the date of grant. Compensation expense for stock-based performance awards was recorded over the required vesting period, and adjusted for increases and decreases in market value at each reporting date up to the measurement dates.

Under its 1998 Long-Term Incentive Plan, or 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, certain of our employees who had been issued awards under the 1998 Plan incurred a change in status from Duke Energy employees to non-employees. As a result, all outstanding stock-based awards were required to be remeasured as of July 2005 under EITF Issue No. 96-18, or EITF 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using the fair value method prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123. Compensation expense is recognized prospectively beginning at the date of the change in status over the remaining vesting period based on the fair value of each award at each reporting date. The fair value of stock options is determined using the Black-Scholes option pricing model and the fair value of all other awards is determined based on the closing equity price at each measurement date.

Effective January 1, 2006, we adopted the provisions of SFAS No. 123(R) (Revised 2004) “Share-Based Payment,” or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Liability classified stock-based compensation cost is remeasured at each reporting date, and is recognized over the requisite service period.

We elected to adopt the modified prospective application method as provided by SFAS 123R and, accordingly, financial statement amounts for the prior periods presented in these consolidated financial statements have not been restated. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.

We recorded stock-based compensation expense for the years ended December 31, 2006 and 2005 as follows, the components of which are further described in Note 13:

	Year Ended December 31,
	2006		2005
	(millions)
Performance awards	$	4	$	3
Phantom awards		4		2
Total	$	8	$	5

F-12

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

The following table shows what net income would have been if the fair value recognition provisions of SFAS 123 had been applied to all stock-based compensation awards for the year ended December 31, 2005.

	Year Ended December 31, 2005
	(millions)
Net income, as reported	$	2,170
Add: stock-based compensation expense included in reported net income		3
Deduct: total stock-based compensation expense determined under fair value-based method for all awards		(3	)
Pro forma net income	$	2,170

Accounting for Sales of Units by a Subsidiary—In December 2005, we formed DCP Partners through the contribution of certain assets and investments in unconsolidated affiliates in exchange for common units, subordinated units and a 2% general partner interest. Concurrent with the formation, we sold approximately 58% of DCP Partners to the public, through an initial public offering, for proceeds of approximately $206 million, net of offering costs. We account for sales of units by a subsidiary under Staff Accounting Bulletin No. 51, or SAB 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. Under SAB 51, a gain on the sale of subsidiary equity cannot be recognized until multiple classes of outstanding securities convert to common equity. As a result, we have deferred approximately $150 million of gain on sale of common units in DCP Partners as other long-term liabilities in the consolidated balance sheets. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.

Income Taxes—We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes.

We follow the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities.

New Accounting Standards—SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115,” or SFAS 159. In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.

SFAS No. 154 “Accounting Changes and Error Corrections,” or SFAS 154. In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated results of operations, cash flows or financial position.

F-13

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

FIN No. 48 “Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109,” or FIN 48. In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for us on January 1, 2007. The adoption of FIN 48 is not expected to have a material impact on our combined results of operations, cash flows or financial position.

EITF Issue No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” or EITF 04-13. In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29 when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. EITF 04-13 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.

Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108—In September 2006, the SEC issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated results of operations, cash flows or financial position.

2. Acquisitions and Dispositions

Acquisitions

Acquisition of Various Gathering, Transmission and Processing Assets—In the fourth quarter of 2005, we entered into an agreement to purchase certain Federal Energy Regulatory Commission, or FERC, regulated pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate these assets as intrastate pipeline. This acquisition is expected to close in the second half of 2007.

Acquisition of Additional Equity Interests—In December 2006, we acquired an additional 33.33 % interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own 66.67% of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering pipeline system in the Gulf of Mexico.

In November 2006, we purchased the remaining 16% minority interest in Dauphin Island Gathering Partners, or DIGP, for $7 million. DIGP was owned 84% by us prior to this transaction, and subsequent to this transaction, is owned 100% by us. DIGP owns gathering and transmission assets in the Gulf Coast.

In December 2005, we purchased an additional 6.67% interest in Discovery Producer Services, LLC, or Discovery, from Williams Energy, LLC for a purchase price of $13 million. Discovery is an unconsolidated affiliate, which, prior to this transaction, was 33.33% owned by us, and subsequent to this transaction is 40% owned by us. Discovery owns and operates an interstate pipeline, a condensate handling facility, a cryogenic gas processing plant and other gathering assets in deepwater offshore Louisiana.

Dispositions

Disposition of Various Gathering, Transmission and Processing Assets—In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified certain of these assets as held for sale, recorded in other non-current assets, consisting primarily of property, plant and equipment totaling $58 million at December 31, 2005. Assets at one location, totaling $48 million as of December 31, 2005, were sold in the first quarter of 2006 for $76 million and we recognized a gain of $28 million. Assets at another location, totaling $9 million as of December 31, 2005, were sold in the first quarter of 2006 for $9 million and we recognized no gain or loss.

F-14

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

In August 2005, we sold certain gas gathering facilities in Kansas and Oklahoma for a sales price of approximately $11 million. No gain or loss was recognized.

In February 2005, we exchanged certain processing plant assets in Wyoming for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.

In February 2005, we sold certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming for approximately $28 million.

Disposition of Equity Interests—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid its outstanding borrowings in full in March 2005. Duke Capital, LLC repaid its outstanding borrowings in full in July 2005.

Distribution of Canadian Business to Duke Energy—In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. The following is a summary of the net assets distributed to Duke Energy on the closing date of July 1, 2005 (millions):

Assets:
Cash	$	44
Accounts receivable		18
Other assets		1
Property, plant and equipment, net		291
Goodwill		18
Total assets	$	372
Liabilities:
Accounts payable	$	11
Other current liabilities		4
Current and long-term debt		1
Deferred income taxes		20
Other long-term liabilities		12
Total liabilities	$	48
Net assets of Canadian business distributed to Duke Energy	$	324

We routinely sell assets that comprise a component of the Company, and are recorded as discontinued operations, but are not individually significant. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented.

There were no assets accounted for as discontinued operations for the year ended December 31, 2006. The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005:

	2005
	(millions)
Operating revenues	$	35
Pre-tax operating income	$	4
Income tax expense		(1	)
Income from discontinued operations	$	3

F-15

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

3. Agreements and Transactions with Affiliates

The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging instruments with affiliates as of December 31:

	2006		2005
	(millions)
Duke Energy:
Unrealized gains on mark-to-market and hedging instruments—current	$	—	$	18
Unrealized gains on mark-to-market and hedging instruments—non-current	$	—	$	19
Unrealized losses on mark-to-market and hedging instruments—current	$	—	$	(20	)
Unrealized losses on mark-to-market and hedging instruments—non-current	$	—	$	(20	)
ConocoPhillips:
Unrealized gains on mark-to-market and hedging instruments—current	$	1	$	9
Unrealized losses on mark-to-market and hedging instruments—current	$	—	$	(4	)

The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the years ended December 31:

	2006		2005
	(millions)
Duke Energy:
Sales of natural gas and petroleum products to affiliates	$	41	$	109
Transportation, storage and processing	$	18	$	2
Purchases of natural gas and petroleum products from affiliates	$	137	$	130
Operating and general and administrative expenses	$	30	$	44
Interest income	$	—	$	8
ConocoPhillips(a):
Sales of natural gas and petroleum products to affiliates	$	2,677	$	2,513
Transportation, storage and processing	$	12	$	11
Purchases of natural gas and petroleum products from affiliates	$	492	$	556
General and administrative expenses	$	5	$	—
Unconsolidated affiliates:
Sales of natural gas and petroleum products to affiliates	$	95	$	163
Transportation, storage and processing	$	20	$	20
Purchases of natural gas and petroleum products from affiliates	$	160	$	144

^(a) Includes ConocoPhillips’ 50% owned equity method investment, CP Chem

Spectra Energy and Duke Energy

Services Agreement—Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

In connection with the Spectra spin, we will need to transfer responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transition these services either to Spectra or to third party service providers.

Included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables of $47 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are other receivables of $8 million and $39 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. During the years ended December 31, 2006 and 2005, we recorded hurricane related business interruption insurance recoveries of $1 million and $3 million, respectively, included in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.

In the fourth quarter of 2006, an insurance provider that is a subsidiary of Duke Energy agreed to settle an insurance claim, related to a damaged underground storage facility, for approximately $21 million. We had recorded a receivable in 2005 related to this claim for approximately $4 million. Upon receipt of the cash in December 2006, we relieved the receivable and recorded business interruption insurance recoveries of approximately $16 million, included in the consolidated statements of operations and comprehensive income as transportation, storage and processing.

F-16

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Commodity Transactions—We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Duke Energy and Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Spectra Energy in the ordinary course of business.

ConocoPhillips

Long-term NGLs Purchases Contract and Transactions — We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem, a 50% equity investment of ConocoPhillips (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement, or the CP Chem NGL Agreement, between us and CP Chem, CP Chem has the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The CP Chem NGL Agreement also grants CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.

Transactions with other unconsolidated affiliates

In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid their outstanding borrowings in full in March 2005. Duke Capital LLC repaid their outstanding borrowings in full in July 2005.

We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell these commodities and provide these services to unconsolidated affiliates in the ordinary course of business.

Estimates related to affiliates

Revenue for goods and services provided but not invoiced to affiliates is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated revenues and purchases recorded at December 31, 2006 and 2005.

4. Marketable Securities

Short-term and restricted investments—At December 31, 2006 and 2005, we had $437 million and $627 million, respectively, of short-term investments. These instruments are classified as available-for-sale securities under SFAS 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as the interest rates re-set on a daily, weekly or monthly basis.

In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash was invested in financial instruments as described above. Under the terms of the amended and restated LLC Agreement, however, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. As this cash was to be used to acquire non-current assets, we had $0 and $264 million, respectively, classified as a long-term asset, as restricted investments, on the consolidated balance sheets at December 31, 2006 and 2005. At December 31, 2006 and 2005, we had restricted investments of $102 million and $100 million, respectively, consisting of collateral for DCP Partners’ term loan.

F-17

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

5. Inventories

Inventories by category were as follows as of December 31:

	2006		2005
	(millions)
Natural gas held for resale	$	34	$	43
NGLs		53		67
Total inventories	$	87	$	110

6. Property, Plant and Equipment

Property, plant and equipment by classification was as follows as of December 31:

	Depreciable Life	2006			2005
		(millions)
Gathering	15 - 30 years	$	2,641		$	2,503
Processing	25 - 30 years		1,904			1,840
Transportation	25 - 30 years		1,217			1,223
Underground storage	20 - 50 years		119			103
General plant	3 - 5 years		146			138
Construction work in progress			203			108
			6,230			5,915
Accumulated depreciation			(2,361	)		(2,079	)
Property, plant and equipment, net		$	3,869		$	3,836

Depreciation expense for 2006 and 2005 was $275 million and $278 million, respectively. Interest capitalized on construction projects in 2006 and 2005, was approximately $3 million and $2 million, respectively. At December 31, 2006, we had non-cancelable purchase obligations of approximately $27 million for capital projects expected to be completed in 2007. In addition, property, plant and equipment includes $10 million and $13 million of non-cash additions for the years ended December 31, 2006 and 2005, respectively.

7. Goodwill and Other Intangibles

The changes in the carrying amount of goodwill are as follows for the years ended December 31:

	2006		2005
	(millions)
Goodwill, beginning of period	$	421	$	452
Purchase price adjustments		—		(11	)
Foreign currency translation adjustments		—		(2	)
Distribution of Canadian business to Duke Energy		—		(18	)
Goodwill, end of period	$	421	$	421

We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.

We completed our annual goodwill impairment test as of August 31, 2006. We also tested goodwill for impairment in July 2005 upon the distribution of substantially all of our Canadian business to Duke Energy, in conjunction with the 50-50 Transaction. These goodwill impairment tests were performed by comparing our reporting units’ estimated fair values to their carrying, or book, values. These valuations indicated our reporting units’ fair values were in excess of their carrying, or book, values; therefore, we have determined that there is no indication of impairment. There were no impairments of goodwill for the years ended December 31, 2006 and 2005.

F-18

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

During 2005, we recorded an adjustment to properly account for deferred taxes established as a result of purchase business combinations that occurred during 2001. As a result of this adjustment, goodwill and deferred income tax liabilities decreased by approximately $11 million and $3 million, respectively, and property, plant and equipment, net, increased by $8 million.

In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. Included in the distribution was $18 million of goodwill, which was determined based on the relative fair value of the Canadian business to the fair value of the Natural Gas Services reporting unit.

The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows for the years ended December 31:

	2006			2005
	(millions)
Commodity sales and purchases contracts	$	132		$	130
Accumulated amortization		(74	)		(64	)
Commodity sales and purchases contracts, net	$	58		$	66

During the years ended December 31, 2006 and 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these intangibles range from less than one year to 20 years with a weighted average remaining period of approximately 7 years.

Estimated amortization for these contracts for the next five years and thereafter is as follows:

	Estimated Amortization
	(millions)
2007	$	8
2008		8
2009		8
2010		8
2011		7
Thereafter		19
Total	$	58

8. Investments in Unconsolidated Affiliates

We have investments in the following unconsolidated affiliates accounted for using the equity method:

	2006 Ownership		December 31,
			2006		2005
	(millions)
Discovery Producer Services LLC	40.00	%	$	114	$	102
Main Pass Oil Gathering Company	66.67	%		47		13
Sycamore Gas System General Partnership	48.45	%		12		13
Mont Belvieu I	20.00	%		11		12
Tri-States NGL Pipeline, LLC	16.67	%		9		9
Black Lake Pipe Line Company	50.00	%		6		6
Other unconsolidated affiliates	Various			5		14
Total investments in unconsolidated affiliates			$	204	$	169

Discovery Producer Services LLC—Discovery Producer Services LLC, or Discovery, owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. In December 2005, we acquired an additional 6.67% interest in Discovery from Williams Energy, LLC for a purchase price of $13 million, bringing our total ownership to 40%. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $49 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

F-19

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Main Pass Oil Gathering Company—In December 2006, we acquired an additional 33.33% interest in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method. The excess of the carrying amount of the investment over the underlying equity of Main Pass of $12 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.

Sycamore Gas System General Partnership—Sycamore Gas System General Partnership, or Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $9 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

Mont Belvieu I—Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I of $11 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.

Tri-States NGL Pipeline, LLC—Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence, therefore, this investment is accounted for under the equity method of accounting in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

Black Lake Pipe Line Company—Black Lake Pipe Line Company, or Black Lake, owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $7 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.

Fox Plant, LLC—In May 2006, we purchased the remaining 50% interest in Fox Plant, LLC, a limited liability company formed for the purpose of constructing, owning, and operating a gathering facility and gas processing plant in Carter County, Oklahoma. Subsequent to May 2006, Fox Plant, LLC was accounted for as a consolidated subsidiary. Fox Plant, LLC is included in other unconsolidated affiliates in the above table as of December 31, 2005.

TEPPCO Partners, L.P.—In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million.

Equity in earnings of unconsolidated affiliates amounted to the following for the years ended December 31:

	2006			2005
	(millions)
Discovery Producer Services LLC	$	17		$	11
Main Pass Oil Gathering Company		3			3
Sycamore Gas System General Partnership		(1	)		(1	)
Mont Belvieu I		(1	)		(1	)
Tri-States NGL Pipeline, LLC		1			1
Black Lake Pipe Line Company		—			—
TEPPCO Partners, L.P.		—			8
Other unconsolidated affiliates		1			1
Total equity in earnings of unconsolidated affiliates	$	20		$	22

F-20

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

The following summarizes combined financial information of unconsolidated affiliates for the years ended and as of December 31:

	2006		2005
	(millions)
Income statement:
Operating revenues	$	322	$	328
Operating expenses	$	287	$	312
Net income	$	42	$	18
Balance sheet:
Current assets	$	115	$	133
Non-current assets		724		740
Current liabilities		61		81
Non-current liabilities		7		6
Net assets	$	771	$	786

9. Estimated Fair Value of Financial Instruments

We have determined the following fair value amounts using available market information and appropriate valuation methodologies. Considerable judgment is required, however, in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

	December 31, 2006						December 31, 2005
	Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
	(millions)
Short-term investments	$	437		$	437		$	627		$	627
Restricted investments		102			102			364			364
Accounts receivable		1,272			1,272			1,636			1,636
Accounts payable		(1,624	)		(1,624	)		(2,119	)		(2,119	)
Net unrealized gains and losses on mark-to-market and hedging instruments		22			22			14			14
Current maturities of long-term debt		—			—			(300	)		(302	)
Long-term debt		(2,115	)		(2,258	)		(1,760	)		(1,942	)

The fair value of short-term investments, restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.

The estimated fair values of current debt, including current maturities of long-term debt, and long-term debt, with the exception of DCP Partners’ long-term debt, are determined by prices obtained from market quotes. The carrying value of DCP Partners’ long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.

10. Asset Retirement Obligations

Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

F-21

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes changes in the asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets, for the years ended December 31:

	2006			2005
	(millions)
Balance as of January 1	$	50		$	57
Accretion expense		3			3
Liabilities incurred		—			1
Liabilities settled		(1	)		—
Distribution of Canadian business to Duke Energy		—			(10	)
Other		—			(1	)
Balance as of December 31	$	52		$	50

11. Financing

Long-term debt was as follows at December 31:

	Principal/Discount
	2006			2005
	(millions)
Debt securities:
Issued November 2001, interest at 5.750% payable semiannually, due November 2006	$	—		$	300
Issued August 2000, interest at 7.875% payable semiannually, due August 2010		800			800
Issued January 2001, interest at 6.875% payable semiannually, due February 2011		250			250
Issued October 2005, interest at 5.375% payable semiannually, due October 2015		200			200
Issued August 2000, interest at 8.125% payable semiannually, due August 2030		300			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036		300			—
DCP Partners’ credit facility revolver, weighted average interest rate of 5.86% at December 31, 2006, due December 2010		168			110
DCP Partners’ credit facility term loan, interest rate of 5.47% at December 31, 2006, due December 2010		100			100
Fair value adjustments related to interest rate swap fair value hedges(a)		4			7
Unamortized discount		(7	)		(7	)
Current portion of long-term debt		—			(300	)
Long-term debt	$	2,115		$	1,760

^(a) See Note 12 for further discussion.

Debt Securities—In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007. The proceeds from this offering were used to repay our 5.75% Senior Notes that matured on November 15, 2006.

In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015, or 5.375% Notes, for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We pay interest semiannually on April 15 and October 15 of each year, commencing April 15, 2006. The proceeds from this offering were used to repay the August 2005 term loan facility discussed below.

In August 2005, we repaid the $600 million 7.5% Notes that were due on August 16, 2005. We repaid a portion of this debt with available cash and proceeds from the issuance of commercial paper, and refinanced a portion of this debt with the August 2005 term loan facility discussed below.

The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.

F-22

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Credit Facilities with Financial Institutions—On April 29, 2005, we entered into a credit facility, or the Facility, to replace a $250 million 364-day facility that was terminated on April 29, 2005. The Facility is used to support our commercial paper program, and for working capital and other general corporate purposes. In December 2005, we amended the Facility to amend the definition of consolidated capitalization to include minority interest, which is referred to in these financial statements as non-controlling interest. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility is a $450 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.35% per year for the initial 50% usage or LIBOR plus 0.45% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.1% based on our credit rating on the drawn and undrawn portions. As of December 31, 2006, there were no borrowings or commercial paper outstanding, and there was approximately $5 million in letters of credit drawn against the Facility. As of December 31, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.

In August 2005, we entered into a credit agreement, or the Term Loan Facility, where we made a one-time request to borrow $200 million in the form of a term loan. We used this Term Loan Facility to repay a portion of our $600 million 7.5% Notes that matured on August 16, 2005. The Term Loan Facility was repaid in October 2005 with proceeds from the 5.375% Notes.

On December 7, 2005, DCP Partners entered into a 5-year credit agreement, or the DCP Partners’ Credit Agreement, with a $250 million revolving credit facility and a $100 million term loan facility. The DCP Partners’ Credit Agreement matures on December 7, 2010. At December 31, 2006 and 2005, there was $168 million and $110 million, respectively, outstanding on the revolving credit facility and $100 million outstanding on the term loan facility. The term loan facility is fully collateralized by investments in high-grade securities, which are classified as restricted investments on the accompanying consolidated balance sheet. Outstanding letters of credit on the DCP Partners’ Credit Agreement were less than $1 million as of December 31, 2006, and there were no letters of credit outstanding at December 31, 2005. The DCP Partners’ Credit Agreement requires DCP Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the DCP Partners’ Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. Indebtedness under the revolving credit facility bears interest, at our option, at either (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50% or (2) LIBOR plus an applicable margin, which ranges from 0.27% to 1.025% dependent upon the leverage level or credit rating. As of December 31, 2006, the $100 million term loan facility bears interest at LIBOR plus a rate per annum of 0.15%. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2006:

	Debt Maturities
	(millions)
2010	$	1,068
2011		250
Thereafter		804
		2,122
Unamortized discount		(7	)
Long-term debt	$	2,115

12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

Commodity price risk—Our principal operations of gathering, processing, compression, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, gathering, treating, processing, storage and trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs,

F-23

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.

Energy trading (market) risk—Certain of our subsidiaries are engaged in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.

Interest rate risk—We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

Credit risk—Our principal customers range from large, natural gas marketing services to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.

As of December 31, 2006, we held cash or letters of credit of $83 million to secure future performance of financial or physical contracts, and had deposited with counterparties $7 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclose credit ratings, which may impact the amounts of collateral requirements.

Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

Commodity hedging strategies—Historically, we have used commodity cash flow hedges, as specifically defined in SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and our ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions. Our current strategy is to use cash flow hedges only for commodity price risk related to DCP Partners’ operations. Some of the assets operated by DCP Partners generate cash flows that are subject to volatility from fluctuating commodity prices. As a publicly traded master limited partnership, an important component of the strategy of DCP Partners is to generate consistent cash flow from its operations in order to pay distributions to its unitholders. For operations other than those of DCP Partners, we do not currently anticipate using cash flow hedges in the near future, because management believes cash flows will be sufficient to fund our business.

Commodity cash flow hedges—We have executed a series of derivative financial instruments, which have been designated as cash flow hedges of the price risk associated with forecasted sales of natural gas, NGLs and condensate through 2010, and the price risk associated with forecasted sales of condensate during 2011, related to assets of DCP Partners. Because of the strong correlation between NGL prices and crude oil prices, and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk.

F-24

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

For the year ended December 31, 2006, amounts recognized as comprehensive income in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were gains of $4 million, and amounts recognized for the effects of any ineffectiveness were insignificant for the year ended December 31, 2006. For the year ended December 31, 2005, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. During the year ended December 31, 2006, we reclassified $1 million in net gains (net of minority interest of $2 million) to the consolidated statements of operations and comprehensive income as a result of settlements. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of a change in the probability of forecasted transactions occurring, which would cause us to discontinue hedge treatment. The deferred balance in AOCI was a gain of $3 million at December 31, 2006, and was insignificant at December 31, 2005. As of December 31, 2006, $1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

Commodity fair value hedges—We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

For the years ended December 31, 2006 and 2005, the gains or losses representing the ineffective portion of our fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items and, therefore, did not recognize an associated gain or loss.

Interest rate cash flow hedges—During 2006, DCP Partners entered into interest rate swap agreements to convert $125 million of the indebtedness on their revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps expire on December 7, 2010 and re-price prospectively approximately every 90 days. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the accompanying consolidated balance sheets. For the year ended December 31, 2006, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were not significant, and there was no ineffectiveness recorded for the year ended December 31, 2006. At December 31, 2006, the gains deferred in AOCI related to these swaps were insignificant. At December 31, 2006, the amount of deferred net gains on derivative instruments in AOCI that are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur are insignificant; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred into AOCI and amortized against interest expense over the life of the respective debt. The amount amortized to interest expense during the years ended December 31, 2006 and 2005, was $1 million for both periods. The deferred balance was a loss of $7 million and $8 million at December 31, 2006 and 2005, respectively. Approximately $1 million of deferred net losses related to these instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the underlying hedged interest expense transaction occurs.

Interest rate fair value hedges—In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities, which were issued in August 2000, to floating rate debt. The interest rate fair value hedge was at a floating rate based on a six-month LIBOR, which was re-priced semiannually through the date of maturity, August 2005.

In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions, which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2006 and 2005, the fair value of the interest rate swaps was a $4 million and $8 million asset, respectively, which is included in the consolidated balance sheets as unrealized gains or losses on mark-to-market and hedging instruments with offsets to the underlying debt included in current maturities of long-term debt and long-term debt.

F-25

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Commodity derivatives—trading and marketing—Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.

13. Stock-Based Compensation

DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan—Relative Performance Units—RPU’s generally cliff vest at the end of eight years, consisting of a three year performance period and a five year deferral period. The number of RPU’s that will ultimately vest range from 0% to 200% of the outstanding RPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. At the end of the performance period, based on the market value of the RPU’s, we will create an account for each grantee in our deferred compensation plan. Payment of the grantee’s deferred compensation account will occur after a five year deferral period, the value of which is based on the value of the participant’s investment elections during the deferral period. Each RPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the RPUs for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the RPU’s, which was calculated using an estimated forfeiture rate of 64%, and is expected to be recognized over a weighted-average period of 7.0 years. The following tables presents information related to RPUs:

	Units	Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—	$	—
Granted	44,080	$	42.89
Outstanding at December 31, 2006	44,080	$	42.89	$	50.78
Expected to vest	15,869	$	42.89	$	50.78

Strategic Performance Units—SPU’s generally cliff vest at the end of three years. The number of SPU’s that will ultimately vest range from 0% to 150% of the outstanding SPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. Each SPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the SPUs for the year ended December 31, 2006, was approximately $1 million. At December 31, 2006 there was approximately $3 million of unrecognized compensation expense related to the SPU’s, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to SPUs:

	Units	Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—	$	—
Granted	84,960	$	42.92
Outstanding at December 31, 2006	84,960	$	42.92	$	50.78
Expected to vest	65,949	$	42.92	$	50.78

F-26

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

The estimate of RPU’s and SPU’s that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.

Phantom Units—Phantom Units generally cliff vest at the end of five years. Each Phantom Unit includes a dividend or distribution equivalent right, which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the Phantom Units, which was calculated using an estimated forfeiture rate of 19%, and is expected to be recognized over a weighted-average period of 4.0 years. The following table presents information related to Phantom Units:

	Units	Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—	$	—
Granted	17,460	$	42.95
Outstanding at December 31, 2006	17,460	$	42.95	$	50.78
Expected to vest	14,143	$	42.95	$	50.78

DCP Partners’ Phantom Units—The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of a common unit of DCP Partners, which generally cliff vest at December 31, 2008. Each DCP Partners’ Phantom Unit includes a distribution equivalent right, which is paid quarterly in arrears. Expense related to the DCP Partners’ Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the DCP Partners’ Phantom Units, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the DCP Partners’ Phantom Units:

	Units	Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—	$	—
Granted	47,750	$	28.60
Outstanding at December 31, 2006	47,750	$	28.60	$	34.55
Expected to vest	34,920	$	28.60	$	34.55

During the year ended December 31, 2006, no awards under the 2006 Plan were forfeited, vested or settled.

F-27

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan—Performance Units—Performance Units generally cliff vest at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance percentage payout is determined by the compensation committee of DCP Partners’ board of directors. Each Performance Unit includes a distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the Performance Units for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the Performance Units, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to the Performance Units:

	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Granted	40,560		$	26.96
Forfeited	(17,470	)	$	26.96
Outstanding at December 31, 2006	23,090		$	26.96	$	34.55
Expected to vest	23,090		$	26.96	$	34.55

The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.

Phantom Units—Of the Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date and 8,000 units vest ratably over three years. Each Phantom Unit includes a distribution equivalent right which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006, estimated unrecognized compensation expense related to the Phantom Units was not significant. The following tables presents information related to the Phantom Units:

	Units		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	—		$	—
Granted	35,900		$	24.05
Forfeited	(11,200	)	$	24.05
Outstanding at December 31, 2006	24,700		$	24.05	$	34.55
Expected to vest	24,700		$	24.05	$	34.55

The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.

All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of the relevant underlying securities at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.

Duke Energy 1998 Plan—Under its 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, our employees incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased accounting for these awards under APB 25 and FIN 44, and began accounting for these awards in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.

F-28

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

Stock Options—Under the 1998 Plan, the exercise price of each option granted could not be less than the market price of Duke Energy’s common stock on the date of grant. Vesting periods range from immediate to four years with a maximum option term of 10 years. Effective July 1, 2005, these options were accounted for in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. As a result, compensation expense subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock options at each reporting date until vesting.

The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.

	Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Life (years)	Aggregate Intrinsic Value (millions)
Outstanding at December 31, 2005	2,592,567		$	29.46	5.2
Exercised	(367,088	)	$	21.15
Forfeited	(124,417	)	$	29.96
Outstanding at December 31, 2006	2,101,062		$	30.89	4.1	$	12
Exercisable at December 31, 2006	1,941,212		$	32.30	4.0	$	9
Expected to vest	155,630		$	13.77	6.2	$	3

The total intrinsic value of options exercised during the year ended December 31, 2006 and 2005, was approximately $3 million and $2 million, respectively. As of December 31, 2006, all compensation expense related to these awards has been recognized.

There were no options granted during the years ended December 31, 2006 or 2005.

Stock-Based Performance Awards—Stock-based performance awards outstanding under the 1998 Plan vest over three years if certain performance targets are achieved. Duke Energy awarded 160,910 shares during the year ended December 31, 2005. There were no stock-based performance awards granted during the year ended December 31, 2006.

The following table summarizes information about stock-based performance awards activity during the year ended December 31, 2006:

	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	342,453		$	23.88
Forfeited	(40,835	)	$	23.85
Outstanding at December 31, 2006	301,618		$	23.90	$	33.21
Expected to vest	289,161		$	23.90	$	33.21

As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted, vested or canceled during the year ended December 31, 2006.

Phantom Stock Awards—Phantom stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 128,850 shares during the year ended December 31, 2005. There were no phantom stock awards granted during the year ended December 31, 2006.

F-29

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

The following table summarizes information about phantom stock awards activity during the year ended December 31, 2006:

	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	241,216		$	24.22
Vested	(54,150	)	$	23.90
Forfeited	(22,378	)	$	24.29
Outstanding at December 31, 2006	164,688		$	24.34	$	33.21
Expected to vest	157,886		$	24.34	$	33.21

The total fair value of the phantom stock awards that vested during the year ended December 31, 2006 and 2005 was approximately $2 million and less than $1 million, respectively. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of 2.7 years. No awards were granted or canceled during the year ended December 31, 2006.

Other Stock Awards—Other stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy granted 3,000 other stock awards during the year ended December 31, 2005. There were no other stock awards granted during the year ended December 31, 2006.

The following table summarizes information about other stock awards activity during the year ended December 31, 2006:

	Shares		Grant Date Weighted- Average Price Per Unit		Measurement Date Weighted- Average Price Per Unit
Outstanding at December 31, 2005	45,400		$	21.73
Vested	(10,600	)	$	21.73
Forfeited	(13,200	)	$	21.73
Outstanding at December 31, 2006	21,600		$	21.73	$	33.21
Expected to vest	20,038		$	21.73	$	33.21

The total fair value of the other stock awards that vested during the years ended December 31, 2006 and 2005 was not significant. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was not significant, and is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted or canceled during the year ended December 31, 2006.

14. Benefits

All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contributed 4% of each eligible employee’s qualified earnings, through December 31, 2006. Effective January 1, 2007, we began contributing a range of 4% to 7% of each eligible employee’s qualified earnings, based on years of service. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings. During 2006 and 2005, we expensed plan contributions of $15 million.

We offer certain eligible executives the opportunity to participate in the DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of our general assets and liabilities, respectively.

F-30

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

15. Income Taxes

We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise, and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes. Taxes associated with these subsidiaries have been reclassified to discontinued operations for year ended December 31, 2005.

In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax.

As a result of the change in Texas franchise law, our tax status in the state of Texas has changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year.

The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. We have computed taxable margin as total revenue less cost of goods sold. Based on information currently available, we recorded a deferred tax liability of $18 million in 2006. The deferred tax liability is recorded as non-current in the consolidated balance sheets as of December 31, 2006, and as a non-cash offset to income tax expense in the consolidated statements of operations and comprehensive income for the year ended December 31, 2006.

Income tax expense consists of the following for the years ended December 31:

	2006		2005
	(millions)
Current:
Federal	$	5	$	9
State		1		2
Deferred:
Federal		—		—
State		17		(2	)
Total income tax expense	$	23	$	9

Temporary differences for our gross deferred tax assets of $4 million primarily relate to basis differences between property, plant and equipment, and investments in unconsolidated affiliates. Temporary differences for our gross deferred tax liabilities of $17 million primarily relate to basis differences between property, plant and equipment.

Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.

16. Commitments and Contingent Liabilities

Litigation—The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Midstream Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

F-31

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

In November 2006, we received a demand associated with the alleged migration of acid gas from a storage formation into a third party producing formation. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.

Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.

General Insurance—In 2005, we carried all of our insurance coverage with an affiliate of Duke Energy. Beginning in 2006, we elected to carry only property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips, however, effective August 2006, we no longer carry insurance coverage with an affiliate of Duke Energy. Our remaining insurance coverage is with an affiliate of ConocoPhillips and a third party insurer. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. Property insurance deductibles are currently $1 million for onshore or non-hurricane related incidents or up to $5 million per occurrence for hurricane related incidents. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Casualty insurance deductibles are currently $1 million per occurrence. The cost of our general insurance coverages increased over the past year reflecting the adverse conditions of the insurance markets.

During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. The resulting losses are expected to be covered by insurance, subject to applicable deductibles for property and business interruption. Insurance recovery receivables related to hurricane Ivan included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are $25 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $3 million and $28 million, respectively, from an insurance provider that is a subsidiary of Duke Energy.

During the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico, however, substantially all of our facilities have resumed pre-hurricane levels of capacity utilization. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages are covered by our insurance, subject to applicable deductibles. The financial impact of recent hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Insurance recovery receivables related to hurricane Katrina included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006 are $21 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $2 million and $5 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. Included in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables related to hurricane Rita of $1 million at December 31, 2006. The balance at December 31, 2005, was not significant. Based on recent negotiations, we have reclassified a portion of these hurricane insurance receivables as non-current at December 31, 2006.

During the years ended December 31, 2006 and 2005, we recorded business interruption insurance recoveries related to these hurricanes of $1 million and $3 million, respectively, in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary

F-32

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at three of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions from January 2001 to date and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. The Compliance Orders seek a civil penalty but did not request a specific amount. We intend to contest these allegations. Management does not believe this will result in a material impact on our consolidated results of operations, cash flows or financial position.

Other Commitments and Contingencies—We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $37 million and $36 million in 2006 and 2005, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006:

Minimum Rental Payments
	(millions)
2007	$	25
2008		19
2009		14
2010		14
2011		12
Thereafter		39
Total gross payments		123
Sublease receipts		(2	)
Total net payments	$	121

17. Guarantees and Indemnifications

In September 2005, we signed a corporate guaranty, which was amended in December 2005 upon our purchase of an additional interest in the related unconsolidated affiliate, pursuant to which we are the guarantor of a maximum of $10 million of construction obligations. The original guaranty was $22 million as of December 31, 2005, and was reduced by construction payments of $12 million during the year ended December 31, 2006. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated results of operations, financial position or cash flows.

We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At both December 31, 2006 and 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.

18. Subsequent Events

During the year ended December 31, 2007, we distributed $1,364 million to Spectra Energy and ConocoPhillips, and DCP Partners distributed $44 million to its unitholders. On January 24, 2008, DCP Partners announced the declaration of a cash distribution of $0.57 per unit, payable on February 14, 2008, to unitholders of record on February 7, 2008.

In September 2007, we issued $450 million principal amount of 6.75% Senior Notes due 2037, or the 6.75% Notes, for proceeds of approximately $444 million (net of related offering costs). The 6.75% Notes mature and become due and payable on September 15,

F-33

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

2037. We will pay interest semiannually on March 15 and September 15 of each year, commencing March 15, 2008. The proceeds of this offering were used to fund the Momentum Energy Group, Inc. or MEG, acquisition.

On August 29, 2007, we acquired the stock of MEG for approximately $635 million plus closing adjustments of approximately $8 million. MEG owns assets in the Fort Worth, Piceance and Powder River producing basins. Concurrent with this transaction, DCP Partners acquired certain subsidiaries of MEG from us for $165 million plus closing adjustments of approximately $10 million, subject to final closing adjustments. These subsidiaries of MEG own assets in the Piceance Basin, including a 70% operated interest in the 31-mile Collbran Valley Gas Gathering joint venture in western Colorado, assets in the Powder River Basin, including the 1,324-mile Douglas gas gathering system, and other facilities in Wyoming. We ultimately funded our portion of this acquisition with the 6.75% Notes, as well as cash on hand. DCP Partners financed this transaction with $120 million of revolver and term loan borrowings under DCP Partners’ Amended Credit Agreement, the issuance of approximately $100 million of common units through a private placement (described in the next sentence) with certain institutional inventors and cash on hand. In August 2007, DCP Partners sold 2,380,952 common limited partner units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate.

In July 2007, we contributed to DCP Partners a 25% limited liability company interest in DCP East Texas Holdings, LLC, our 40% limited liability company interest in Discovery Producer Services LLC, and a derivative instrument, for aggregate consideration of $244 million in cash, including $1 million for net working capital and other adjustments, $27 million in common units and $1 million in general partner equivalent units. We own the remaining 75% limited liability company interest in East Texas Holdings, LLC, while third parties still own the other 60% limited liability interest in Discovery Producer Services LLC. DCP Partners financed the cash portion of this transaction with borrowings under DCP Partners’ existing credit agreement. We will continue to operate these assets and these assets will continue to be included in our financial statements, along with DCP Partners.

In June 2007, DCP Partners entered into a private placement agreement with a group of institutional investors for $130 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $129 million, net of offering costs. DCP Partners used a portion of the net proceeds of this private placement to pay down a portion of the debt associated with the acquisition from Anadarko Petroleum Corporation of assets in southern Oklahoma, and used the remaining portion of the net proceeds to fund future capital expenditures, including the MEG acquisition.

In June 2007, DCP Partners entered into an Amended and Restated Credit Agreement, or DCP Partners’ Amended Credit Agreement, which amended DCP Partners’ Credit Agreement. This new 5-year DCP Partners’ Amended Credit Agreement consists of a $600 million revolving credit facility and a $250 million term loan facility, and matures on June 21, 2012. The amendment also improved pricing and certain other terms and conditions of DCP Partners’ Credit Agreement.

In May 2007, DCP Partners acquired certain gathering and compression assets located in southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181 million.

On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. We do not expect this transaction to have a material effect on our operations.

On January 1, 2007, we changed our name from Duke Energy Field Services, LLC to DCP Midstream, LLC, to coincide with the Spectra spin.

F-34

DCP MIDSTREAM, LLC

(formerly Duke Energy Field Services, LLC)

Notes To Consolidated Financial Statements—(Continued)

Years Ended December 31, 2006 and 2005

	Increases
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts(b)			Deductions(c)			Balance at End of Period
	($ in millions)
December 31, 2006
Allowance for doubtful accounts	$	4	$	—	$	—		$	(1	)	$	3
Environmental		13		3		—			(4	)		12
Litigation		5		6		—			(2	)		9
Other(a)		6		—		—			(2	)		4
	$	28	$	9	$	—		$	(9	)	$	28
December 31, 2005
Allowance for doubtful accounts	$	4	$	1	$	—		$	(1	)	$	4
Environmental		17		5		—			(9	)		13
Litigation		8		1		2			(6	)		5
Other(a)		8		11		(2	)		(11	)		6
	$	37	$	18	$	—		$	(27	)	$	28

(a) Principally consists of other contingency reserves, which are included in other current liabilities.

(b) Consists of other contingency and litigation reserves reclassified between accounts.

(c) Principally consists cash payments, collections, reserve reversals and liabilities settled.

F-35

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	Amended and Restated Combination Agreement dated as of September 20, 2001, among Duke Energy Corporation, 3058368 Nova Scotia Company, 3946509 Canada Inc. and Westcoast Energy Inc. (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended September 30, 2001, File No. 1-4928, as Exhibit 10-7).
2.3	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).

E-1

PART IV

Exhibit Number
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***	Master Transaction Agreement by and among Duke Energy Marketing America, LLC, Duke Energy North America, LLC, Duke Energy Trading and Marketing, L.L.C., Duke Energy Marketing Limited Partnership, Engage Energy Canada, L.P. and Barclay Bank PLC, dated as of November 17, 2005 (filed with the Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2005, File No. 1-4928, as Exhibit 10.8).
10.3**	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).
10.3.1**	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).
10.3.2**	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).
10.3.3**	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).

E-2

PART IV

Exhibit Number
10.4**	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).
10.5**	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).
10.6**	Duke Energy Corporation Executive Savings Plan, as amended and restated (filed with Form 10-K of Duke Energy Corporation, dated October 31, 2007, File No. 1-4928, as Exhibit 10.1).
10.7**	Duke Energy Corporation Executive Cash Balance Plan (filed with Form 10-K of TEPPCO Partners, LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10-8).
10.7.1**	Amendment No. 1 to the Duke Energy Corporation Executive Cash Balance Plan, dated August 26, 1999 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.1).
10.7.2**	Amendment No. 2 to the Duke Energy Corporation Executive Cash Balance Plan, dated March 6, 2000 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.2).
10.7.3**	Amendment No. 3 to the Duke Energy Corporation Executive Cash Balance Plan, dated December 21, 2000 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.3).
10.7.4**	Amendment No. 4 to the Duke Energy Corporation Executive Cash Balance Plan, dated October 27, 2004, effective December 31, 2004 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-7.4).
10.7.5**	Amendment to the Duke Energy Corporation Executive Cash Balance Plan, effective December 1, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.18.5).
10.7.6**	Amendment to the Duke Energy Corporation Executive Cash Balance Plan I & II, effective December 31, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.18.6).
10.8**	Form of Key Employee Severance Agreement and Release between Duke Energy Corporation and certain key executives (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 1999, File No. 1-4928, as Exhibit 10-BB).
10.8.1**	First Amendment to Key Employee Severance Agreement and General Release between Duke Energy Corporation and Richard J. Osborne, dated August 21, 2004 (filed with Form 10-Q of Duke Energy Carolinas, LLC for the quarter ended October 31, 2004, File No. 1-4928, as Exhibit 10-2).
10.9**	Form of Change in Control Agreement between Duke Energy Corporation and certain key executives dated as of July 1, 2005 (filed with Form 8-K of Duke Energy Carolinas, LLC dated August 24, 2005, File No. 1-4928, as Exhibit 10-1).
10.10**	Employment Agreement dated November 2003 between Paul M. Anderson and Duke Energy Corporation (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-18).
10.10.1**	First Amendment to Employment Agreement dated March 9, 2004 between Paul M. Anderson and Duke Energy Corporation (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-18.1).
10.10.2**	Second Amendment to Employment Agreement, dated as of April 4, 2006, by and among Paul M. Anderson, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation) and Duke Energy Corporation (subsequently renamed Duke Energy Carolinas, LLC) (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.5).
10.11**	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).

E-3

PART IV

Exhibit Number
10.12**	Supplemental Compensation Agreement dated June 17, 1997 between Duke Power Company and Dr. Ruth G. Shaw (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2003, File No. 1-4928, as Exhibit 10-19).
10.12.1**	Severance and Retention Agreement between Duke Energy Corporation and Ruth Shaw, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.7).
10.12.2**	Severance and Consulting Agreement between Duke Energy Corporation and Ruth Shaw, dated October 24, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, October 27, 2006, as Exhibit 10.2).
10.13**	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).
10.14**	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).
10.15**	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).
10.16**	Agreement between Duke Energy Corporation and Jimmy W. Mogg relating to certain retirement benefits, consisting of letter agreements dated May 25, 1995, August 4, 2001 and March 29, 2004 (filed with Form 10-K of Duke Energy Carolinas, LLC for the year ended December 31, 2004, File No. 1-4928, as Exhibit 10-23).
10.17	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).
10.18	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).
10.19**	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).
10.19.1**	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).
10.19.2**	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).
10.19.3**	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**	Retention Award Agreement between Duke Energy Corporation and David L. Hauser, dated April 4, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, April 6, 2006, as Exhibit 10.6).
10.21**	Summary of Director Compensation (filed with the Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2006, File No. 1-32853, as Exhibit 10.13).
10.22**	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).
10.23	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).

E-4

PART IV

Exhibit Number
10.24	Agreement with Dynegy Inc. and Rockingham Power, L.L.C. to acquire an approximately 825 megawatt power plant located in Rockingham County, N.C. for approximately $195 million (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, May 25, 2006, as Exhibit 10.1).
10.25	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).
10.26**	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).
10.27**	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).
10.28	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).
10.29	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).
10.30**	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).
10.31	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).
10.32	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).
10.32.1	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).

E-5

PART IV

Exhibit Number
10.32.2	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).
10.32.3	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).
10.32.4	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).
10.33	Employee 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 10.3).
10.33.1	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).
10.34**	Agreement between Duke Energy Corporation and Fred J. Fowler, dated December 19, 2006 (filed with Form 8-K of Duke Energy Corporation, File No. 1-32853, December 22, 2006, as Exhibit 10.1).
10.35**	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).
10.36**	Amendment to the Cinergy Corp. Excess Pension Plan, effective January 1, 2007 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.64).
10.37**	Amendment to the Cinergy Corp. 401(k) Excess Plan, effective December 18, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.65).
10.38**	Amendment to the Cinergy Corp. Excess Profit Sharing Plan, effective December 19, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.66).
10.39**	Amendment to the Cinergy Corp. 401(k) Excess Plan, effective December 19, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.67).
10.40**	Amendment to the Cinergy Corp. Directors’ Deferred Compensation Plan, effective December 19, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2006, File No. 1-32853, as Exhibit 10.68).
10.41**	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).
10.42**	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).
10.43	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).
10.43.1	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).
10.44**	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).
10.45**	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).

E-6

PART IV

Exhibit Number
10.46	$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).
10.47**	Summary of Director Compensation Program (filed in Form 8-K of Duke Energy Corporation, May 15, 2007, File No. 1-32853, as Exhibit 10.1).
10.48	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).
10.49**	Employment Agreement, dated September 24, 2002, by and between Cinergy Corp. and James L. Turner (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.64).
10.49.1**	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).
10.49.2**	Amendment No. 1 to Employment Agreement, dated December 17, 2003, by and between Cinergy Corp. and James L. Turner (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.64.2).
10.49.3**	Amendment No. 2 to Employment Agreement, dated July 19, 2004, by and between Cinergy Corp. and James L. Turner (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.64.3).
10.49.4**	Amendment No. 3 to Employment Agreement, dated May 9, 2005, by and between Cinergy Corp. and James L. Turner (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.64.4).
10.49.5**	Amendment No. 4 to Employment Agreement, dated December 14, 2005, by and between Cinergy Corp. and James L. Turner (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.64.5).
10.50**	Retention Award Agreement by and between Duke Energy Corporation and James 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 10.65).
10.51**	Employment Agreement, dated November 15, 2002, by and between Cinergy Corp. and Marc E. Manly (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.66).
10.51.1**	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).
10.51.2**	Amendment No. 1 to Employment Agreement, dated December 17, 2003, by and between Cinergy Corp. and Marc E. Manly (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.66.2).
10.51.3**	Amendment No. 2 to Employment Agreement, dated May 9, 2005, by and between Cinergy Corp. and Marc E. Manly (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.66.3).

E-7

PART IV

Exhibit Number
10.51.4**	Amendment No. 3 to Employment Agreement, dated December 14, 2005, by and between Cinergy Corp. and Marc E. Manly (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.66.4).
10.52**	Retention Award Agreement by and between Duke Energy Corporation and Marc 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 10.67).
10.53**	Split Dollar Collateral Assignment Insurance Plan Agreement by and between Duke Energy Carolinas, LLC (formerly known as Duke Energy Corporation) and Henry B. Barron Jr., dated October 1, 2997 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.68).
10.54**	Restricted Stock Award Agreement by and between Duke Energy Carolinas, LLC (formerly known as Duke Energy Corporation) and Henry B. Barron Jr., dated February 1, 2006 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.69).
10.55**	Amendment to the Cinergy Corp. Nonqualified Deferred Incentive Compensation Plan, effective December 19, 2007 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.70).
10.56**	Amendment to the Cinergy Corp. 401(k) Excess Plan, effective December 19, 2007 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.71).
10.57**	Amendment to the Cinergy Corp. Excess Profit Sharing Plan, effective December 19, 2007 (filed with Form 10-K of Duke Energy Corporation for the year ended December 31, 2007, File No. 1-32853, as Exhibit 10.72).
10.58	Amended and Restated Engineering, Procurement and Construction Agreement, dated February 20, 208, 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).
10.59**	Agreement, effective March 31, 2008, by and between Henry B. Barron, Jr. and Duke Energy Corporation (filed in Form 10-Q of Duke Energy Corporation for the quarter ended March 31, 2008, File No. 1-32853, as Exhibit 10.2).
10.60**	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).
10.61**	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).
10.62	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).
10.63**	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).
10.64	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).
10.65	Engineering and Construction Agreement, dated as of May 5, 2008, by and between Duke Energy Carolinas, LLC and Shaw North Carolina, Inc. (filed in Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2008, File No. 1-32853, as Exhibit 10.3).
10.66	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).
10.67**	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).

E-8

PART IV

Exhibit Number
10.68**	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).
10.69**	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).
10.70**	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).
10.71**	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).
10.72**	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).
10.73**	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).
10.74**	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).
10.75**	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).
*10.76**	Deferred Compensation Agreement dated December 16, 1992, between PSI Energy, Inc. and James E. Rogers, Jr.
*10.77	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).
*12	Computation of Ratio of Earnings to Fixed Charges.
*21	List of Subsidiaries.
*23.1	Consent of Independent Registered Public Accounting Firm.
*23.2	Consent of Independent Registered Public Accounting Firm.
*24.1	Power of attorney authorizing David L. Hauser 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.
*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.

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-9

EX-10.76

Exhibit 10.76

DEFERRED COMPENSATION AGREEMENT

THIS AGREEMENT, dated December 16, 1992, is between PSI Energy, Inc. (“PSI”) and James E. Rogers, Jr. (“Rogers”).

A.    PSI desires to assure itself of the continued benefit of Rogers’ services until his retirement by providing an incentive for Rogers to continue his employment with PSI.

B.    This Agreement is intended by PSI to provide an incentive to Rogers to continue his employment with PSI until his retirement.

The parties agree as follows:

SECTION 1

DEFERRED INCENTIVE AWARD

On December 11, 1991, but effective January 1, 1992, PSI’s Board of Directors directed that in lieu of awarding Rogers a full cash increase to his annual base pay, Rogers shall be credited with a Fifty Thousand Dollar ($50,000) annual base pay increase in the form of deferred compensation (“Deferred Incentive Award”) for the five (5)-year period beginning January 1, 1992, and ending December 31, 1996 (“First Award Period”). Thus, Rogers will not receive Two Hundred Fifty Thousand Dollars ($250,000) in cash compensation during the First Award Period which he would have received but for this Agreement. If Rogers remains employed by PSI at the completion of the First Award Period, the Fifty Thousand Dollar ($50,000) deferred annual base pay increase shall be further deferred for an additional five (5)-year period beginning January 1, 1997, and ending December 31, 2001 (“Second Award Period”). Thus, potentially Rogers will not receive a total of Five Hundred Thousand Dollars ($500,000) in cash compensation during the First Award Period and the Second Award Period which he would have otherwise received but for this Agreement.

SECTION 2

BENEFITS REGARDING FIRST AWARD PERIOD

a.    Benefits if Employment Terminates for a Reason Other than Death before January 1, 1997. Subject to Subsection 2.c., if Rogers’ employment with PSI terminates,

involuntarily or voluntarily, for any reason other than death prior to the completion of the First Award period, he shall receive a lump sum payment as follows:

Date of Termination	Lump Sum Amount
On or after 1/1/92 and prior to 1/1/93	$	50,000
On or after 1/1/93 and prior to 1/1/94	$	105,000
On or after 1/1/94 and prior to 1/1/95	$	165,000
On or after 1/1/95 and or to 1/1/96	$	230,000
On or after 1/1/96 and prior to 1/1/97	$	300,000

b.    Benefits if Employment Terminates for a Reason Other than Death after December 31, 1996. If Rogers’ employment with PSI terminates, involuntarily or voluntarily, for any reason other than death after completion of the First Award Period, he shall receive annual benefits over a fifteen (15)-year certain period beginning the first January following his employment termination. However, benefit payments shall not commence earlier than January, 2003, nor later than January, 2010. The annual benefit amounts payable for a fifteen (15)-year certain period are as follows:

Commencement Date of Benefits	15-Year Certain Annual Benefit
January, 2003	$	179,000
January, 2004	$	210,000
January, 2005	$	247,000
January, 2006	$	290,000
January, 2007	$	341,000
January, 2008	$	401,000
January, 2009	$	471,000
January, 2010	$	554,000

c.    Benefits Upon Disability before January 1, 1997. “Disability” shall have the same meaning as “total disability” in PSI’s Long Term Disability Plan, as amended from time to time. However, if at the determination of disability PSI does not sponsor the PSI Long Term Disability Plan, “disability” shall mean the complete inability to perform the normal duties of occupation

2

during the first six months after commencement of disability; thereafter, “disability” means the inability to engage in any gainful occupation for which Rogers is reasonably fitted by education, training, or experience.

If Rogers incurs disability prior to the completion of the First Award Period, he shall be entitled to receive the annual benefits provided in Subsection 2.b. in the proportion that the total of his Deferred Incentive Awards received at the occurrence of the disability (which awards are made at the beginning of each calendar year) bears to the total incentive awards over the First Award Period. Payment of benefits shall commence as of the cessation of the disability but no later than January, 2010.

d.    Benefits Payable Upon Rogers’ Death. In lieu of the benefits described in Subsections 2.a., 2.b., and 2.c., death benefits payable to Rogers’ designated beneficiary shall be made as follows:

1.    If Rogers is “insurable” and his death occurs either (A) prior to January 1, 1997, while Rogers is either actively employed by PSI or “disabled” (as defined in Subsection 2. c.) or (B) on or after January 1, 1997, but prior to the commencement of the payment of benefits under Subsection 2.b., his designated beneficiary shall receive an annual benefit payable for a fifteen (15)-year certain period commencing in the month following Rogers’ death as follows:

Age at Death	15-Year Certain Annual Benefit
44-54	$	297,000
55	$	326,000
56	$	359,000
57	$	395,000
58	$	422,000
59	$	452,000
60	$	484,000
61	$	517,000
62	$	554,000

For purposes of this Agreement, the term “insurable” means the life of Rogers is insurable by an insurance company at rates acceptable to PSI in the exercise of its sole and absolute discretion and Rogers is deemed insurable only when so notified in writing by the Chairman of the Compensation and Nominating Committee of PSI’s Board of Directors.

3

2.    If Rogers is not “insurable” when application for a life insurance policy is made in 1992 and his death occurs prior to the completion of the First Award Period,

his designated beneficiary shall receive a lump sum benefit equal to the amount Rogers would have received pursuant to Subsection 2.a. if he had terminated employment prior to completion of the First Award Period.

3.    If Rogers is not “insurable” and his death occurs after completion of the First Award Period, his designated beneficiary shall receive an annual benefit payable for a fifteen (15)-year certain period commencing in the month following Rogers’ death as follows:

Age at Death	15-Year Certain Annual Benefit
49-50	$	80,000
51	$	94,000
52	$	110,000
53	$	130,000
54	$	152,000
55	$	179,000
56	$	210,000
57	$	247,000
58	$	290,000
59	$	341,000
60	$	401,000
61	$	471,000
62	$	554,000

SECTION 3

BENEFITS REGARDING SECOND AWARD PERIOD

a.    Benefits if Employment Terminates for a Reason Other Than Death on or After January 1, 1997, but Before January 1, 2002. Subject to Subsection 3.c., if Rogers’ employment with PSI terminates, involuntarily or voluntarily, for any reason other than death prior to the completion of the Second Award Period, he shall receive a lump sum payment as follows:

Date of Termination	Lump Sum Amount
On or after 1/1/97 and prior to 1/1/98	$	50,000
On or after 1/1/98 and prior to 1/1/99	$	105,000

4

On or after 1/1/99 and prior to 1/1/2000	$	165,000
On or after 1/1/2000 and prior to 1/1/2001	$	230,000
On or after 1/1/2001 and prior to 1/1/2002	$	300,000

b.    Benefits if Employment Terminates for a Reason Other Than Death After December 31. 2001. If Rogers’ employment with PSI terminates, involuntarily or voluntarily, for any reason other than death after completion of the Second Award Period, he will receive, in addition to the annual benefits described in Subsection 2.b., annual benefits over a fifteen (15)-year certain period beginning in January following his employment termination. However, no benefits shall begin earlier than January, 2008, nor later than January, 2010. The annual benefit amounts, payable for a fifteen (15)-year certain period are as follows:

Commencement Date of Benefits	15-Year Certain Annual Benefit
January, 2008	$	179,000
January, 2009	$	210,000
January, 2010	$	247,000

c.    Benefits Upon Disability on or After January 1, 1997, but Before January 1, 2002. “Disability” shall have the same meaning as “total disability” in PSI’s Long Term Disability Plan, as amended from time to time. However, if at the determination of disability PSI does not sponsor the PSI Long Term Disability Plan, “disability” shall mean the complete inability to perform the normal duties of occupation during the first six months after commencement of disability; thereafter, “disability” means the inability to engage in any gainful occupation for which Rogers is reasonably fitted by education, training, or experience.

If Rogers incurs disability prior to the completion of the Second Award Period, he shall be entitled to receive, in addition to the annual benefits described in Subsection 2.b., the annual benefits provided in Subsection 3.b. in the proportion that the total of his Deferred Incentive Awards received at the occurrence of the disability (which awards are made at the beginning of each calendar year) bears to the total incentive awards for the Second Award Period. Payment of benefits shall commence as of the cessation of the disability but no later than January, 2010.

5

d.    Benefits Payable Upon Rogers’ Death. In lieu of the benefits described in Subsections 3.a., 3.b., and 3.c., death benefits, in addition to the annual benefits described in Subsection 2.d., payable to Rogers’ designated beneficiary shall be made as follows:

1.    If Rogers is “insurable” and his death occurs either (A) prior to January 1, 2002, while Rogers is either actively employed by PSI or “disabled” (as defined in Subsection 2.c.) or (B) on or after January 1, 2002, but prior to the commencement of the payment of benefits, his designated beneficiary shall receive an annual benefit payable for a fifteen (15)-year certain period commencing in the month following Rogers’ death as follows:

Age at Death	15-Year Certain Annual Benefit
49-59	$	202,000
60	$	216,000
61	$	231,000
62	$	247,000

2.    If Rogers is not “insurable” and his death occurs prior to the completion of the Second Award Period, his designated beneficiary shall receive a lump sum benefit equal to the amount Rogers would have received pursuant to Subsection 3.a. if he had terminated employment prior to completion of the Second Award Period.

3.    If Rogers is not “insurable” and his death occurs after completion of the Second Award Period, his designated beneficiary shall receive an annual benefit payable for a fifteen (15) -year certain period beginning in the month following Rogers’ death as follows:

Age at Death	15-Year Certain Annual Benefit
54-55	$	80,000
56	$	94,000
57	$	110,000
58	$	130,000
59	$	152,000
60	$	179,000
61	$	210,000
62	$	247,000

SECTION 4

DESIGNATION OF BENEFICIARY

Rogers may designate, revoke, and redesignate beneficiaries. This action shall be taken in writing and delivered to PSI’s Manager, Benefits & Payroll, and shall be effective upon receipt

6

by PSI’s Manager, Benefits & Payroll. Upon Rogers’ death, any benefit payable under this Agreement shall be paid to the person or persons determined under this Section. Amounts payable shall be paid to the highest priority person or persons surviving at the time distribution is actually paid or commences. Distribution is as follows:

1. First, to the person or persons properly designated by Rogers under this Section.

2. Second, to Rogers’ surviving spouse.

3. Third, to Rogers’ surviving children.

4. Fourth, to Rogers’ surviving parents.

5. Fifth, to Rogers’ brothers and sisters.

6. Sixth, to Rogers’ estate.

The determination of PSI’s Manager, Benefits & Payroll as to which persons, if any, qualify within these classes shall be final and conclusive upon all persons.

SECTION 5

BENEFIT CLAIMS PROCEDURES

If for any reason a claim for benefits under this Agreement is denied by PSI, the senior level Vice President of PSI having responsibility for PSI’s human resources functions (“Claims Manager”) shall deliver to the claimant a written explanation setting forth the specific reasons for the denial, pertinent references to the Agreement’s provisions on which the denial is based, any other data as may be pertinent, and information on the procedures to be followed by the claimant in obtaining a review of his claim, all written in a manner calculated to be understood by the claimant. For this purpose:

a.    The claimant’s claim shall be deemed filed when presented orally or in writing to the Claims Manager.

b.    The Claims Manager’s explanation shall be in writing delivered to the claimant within 90 days of the date the claim is filed.

The claimant shall have 60 days following his receipt of the denial of the claim to file with the Claims Manager a written request for review of the denial. For the review, the claimant or his representative may submit pertinent documents and written issues and comments.

7

The Claims Manager shall decide the issue on review and furnish the claimant with a copy within 60 days of receipt of the claimant’s request for review of his claim. The decision on review shall be in writing and shall include specific reasons for the decision written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent provisions of the Agreement on which the decision is based. If a copy of the decision is not furnished to the claimant within the 60-day period, the claim shall be denied on review.

SECTION 6

ARBITRATION OF DENIED CLAIMS

Any controversy or claim arising out of or relating to a final decision, upon review pursuant to the procedures set forth in Section 5, that denies a claim for benefits under this Agreement shall be settled by arbitration under three arbitrators in accordance with the Commercial Arbitration Rules of the American Arbitration Association, and judgment upon the award rendered by the arbitrators may be entered in any court with competent jurisdiction. Any arbitration under this Agreement shall be subject to the statutes of limitations that would apply if the claim on which the arbitration is based were brought as a suit in a United States district court under the Employee Retirement Income Security Act of 1974, as amended. The site of any arbitration under this Agreement shall be Indianapolis, Indiana.

SECTION 7

PAYMENT OF BENEFITS

The benefits under this Agreement shall be paid solely from PSI’s general assets. Rogers and his beneficiary or beneficiaries, shall not have any interest in any specific assets of PSI under the terms of this Agreement. This Agreement shall not be considered to create an escrow account, trust fund, or other funding arrangement of any kind or a fiduciary relationship between Rogers and PSI.

SECTION 8

FACILITY OF PAYMENT

If any benefit under this Agreement is payable to a minor, or other person under legal disability, PSI shall have the payment made to the legal guardian of that person or to the person or organization as a court of competent jurisdiction may direct. Any payment under this Section shall be a complete discharge of any liability under this Agreement to that person.

8

SECTION 9

EFFECT ON OTHER BENEFITS

Any deferred compensation payable under this Agreement shall not be deemed salary or other compensation to Rogers for the purposes of computing benefits to which he may be entitled under any qualified pension plan of PSI for the benefit of its employees.

SECTION 10

THIS AGREEMENT IS NOT A CONTRACT FOR EMPLOYMENT

Nothing contained in this Agreement shall be construed as conferring upon Rogers the right to continue in PSI’s employ as an executive or in any other capacity. This Agreement shall not constitute an employment contract for a definite term or in any way act as a restriction on PSI’s right to discharge Rogers at any time or Rogers’ right to terminate employment at any time.

SECTION 11

NONALIENATION OF BENEFITS

Neither Rogers nor his beneficiary shall have any right to anticipate, pledge, alienate, or assign any rights under this Agreement, and any effort to do so shall be null and void. The benefits payable under this Agreement shall be exempt from the claims of Rogers’ or his beneficiary’s creditors or other claimants and from all orders, decrees, levies, and executions and any other legal process to the fullest extent that may be permitted by law.

SECTION 12

MERGER, CONSOLIDATION, OR CHANGE IN CONTROL

If a merger or consolidation by PSI with another corporation, or the acquisition of substantially all of the assets or outstanding stock of PSI by another corporation other than PSI Resources, Inc. (“Resources”) or any of its subsidiaries or affiliates, or a Change in Control of Resources occurs, then the obligations and responsibilities of PSI under this Agreement shall be assumed by any successor, acquiring corporation, or controlling entity, and all of the rights, privileges, and benefits of Rogers under this Agreement shall continue.

9

For purposes of this Agreement, a “Change in Control” shall occur if (1) any “person” or “group” (within the meaning of Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “1934 Act”)) becomes the “beneficial owner” (as defined in Rule 13d-3 of the 1934 Act) of more than 50 percent of the then outstanding voting stock of Resources, otherwise than through a transaction arranged by, or consummated with the prior approval of, Resources’ Board of Directors; (2) the shareholders of Resources approve a definitive agreement to merge or consolidate Resources with or into another corporation in a transaction in which neither Resources nor any of its subsidiaries or affiliates will be the surviving corporation, or to sell or otherwise dispose of all or substantially all of Resources’ assets to any person or group other than Resources or any of its subsidiaries or affiliates, other than a merger or a sale which will result in the voting securities of Resources outstanding prior to the merger or sale continuing to represent at least 50 percent of the combined voting power of the voting securities of the corporation surviving the merger or purchasing the assets; or (3) during any period of two consecutive years, individuals who at the beginning of that period constitute Resources’ Board of Directors (and any new director whose election by Resources’ Board of Directors or whose nomination for election by Resources’ shareholders was approved by a vote of at least two-thirds of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved) cease for any reason, with the exception of the exercise of the voting rights conferred upon the record holders of Resources’ cumulative preferred stock pursuant to the provision of Article (V)(B)(iii) of Resources’ Articles of Incorporation, to constitute a majority of Resources’ Board of Directors.

SECTION 13

ENTIRE AGREEMENT; AMENDMENT

This Agreement and any written amendments to this Agreement contain all the terms and provisions of the parties’ rights and obligations relating to the subject of this Agreement and shall constitute the entire agreement of the parties, any other alleged terms or provisions being of no effect. This Agreement may not be amended or modified except by a written document signed by all parties to this Agreement.

10

SECTION 14

INTERPRETATION OF AGREEMENT

No member of PSI’s Board of Directors shall be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Agreement unless attributable to his own willful misconduct or lack of good faith.

SECTION 15

GOVERNING LAW

This Agreement shall be construed and administered by the laws of the State of Indiana to the extent those laws are not preempted by the laws of the United States of America.

SECTION 16

BINDING AGREEMENT

This Agreement shall bind all parties, and their successors, assigns, personal representatives, heirs, and any beneficiary. In addition to any obligations imposed by law upon any successor to PSI, PSI will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of PSI to expressly assume and agree to perform this Agreement in the same manner and to the same extent that PSI would be required to perform it if no successor had taken place. Failure of PSI to obtain such assumption and agreement prior to the effectiveness of any such succession shall be a breach of this Agreement and shall entitle Rogers to all amounts that would have been paid pursuant to the terms of Section 2b. of this Agreement had Rogers remained in employment until after the completion of the First Award Period commencing at such time as provided for pursuant to the terms of such section.

11

EXECUTED by PSI and Rogers effective as of December 16, 1992.

PSI ENERGY, INC.
By:
	Van P. Smith, Chairman
	Compensation and Nominating
	Committee of the PSI Energy, Inc.
	Board of Directors
	JAMES E. ROGERS, JR.
By:
	James E. Rogers, Jr.

12

EX-10.77

Exhibit 10.77

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

ENGINEERING, PROCUREMENT

AND

CONSTRUCTION MANAGEMENT AGREEMENT

by and between

DUKE ENERGY INDIANA, INC., as Owner

and

BECHTEL POWER CORPORATION, as Contractor

for the

CONSTRUCTION OF AN INTEGRATED GASIFICATION

COMBINED CYCLE COAL-FIRED ELECTRICAL

GENERATION FACILITY IN EDWARDSPORT, INDIANA

Dated December 15, 2008

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION. Contains confidential information proprietary to Duke Energy Indiana, Inc. and/or Bechtel Power Corporation that may only be used, reproduced, or disclosed outside of such companies pursuant to the terms of that certain confidentiality letter agreement, dated as of June 9, 2008, by and between Duke Energy Indiana, Inc. and Bechtel Power Corporation, as amended, restated or supplemented from time to time.

Table of Contents

			Page
1.	DEFINITIONS		2
2.	GENERAL PROVISIONS		13
	2.1	Intent of Contract Documents	13
	2.2	Independent Contractor	14
	2.3	Subcontracting	14
	2.4	Interpretation	14
	2.5	Inclusion; Conflicts	15
	2.6	Days	15
3.	CONTRACTOR RESPONSIBILITIES		15
	3.1	Performance of Services	15
	3.2	Appointment as Agent	16
	3.3	Scope of Procurement Services	16
	3.4	Scope of Construction Management Services	18
	3.5	Engineering Services	18
	3.6	Development of Project Plans	19
	3.7	Intentionally Omitted	19
	3.8	Facility Manuals; Training	19
	3.9	Periodic Reports and Meetings	19
	3.10	Compliance with Laws	20
	3.11	Owner Office Space	20
	3.12	Emergencies	20
	3.13	Signage	20
	3.14	Acknowledgement of Scope of Services	21
	3.15	Use of Existing Owner Property	21
4.	CONTRACTOR PERSONNEL		21
	4.1	Contractor’s Personnel	21
	4.2	Staffing Plan	22
	4.3	Supervision and Discipline	22
	4.4	Contractor’s Key Personnel	22
	4.5	Drug and Alcohol Testing	23
	4.6	Training of Employees	23
	4.7	Substitution	23
	4.8	Employer Responsibilities	23
5.	BORROWED EMPLOYEES		24
	5.1	Assignment of Borrowed Employees	24
	5.2	Qualifications	24
	5.3	Assigned Job Duties	25
	5.4	Responsibility for Work	25
	5.5	Employer Responsibilities	25
	5.6	Cooperation	26
	5.7	No Third Party Rights	27

i

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

6.	PROJECT MANAGEMENT		27
	6.1	Owner’s Representative	27
	6.2	Project Management; Communication and Management Protocol	27
	6.3	Steering Committee	27
	6.4	GE Change Review Board	27
	6.5	Access; Contractor’s Office Space	27
	6.6	Estimate	28
7.	PROJECT SCHEDULE		28
	7.1	Schedule Compliance; Updates	28
	7.2	***	28
8.	COMPENSATION AND PAYMENT		28
	8.1	Contract Price	28
	8.2	***	28
	8.3	***	28
	8.4	Invoicing and Payments	29
	8.5	***	29
	8.6	Final Payment	29
	8.7	Certification by Contractor	30
	8.8	No Acceptance by Payment	30
9.	CHANGE ORDERS		30
	9.1	Change Requests	30
	9.2	Change Proposals	30
	9.3	Change Orders	31
	9.4	Contractor Proposed Changes	31
	9.5	***	32
10.	FORCE MAJEURE		32
	10.1	Event of Force Majeure	32
	10.2	Notice	32
	10.3	Suspension; Termination Due to Force Majeure	32
11.	MECHANICAL COMPLETION; SUBSTANTIAL COMPLETION; FINAL COMPLETION		32
	11.1	Mechanical Completion	32
	11.2	Substantial Completion	33
	11.3	Final Completion	34
12.	WARRANTY		34
	12.1	Warranty	34
	12.2	Defects	35
	12.3	Extension of Warranty Periods	35
	12.4	Intellectual Property Warranties	35
	12.5	Responsibility for Warranty Services	36
	12.6	Exclusive Warranties	36
13.	INDEMNIFICATION		36
	13.1	Contractor’s Indemnity	36

ii

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

	13.2	Owner’s Indemnity	37
	13.3	Intellectual Property Indemnity	38
	13.4	Indemnity Procedures for Third Party Claims	38
	13.5	Insurance	39
14.	INSURANCE		39
	14.1	***	39
	14.2	***	40
	14.3	***	40
	14.4	***	40
	14.5	Contractor Insurance	41
	14.6	General Requirements	43
	14.7	Contractor Responsibility	44
15.	PROJECT CREDIT SUPPORT		44
	15.1	***	44
	15.2	Cooperation with Owner Financing	44
16.	LIMITATION OF LIABILITY		45
	16.1	Liability Cap	45
	16.2	No Consequential Damages	45
17.	LIENS		45
	17.1	Liens	45
	17.2	Discharge or Bond	45
18.	INTELLECTUAL PROPERTY		46
	18.1	Delivery of Documentation	46
	18.2	Grant of Intellectual Property License	47
	18.3	Grant of Sulfur License	47
	18.4	Limitations	48
	18.5	Other Licenses	48
	18.6	Additional Warranties, Representations and Covenants	48
19.	DEFAULT; TERMINATION AND SUSPENSION		48
	19.1	Contractor Events of Default	48
	19.2	Owner Remedies	49
	19.3	Owner Event of Default	50
	19.4	Contractor Remedies	50
	19.5	Termination Rights	50
	19.6	Termination for Force Majeure	51
	19.7	Suspension	51
20.	Intentionally Omitted.		53
21.	RECORDS AND AUDIT; COOPERATION		53
	21.1	Intentionally Omitted	53
	21.2	Accounting Records	53
	21.3	Audit Rights	53
	21.4	Cooperation	54
	21.5	Sales Tax Records	54

iii

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

22.	TAXES		55
	22.1	General	55
	22.2	Sales and Use Taxes	55
	22.3	Tax Indemnification	55
	22.4	Cooperation and Assistance	55
	22.5	Tax Protests and Appeals	55
	22.6	Survival	56
23.	DISPUTE RESOLUTION		56
	23.1	Disputes	56
	23.2	Meeting Regarding Dispute	56
	23.3	Initiation of Binding Arbitration and Selection of Arbitrators	56
	23.4	Arbitration Procedures	57
	23.5	Consolidation	57
	23.6	Enforcement	57
	23.7	Fees and Costs	58
	23.8	Interim Relief	58
	23.9	Award	58
	23.10	Confidentiality	58
24.	MISCELLANEOUS PROVISIONS		58
	24.1	Remedies	58
	24.2	Governing Laws	58
	24.3	Entire Agreement	58
	24.4	Successors and Assigns	58
	24.5	No Third Party Beneficiaries	59
	24.6	No Waiver	59
	24.7	Survival	59
	24.8	Severability	59
	24.9	Notices	59
	24.10	Vienna Convention	60
	24.11	Counterparts	60
	24.12	Confidentiality	61
	24.13	Business Practices	61
	24.14	Covenant of Good Faith and Fair Dealing	61

iv

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

EXHIBITS

Exhibit A	Scope Book
Exhibit B	Communication and Management Protocol
Exhibit C	Material Assignment Schedule
Exhibit D	Site Description
Exhibit E	List of Technical Data
Exhibit F	Staffing Plan and List of Contractor’s Key Management and Construction Personnel
Exhibit G	Baseline Contractor Schedule
Exhibit H	***
Exhibit I	***
Exhibit J	***
Exhibit K	***
Exhibit L	Confidentiality Agreement

v

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

ENGINEERING, PROCUREMENT AND

CONSTRUCTION MANAGEMENT AGREEMENT

This ENGINEERING, PROCUREMENT AND CONSTRUCTION MANAGEMENT AGREEMENT (the “Agreement”) is entered into as of the 15th day of December, 2008 (the “Effective Date”), by and between DUKE ENERGY INDIANA, INC., an Indiana corporation having a place of business in Plainfield, Indiana (“Owner”), and BECHTEL POWER CORPORATION, a Nevada corporation with a place of business in Frederick, Maryland (“Contractor”). Owner and Contractor may be referred to individually as a “Party” and collectively as the “Parties”.

RECITALS

WHEREAS, Owner has announced its intent to procure, construct, install and commission a new, nominally rated 630 MW integrated gasification combined cycle coal-fired electrical generation facility (the “Facility”) to be located at the Edwardsport Site (as further described in Exhibit D attached hereto, the “Site”) in Knox County, Indiana (the “Project”);

WHEREAS, Contractor is engaged in the business of designing, engineering, constructing and commissioning power generating facilities;

WHEREAS, the Parties, together with the General Electric Company, acting through its GE Energy business (“GE”), have previously entered into (a) that certain Technical Services Agreement, dated as of February 13, 2006, and (b) that certain Technical Services Agreement, dated as of May 7, 2007 (collectively, as amended, the “Initial TSAs”), pursuant to which Contractor and GE provided Owner (i) a Front-End Engineering and Design Study (a “FEED Study”), which included a feasibility study for the construction of the Facility as well as a Facility design and a basis for determining the price for Contractor and GE to provide the engineering, design, procurement, construction and commissioning of the relevant portions of the Facility, and (ii) certain additional engineering services in support of the Project;

WHEREAS, following review of the FEED Study and the other work products delivered to Owner by Contractor and GE pursuant to the Initial TSAs, the Parties have mutually agreed to modify the scope of services to be provided by Contractor and GE with respect to the Facility and the price structure related thereto;

WHEREAS, as a result of such modification, Owner and GE have entered into an agreement pursuant to which GE will provide certain equipment and engineering services related to the Project;

WHEREAS, as an additional result of such modification, Owner and Contractor have entered into a non-binding Term Sheet, dated as of April 25, 2008 (the “Term Sheet”), which provides the basis for negotiations between Contractor and Owner with respect to an agreement whereby Contractor would perform certain engineering, procurement and construction management services in connection with the Project;

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

WHEREAS, the Parties have entered into a Technical Services Agreement, dated as of June 9, 2008 (the “Recent TSA”), pursuant to which Contractor has commenced, on a limited notice to proceed basis, certain of the services described in the Term Sheet on the terms and conditions set forth in the Recent TSA; and

WHEREAS, the Parties now desire that Owner engage Contractor to perform engineering, procurement and construction management services in connection with the Project as 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:

*** shall mean ***.

*** shall mean ***.

“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.

“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, Change Orders).

“Air Permit” shall mean, collectively, the documents issued by the Indiana Department of Environmental Management, Office of Air Quality, related to and permitting the Significant Source Modification to Part 70 of the existing Operating Permit No. T083-7243-00003 issued to Owner on January 25, 2008.

“Assigned Job Duties” shall have the meaning set forth in Section 5.1.

“B&V” shall have the meaning set forth in Section 21.4(b).

“Baseline Contractor Schedule” shall mean the critical schedule of key dates and milestones for Contractor’s Scope of Services, including the Milestones, as of the Effective Date, as prepared by Owner and Contractor and attached hereto as Exhibit G, as amended from time to time pursuant to Article 9.

“Borrowed Employees” shall have the meaning set forth in Section 5.1.

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

2

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“***” shall have the meaning set forth in Section 8.2.

*** shall mean ***.

“Certificate of Final Completion” shall have the meaning set forth in Section 11.3(e).

“Certificate of Mechanical Completion” shall have the meaning set forth in Section 11.1(e).

“Change” shall have the meaning set forth in Section 9.1.

“Change in Law” shall mean a change to a Law, or a change in the binding interpretation or application of a Law by the cognizant executive or judicial authorities having jurisdiction thereof, after the Effective Date that results in an increase in costs for Contractor to perform the Services, as affected to comply with such change, which increase in costs Contractor would not have incurred but for this Agreement; provided, however, that a “Change in Law” shall not include (a) 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 or (b) any change to any Law, or a change in the binding interpretation or application of a Law by the cognizant executive or judicial authorities having jurisdiction thereof, that governs the manner in which Contractor performs its obligations under this Agreement.

“Change Order” shall have the meaning set forth in Section 9.3.

“CM ISBL Work” shall mean that portion of the work, including re-work, in connection with the Project that is “inside the battery limit,” namely the gasification island, power block, flare system and cooling tower, and above the ground and above the finished foundations, including all such work to be performed or provided under the Owner Contracts, as such work is further described in Part I of the Scope Book.

“Communication and Management Protocol” shall mean the Communication and Management Protocol to be followed by Owner and Contractor attached hereto as Exhibit B.

“Competitors of Contractor” shall mean each of *** and their respective Affiliates (other than any such Affiliate that, before becoming such an Affiliate, was a Permitted User).

“Confidentiality Agreement” shall mean that certain confidentiality letter agreement, dated as of June 9, 2008, by and between Owner and Contractor attached hereto as Exhibit L.

“Construction Management Services” shall have the meaning set forth in Section 3.4(a).

“Construction Phase” shall have the meaning set forth in Section 18.2.

3

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“Contract Price” shall mean the sum of (a) the *** and (b) the ***, as such amounts may be adjusted by Change Orders in the manner set forth herein.

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

“Contractor Default” shall have the meaning set forth in Section 19.1.

“Contractor Indemnitees” shall have the meaning set forth in Section 13.2.

“Contractor EP Schedule” shall mean the critical schedule of key dates and milestones relating to the Engineering Services and the Procurement Services to be performed by Contractor hereunder (including the Milestones related thereto) as prepared by Contractor, and as modified or updated from time to time by Contractor in accordance with Section 6.2.2 of Part I of the Scope Book and Section 7.1 herein.

“Contractor’s Houston Office” shall mean the office of Contractor located at 3000 Post Oak Road, Houston, Texas 77056.

“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.

“Contractor’s Steering Committee Members” shall mean the two (2) executives of Contractor designated by Contractor to represent Contractor on the Steering Committee.

“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.

“CPCN” shall mean the Certificate of Public Convenience and Necessity issued to Owner by the IURC authorizing Owner to begin construction of the Facility.

“CPR Rules” shall have the meaning set forth in Section 23.2.

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

“Defects” shall have the meaning set forth in Section 12.2.

“Design Documentation” shall have the meaning set forth in Section 3.5, and in each case excluding any Technical Data.

“Dispute” shall have the meaning set forth in Section 23.1.

4

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“Dispute Resolution Meeting” shall have the meaning set forth in Section 23.2.

“Documentation” shall mean collectively (a) all drawings, specifications, reports, studies, plans, manuals, schedules, analyses, recommendations, estimates and other documents, and the data therein, in printed or electronic format, that are prepared in the performance of the Services and delivered, or required hereunder to be delivered, to Owner, including Design Documentation, and (b) all “Work Product” as defined in the Recent TSA.

“Effective Date” shall mean the date set forth in the first paragraph of this Agreement.

“Engineering Services” shall have the meaning set forth in Section 3.5.

“Environmental, Safety and Health Plan” shall mean that certain Site Environmental, Safety and Health Plan, which, among other things, addresses unsafe and undesirable behavior for 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 (including work safety and fitness for duty), for the Project, Rev. 5, as amended, restated or supplemented from time to time.

“Estimate” shall mean ***.

“***” shall have the meaning set forth in Section 8.3(a).

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

“FEED Study” shall have the meaning set forth in the Recitals.

***

“Final Completion” shall have the meaning set forth in Section 11.3.

“Final Completion Date” shall mean the date on which Final Completion actually occurs, as determined in the manner set forth in Section 11.3(e).

“Final Payment Invoice” shall have the meaning set forth in Section 8.6.

“Financial Institutions” shall mean any party entering into a loan agreement, guarantee, note, indenture or security agreement with Owner or its Affiliates in relation to the Facility, including arrangements relating to interest rate or currency hedging and arrangements relating to the construction or permanent financing or refinancing of the Facility.

***

“Force Majeure” shall mean, with respect to a Party, (i) unanticipated causes beyond its reasonable control (actions of Affiliates and subcontractors of a Party will be deemed to be under the control of that Party); or (ii) acts of God (including fires, earthquakes, floods, hurricanes, tornadoes, earthquakes, lightning, pandemic, epidemics and other natural

5

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

calamities), severe weather conditions, strikes or other labor disturbances except those involving only employees of Contractor (unless they are a part of a national or international strike or other national or international labor disturbance), war (declared or undeclared), or riots, in each case, which actually delays or prevents a Party’s performance hereunder. For the avoidance of doubt, local strikes and other local labor disturbances involving employees of Contractor that are not a part of a regional, national or international strike or other national or international labor disturbance shall not be deemed to be Force Majeure. Force Majeure shall not include inability to pay.

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

“GE Change Review Board” shall mean GE’s “Project Manager” under the GE Equipment Contract and Owner’s Project General Manager.

“GE Equipment” shall mean the power generation, gasification island, power island and related equipment to be provided pursuant to the GE Equipment Contract.

“GE Equipment Contract” shall mean the Contract for the Sale of Power Generation, Gasification Island and Miscellaneous Power Island Equipment and Related Services, dated as of December 20, 2007, by and between Owner and GE.

“Government Approvals” means 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.

“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.

“Hazardous Materials” shall mean substances defined as “hazardous substances” pursuant to Section 101(14) of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (42 U.S.C. Section 9601(14)); those substances defined, identified or listed as “hazardous waste” pursuant to Section 1004(5) or Section 3001 of the Resource, Conservation and Recovery Act (42 U.S.C. Section 6901 or 6921); 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, as amended (33 U.S.C. Section 3121(b)(2)(A) or Section 1317(a)(1)); 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, as amended (15 U.S.C. Sections 2605 or Section 2606); those substances defined as “contaminants” pursuant to Section 1401 of the Safe Drinking Water Act, as amended (42 U.S.C. Sections 300f), 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

6

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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. Section 136(u)); those substances defined as a “source”, “special nuclear” or “by-product” material pursuant to Section 11 of the Atomic Energy Act of 1954, as amended (42 U.S.C. Section 2014); those substances defined as “residual radioactive material” in Section 101 of the Uranium Mill Tailings Radiation Control Act of 1978, as amended (42 U.S.C. Sections 7901); those substances defined as “toxic materials” or “harmful physical agents” pursuant to Section 6 of the Occupational Safety and Health Act, as amended (29 U.S.C. Section 651); those substances defined as “hazardous air pollutants” pursuant to Section 112(a)(6), or “regulated substance” pursuant to Section 112(r)(2)(B) of the Clean Air Act, as amended (42 U.S.C. Section 7412(a)(6) or Section 7412(r)(2)(B)); those substances listed 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. Section 11002(a)(2)); and those other hazardous substances, hazardous wastes, toxic pollutants, hazardous materials, chemical substances or mixtures, imminently hazardous chemical substances or mixtures, contaminants, pesticides, source materials, by-product materials, residual radioactive materials, toxic materials, harmful physical agents, air pollutants, regulated substances, or extremely hazardous substances defined, listed or identified in any regulations promulgated pursuant to any environmental Law, and all other contaminants, toxins, pollutants, hazardous substances, substances, materials and contaminants, toxic and hazardous materials, the use, disposition, possession or control of which is regulated by one or more Laws.

“HR Issues” shall have the meaning set forth in Section 5.1.

“HR Policies” shall have the meaning set forth in Section 5.1.

“Indemnified Party” shall mean Owner Indemnitees or Contractor Indemnitees, as applicable.

“Initial TSAs” shall have the meaning set forth in the Recitals.

“IURC” shall have the meaning set forth in Section 21.4.

“Laws” shall mean, at any date of determination, all statutes, laws, codes, ordinances, orders, judgments, decrees, injunctions, licenses, rules, permits, approvals, agreements, and regulations of any Government Authority, 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 of Contractor (provided that neither the Managed Vendors nor GE shall be construed to be “under the control” of Contractor) or any Subcontractor against the Facility, the Site, the Owner Equipment, the GE Equipment or any other structure or equipment at the Site.

“License Continuation Fee” shall have the meaning set forth in Section 19.5(c)(ii).

7

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“Managed Vendors” shall mean the suppliers of Owner Equipment or Owner Services pursuant to the Owner Contracts.

“Material Assignment Schedule” shall mean the Material Assignment Schedule attached hereto as Exhibit C, as amended or supplemented from time to time in accordance with Section 3.3(a).

“Mechanical Completion” shall have the meaning set forth in Section 11.1.

“Mechanical Completion Date” shall mean the date on which Mechanical Completion actually occurs, as determined in the manner set forth in Section 11.1(e).

“Milestone” shall mean an activity or series of activities in the execution of the Services or the CM ISBL Work designated as a “Milestone” on the Baseline Contractor Schedule or the Contractor EP Schedule.

“Mine Remediation Reports” shall mean the “Mine Subsidence Evaluation, Edwardsport Power Plant, GAI Project Number: C040605” dated April 2005, and “Final Report, Edwardsport Mine Stabilization, Duke Energy, Edwardsport Generating Station, GAI Project Number: C060638.02” dated April 2008.

“*** Payment Invoice” shall have the meaning set forth in Section 8.3(a).

“Monthly Progress Report” shall mean the written report Contractor delivers to Owner each month describing the progress in the Services and the CM ISBL Work achieved during the prior month, as provided in Section 3.9(a).

“Non-Directed Change” shall have the meaning set forth in Section 9.1.

“Notice of Final Completion” shall have the meaning set forth in Section 11.3(d).

“Notice of Mechanical Completion” shall have the meaning set forth in Section 11.1(c).

“NPDES Permit” shall mean the documents issued by the Indiana Department of Environmental Management, Office of Water Quality, related to the modification of the existing Edwardsport Generating Station NPDES permit number IN0002780 for the purpose of characterizing and permitting discharge of the integrated gasification combined cycle process and stormwaters via the existing outfall, which documents shall be issued following Owner’s application for such modification (it being understood that Owner shall submit such application after the Effective Date at a time reasonably determined by Owner, in its sole discretion, based upon the critical path activities set forth in the then-current Project Schedule).

“***” shall have the meaning set forth in Section 14.4(a).

“*** Administrator” shall have the meaning set forth in Section 14.6(b).

8

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“*** Site” shall have the meaning set forth in Section 14.4(c).

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

“Owner Contracts” shall mean the Owner Equipment Contracts and the Owner Service Contracts.

“Owner Default” shall have the meaning set forth in Section 19.3.

“Owner Equipment” shall mean the equipment that Owner shall purchase as contemplated by the Material Assignment Schedule and with respect to which Contractor shall provide Procurement Services as generally described in Part I of the Scope Book and in the Material Assignment Schedule.

“Owner Equipment Contracts” shall mean the contracts, purchase orders, limited notices to proceed or other agreements between Owner and the suppliers of Owner Equipment.

“Owner Indemnitees” shall have the meaning set forth in Section 13.1.

“Owner Items” shall mean the Owner Equipment and other materials, supplies, parts and equipment used or to be used by any Managed Vendor in connection with the CM ISBL Work.

“Owner Service Contracts” shall mean the contracts, purchase orders, limited notices to proceed or other agreements between Owner and the suppliers of Owner Services.

“Owner Services” shall mean the services that Owner shall procure and with respect to which Contractor shall provide Construction Management Services as described in Part I of the Scope Book and as indicated in the Material Assignment Schedule.

“Owner Suppliers” shall mean the vendors, suppliers, construction contractors and others providing Procurement Items to Owner in respect of the Facility.

“Owner’s Plainfield Office” shall mean the office of Owner located at 1000 East Main Street, Plainfield, Indiana 46168.

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

“Party” shall have the meaning set forth in the first paragraph.

“Permitted User” shall mean any independent contractor engaged by Owner or any of its Affiliates that (a) is under a confidentiality obligation to Owner or such Affiliate and (b) agrees to use the Documentation only for the purposes for which such independent contractor

9

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

was engaged by Owner or such Affiliate (which purposes may not be broader than the Permitted Purposes).

“Permitted Purposes” shall have the meaning set forth in Section 18.2.

“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.

“Procurement Items” shall have the meaning set forth in Section 3.3(a).

“Procurement Services” shall have the meaning set forth in Section 3.3(a).

“Progress Meetings” shall have the meaning set forth in Section 3.9(b).

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

“Project Job Rules and Regulations” shall mean those certain Project Job Rules and Regulations Rev. dated July 22, 2008, as amended, restated or supplemented from time to time.

“Project Schedule” shall mean the critical schedule of key dates and milestones for the Project as prepared by Owner and as modified or updated from time to time by Owner.

“Prudent Industry Practice” shall mean those practices, methods, processes and standards of safety and performance, as the same may change from time to time, as are commonly used, or are generally accepted, in the engineering, procurement or construction management, in the case of Contractor, or construction, operation and maintenance, in the case of Owner, of electric power generation facilities with a complexity at a level similar to the Facility (irrespective of whether any such similar facility is intended to capture carbon dioxide), 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, methods, processes and standards in accordance with generally accepted standards of professional care, skill, diligence, and competence applicable to the engineering, procurement and construction management, in the case of Contractor, or construction, operation and maintenance, in the case of Owner, practices in the United States for electric power generation facilities with a complexity at a level similar to the Facility (irrespective of whether any such similar facility is intended to capture carbon dioxide). “Prudent Industry

10

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Practice” does not necessarily mean a practice that would achieve an optimal solution or minimal solution, or any method or standard in all cases.

“Punch List Items” shall mean any minor defects identified by Owner or Contractor during installation and commissioning (and upon which the Parties shall mutually agree) that do not affect the safety, reliability, operability or the mechanical integrity of the Facility or the ability of Owner to operate the Facility in accordance with Prudent Industry Practices.

“Quality Assurance Plan” shall mean that certain Duke Energy Edwardsport IGCC Project Integrated Quality Plan, which comprises all those planned and systematic actions necessary or prudent to provide adequate confidence that a structure, system or component will perform satisfactorily in service and includes management and control of the design, engineering, and construction services for the Project, Rev. dated October 21, 2008, as amended, restated or supplemented from time to time.

“***” shall have the meaning set forth in Exhibit J.

“Recent TSA” shall have the meaning set forth in the Recitals.

***

“Sales and Use Taxes” shall mean all present and future sales, use and similar Taxes imposed on the sale of any materials from Contractor to Owner, if any, or the performance of the Services by Contractor by the State or any other Government Authority.

“Scope Book” shall mean the Scope Book attached hereto as Exhibit A.

“Scope of Services” shall mean the scope of Services to be performed by Contractor as described in Part I of the Scope Book. Contractor’s Scope of Services shall not include any of the services, equipment, materials or other work required to be provided by Owner as described in Part I of the Scope Book.

***

“Screening Measures” shall have the meaning set forth in Section 5.1.

“SDS” shall have the meaning set forth in Section 3.10.

“Services” shall mean the engineering, procurement, construction management and related services and other obligations to be performed or complied with by Contractor hereunder, including those services and other obligations to be performed or complied with by Contractor as described in Part I of the Scope Book, the Material Assignment Schedule or the Communication and Management Protocol, and the repair and warranty work relating thereto, and shall include all of the foregoing items that were performed prior to the Effective Date pursuant to the Recent TSA; provided, however, that the Services shall not include any Shared Services.

“Shared Services” shall have the meaning set forth in Section 3.1(b).

11

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“Site” shall have the meaning set forth in the Recitals as further described in Exhibit D and shall include any additional property that Owner purchases, leases or otherwise has an ownership interest in and that is used for the Project.

“Site Control and Access Plan” shall mean (a) the Time and Attendance Procedure, Document Number 25441-100-GPP-GCP-01012, Rev. 0 dated September 15, 2008, as amended, restated or supplemented from time to time and (b) any other Site Project Procedures, which, among other things, address the safe, efficient and proper prosecution of the Project at the Site, security at the Site, custody and control of equipment, materials and supplies at the Site and right of access and entrance to the Site by all Persons.

“Site Project Procedures” shall have the meaning set forth in Part I of the Scope Book.

“Staffing Plan” shall mean the summary project organization chart reflecting the overall organization and supervision of the Persons employed or managed by Contractor to provide the Services, attached hereto as Exhibit F.

“***” shall have the meaning set forth in Section 15.1.

“State” shall mean the State of Indiana.

“Steering Committee” shall have the meaning set forth in Section 6.3.

“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 (e.g., a second- or third-tier subcontractor) to perform any of the Services, at the Site or elsewhere.

“Substantial Completion” shall have the meaning set forth in Section 11.2.

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

“Sulfur Intellectual Property Rights” shall mean any and all existing and future patent rights, trademark rights, copyright rights, trade secret rights, know how rights and other rights owned by or licensed to Contractor relating to processes or apparatus for the conversion of hydrogen sulfide to sulfur in an environmentally acceptable manner, including Claus sulfur recovery, hydrogenating tail gas treating, and thermal oxidizing.

“Sulfur Jointly Developed Improvements” shall mean any and all improvements, modifications, variations, additions, deletions, or other changes of any kind or nature, which are useful for or in connection with Claus sulfur recovery, hydrogenation tail gas treating and thermal oxidizing, which are developed or acquired jointly by Owner and Contractor during the term of this Agreement and which are based in whole or in part on the Sulfur Intellectual Property Rights.

“Sulfur License” shall have the meaning set forth in Section 18.3.

12

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

“Sulfur Licensee Improvements” shall mean any and all improvements, modifications, variations, additions, deletions or other changes of any kind or nature which are useful for or in connection with Claus sulfur recovery, hydrogenation tail gas treating and thermal oxidizing, which are based in whole or in part on the Sulfur Intellectual Property Rights and which are developed by Owner during the term of this Agreement and which are not at the time known to Contractor, or known in the public domain.

“Sulfur License Royalty” shall have the meaning set forth in Section 18.3.

***

***

***

***

“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, personal property (tangible and intangible), real estate, excise and stamp taxes), levies, imports, duties, assessments, fees, charges and withholdings of any nature whatsoever, and all penalties, fines, additions to tax, and interest imposed by any Government Authority. Taxes shall also include Sales and Use Taxes and all present and future customs, duties or levies or other import or export fees, including any charges imposed by North American Free Trade Association (NAFTA).

“Technical Data” shall mean the calculations identified in Exhibit E attached hereto.

“Term Sheet” shall have the meaning set forth in the Recitals.

“Termination Charges” shall have the meaning set forth in Section 19.5(c)(i).

“Third Party Claim” shall mean any claim, demand or cause of action of every kind and character by any Person other than Owner, Contractor or their respective Affiliates.

“Warranties” shall have the meaning set forth in Section 12.1.

“Warranty Period” shall mean the period commencing on the Substantial Completion Date and ending on the date that is the earlier of (a) *** and (b) ***, as such period may be extended from time to time as provided in Section 12.3.

2. GENERAL PROVISIONS

2.1 Intent of Contract Documents. It is the intent of the Parties that Contractor 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 9 or as otherwise expressly set forth herein.

13

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 Sections 3.2, 3.3 and 3.4.

2.3 Subcontracting. Contractor shall not engage any Person, excluding Persons related to or affiliated with Contractor and functioning in the offices specifically identified in Exhibit I, to perform any portion of the Services without the prior written consent of Owner, which consent shall not be unreasonably withheld. In any event, Contractor shall ensure that it shall have the right to grant the intellectual property licenses to Owner, its Affiliates and Permitted Users herein irrespective of the performance by any Subcontractor of any Services. No contractual relationship shall exist between Owner and any Subcontractor with respect to the Services. 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.

2.4 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) Plural/Singular. Words importing the singular also include the plural and vice versa.

(c) 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.

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

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

(f) 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.

(g) 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.

14

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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

(i) Approve. Provisions including the word “approve”, “approved” or “approval” require the approval to be recorded in writing.

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

(k) 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.

2.5 Inclusion; Conflicts. 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 or section of a document, once that requirement is specifically listed in another document or section, shall not imply the inapplicability of that requirement, and Contractor shall provide as part of its obligations hereunder all items required to conform the Services to the requirements of this Agreement. Any provision addressing any issue with specificity shall not be construed to limit any provision addressing the same or similar issue in general. 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).

2.6 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 Services.

(a) Generally. Contractor shall diligently, duly and properly perform and complete the Services and its other obligations in accordance with this Agreement, applicable Laws and Prudent Industry Practices, and shall obtain and maintain all Government Approvals necessary or prudent for the proper execution and completion of the Services. Contractor shall perform and provide all services not specifically delineated in this Agreement to the extent customary and necessary to complete the Services in accordance with Prudent Industry Practices. Contractor shall perform and provide the Services in a manner that will not disrupt or interfere with Owner’s operation of its existing coal-fired electric generation plant adjacent to the Site.

15

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(b) Shared Services. The Parties acknowledge and agree that they have established a shared services team comprised of personnel from each Party as more particularly described in the Communication and Management Protocol, which team is intended to provide support for work on the entirety of the Project, including the Services to be provided by Contractor hereunder, as described in the Communication and Management Protocol, in order to reduce costs for the Project (the “Shared Services”). Owner shall be responsible for directing and supervising the Shared Services team and in the performance of the work allocated to the Shared Services team. The personnel of Contractor on the Shared Services team, without regard to the type of work to be performed by such personnel or the portion of the Project for which such work relates, shall at all times be Borrowed Employees as contemplated by Article 5. The Parties acknowledge and agree that this Shared Services team shall be available to Owner for work relating to any portion of the entire Project, including work outside of the CM ISBL Work. In performing the services with respect to any type of work allocated to the Shared Services team as indicated in the Staffing Plan or Communication and Management Protocol, Contractor shall use only personnel from this Shared Services team. The Parties agree to provide good faith, prompt and courteous coordination and collaboration, and to assist the other Party, at its request, in such other activities, as may be reasonably required for the successful and timely completion of work to be performed by the Shared Services team.

3.2 Appointment as Agent. Subject to the defined limits of authority set forth in this Section, Owner hereby authorizes Contractor to, and Contractor hereby agrees to, act as Owner’s agent for the purpose of performing the Procurement Services and the Construction Management Services. Contractor shall have no authority to, and shall not, take any of the following actions in connection with the Procurement Services or the Construction Management Services (without Owner’s general or specific approval): (1) make awards, (2) approve invoices, (3) consent to any change order under any Owner Contract or the GE Equipment Contract; (4) agree to or permit any amendment, modification, or supplement of any Owner Contract or the GE Equipment Contract; (5) waive or prejudice any of Owner’s rights with respect to any Owner Contract or the GE Equipment Contract, as applicable, or the obligations of the Managed Vendors or GE, respectively, relating thereto; (6) initiate or conduct any litigation, arbitration or other similar proceedings on behalf of Owner; (7) take any action that would cause a default or breach by Owner of an Owner Contract or the GE Equipment Contract; or (8) agree to or consent to termination or suspension of work or activities under any Owner Contract or the GE Equipment Contract.

3.3 Scope of Procurement Services.

(a) Subject to Section 3.2, Contractor shall perform procurement Services for services, equipment (including spare parts related thereto), materials and supplies (collectively, the “Procurement Items”), as such Services are further described in this Section and in Part I of the Scope Book (the “Procurement Services”). The Parties acknowledge and agree that the Material Assignment Schedule contains a preliminary schedule of Procurement Items required for the Project for which Contractor shall provide Procurement Services, that Contractor is

16

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

not obligated hereunder to provide Procurement Services with respect to all services, equipment (including spare parts related thereto), materials and supplies required for the Project and that the amount or type of Procurement Items required for the Project for which Contractor shall provide Procurement Services may be changed by Owner from time to time. Accordingly, Owner may, from time to time, propose changes to the Material Assignment Schedule to change the amount or type of Procurement Items required for the Project for which Contractor shall perform Procurement Services, and the Parties shall proceed with respect to such proposed change in accordance with the terms and conditions set forth in Article 9. Contractor shall perform the Procurement Services, as a Reimbursable Cost, with respect to any additions to the Material Assignment Schedule in accordance with the terms of this Agreement.

(b) Contractor shall, in connection with the provision of Procurement Services, provide the advice and recommendations to Owner as described in Part I of the Scope Book based on the actions that Contractor would take if Contractor were directly responsible to Owner as the prime contractor for the applicable Procurement Items. Each contract, purchase order or other agreement executed or entered into pursuant to this Section 3.3 shall be executed by Owner, and each such contract, purchase order or other agreement shall be an Owner Contract for all purposes hereunder. In connection with the Procurement Services to be provided hereunder, the Parties shall mutually develop a process to integrate Owner’s purchasing system with Contractor’s purchasing system in order to coordinate the management of materials purchased for the Facility and the payments made or due to Owner Suppliers. Nothing contained herein shall create any contractual relationship between Contractor, on the one hand, and GE or any Managed Vendor, on the other hand, and Contractor shall have no liability (including any payment liability) to GE or any Managed Vendor with respect to goods or services provided by any of them pursuant to the GE Equipment Contract or the Owner Contracts, as applicable.

17

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

3.4 Scope of Construction Management Services.

(a) Subject to Section 3.2, Contractor shall generally manage, supervise and coordinate all CM ISBL Work as contemplated herein and as further described in Part I of the Scope Book and the Communication and Management Protocol (the “Construction Management Services”). Contractor shall perform the Construction Management Services in a manner designed to achieve Mechanical Completion, Substantial Completion and Final Completion by their respective dates set forth in the Project Schedule. Contractor shall perform the Construction Management Services in a manner designed to achieve completion of the CM ISBL Work in compliance with the Scope Book, Design Documentation, Project Schedule and the other terms and conditions set forth herein. Contractor shall diligently perform the Construction Management Services in accordance with Prudent Industry Practices and the other terms and conditions of this Agreement. In performing the Construction Management Services hereunder, Contractor and Owner understand that Contractor is acting in a construction management role and does not assume the liabilities and obligations of a prime contractor with respect to the responsibilities assumed by the Managed Vendors or GE, unless the same or similar obligations are specifically set forth herein.

(b) Without limiting the generality of Section 3.4(a), but subject to Section 3.2, in performing the Construction Management Services, Contractor shall, for the benefit of Owner and with the same diligence and care and pursuant to the same standards as Contractor uses on any other electric generating power plant construction project in the United States with a similar level of complexity where Contractor is acting as the contractor for such project (but not less than the diligence, care and standards required by this Agreement), require each Managed Vendor to perform all elements of its work to be performed by such Person in compliance with the terms of the Owner Contract for such Managed Vendor and manage the Owner Contracts in a manner designed to achieve the Project Schedule. Owner shall provide Contractor with the relevant portions of each Owner Contract in order for Contractor to perform the Construction Management Services with respect thereto.

3.5 Engineering Services. Contractor shall diligently, duly and properly perform and complete engineering Services, including providing working drawings, designs and specifications (the “Design Documentation”) setting forth in detail the design of, and the requirements and procedures for the construction or testing for, that portion of the Project for which Contractor is responsible for the design, as more fully described in Part I of the Scope Book (collectively, the “Engineering Services”). Contractor hereby acknowledges that the Design Documentation shall form the basis for work performed by other contractors, subcontractors, Managed Vendors or Owner Suppliers in respect of the Facility and that any review or approval by Owner of any Design Documentation shall not relieve Contractor from any obligation or responsibility under this Agreement.

18

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

3.6 Development of Project Plans.

(a) Site Control and Access Plan. Contractor shall comply with, implement and enforce the Site Control and Access Plan as set forth in the Scope Book. For the avoidance of doubt, Owner shall have the ultimate authority with respect to the contents of the Site Control and Access Plan and may update the Site Control and Access Plan from time to time.

(b) Environmental, Safety and Health Plan. Contractor shall comply with, implement and enforce the Environmental, Safety and Health Plan as set forth in the Scope Book. For the avoidance of doubt, Owner shall have the ultimate authority with respect to the contents of the Environmental, Safety and Health Plan and may update the Environmental, Safety and Health Plan from time to time.

(c) Quality Assurance Plan. Contractor shall comply with, implement and enforce the Quality Assurance Plan as set forth in the Scope Book. For the avoidance of doubt, Owner shall have the ultimate authority with respect to the contents of the Quality Assurance Plan and may update the Quality Assurance Plan from time to time.

3.7 Intentionally Omitted.

3.8 Facility Manuals; Training. In connection with the Construction Management Services, Contractor shall review and assist Owner in collecting the manuals prepared by Managed Vendors in the manner set forth in Part I of the Scope Book.

3.9 Periodic Reports and Meetings.

(a) Status Report. Within *** Days after the end of each calendar month, Contractor shall prepare and submit to Owner a written status report covering the previous calendar month, which report shall be prepared in a manner and format (hard copy and electronic) reasonably acceptable to Owner and shall include the information required to be included in such status report as described in Section 6.3 of Part I of the Scope Book (the “Monthly Progress Report”). In addition, Contractor shall prepare and deliver to Owner such engineering, procurement, material handling, cost, schedule, manpower, quality, safety, resource or other project reports relating to the Project as described in Section 6.6 of Part I of the Scope Book and at the frequency set forth therein.

(b) Progress 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 Services and the CM ISBL Work and anticipating and resolving any problems (“Progress Meetings”). The Progress Meetings may also include, at the request of Owner, Managed Vendors, GE, Owner Suppliers, the Financial Institutions, Subcontractors, consultants and other Persons. Contractor shall prepare and promptly deliver to Owner written

19

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 a 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 Project Manager shall attend all Progress Meetings after Contractor mobilizes to the Site. *** In addition to the above monthly Progress Meetings and unless excused by Owner, Contractor and Owner shall hold regularly scheduled (but not less frequently than weekly during construction) status or scheduling meetings as requested by Owner.

3.10 Compliance with Laws. Contractor shall perform all Services in conformance with applicable Law. Notwithstanding anything to the contrary contained herein, Contractor shall not be required to take any action or perform any Services hereunder that would result in the violation of any applicable Laws, including U.S. anti-boycott Laws, and applicable Laws pertaining to export control and sanctions. If not otherwise exempted by Title 48 and to the extent applicable, Contractor shall adopt and utilize a subcontracting plan that complies with 48 C.F.R. 52-219-9 for Small Diverse Suppliers (“SDS”). Contractor shall: (i) use all commercially reasonable efforts to utilize SDS (and Large Diverse Suppliers); and (ii) provide Owner a quarterly status report in a format reasonably acceptable to Owner. Contractor shall enter such report on Owner’s website at www.duke-energy.com/suppliers/supplier-diversity.asp. Owner, its designated auditors and any applicable Government Authority shall have the right of access during normal business hours to inspect Contractor’s records related to the Project as they relate to SDS and compliance with this Section.

3.11 Owner Office Space. Contractor shall provide Owner with five offices and six cubicles in Contractor’s Houston Office and two cubicles in Contractor’s office located in Frederick, Maryland and such additional space as reasonably requested by Owner. *** To the extent any additional office space is requested by Owner and there are issues with respect to the scope of such request or availability of office space, the Parties will discuss the allocation of such office space and/or invoicing for such office space.

3.12 Emergencies. In the event of any emergency endangering life or property, Contractor shall take, or direct any Persons under Contractor’s control to take, all actions as may be reasonable and necessary to prevent, avoid or mitigate injury, damage or loss and shall immediately report each such emergency, and Contractor’s responses thereto, to Owner’s Project General Manager and shall provide Owner a written report of such emergency, and Contractor’s responses thereto, within twenty-four (24) hours after the occurrence of such emergency.

3.13 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.

20

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

3.14 Acknowledgement of Scope of Services. Contractor and Owner hereby acknowledge that the Services are only a portion of the work required for the completion of the entire Project and that the successful and timely completion of the Project in accordance with the Project Schedule will require the good faith, prompt and courteous coordination and collaboration among many contractors, subcontractors and other Persons, including Contractor, Managed Vendors, GE, Owner Suppliers, Owner and Owner’s other contractors. Contractor agrees to provide such good faith, prompt and courteous coordination and collaboration on its own behalf and to assist Owner, upon request, in such other activities as may be required for the successful and timely completion of the Project, including assistance in obtaining any Governmental Approvals necessary for the operation, maintenance, use and ownership of the Facility. Owner shall use reasonable efforts to require Owner’s other contractors to coordinate, collaborate and cooperate with Contractor in a manner designed to achieve and maintain a schedule and sequence that will accommodate the interest of all parties so as not to unreasonably disrupt and interfere with their respective work.

3.15 Use of Existing Owner Property. Circumstances may arise where Contractor requests Owner to make available to Contractor certain of Owner’s equipment or facilities for the performance of Contractor’s Services the use of which is not provided for in this Agreement. Upon such request, Owner shall use commercially reasonable efforts to provide Contractor with the use of such equipment or facilities; provided, that the use of such equipment or facilities shall not unreasonably disrupt or interfere with the work of other contractors, subcontractors and other Persons, including Managed Vendors, GE, Owner Suppliers, Owner and Owner’s other contractors. Contractor shall be responsible for reasonably inspecting such equipment to assure itself of the safety of such equipment before use and shall return such equipment to Owner in the condition which it was received, except for reasonable wear and tear. Contractor shall inspect such equipment before Contractor’s use and upon its return to Owner. Upon return, Owner may also inspect such equipment to substantiate whether or not any part of the equipment used by Contractor has been damaged in any way as a result of its use by Contractor. If Owner is required to expend amounts (a) to repair any uninsured damage to its equipment or (b) to pay any deductible required to be paid for any insured damage, in each case, resulting from Contractor’s use of such equipment or facilities (ordinary wear and tear excepted), ***.

4. CONTRACTOR PERSONNEL

4.1 Contractor’s Personnel. Contractor shall comply in all respects with all applicable labor, employment and immigration Laws that may impact Contractor’s Services 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 for its employees that will be performing Services and Shared Services and for all Borrowed Employees provided by Contractor. Contractor acknowledges and agrees that it is responsible for conducting adequate screening of its employees and agents prior to assigning any such Person to perform any Service. By providing an employee or agent under this Agreement, Contractor warrants and represents that it has completed the Screening Measures (as defined in Section 5.1 below) with respect to such Person and that such Screening Measures did not reveal any information that adversely affects such Person’s

21

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

suitability for assignment by Contractor to perform the Service. Owner, in its sole discretion, shall have the option of barring from the Site any person whom Owner determines is not fit or qualified to perform the Service, or who violates applicable requirements hereunder. 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 advise and instruct the Persons assigned to the Site by Contractor to comply with all applicable office and field rules, regulations and safety procedures. At all times, a person assigned by Contractor to perform Services shall remain an employee of Contractor.

4.2 Staffing Plan. Contractor shall implement and maintain the Staffing Plan in connection with the provision of the Services. Owner may incorporate changes to the Contractor staffing scope in the Staffing Plan with the consent of Contractor (such consent not to be unreasonably withheld). Owner shall have the right to make any other changes to such organization chart in its sole discretion. 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 in accordance with the Staffing Plan and the Project Schedule.

4.3 Supervision and Discipline. Contractor shall supervise, coordinate and direct the Services in accordance with Prudent Industry Practices. Contractor shall enforce discipline and good order among all Persons carrying out the Services and shall use commercially reasonable efforts to enforce discipline and good order among all Persons performing CM ISBL Work at the Site, in each case in accordance with the Project Job Rules and Regulations. Contractor shall at all times take all necessary precautions to prevent any unlawful, unsafe or disorderly conduct by or among Persons performing the Services. Contractor shall only permit the employment of Persons who are fit on each Day they perform the Services and who are qualified and skilled in the tasks assigned to them. Contractor shall retain responsibility for the performance, conduct and compliance of each of its employees and agents assigned to perform the Services at the Site. Owner shall have the right to bar from the Site any Person. Upon request of Owner in its discretion, 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 (if any such Person is a “key personnel” as described in Section 4.4, such discretion exercised by Owner must be reasonable). In addition, in the event that 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.

4.4 Contractor’s Key Personnel. Exhibit F contains a list of the name and title of each of Contractor’s key personnel who shall be responsible for the performance of Contractor’s obligations under this Agreement. The key personnel set forth on Exhibit F includes a designation of Contractor’s Project Manager and Contractor’s Site Representative. Replacement of any of the key personnel listed in Exhibit F, other than due to death, termination in employment or a leave of absence permitted as required by applicable Law, shall be subject to the prior written approval of Owner, which approval Owner shall not

22

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

unreasonably withhold, and any replacement must be qualified for the applicable position as mutually agreed between the Parties (such Owner acknowledgement of qualifications not to be unreasonably withheld). Contractor shall remove and replace any such key personnel at Owner’s reasonable discretion. 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 perform the responsibilities of Contractor under this Agreement, and (c) to bind Contractor as to the day-to-day project management operations under the Agreement, in each case, subject to the terms and conditions set forth in the Communication and Management Protocol. Contractor’s Site Representative or other Contractor supervisory personnel shall be present at the Site at all times when the Services or CM ISBL Work are being performed at the Site.

4.5 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 in accordance with the Environmental, Safety and Health Plan 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. Upon request, and to the extent permitted by applicable Law, Contractor will furnish Owner copies of the records of employee drug and alcohol test results required to be kept by applicable Law. Contractor will indemnify and hold harmless Owner from any and all liability for any claims made by a Contractor or Subcontractor employee resulting from removal from the Site by Contractor or by Owner in the event of an emergency or other exigent circumstances as provided in this Article.

4.6 Training of Employees. Contractor represents that all Contractor and Subcontractor personnel have received all necessary training required to perform the Services in accordance with applicable Laws.

4.7 Substitution. Subject to Section 4.4, Contractor reserves the right to change any of its personnel performing Services. In such event, Contractor shall provide replacement personnel meeting the requisite qualifications of the position to be filled and who have substantially similar capabilities.

4.8 Employer Responsibilities. For so long as any Person is assigned by a Party to perform Services at the Site, the Party assigning the Person and such Person shall act as an independent contractor and not as an agent or employee of the other Party. Neither Party intends to create a co-employment relationship for the Persons working at the Site. Each Party shall comply, at its expense, with all applicable provisions of workers’ compensation Laws, unemployment compensation Laws, federal social securities Laws, the Fair Labor Standards Act and all other applicable federal, state and local Laws relating to terms and conditions of employment required to be fulfilled by employers with respect to any of its own employees.

23

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

5. BORROWED EMPLOYEES

5.1 Assignment of Borrowed Employees. Each of Contractor and Owner shall assign certain of its employees (the “Borrowed Employees”) to the other Party to perform certain job duties required for completion of the entire Project, including the job duties identified as Shared Services in the Staffing Plan and the Communication and Management Protocol and the job duties necessary to complete portions of the CM ISBL Work (collectively, the “Assigned Job Duties”). By assigning a Borrowed Employee, each Party represents that it has completed the Screening Measures (as defined below) with respect to such Borrowed Employee and that such Screening Measures did not reveal any information that adversely affects such Borrowed Employee’s suitability for employment by such Party. As used in this Section, the term “Screening Measures” means, with respect to either Party, such screening and eligibility measures as required by such Party’s generally applicable human resources policies and procedures (the “HR Policies”) and applicable Law. Each Party shall maintain all records with respect to each of its Borrowed Employees as required of an employer by applicable Law. At all times that a person is serving as a Borrowed Employee, such Borrowed Employee shall remain an employee of the Party supplying such Borrowed Employee subject to all of its HR Policies. Promptly after execution of this Agreement, each Party shall designate in writing a liaison to be responsible for addressing performance, conduct, and compliance issues (“HR Issues”) relating to the Borrowed Employees. Each Party may change its designated liaison from time to time upon ten (10) Days prior written notice to the other Party.

5.2 Qualifications. Each Party shall provide curriculum vitae for each person such Party proposes to be a Borrowed Employee, which curriculum vitae shall include a description of the role of such person in his or her recent projects. Each Party shall permit the other Party the opportunity to interview each such person. Each Party covenants that its Borrowed Employees shall have such credentials represented in writing by it to the other Party. Contractor shall reassign any such Borrowed Employee to a project other than the Project at Owner’s request exercised in its reasonable discretion. Contractor shall not cease providing Owner with the services of any of its Borrowed Employees without the prior written approval of Owner, provided that Contractor may cease providing Owner with the services of a Borrowed Employee without the prior approval of the Owner (a) if such Borrowed Employee dies, resigns, transfers in accordance with the HR Policies, goes on leave of absence in accordance with the HR Policies (in which case Contractor shall provide Owner notice of all relevant dates regarding such leave of absence), or is terminated for cause, as defined in the HR Policies, (b) if such Borrowed Employee is not expected (by Owner) to perform any services in connection with, or otherwise relating to, the start-up of the Facility (including any scheduling or planning), upon the Mechanical Completion Date or such later date upon which the Parties may mutually agree or (c) if such Borrowed Employee is expected (by Owner) to perform services in connection with, or otherwise relating to, the start-up of the Facility (including any scheduling or planning), upon the Final Completion Date. If Contractor ceases to provide a Borrowed Employee as permitted herein, Contractor shall promptly replace such Borrowed Employee with another Borrowed Employee meeting the requirements hereof. Owner may reassign any of its Borrowed Employees.

24

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

5.3 Assigned Job Duties. Each Party shall determine the procedures to be followed by the Borrowed Employees assigned to such Party with respect to their Assigned Job Duties; provided, however, that such Party shall not direct such Borrowed Employees to perform any duties other than the Assigned Job Duties or to perform the Assigned Job Duties in a manner that would violate any of the other Party’s HR Policies known to such Party. Each Party represents to the other Party that nothing in its HR Policies prevent any of its Borrowed Employees from performing his or her Assigned Job Duties. The Borrowed Employees assigned to each Party shall be advised by such Party of, and the assigning Party shall instruct such Borrowed Employees to comply with, all applicable office and field rules, regulations and safety procedures. To the extent permitted by applicable Law, each Party assigning Borrowed Employees shall provide the other Party with such information pertaining to such Borrowed Employees in connection with rendering the Assigned Job Duties as the other Party may request and which is reasonably necessary to the other Party’s direction and oversight of such Borrowed Employees and the performance of the Assigned Job Duties. Each Party shall require each of its Borrowed Employees to obtain and maintain all licenses (including professional engineering licenses) and work permits, if any, required in connection with his or her performance of the Assigned Job Duties.

5.4 Responsibility for Work. Each Party shall be solely responsible for the effectiveness or technical, economic or environmental feasibility of any method, technique, or process implemented by such Party or third parties resulting from any Borrowed Employee furnished to it under this Section. Accordingly, neither Party assigning Borrowed Employees shall have any liability to the other Party for loss or damage arising out of or resulting from the performance by such Borrowed Employees of the Assigned Job Duties, including loss of or damage to property of the other Party, and the other Party hereby releases and agrees to indemnify, hold harmless and defend the Party assigning Borrowed Employees and each such Borrowed Employee from and against any and all claims, demands, losses, damages, costs, liabilities and expenses (including reasonable attorneys’ fees) for injuries to persons (including death) and for damage to property, including property of the other Party or others, arising out of the performance by such Borrowed Employee of his or her Assigned Job Duties, provided that such Borrowed Employee had the credentials represented in writing by the Party assigning Borrowed Employees to the other Party.

5.5 Employer Responsibilities. For so long as any person serves as a Borrowed Employee, the Party assigning such Borrowed Employee and such Borrowed Employee shall act as an independent contractor and not as an agent or employee of the other Party. Neither Party intends to create a co-employment relationship for the Borrowed Employees. Each Party shall comply, at its expense, with all applicable provisions of workers’ compensation Laws, unemployment compensation Laws, federal social security Law, the Fair Labor Standards Act, and all other applicable federal, state, and local Laws relating to terms and conditions of employment required to be fulfilled by employers with respect to any of its Borrowed Employee. Without limiting the generality of the foregoing and for so long as any person serves as a Borrowed Employee of a Party, such Party shall:

(a) pay such Borrowed Employee at such compensation levels (including any overtime pay, if applicable), and provide employee benefits, as it provided such

25

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

person prior to becoming a Borrowed Employee, subject to periodic reviews and adjustments in the ordinary course of business;

(b) make wage payments to such Borrowed Employee through its payroll systems and on the same basis as such compensation is provided to any of its other employees;

(c) make all applicable payroll withholding deductions for such Borrowed Employee, including Federal and State income tax, social security, unemployment and disability insurance (if applicable), and promptly remit such withholding deductions and taxes due to all taxing authorities;

(d) provide each such Borrowed Employee, on the same basis as its other employees, with access to an electronic pay stub each pay day and a W-2 form at the end of each year during which such person is a Borrowed Employee;

(e) inform such Borrowed Employee of changes in benefits in the same manner such information is provided to its other employees and enable such Borrowed Employee to enroll in new benefit programs;

(f) have sole responsibility for administering all of its retirement plan(s), health and welfare plan(s) and all other non-statutory employee benefit plans and programs for which such Borrowed Employee is eligible to participate; and

(g) maintain workers’ compensation insurance and keep such insurance in full force and effect at all times with respect to such Borrowed Employee and in compliance with applicable Law.

For the avoidance of doubt, the Parties acknowledge and agree that no Borrowed Employee shall be considered an employee of the Party to whom such Borrowed Employee is assigned for any purposes, including HR Issues, discipline, termination, retirement benefits, workers’ compensation or employer’s liability insurance, all of which shall remain the responsibility of the Party assigning such Borrowed Employee. Each Party assigning a Borrowed Employee hereby releases and agrees to indemnify, hold harmless and defend the other Party from and against any and all claims, demands, losses, damages, costs, liabilities and expenses (including reasonable attorneys’ fees) arising out of the failure of the assigning Party to comply with its obligations in this Section 5.5. Each Party shall maintain payroll and other wage, benefit and tax records related to its Borrowed Employees in accordance with generally accepted accounting practices and all applicable Laws. Upon written request of each Party and to the extent permitted by applicable Law, the other Party shall make available to the requesting Party its records relating to the other Party’s obligations in this Section 5.5 and its compliance with such obligations, and shall provide such certificates and copies of such receipts or vouchers, as the requesting Party may reasonably require to assure itself that the other Party has complied with its obligations in this Section 5.5.

5.6 Cooperation. Each Party will reasonably cooperate with the other Party in the defense of any and all claims, including litigation and administrative claims, against such

26

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

other Party brought by any Borrowed Employee, unless and then only to the extent that the Parties have an actual conflict of interest with respect to such matter. Such cooperation may include providing the other Party with access to claim information, facilities, witnesses and other information and documents as reasonably requested.

5.7 No Third Party Rights. No provision of this Agreement shall create any third party rights in any Borrowed Employee (including any beneficiary or dependent thereof).

6. PROJECT MANAGEMENT

6.1 Owner’s Representative. Owner shall appoint Owner’s Project General Manager 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 9.

6.2 Project Management; Communication and Management Protocol. The Parties hereby acknowledge and agree that Owner shall have the right and authority to direct all matters relating to the Project, subject, with respect to the CM ISBL Work, to the Communication and Management Protocol. Without limiting the generality of the foregoing, Contractor’s Project Manager shall report to Owner’s Project General Manager. The Parties shall interface, communicate, coordinate and collaborate with one another in the manner set forth in the Communication and Management Protocol in order to achieve the successful and timely completion of the Project.

6.3 Steering Committee. The Parties shall establish a steering committee (the “Steering Committee”) consisting of Contractor’s Steering Committee Members and two (2) executives designated by Owner. The purpose of the Steering Committee shall be to provide guidance with respect to the Project and to ensure efficient project management in accordance with the terms and conditions set forth herein. The members of the Steering Committee shall meet at least once each calendar quarter (and at such other times reasonably requested by Owner) at such times and locations as Owner shall reasonably request for the purpose of discussing the status of the Project and resolving any existing or potential problems or issues with respect to the Project. At the request of Owner, executives from GE may also participate in such Steering Committee.

6.4 GE Change Review Board. At the request of Owner, Contractor’s Project Manager shall participate in any meetings of the GE Change Review Board to discuss the impact to the Project of any changes in the “Process Design Package” supplied by GE or the scope of the GE Equipment Contract, including the means to ameliorate any such impact.

6.5 Access; Contractor’s Office Space. From the Effective Date until the Substantial Completion Date, Owner shall provide Contractor unrestricted right of access to such portion of the Site as Contractor may reasonably require to perform the Services at the Site and for Contractor’s office space and employee parking. Owner (and its representatives)

27

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

shall at all times have access to the Site. Owner shall provide Contractor with office space at the Site as described in Part I of the Scope Book.

6.6 Estimate. Upon request of Owner, Contractor shall assist Owner in preparing a budget for the Project, in detail reasonably satisfactory to Owner, based upon the information contained in the Estimate. At the request of Owner from time to time, Contractor shall temporarily relocate one of its employees to Owner’s Plainfield Office with a hard copy and an accessible, electronic copy of the Estimate. Such relocated employee shall remain at Owner’s Plainfield Office for the length of time requested by Owner; provided, that such employee shall not be required to remain at Owner’s Plainfield Office beyond the Final Completion Date. Alternatively, at the request of Owner from time to time, Contractor shall send an employee to Owner’s Plainfield Office with a hard copy and an accessible, electronic copy of the Estimate. Owner shall bear all *** incurred by Contractor in relocating such employee or sending such employee to Owner’s Plainfield Office. Contractor shall make available to Owner at Contractor’s Houston Office and at the Site, during normal business hours upon Owner’s request from time to time, a hard copy and an accessible, electronic copy of the Estimate for Owner’s review and inspection.

7. PROJECT SCHEDULE

7.1 Schedule Compliance; Updates. Contractor shall perform its obligations under this Agreement and shall direct the Managed Vendors to perform work in relation to the CM ISBL Work in a manner designed to comply with the Project Schedule. Contractor shall (a) provide the Contractor EP Schedule to Owner for uploading into the Project Schedule and the Contractor EP Schedule shall be updated from time to time and (b) cooperate with Owner and participate in developing and updating the Project Schedule, including, without limitation, assisting Owner in collecting the information obtained from Managed Vendors that Owner will use to update the Project Schedule, in each case, in the manner set forth in Section 6 of Part I of the Scope Book and in the Communication and Management Protocol. For the avoidance of doubt, this Section 7.1 shall not limit the Construction Management Services, including Contractor’s obligation to coordinate the activities of Managed Vendors.

7.2 ***

8. COMPENSATION AND PAYMENT

8.1 Contract Price. In consideration of the performance by Contractor of the Services and its other obligations hereunder, Owner shall pay to Contractor the Contract Price in accordance with the terms and conditions set forth herein.

8.2 ***

8.3 ***

(a) ***

(i) ***

28

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(ii) ***

(iii) ***

(iv) ***

(b) ***

8.4 Invoicing 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 *** is paid by Owner or (ii) *** Days after Owner receives the *** and such substantiating documentation and materials as Owner may have reasonably required. 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 8.4(b) below, make any correction or modification that should properly be made to any amount previously considered due.

(b) Owner shall pay Contractor, within *** Days of receipt of the *** and such substantiating documentation and materials as Owner may have reasonably required, in U.S. dollars, the undisputed amounts designated in such ***, plus any additions and less any deductions which may have become due under this Agreement, as reflected in the ***. Any amount of a *** that Owner disputes shall be resolved promptly in accordance with Article 23; provided, that, if the amount in dispute equals or exceeds ***, the Parties shall initiate the dispute resolution procedures set forth in Article 23 within *** Days following the determination of the existence of a dispute. Once the dispute is resolved, Owner or Contractor, as applicable, shall 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 8.4(b)) within *** Days after receipt of a substantiated *** Payment Invoice which complies with the requirements of this Article, interest shall thereafter accrue on such sums due and owing at the *** until paid.

8.5 ***

(a) ***

(b) ***

8.6 Final Payment. Following achievement of Final Completion, Contractor shall submit to Owner an invoice for the final payment and other payments due under this

29

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Agreement (the “Final Payment Invoice”) which shall contain *** (d) a determination of all other remaining amounts due to it pursuant to this Agreement and (e) all supporting documentation reasonably requested by Owner. When submitting the Final Payment Invoice, Contractor shall submit a written discharge, in form and substance 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. The procedures set forth in Section 8.4 (including application of interest for late payments) shall be followed for payment of the applicable Final Payment Invoice, and Owner shall be entitled to offset against any *** or Final Payment Invoice any amounts owing by Contractor to Owner under this Agreement.

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

“There are no known Liens that are outstanding at the date of this invoice and arose by or through Contractor, any Subcontractor or any Person claiming through Contractor or any Subcontractor for which Contractor has not provided a bond or other assurance of payment; all amounts that are due and payable to any third party (including Subcontractors) with respect to the Services 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 paid but so included and amounts disputed between Owner and Contractor, there is no known basis for a Lien to be filed. 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 Services included in this invoice.”

8.8 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.

9. CHANGE ORDERS

9.1 Change Requests. Without invalidating this Agreement, Owner may require Contractor to perform hereunder services not included in the Services, remove services included in the Services or revise services included in the Services (each, a “Change”); provided, that, without the consent of Contractor (such consent not to be unreasonably withheld), Owner may not direct a Change that requires Contractor to perform services (a) *** (b) *** or (c) *** (each, a “Non-Directed Change”).

9.2 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 a good faith estimate of the cost to develop a Change Order for such Change, such development costs to be determined on a *** basis. 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,

30

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 the proposed contents for a 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 Services, the ***, the Baseline Contractor Schedule, any warranties herein and the operation or maintenance of the Facility,

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

(c) Contractor’s proposal for any necessary modifications to any other provisions of this Agreement, including the Scope Book and the Communication and Management Protocol.

Contractor shall provide Owner such supporting documentation for the foregoing as Owner may reasonably request. 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 Services while awaiting a response. If Owner 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 (other than a Change requested by Contractor pursuant to Section 9.4 but not required to be made by this Agreement), it shall pay Contractor *** incurred in developing the estimates and other information regarding the potential Change.

9.3 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 necessary to effect the Change (the “Change Order”). If Contractor refuses to accept such necessary revisions in the Change Order, Contractor shall provide Owner written notice thereof within *** 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, (a) the Parties shall resolve the Dispute over the necessary revisions in accordance with the dispute resolution procedures set forth in Article 23 and (b) if the Change requires additional Services, Owner shall continue to pay Contractor *** incurred in performing the Services ordered in the Change Order in accordance with Article 8, subject to resolution of the Dispute pursuant to Article 23. For the avoidance of doubt, Owner may issue a Change Order in order to effect a Change prior to completion of the process described in Section 9.2 and, if the Parties dispute whether any instructions by Owner constitute a Change or are permitted by the terms of this Agreement without the necessity of a Change, Contractor shall comply with such instructions, but shall be entitled to reserve its right to dispute that a Change has occurred.

9.4 Contractor Proposed Changes. Contractor shall have the right to request a Change (in which event it shall provide Owner the information required by Section 9.2) but

31

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

shall have no right to require a Change that is not required by this Agreement without the prior written consent of Owner. If Contractor determines that a Change is required by this Agreement, Contractor shall give Owner written notice within *** Days thereof.

9.5 ***

10. FORCE MAJEURE

10.1 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 actually 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, to minimize any delay in or impact upon the performance of this Agreement or any damage to or other impact upon the Owner Equipment or the GE Equipment and contain costs and expenses arising from such Force Majeure event or its effects; provided, that Owner shall have the right to direct the efforts to be expended by Contractor in removing the cause affecting such non-performance and minimizing the impact thereof.

10.2 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 upon the earlier of (a) *** Days after the notifying Party or its Project Manager becomes aware, through the exercise of reasonable diligence, of the event of Force Majeure and (b) *** Days after the event of Force Majeure. The Party affected by an event of Force Majeure shall provide the other Party with weekly updates (i) estimating its expected duration, the cost of any remedial action, and the probable impact on the performance of its obligations hereunder, (ii) of the actions taken to remove or overcome the event of Force Majeure and (iii) 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.

10.3 Suspension; Termination Due to Force Majeure. If any event of Force Majeure claimed by Contractor or Owner delays Contractor’s performance of substantially all of the Services for an aggregate time period greater than *** consecutive Days, then either Party shall have the right to terminate this Agreement without liability upon *** Days prior written notice to the other Party.

11. MECHANICAL COMPLETION; SUBSTANTIAL COMPLETION; FINAL COMPLETION

11.1 Mechanical Completion. “Mechanical Completion” shall mean that the following conditions have been satisfied:

(a) All materials, equipment and systems (other than any Punch List Items) related to the safe start-up and testing of the Facility (excluding any

32

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

permanent improvements on the Site not to be performed, provided, construction managed or administered by Contractor as part of the Services) shall have been constructed and installed in accordance with the applicable Owner Contract and applicable Laws, and in a manner that does not void any warranties, and all such systems shall have been checked for alignment, lubrication, rotation and hydrostatic and pneumatic pressure integrity as required;

(b) The Owner Equipment and the GE Equipment (excluding the air separation unit), respectively, shall be ready to turn over to Owner for start-up pursuant to the applicable Owner Contract;

(c) Contractor shall have delivered to Owner all Documentation that Contractor is required to deliver to Owner pursuant to the Contractor EP Schedule and the Project Schedule, by the Mechanical Completion Date;

(d) Contractor shall have delivered to Owner the turnover packages (the required contents of which shall be determined by Owner) for each system as signed by Contractor and a certificate certifying that, to Contractor’s knowledge, all of the preceding conditions in this Section 11.1 have been satisfied (the “Notice of Mechanical Completion”); and

(e) Within five (5) Days of receipt of the Notice of Mechanical Completion by Owner, Owner shall inspect the Facility related to Contractor’s Scope of Services and, following such inspection, Owner shall either: (i) deliver to Contractor a written acceptance of Contractor’s Notice of Mechanical Completion (the “Certificate of Mechanical Completion”) or (ii) notify Contractor in writing that it disputes Contractor’s certification that the conditions for Mechanical Completion have been met, stating with specificity the reasons therefor. If Owner issues the Certificate of Mechanical Completion, the date of Owner’s issuance of the Certificate of Mechanical Completion shall be deemed the Mechanical Completion Date. If Owner notifies Contractor that it disputes satisfaction of the conditions for Mechanical Completion, then Contractor shall either promptly undertake such action or Services as is necessary to meet such conditions and issue another Notice of Mechanical Completion to Owner upon completion thereof or refer the matter to dispute resolution in accordance with Article 23. In the event Contractor prevails in the Dispute, the fifth (5^th) Day following the date of Owner’s receipt of the then applicable Notice of Mechanical Completion will be deemed the Mechanical Completion Date.

11.2 Substantial Completion. “Substantial Completion” shall mean that the following conditions have been satisfied:

(a) Mechanical Completion shall have been achieved; and

(b) “Substantial Completion” (as defined in the GE Equipment Contract) shall have occurred. Owner shall notify Contractor in writing within ten (10) Days

33

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

of achievement of “Substantial Completion” under the terms of the GE Equipment Contract.

11.3 Final Completion. “Final Completion” shall mean that the following conditions have been satisfied:

(a) Substantial Completion shall have been achieved;

(b) Contractor shall have completed the performance of the Services according to all of the provisions of this Agreement, other than items that cannot be completed until after Final Completion (e.g., warranty work);

(c) Contractor shall have delivered to Owner the Documentation that Contractor is required to deliver to Owner pursuant hereto by the Final Completion Date;

(d) Contractor shall have delivered to Owner a certificate signed by Contractor certifying that the conditions set forth in the preceding clauses (b) and (c) in this Section 11.3 have been satisfied (the “Notice of Final Completion”); and

(e) Within five (5) Business Days of receipt of the Notice of Final Completion by Owner, Owner shall inspect the Facility related to Contractor’s Scope of Services and, following such inspection, Owner shall either: (i) deliver to Contractor a written acceptance of Contractor’s Notice of Final Completion (the “Certificate of Final Completion”), or (ii) notify Contractor in writing that it disputes Contractor’s certification that the conditions for Final Completion have been met, stating with specificity the reasons therefor. If Owner issues the Certificate of Final Completion, the date of Owner’s receipt of the Notice of Final Completion will be deemed the Final Completion Date. If Owner notifies Contractor that it disputes satisfaction of the conditions for Final Completion, then Contractor shall either promptly undertake such action or Services as necessary to meet such conditions and issue another Notice of Final Completion to Owner upon completion thereof or refer the matter to dispute resolution in accordance with Article 23. In the event Contractor prevails in the Dispute, the date of Owner’s receipt of the then applicable Notice of Final Completion shall be deemed the Final Completion Date.

12. WARRANTY

12.1 Warranty. Contractor warrants as follows (collectively, the “Warranties”):

(a) all Services will be performed in a prompt, professional and workmanlike manner in accordance with Prudent Industry Practices, will conform to the requirements of this Agreement, will be free from defects and will reflect competent professional knowledge and judgment;

(b) the design Services will be free from errors and omissions; and

34

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(c) the Engineering Services (i) will be consistent with the data supplied to Contractor by Owner for integration of Owner’s scope of work for the Facility with the remainder of the Facility, (ii) will be consistent with the process design package documents delivered to Owner pursuant to the GE Equipment Contract, as such documents are described in Attachments R-01 through R-08 to Exhibit R of the GE Equipment Contract (as such documents are amended, restated, supplemented or revised in accordance with the GE Equipment Contract) and Attachments R-09 and R-10 to Exhibit R of the GE Equipment Contract (as such documents are amended, restated, supplemented or revised by Contractor and Owner, respectively), in each case provided to Contractor in accordance with the Communication and Management Protocol and applicable Site Project Procedures, (iii) will not cause the Facility to fail to meet the minimum performance guarantees as provided by Owner to Contractor from time to time, (iv) will not cause the Facility to fail to meet the requirements of the Air Permit or NPDES Permit for the Project or any applicable Laws, in each case, as applicable to the Scope of Services, (v) will be consistent with any design criteria provided by any Managed Vendor or Owner Supplier and (vi) will be consistent with the Scope Book and the Mine Remediation Reports.

12.2 Defects. If any deviation from, breach of, or failure of the Warranties (a “Defect”) is discovered by Owner or Contractor, Contractor shall commence, within a timely manner upon such Defect being discovered or upon notice of such Defect from Owner (which notice shall be delivered promptly but in any event no later than thirty (30) days from discovery), to correct, and diligently and continually prosecute measures which are reasonably calculated to correct, such Defect, including re-performance or re-provision of any affected portion of the Services, and shall demonstrate to Owner’s reasonable satisfaction that such Defect has been properly corrected. The Parties shall use commercially reasonable efforts to coordinate performance of warranty Services at a time responsive to and consistent with Owner’s interest in the efficient operation of its business. *** Contractor shall not be entitled to *** in correcting any Defect during the Warranty Period. Owner shall provide Contractor with reasonable support and access at the Site, facilities, data and information as may be necessary for Contractor to correct Defects; provided, that any such access shall be restricted, and subject to such conditions, as Owner may have instituted generally for its contractors. In no event shall Contractor’s warranty obligations include any obligation to perform or to be liable for the costs of any remedial construction rework, repair or replacement of components, parts, equipment or material.

12.3 Extension of Warranty Periods. If a Defect is discovered prior to or within the Warranty Period, then the Warranty Period shall be extended to the *** of the date such Defect was corrected if such *** is later than the last Day of the then existing Warranty Period, but only with respect to the Service that was the subject of such Defect. In no event, however, shall Contractor’s obligations under Section 12.1, including any rewarranty, extend beyond the earlier to occur of (i) *** after Substantial Completion and (ii) *** after achievement of Mechanical Completion.

12.4 Intellectual Property Warranties. Contactor warrants that: (a) the Services, (b) Documentation (other than any Technical Data), (c) Owner’s or any Permitted User’s authorized implementation of processes described in the Documentation (other than any

35

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Technical Data), (d) Owner’s or any Permitted User’s authorized construction or operation of the Facility as described in the Documentation (other than any Technical Data), (e) Owner’s or any Permitted User’s practice or exercise of the Sulfur Intellectual Property Rights, and (f) Owner’s or any Permitted User’s authorized use of data contained in the Documentation (other than any Technical Data) shall 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 of any third party. Contractor warrants that it has the right to grant the licenses purported to be granted by it herein. The foregoing warranties shall not apply with respect to Owner’s exercise of any intellectual property rights owned by GE (and not owned by Contractor) or any modification to the Documentation made by Owner or its Permitted Users, unless such modification was authorized in writing by Contractor. In the event Owner terminates the Agreement pursuant to Section 19.5(b) and Owner fails to pay the License Continuation Fee identified in Section 19.5(c)(ii), then the warranty obligations contained in Sections 12.4(b), (c), (d) and (f) shall immediately cease and terminate.

12.5 Responsibility for Warranty Services. Contractor shall have primary liability with respect to the warranties specified in Sections 12.1 and 12.4, whether or not any Defect or other matter is also covered by a warranty of a Subcontractor, and Owner need only look to Contractor to correct such Defect. 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 Services shall not excuse Contractor from its liability on its warranties to Owner. Contractor shall have no liability for fabrication errors or violations of an Owner Services Contract or an Owner Equipment Contract or other defect in items supplied or work performed by Owner Suppliers unless such items or work were prepared or performed in accordance with the Design Documentation provided by Contractor or otherwise at the direction of Contractor, in which case Contractor’s liability shall be limited to the re-performance of the applicable Services that are the cause of such error, violation or defect.

12.6 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 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.

13. INDEMNIFICATION

13.1 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 and Financial Institutions (collectively, the “Owner Indemnitees”) from and against:

36

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(a) any and all Third Party Claims and all damages, liabilities, losses, costs and expenses associated therewith (including reasonable attorneys’ fees and other professionals’ fees) for any injury of or death to persons, damage to or destruction of third party property (other than the Facility), 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 negligence or willful misconduct of Contractor;

(b) any fines or penalties arising out of any violation or alleged violation of Laws by Contractor; and

(c) 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 reasonable attorneys’ fees and other professionals’ fees) for improper management of Hazardous Materials brought onto or generated (other than normal operational by-products) on the Site by Contractor and, with respect to any Hazardous Materials brought onto the Site in containers, any release of such Hazardous Materials caused by Contractor.

In no event shall Contractor’s indemnification obligations hereunder extend to bodily injury or property damage claims brought by employees of Managed Vendors, or any of Owner’s other contractors, and their respective lower-tier subcontractors. Owner agrees that it shall use commercially reasonable efforts to cause all indemnity, release, additional insured and hold-harmless agreements contained in Owner Contracts whereby the Managed Vendors agree to indemnify, release or hold harmless Owner or name Owner as an additional insured to extend similar protection to Contractor. Contractor’s liability under Section 13.1(c) shall terminate *** after the expiration of the Warranty Period.

13.2 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”) from and against:

(a) any and all Third Party Claims and all damages, liabilities, losses, costs and expenses associated therewith (including reasonable attorneys’ fees and other professionals’ fees) for any injury of or death to persons, damage to or destruction of third party property (other than the Facility), 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 negligence or willful misconduct of Owner;

(b) any fines or penalties arising out of any violation or alleged violation of Laws by Owner; and

(c) 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 reasonable attorneys’ fees and other professionals’ fees) for:

37

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(i) any pre-existing environmental conditions existing at the Site and any damages or claims resulting from Hazardous Materials brought onto or generated on the Site by any party other than Contractor, as well as any normal operational by-products; or

(ii) any mine remediation work or mine subsidence performed by or on behalf of Owner; provided, that Owner’s indemnity obligations under this Section shall not extend to any failure of Contractor to address or incorporate information specifically stated in the Mine Remediation Reports.

13.3 Intellectual Property Indemnity. Contractor shall defend, indemnify and hold harmless Owner Indemnitees from and against all liabilities, actions, damages, claims, demands requests, judgments, losses, costs, expenses, suits or actions, including reasonable attorneys’ fees and court costs for allegations that the Services, Documentation (other than any Technical Data), Owner’s or any Permitted User’s authorized implementation of processes described in the Documentation (other than any Technical Data), Owner’s or any Permitted User’s practice or exercise of the Sulfur Intellectual Property Rights, Owner’s or any Permitted User’s authorized construction or operation of the Facility as described in the Documentation (other than any Technical Data), or Owner’s or any Permitted User’s authorized use of data contained in the Documentation (other than any Technical Data) infringe any intellectual or proprietary right of any third party, including any copyrights, patent rights, trademark rights, trade secret rights or confidentiality rights of any third party. The foregoing obligations shall not apply with respect to infringements caused solely by Owner’s exercise of any intellectual property rights owned by GE (and not owned by Contractor) or any modification to the Documentation made by Owner or its Permitted Users, unless such modification was authorized in writing by Contractor. In the event Owner terminates the Agreement pursuant to Section 19.5(b) and Owner fails to pay the License Continuation Fee identified in Section 19.5(c)(ii), then the indemnity obligations contained in this Section 13.3 shall (i) only apply to the actions or activities (including, without limitation, the use of any Documentation) of the Owner Indemnitees taken prior to the expiration of the license granted pursuant to Section 18.2 and (ii) survive for a period of *** from the date of such termination or expiration.

13.4 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 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 obligation to conduct and control, through counsel of its own choosing, reasonably acceptable to the

38

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Indemnified Party, any Third Party Claim; provided, however, that (i) the Indemnified Party may, at its election, participate in the defense thereof at its sole cost and expense and (ii) 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 indemnifying 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, (iii) the Indemnified Party or its Affiliates will have no liability with respect to such compromise or settlement, and (iv) the Indemnified Party and its Affiliates will have no restriction on their respective exercise of rights granted herein. 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.

13.5 Insurance. Notwithstanding anything in this Agreement to the contrary, the indemnification obligations in this Agreement are independent of, and shall not be limited by, any insurance required hereunder or otherwise available.

14. INSURANCE

14.1 ***.

(a) ***

(b) ***

39

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(c) ***

(d) ***

(e) ***

(f) ***

14.2 ***

14.3 ***.

14.4 ***.

(a) ***

(i) ***

(A) ***

(B) ***

(C) ***

***

(A) ***

(B) ***

(C) ***

(D) ***

(E) ***

(F) ***

(G) ***

(H) ***

(I) ***

(J) ***

(ii) ***

(b) ***

40

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(c) ***

(d) ***

(e) ***

(f) ***

(g) ***

(i) ***

(ii) ***

14.5 Contractor Insurance.

(a) Contractor shall, and shall require and ensure that each of its Subcontractors performing Services on Site whether or not enrolled in the ***, purchase and maintain the insurance coverages listed below from a company or companies licensed 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 and are reasonably acceptable to Owner. Contractor’s insurance shall be effective as of the Effective Date and shall be maintained until Final Completion, except for Products Liability/Completed Operations coverage, which shall be maintained for ten (10) years beyond Final Completion. Deductible amounts shall be the sole responsibility of Contractor and the Subcontractors.

(i) Automobile, Bodily Injury and Property Damage Liability insurance covering all automobiles whether owned, non-owned, leased or hired, having *** combined single limit;

(ii) All Risk Contractor’s Equipment Insurance covering owned, used and leased tools, construction plant and equipment required to perform the Services (Contractor or Subcontractors may elect to self-insure such exposure if approved in writing by Owner, which approval shall not be unreasonably withheld);

(iii) Workers’ Compensation and Employer’s Liability Insurance having Indiana Statutory Limits with All States coverage including U.S. Longshoremen’s and Harbor Workers Act Coverage as appropriate and Employer’s Liability will be provided with the following limits:

(A) $*** Each Accident Bodily Injury by Disease;

(B) $*** Policy Limit Bodily Injury by Disease; and

(C) $*** Each Disease Bodily Injury by Disease.

41

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Such Workers’ Compensation insurance shall include a waiver of subrogation in favor of the Owner, Contractor and any Subcontractor that is enrolled in the ***.

(iv) Commercial General Liability Insurance covering Off-Site Activities Only (if enrolled in the ***, otherwise without the Off-Site Activities Only limitation) having limits of $*** per occurrence, $*** annual aggregate. Coverage shall be written on an ISO occurrence Form (CG 00 01 12/04) or equivalent and include the following:

(A) Premises-Operations;

(B) Products Liability/Completed Operations;

(C) Broad Form Property Damage;

(D) Contractual Liability (Broad Form) Including Third Party Coverage;

(E) Explosion, Collapse and Underground; and

(F) Fellow Employee Exclusion Removed.

(v) Umbrella Liability covering Off-Site Activities Only *** having limits of $*** per occurrence and aggregate for Contractor and $*** per occurrence and aggregate for Subcontractors. Such umbrella liability policy shall follow the form of the required underlying coverages, be in excess of those underlying policies without gaps in limits and provide coverage as broad as the underlying.

(vi) If aircraft are used in performance of the Services, Contractor shall provide or cause the operators of aircraft to provide Aircraft Liability Insurance having a per occurrence limit of $***.

(b) Prior to beginning any Services at the Site, Contractor and each Subcontractor shall furnish to Owner’s designated *** industry standard ACORD or Owner-approved form certificates evidencing the above coverages. Certificates shall show that policies will not be canceled, renewed or materially modified unless at least thirty (30) days’ prior written notice via certified United States mail has been given to Owner. All coverages and certificates (except Workers Compensation) further shall show Owner and its successors and assigns as additional insureds for their imputed liability as a result of Contractor’s negligent operations hereunder, using ISO additional insured (CG 20 10 11 85) or equivalent of the combination of forms CG 2033 and CG 20 37 for completed operations. All insurance coverage shall include a waiver of subrogation rights by the insurer against Owner, Contractor and Subcontractors *** and as contractually required. Neither approval nor failure to disapprove insurance furnished by Contractor or any Subcontractor shall relieve

42

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Contractor from responsibility to provide, or cause to be provided, insurance as required by this Agreement.

14.6 General Requirements.

(a) Contractor acknowledges and agrees that Contractor’s costs for maintaining the insurance required under Section 14.5 are *** to the Agreement and will not be separately invoiced ***.

(b) ***

(c) Each Subcontractor *** coverage under this Article shall seek *** by giving written notice to ***, in writing, within two (2) Business Days after the award of any subcontract providing the following information:

1. Subcontract Number

2. Legal Name of Subcontractor

3. Address

4. Telephone, persons to contact

5. Estimated amount of subcontract

6. Estimated dates the subcontract work will commence and will be completed

7. Type(s) of work to be performed

It is the responsibility of Contractor to cause all of its Subcontractors to give such written notice ***. Subcontractors who are not *** shall not be covered by ***. Owner shall have no liability or responsibility for the absence of insurance coverage for Subcontractors who do not provide written notice as described in this Section.

(d) Promptly upon placement of ***, Contractor shall properly ***. All Subcontractors shall properly *** prior to commencing any services at the Site.

(e) All dividends or refunds payable under *** shall be the property of Owner and are hereby assigned to Owner.

(f) Contractor and each Subcontractor shall report all accidents and shall assist in every manner reasonable in the investigation of any accident. Upon request, Contractor and each Subcontractor shall cooperate with Owner and the insurance company designated by Owner in the handling of any claim by securing and giving evidence and obtaining the attendance of witnesses as required for any claim or suit.

(g) Contractor and each enrolled Subcontractor shall furnish *** with information required to issue any insurance policies to be provided under this Article. If requested by Owner, Contractor and each enrolled Subcontractor shall attend a meeting held to explain and discuss ***.

43

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(h) Contractor shall incorporate a copy of these insurance requirements in each subcontract and shall require each enrolled Subcontractor to whom these requirements apply to fully comply with these insurance requirements.

(i) Contractor shall not attempt to exercise any right to cancel *** policy without the express written consent of Owner.

(j) Nothing contained in this Article 14 will relieve Contractor or its Subcontractors of their respective obligations to exercise due care in the performance of their duties in connection with the Services and to complete the Services in strict compliance with the Agreement.

14.7 Contractor Responsibility. The provisions of this Article 14 do not modify or change any responsibility of Contractor or any of 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 obligations as stated in Article 13 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 Contractor’s insurance coverages.

15. PROJECT CREDIT SUPPORT

15.1 ***.

(a) ***

(b) ***

(c) ***

(d) ***

15.2 Cooperation with Owner Financing.

(a) Contractor shall promptly provide to Owner (i) all cooperation that Owner reasonably requests to make presentations to potential Financial Institutions and their consultants and representatives and to respond to any questions or requirements asked or imposed by any Financial Institutions, and (ii) all cooperation that Owner reasonably requests with respect to Financial Institutions and their consultants and representatives, including developing and providing information regarding the Facility (to the extent available to Contractor) and this Agreement. At the request of Owner, Contractor shall provide the Financial Institutions and their consultants and representatives with reasonable access to, and will permit them to review, the Documentation, subject to their execution of a confidentiality agreement substantially in the form of Attachment No. 2 to the Confidentiality Agreement. In addition, Contractor shall provide the Financial Institutions with the right to receive

44

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

and render performance and to give reasonable time to cure defaults by Owner, on behalf of Owner, under this Agreement.

(b) Owner shall be entitled to grant a security interest or other lien in this Agreement to one or more Financial Institutions as security for financing for the Project. Contractor also shall enter into a consent to assignment with the Financial Institutions regarding this Agreement in a customary form. Owner will be entitled to assign, and Contractor shall ensure that the relevant instruments permit the assignment of, the benefit of any *** or other financial instrument at any time to the Financial Institutions to secure the obligations of Owner under the financing for the Project without the consent of Contractor or the issuer of such *** or other financial instrument being required.

16. LIMITATION OF LIABILITY

16.1 Liability Cap. CONTRACTOR’S AGGREGATE LIABILITY UNDER THIS AGREEMENT WILL NOT EXCEED ***.

16.2 No Consequential Damages. NEITHER OWNER NOR CONTRACTOR WILL BE LIABLE TO THE OTHER FOR CONSEQUENTIAL DAMAGES. THIS SECTION 16.2 SHALL NOT BE INTERPRETED TO LIMIT, AND THE PARTIES AGREE THAT THIS SECTION 16.2 DOES NOT LIMIT, CONTRACTOR’S RIGHT TO COMPENSATION FOR SERVICES UNDER THIS AGREEMENT. IN ADDITION, THE PARTIES AGREE THAT THIS SECTION 16.2 SHALL NOT BE CONSTRUED TO, AND IS NOT INTENDED TO, LIMIT OR RELIEVE EITHER PARTY OF ITS EXPRESS, LIMITED OBLIGATIONS UNDER ARTICLE 13. THE WAIVERS AND DISCLAIMERS OF LIABILITY, RELEASES FROM LIABILITY, LIMITATIONS AND APPORTIONMENTS OF LIABILITY AND EXCLUSIVE REMEDY PROVISIONS AND DEFENSE AND INDEMNITY OBLIGATIONS EXPRESSED THROUGHOUT THIS AGREEMENT SHALL APPLY EVEN IN THE EVENT OF THE FAULT, NEGLIGENCE, STRICT LIABILITY, BREACH OF CONTRACT OR OTHERWISE OF THE PARTY RELEASED OR WHOSE LIABILITY IS WAIVED, DISCLAIMED, LIMITED, APPORTIONED OR FIXED BY SUCH EXCLUSIVE REMEDY PROVISIONS, OR WHO IS DEFENDED OR INDEMNIFIED. TO THE EXTENT A PARTY IS DEFENDED OR INDEMNIFIED HEREUNDER WITH RESPECT TO ANY CLAIM, SUCH PARTY MAY NOT PURSUE A CLAIM AGAINST THE DEFENDING OR INDEMNIFYING PARTY’S AFFILIATES OR SUBCONTRACTORS OR THEIR RESPECTIVE DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS FOR THE SAME CLAIM.

17. LIENS

17.1 Liens. Contractor shall keep the Facility, the Site, the Owner Equipment, the GE Equipment and any other structure or equipment at the Site free from all Liens and shall promptly notify Owner of any such Liens.

17.2 Discharge or Bond. Contractor shall take prompt steps to discharge or bond any Lien. If Contractor fails to so discharge or promptly bond any Lien, Owner shall have the

45

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 at Contractor’s expense, including reasonable attorneys’ fees, costs and expenses. Owner shall have the right to deduct and offset any expenses so incurred from any payment due, or which may become due, to Contractor under this Agreement or to recover those expenses from Contractor. Contractor shall have the right to contest any Lien, provided 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 the Lien in accordance with the Laws of the State.

18. INTELLECTUAL PROPERTY

18.1 Delivery of Documentation. Contractor shall deliver to Owner complete and accurate copies (in physical and electronic format) of all Documentation required hereunder to be prepared or delivered, or otherwise agreed by the Parties to be delivered by Contractor, in accordance with the following:

(a) Documentation for which a specific delivery date or delivery schedule is set forth herein or in the Scope Book, including within the Contractor EP Schedule and Project Schedule, shall be delivered in accordance with such delivery date or delivery schedule;

(b) Documentation prepared in conjunction with the Services necessary for the performance of a specific task, procedure or test for which a specific delivery date or delivery schedule is not set forth herein, in the Scope Book or in the Contractor EP Schedule and Project Schedule shall be delivered to Owner a reasonable period of time (as determined by Owner) prior to the performance of such task, procedure or test necessary to support the needs of the Project;

(c) All final, “as-built” Documentation (in hard copy and electronic formats (non-native files)) as provided in Reference 3-10 of Part I of the Scope Book, including all drawings of buildings, structures, plants, operating equipment and ancillary plant equipment, shall be delivered no later than Final Completion; and

(d) Technical Data shall be delivered to Owner at Final Completion, and to be used in future modifications at Owner’s sole risk (and provided for such purpose “AS IS” without warranty by Contractor).

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 of an “as-built” status upon Final Completion. Contractor shall provide Owner during the Warranty Period any corrections to errors discovered by Contractor or Owner in the Documentation (other than any Technical Data) subsequent to Final Completion. Contractor shall promptly notify Owner of the discovery of any such errors. In the event that this Agreement is terminated: by Owner pursuant to Section 19.2(a); by Contractor or Owner pursuant to Section 19.6; or by Owner pursuant to Section 19.5(a) or 19.5(b) and, with respect to termination pursuant to Section 19.5(b), Owner pays the License Continuation Fee as

46

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

described in Section 19.5(c)(ii), then Contractor shall deliver to Owner within ten (10) Days after such termination all then existing Documentation, including drafts thereof, in hard copy and electronic formats reasonably requested by Owner, provided that such Documentation and the intellectual property rights resulting from the Services or related to or described in the Documentation shall continue to be subject to the Confidentiality Agreement and this Article. The media on which Documentation is provided to Owner will be free of viruses and other harmful or malicious code or programming and will be capable of conveying the information contained therein correctly.

18.2 Grant of Intellectual Property License. Contractor hereby grants to Owner, its Affiliates and each Permitted User an irrevocable (subject to the last sentence of this Section 18.2), perpetual, royalty-free, fully paid up nonexclusive license to (a) reproduce, distribute, display, perform, create derivative works from and otherwise use the Documentation and (b) practice, make, exercise and otherwise use all intellectual property rights resulting from the Services or related to or described in the Documentation, in each case, solely for the purposes of Facility design, construction, maintenance, operation (for electricity generation, byproduct production or otherwise), training, modification, consultation, repair, reconstruction, licensing, simulation, commissioning, decommissioning and compliance with Laws and otherwise for Owner’s internal business purposes (collectively, the “Permitted Purposes”). To the extent that exercise of the foregoing license rights requires use or disclosure of Confidential Information as defined in the Confidentiality Agreement, such use or disclosure shall be subject to the terms and conditions set forth in the Confidentiality Agreement; provided, however, that restrictions in the Confidentiality Agreement on the use of Contractor’s Confidential Information by Competitors of Contractor prior to the Substantial Completion Date shall cease and terminate in the event that this Agreement is terminated by Owner pursuant to Section 19.2(a). In the event that Owner terminates this Agreement pursuant to Section 19.5(b) and fails to pay the License Continuation Fee, if any, by the date such License Continuation Fee is due pursuant to Section 19.5(c)(ii), then the foregoing license shall immediately cease and terminate.

18.3 Grant of Sulfur License. Contractor hereby grants to Owner, its Affiliates and each Permitted User an irrevocable (subject to the last sentence of this Section 18.3), perpetual, royalty-free (other than the Sulfur License Royalty), and nonexclusive license to practice and exercise the Sulfur Intellectual Property Rights for the removal of hydrogen sulfide and production of sulfur and otherwise for any of the Permitted Purposes (the “Sulfur License”). In consideration for the Sulfur License, Owner shall pay to Contractor a one-time royalty fee in an aggregate amount equal to $*** (the “Sulfur License Royalty”) in a manner determined by the Parties. To the extent that exercise or practice of the Sulfur License requires use or disclosure of Bechtel Sulfur Information as defined in the Confidentiality Agreement, such use or disclosure shall be subject to the terms and conditions set forth in the Confidentiality Agreement; provided, however, that restrictions in the Confidentiality Agreement on the use of Bechtel Sulfur Information by Competitors of Contractor prior to the Substantial Completion Date shall cease and terminate in the event that this Agreement is terminated by Owner pursuant to Section 19.2(a). In the event that Owner terminates this Agreement and fails to pay the Sulfur License Royalty (to the extent not then paid) within *** following the date of such termination, then the Sulfur License shall cease and terminate.

47

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

18.4 Limitations. Contractor reserves all intellectual property rights not set forth herein. Owner shall not remove any patent, copyright or trademark notice from the Documentation. Owner hereby grants to Contractor an irrevocable, non-exclusive, worldwide, royalty-free license under Sulfur Licensee Improvements and Sulfur Jointly Developed Improvements to use Sulfur Licensee Improvements and Sulfur Jointly Developed Improvements in the Claus sulfur recovery, hydrogenation tail gas treating and thermal oxidizing processes or for any other purpose, together with the right to grant licenses, without accounting therefor to Owner and with no restrictions on sublicensing of any Sulfur Licensee Improvement or any Sulfur Jointly Developed Improvement. Within a reasonable time after request by Contractor, Owner shall make qualified personnel available to discuss with Contractor whether any material Sulfur Licensee Improvements or Sulfur Jointly Developed Improvements have been created, and, if so, subsequent to such discussions, to document such Sulfur Licensee Improvements or Sulfur Jointly Developed Improvements. THE SULFUR LICENSEE IMPROVEMENTS AND SULFUR JOINTLY DEVELOPED IMPROVEMENTS ARE PROVIDED “AS IS” AND WITHOUT WARRANTY OF ANY KIND, WHETHER EXPRESS OR IMPLIED, AND ALL IMPLIED WARRANTIES INCLUDING ANY WARRANTY OF MERCHANTABILITY RELATING TO SUCH IMPROVEMENTS ARE HEREBY EXPRESSLY DISCLAIMED BY OWNER. USE OF THE SULFUR LICENSEE IMPROVEMENTS AND SULFUR JOINTLY DEVELOPED IMPROVEMENTS BY CONTRACTOR AND ITS LICENSEES ARE AT CONTRACTOR’S SOLE RISK. CONTRACTOR SHALL INDEMNIFY, DEFEND AND HOLD HARMLESS OWNER AND ITS AFFILIATES FOR AND AGAINST ALL CLAIMS RELATED TO ANY SUCH IMPROVEMENTS MADE AGAINST OWNER OR ITS AFFILIATES BY A PERSON TO WHICH CONTRACTOR OR ITS AFFILIATES HAVE PROVIDED OR LICENSED ANY SULFUR LICENSEE IMPROVEMENT AND SULFUR JOINTLY DEVELOPED IMPROVEMENT.

18.5 Other Licenses. To the extent that a license may be required under any patent, copyright, trade secret right or other proprietary right of Contractor or Subcontractor to perform a Permitted Purpose, Contractor hereby grants to Owner, its Affiliates and each Permitted User an irrevocable, perpetual, royalty-free, nonexclusive license to practice and exercise such other patent, copyright, trade secret right and proprietary right for any Permitted Purpose.

18.6 Additional Warranties, Representations and Covenants. Contractor represents, warrants and covenants that, except for the license rights granted herein and except with respect to any intellectual property owned exclusively by GE contained in such Documentation, Contractor owns all rights, title and interest in and to the Documentation and has the right to grant the license rights granted by Contractor herein.

19. DEFAULT; TERMINATION AND SUSPENSION

19.1 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”):

48

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(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 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;

(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; and

(d) Breach. Contractor breaches any of its material obligations under this Agreement other than those obligations relating to the matters set forth in Section 19.1(a) through (c) and for which no other remedy is specified in this Agreement and, if such breach is capable of being cured, Contractor 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 Contractor immediately commences to cure such breach and diligently and continually prosecutes measures which are reasonably calculated to cure such breach within such *** period.

19.2 Owner Remedies. In the event of a Contractor Default, Owner shall have any or all of the following rights and remedies:

(a) Termination. Owner may terminate this Agreement immediately by delivery of a notice of termination to Contractor, in which event, as Owner’s sole and exclusive remedy in connection with termination for a Contractor Default, but without prejudice to remedies that Owner may have for breach of any obligations that survive termination, Owner may recover from Contractor (subject to Article 16) Owner’s actual and reasonable costs (at fully burdened rates for internal personnel costs) of replacing Contractor and mobilizing one or more other contractors in order to complete the Services, including (i) all actual and reasonable costs of preparing requests for proposals, reviewing proposals, selecting and negotiating with contractors and (ii) all actual and reasonable costs for the replacement contractors to mobilize, review and understand Project-related documents and meet with Project participants in order to get to substantially the same position as Contractor was at the point of termination; and

49

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(b) Other Remedies. Subject to Article 16 and Section 24.1, if Owner does not terminate this Agreement pursuant to Section 19.2(a) as a result of such Contractor Default, Owner shall have any other remedy available at law or in equity.

19.3 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) Insolvency. Owner 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;

(b) 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

(c) Material Breach. Unless due to the breach by Contractor of its obligations hereunder, suspensions of all or substantially all of the Services for a period of *** consecutive Days or a cumulative total of *** Days, in the aggregate, in any *** period.

19.4 Contractor Remedies. In the event of an Owner Default, Contractor shall have any or all of the following rights and remedies:

(a) Termination. Contractor, without prejudice to remedies that Contractor may have for breach of any obligations that survive termination, may terminate this Agreement immediately by delivery of a notice of termination to Owner, and such termination shall be deemed as if done for convenience of Owner under Sections 19.5(b) and 19.7;

(b) Other Remedies. Subject to Article 16 and Section 24.1, Contractor shall have any other remedy available at law or in equity.

19.5 Termination Rights.

(a) Termination for Project Cancellation. Upon prior written notice to Contractor, Owner will be entitled to terminate this Agreement at any time as a result of Project cancellation by Owner, in which event Owner shall pay the cancellation charges set forth in Section 19.5(c)(i).

50

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(b) Termination for Convenience. Owner may terminate this Agreement at its convenience and in its entirety upon prior written notice to Contractor (provided, that, for a period of *** after such written notice, representatives of each of Contractor and Owner (escalating to executives) shall discuss the issues prompting such notice and at any time prior to expiration of such 30-Day period, Owner, in its sole discretion, may withdraw such notice), in which event Owner shall pay the cancellation charges set forth in Section 19.5(c)(ii) below.

(c) Cancellation Charges.

(i) If Owner terminates this Agreement under Section 19.5(a), Owner shall pay the termination charges to Contractor, within thirty (30) Days after the date of such termination, 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 Services performed in accordance with this Agreement prior to such termination, ***, and all unavoidable and reasonably incurred demobilization costs, including cancellation charges paid to Subcontractors (collectively, the “Termination Charges”). The total amount payable by Owner as a Termination Charge shall be reduced by any rebates, credits or refunds obtained or, if the Termination Charge has been paid, Contractor shall refund to Owner the amount of such rebates, credits or refunds.

(ii) If Owner terminates this Agreement under Section 19.5(b), Owner shall pay to Contractor, within thirty (30) Days after the date of such termination, as Contractor’s exclusive remedy, an amount equal to (A) the Termination Charges calculated as of the date of such termination in the manner set forth in Section 19.5(c)(i), plus (B) if Owner desires to maintain the license granted pursuant to Section 18.2 following such termination, an amount (which shall not be less than zero) equal to $*** (the amount determined pursuant to this clause (B), the “License Continuation Fee”).

19.6 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 10, provided that such termination shall not relieve the terminating Party from its obligation to pay any then due and owing amounts hereunder.

19.7 Suspension.

(a) Owner may, in its sole discretion, order Contractor to suspend all or any portion of the Services 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.

(b) Contractor may suspend the Services without liability upon written notice to Owner after the occurrence of any of the following:

51

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

(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) Breach. Owner breaches any of its material obligations under this Agreement other than those obligations relating to the matters set forth in Section 19.7(b)(i) above and for which no other remedy is specified in the 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.

(c) During any suspension pursuant to Section 19.7(a) and Section 19.7(b)(ii), Contractor shall, to the extent requested by Owner and as a ***, maintain its Project personnel designated to provide the Services hereunder for a period of six (6) months from the commencement date of such suspension. During any such suspension, Contractor shall, to the extent requested by Owner and at Owner’s direction, (i) mobilize and demobilize Contractor’s plant, forces and equipment, (ii) suspend all rental agreements, if any, and (iii) maintain and protect that portion of the work that has been suspended. Contractor shall be reimbursed on a *** for all *** reasonably incurred and directly related to the performance of such activities at Owner’s request and direction and such other *** in connection with such suspension. Within ten (10) Days (i) with respect to suspension under Section 19.7(a), after Owner gives Contractor written notice to resume Services, or (ii) with respect to suspension under Section 19.7(b)(ii), after Contractor acknowledges that Owner has remedied the breach, Contractor shall submit a plan for resumption of the suspended Services. Contractor and Owner shall discuss and agree upon such plan for resumption of the suspended Services, but in any event Contractor shall use all commercially reasonable efforts to fully resume the Services as soon as reasonably possible. In the event a suspension pursuant to Section 19.7(a) continues for more than ***, Contractor shall have the right to terminate the Agreement.

(d) During any suspension pursuant to Section 19.7(b)(i), Contractor shall (i) mobilize and demobilize Contractor’s plant, forces and equipment, (ii) suspend all rental agreements, if any, and (iii) maintain and protect that portion of the work that has been suspended but only to the extent necessary to address any personnel safety issues. Contractor shall be reimbursed on a *** for all *** reasonably incurred and directly related to the performance of such activities, as well as all other *** reasonably incurred by Contractor in connection with such suspension. Contractor shall resume any suspended Services promptly following the reason for such suspension ceasing and shall use all commercially reasonable efforts to fully resume the Services as soon as reasonably possible.

52

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

20. Intentionally Omitted.

21. RECORDS AND AUDIT; COOPERATION

21.1 Intentionally Omitted.

21.2 Accounting Records. Except to the extent applicable Law requires a longer retention, Contractor shall maintain and shall cause its Subcontractors to maintain complete accounting records relating to all Services performed or provided under this Agreement *** 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 (or, if Final Completion does not occur, for three (3) years after termination of this Agreement), except that records relating to Sales and Use Taxes for such items must be retained for four (4) years as specified in Section 21.5. 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.

21.3 Audit Rights.

(a) For verification of ***, Owner or its authorized representative shall have the right and complete access at reasonable times during normal business hours to examine, audit and copy Contractor’s records and books related to *** as is reasonably necessary for Owner to verify such costs. Neither Owner nor its authorized representative shall have the right to audit Contractor’s records and books concerning agreed rates, agreed lump sum amounts, agreed allowances or multipliers. If any audit 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 (i) *** or (ii) the maximum rate allowed by applicable Law.

(b) ***

(c) Any records made available by one Party to the other Party for audit that are proprietary or confidential in nature will be deemed to be Confidential Information of such Party without the need for any marking or other designation and shall be held by the receiving Party in confidence as provided in the Confidentiality Agreement, except as disclosure may be required in order to pursue an audit claim. Any such audit shall be at the expense of the Party conducting such audit; provided, however, that the Party being audited shall provide reasonable assistance necessary to enable the auditing Party to conduct such audit.

53

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

21.4 Cooperation.

(a) Contractor acknowledges that Owner is a regulated entity that is subject to the jurisdiction of the Indiana Utility Regulatory Commission (the “IURC”) and other Government Authorities and, as such, must from time to time provide information about its operations, business and affairs to the IURC and such other Government Authorities. Accordingly, subject to the procedures set forth in Section 21.4(b), Contractor shall promptly and in good faith cooperate with Owner in all requests for information by the IURC or any such Government Authority or by Owner for the IURC or any such Government Authority, including providing testimony and such assistance and information as Owner may reasonably request and that is available to or can be developed or produced by Contractor relating to Contractor, any Subcontractor, the Services, the CM ISBL Work, the Facility or the Project in order for Owner to comply with requests from Government Authorities having jurisdiction over it, including the IURC, irrespective of whether compliance with such request is mandated by applicable Laws.

(b) The IURC has retained the services of Black and Veatch Corporation as its advisor with respect to the Project (“B&V”). Notwithstanding anything contained herein to the contrary, in the event that Owner receives an order or other request for information by the IURC or any Government Authority that Owner believes could reasonably be expected to require the disclosure of Contractor Confidential Information, technical engineering deliverables created by Contractor, Contractor’s construction procedures, or Contractor’s proprietary estimating and pricing information, methods and procedures that, in each case, have not been specifically created for the Project, Owner shall promptly provide notice of such order or other request for information to Contractor. Following such notice, Owner and Contractor agree to meet promptly and in good faith to determine the process that Owner shall use in responding to such request, which may include the implementation of information access procedures necessary to control the access of B&V to such Contractor information, in order to limit and protect the disclosure of such Contractor Information to B&V while ensuring that Owner complies with such requests in all respects.

21.5 Sales 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 payable with respect to the Services and (b) any assessment, refund claim or proceeding relating to Taxes payable with respect to the Services. 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 Services or the payment of Sales Taxes, if any, for a period of not less than four (4) years from the Final Completion Date (or, if Final Completion does not occur, for four (4) years after termination of this Agreement). 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,

54

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 Services; provided, that if Owner requires Contractor to take action under this Section at any time after two (2) years after completion of the particular item of Services, Owner shall reimburse Contractor for all actual and reasonable expenses Contractor incurs in taking those actions.

22. TAXES

22.1 General. Contractor shall pay all Taxes on Contractor’s employees, purchases of goods, tools, equipment, supplies and other consumables which are not permanently incorporated into the Facility and which remain the property of the Contractor. Contractor shall also pay all Taxes attributable to Contractor’s and its Subcontractors’ employees, construction equipment, temporary buildings and other property used by Contractor and its Subcontractors in its performance of the Services under this Agreement which are not permanently incorporated into the Facility and which remain the property of the Contractor. Allowance for such Taxes is not included in ***, and 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.

22.2 Sales and Use Taxes. For Sales and Use Tax purposes of the State, the Parties agree that this Agreement is a separated contract. Owner shall pay directly when due and payable all Sales and Use Taxes. Owner shall provide to Contractor an Indiana Direct Pay Permit and ST-105 Certificate. If an audit by a Government Authority determines that any additional Sales and Use Taxes are due from Contractor, then Owner shall reimburse Contractor for such Sales and Use Taxes promptly upon receipt of an invoice for such Sales and Use Taxes.

22.3 Tax Indemnification. Contractor shall defend, indemnify and hold harmless Owner and its Affiliates from and against all claims by any Government Authority claiming Taxes based upon gross receipts or on the income of Contractor, its Subcontractors or their respective employees, agents or representatives derived from any payment for the Services made to or earned by such Persons under the Agreement. If required by Law or any Government Authority, Owner shall have the right to withhold amounts, at the withholding rate specified by Law, from payments due from Owner to Contractor hereunder, and any amount so withheld shall be credited against any payment otherwise owing by Owner to Contractor under the Agreement.

22.4 Cooperation and Assistance. Contractor shall promptly notify Owner upon receipt by Contractor of any proposed tax audits or tax assessments relating to the Services. Contractor shall assist and cooperate with Owner’s efforts to minimize potential tax liability by providing records and other necessary documentation to appropriate authorities in response to such proposed tax audits or tax assessments.

22.5 Tax Protests and Appeals. If it elects to do so, Owner shall be entitled to protest, defend or appeal in the name of Contractor or a Subcontractor, as the case may be, in any and all administrative and judicial proceedings: (a) the assessment of any Taxes or (b) the

55

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

denial of any refund claim filed. Should Owner elect to protest or appeal any assessment or denial, Contractor shall reasonably cooperate and assist as necessary with such protest or appeal. The Parties agree that any such protest or appeal shall be controlled by Owner, including choice of counsel, with Owner bearing all costs, fees and expenses in furtherance of the protest or appeal. Any and all refunds of Taxes and interest resulting from any protest or appeal shall be solely for the account of Owner. Contractor shall impose a similar obligation in its agreements with Subcontractors.

22.6 Survival. Contractor’s and Owner’s obligations under this Article 22 shall survive the termination or expiration of the Agreement for any reason and shall last so long as necessary to resolve any and all matters regarding Taxes attributable to the Services.

23. DISPUTE RESOLUTION

23.1 Disputes. The Parties hereby agree to submit any dispute or other controversy arising out of or relating to this Agreement, including, with respect to the arbitrability, negotiation, invalidity, termination, or breach thereof, (each a “Dispute”) to resolution in accordance with this Article 23.

23.2 Meeting Regarding Dispute. In the event of a Dispute, the Parties shall first attempt in good faith to settle and resolve such Dispute in accordance with the provisions of this Section 23.2. A Party asserting the existence of a Dispute shall notify the other Party of the Dispute in writing setting forth the nature of the Dispute in reasonable detail. Within *** Days after delivery of any such notice by one Party to the other Party regarding a Dispute, the Parties shall meet at a mutually agreed time and place to attempt, with diligence and good faith, to resolve and settle such Dispute (“Dispute Resolution Meeting”). In the event the Parties are unable to resolve the Dispute, either Party may request that the matter be referred to non-binding mediation. The Parties agree to such non-binding mediation in Indianapolis, Indiana at a mutually agreed upon time and place with a mutually agreed neutral mediator, following procedures agreed to by the Parties or set by the mediator. Should mutual resolution and settlement not be obtained within *** Days after the Dispute Resolution Meeting (or should no such meeting take place within such *** Day period), then either Party may, by notice to the other Party, submit the Dispute to non-administered binding arbitration in Indianapolis, Indiana, in accordance with the International Institute for Conflict Prevention and Resolution’s Rules for Non-Administered Arbitration (the “CPR Rules”) and the provisions of this Article 23. Judgment on the award rendered by the arbitrator(s) may be entered in any court having jurisdiction thereof in accordance with the remaining provisions of this Article 23. Should the Parties agree to engage in mediation, such proceeding shall not affect the timing or process for arbitration.

23.3 Initiation of Binding Arbitration and Selection of Arbitrators. The Party desiring arbitration shall so notify the other Party, identifying in reasonable detail the Dispute to be arbitrated and the relief sought and file notice of arbitration in accordance with the CPR Rules. Arbitration hereunder shall be before *** selected in accordance with the CPR Rules and qualified in the field most relevant to the issues raised in the Dispute. In the event that any Party’s claim exceeds ***, exclusive of interest, the Dispute shall be heard and

56

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

determined by a three-person panel of neutral arbitrators selected in accordance with the CPR Rules and qualified in the field most relevant to the issues raised in the Dispute.

23.4 Arbitration Procedures. The arbitrator(s) shall conduct a hearing no later than ninety (90) Days after submission of the matter to arbitration (or such other timeframe as mutually agreed by the Parties), and a decision shall be rendered by the arbitrator(s) within thirty (30) Days of the hearing. In connection with any Dispute, the Parties shall have such rights to discovery, including depositions, as the arbitrator(s) may permit, provided that, where the amount in controversy with respect to such Dispute is equal to or more than $***, the Parties shall have the rights to discovery set forth in Rules 26 through 36 of the Federal Rules of Civil Procedure (or, to the extent that the proceeding involves only the Parties, in accordance with such rules of discovery as mutually agreed by the Parties). Any dispute concerning discovery will be resolved by the arbitrator(s). Each Party will, upon the written request of the other Party, promptly provide the other with copies of documents on which the requesting Party may rely in support of a claim or defense or which are relevant to the issues raised in the Dispute. At the hearing, the Parties shall present such evidence and witnesses as they may choose, with or without counsel. Adherence to formal rules of evidence shall not be required but the arbitrator(s) shall consider any evidence and testimony that it determines to be relevant, in accordance with procedures that it determines to be appropriate. Any award entered in arbitration shall be made by a written opinion stating the reasons for the award made.

23.5 Consolidation. Owner, in its sole discretion, shall have the option at any time to (a) join Contractor to any arbitration or dispute that involves Owner and any Person providing services to Owner in connection with the Project or (b) consolidate any arbitration or Dispute arising hereunder with any existing arbitration, proceeding or other similar matter which involves Owner and any Person providing services to Owner in connection with the Project, and Contractor hereby consents to any such joinder or consolidation. If Owner and Contractor are involved in an arbitration or dispute in connection with the Project, and Contractor reasonably believes that a third party (including GE, a Managed Vendor or a Subcontractor) is substantially involved in a common question of fact or such third party’s presence is necessary if complete relief is to be afforded and/or inconsistent decisions are to be avoided, then, Contractor shall promptly provide notice thereof to Owner requesting that such third party be consolidated into such arbitration or dispute. If Owner, in its sole discretion, agrees to grant such request, the Parties will use their respective reasonable efforts to consolidate such third party into the applicable arbitration or dispute, making such accommodating adjustments as are fair and appropriate to accommodate additional parties; provided, however, that such third party has consented to such inclusion and agrees to be bound by the award of the arbitrators.

23.6 Enforcement. This submission and agreement to arbitrate shall be specifically enforceable. Arbitration may proceed in the absence of a Party if notice of the proceedings has been given to such Party in accordance herewith. The Parties agree to abide by all awards rendered in such proceedings. During the pendency of a Dispute, each Party shall continue to perform all of its respective obligations under this Agreement. If the Dispute concerns a Party’s cessation of performance under this Agreement, then that Party shall not be deemed in default under the terms of this Agreement with respect to the specific matter that is the subject

57

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

of the Dispute if that Party ceased performance in what it considered in good faith to be compliant with the terms of this Agreement, during the pendency of the Dispute.

23.7  Fees  and  Costs.  Each  Party  shall  bear  its  own  costs  and  expenses  related  to  the  arbitration  and  mediation. The arbitrator’s(s’) fees and mediators fees and other administrative costs of the arbitration and the mediation shall be borne equally by the Parties.

23.8 Interim Relief. Either Party may apply to the arbitrator(s) seeking injunctive relief until the arbitration award is rendered or the controversy is otherwise resolved. Either Party may, without waiving any remedy under this Agreement, seek from any court having jurisdiction any interim or provisional relief that is necessary to protect the rights or property of that Party, pending the establishment of the arbitral tribunal.

23.9 Award. The arbitrator(s) will have no authority to award any damages precluded by Article 16.

23.10 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 23 or arbitration as confidential information of the other Party in accordance with the Confidentiality Agreement and shall use commercially reasonable efforts to cause any arbitrator(s) to keep such information confidential.

24. MISCELLANEOUS PROVISIONS

24.1 Remedies. Subject to Section 12.6, Article 16, Section 19.2(a), Exhibit J and any other provision of the Agreement pursuant to which an exclusive remedy is expressly provided, the rights and remedies available hereunder will be in addition to and not in limitation of any rights and remedies otherwise imposed or available at law or in equity.

24.2 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.

24.3 Entire Agreement. This Agreement and the Confidentiality Agreement represent the entire agreement between Owner and Contractor with respect to the subject matter hereof and thereof, and supersede all prior negotiations, binding documents, representations and agreements, whether written or oral, with respect to the subject matter hereof and thereof, including the Term Sheet, the Initial TSAs and the Recent TSA. This Agreement may be amended or modified only by a written instrument duly executed by each of the Parties.

24.4 Successors and Assigns. Neither this Agreement nor any right, interest or obligation hereunder may be assigned by Contractor 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 to a parent company or a wholly-owned Affiliate, provided that Contractor shall not be relieved of any of its obligations hereunder and provided that such assignee demonstrates to the reasonable satisfaction of Owner that it is capable of fulfilling all of the obligations of Contractor

58

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 may assign this Agreement or any benefit, interest, right or cause of action arising under this Agreement to any Person, provided that, if such assignment occurs prior to payment of the Final Payment Invoice, then such assignment shall not relieve Owner of any of its obligations hereunder.

24.5 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. Neither this Agreement nor anything contained herein shall be construed to create a contractual relationship of any kind between: (a) Contractor and any other contractor or any subcontractor of any such other contractor; (b) Contractor and any Managed Vendor; (c) Contractor and GE; or (d) any person or entities other than Owner and Contractor, except as expressly provided in this Agreement (Owner Indemnitees and Contractor Indemnitees are intended third party beneficiaries under Article 13).

24.6 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 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.

24.7 Survival. Article 13 (Indemnification), Article 16 (Limitation of Liability), Article 18 (Intellectual Property), Article 22 (Taxes), Article 23 (Dispute Resolution), Article 24 (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.

24.8 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 23, 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.

24.9 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) Business Days after the date of mailing if sent by certified or registered mail, or (iii) one (1) Business Day after the date of delivery to

59

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 Indiana, Inc.
	1000 East Main Street, WP631
	Plainfield, Indiana 46168
	Attn: ***
	Title: ***
	Facsimile No.: ***
with a copy to:	Duke Energy Corporation
	139 East Fourth Street, EA025
	Cincinnati, Ohio 45202
	Attn: ***
	Title: ***
	Facsimile No.: ***
If to Contractor:	Bechtel Power Corporation
	5275 Westview Drive
	Frederick, Maryland 21703
	Attn: ***
	Title: ***
	Facsimile No.: ***
with a copy to:	Bechtel Power Corporation
	5275 Westview Drive
	Frederick, Maryland 21703
	Attn: ***
	Title: ***
	Facsimile No.: ***

24.10 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.

24.11 Counterparts. This Agreement may be executed by the Parties in multiple counterparts and shall be effective as of the date set forth above when each Party shall have executed and delivered a counterpart hereof, whether or not the same counterpart is executed and delivered by each Party. When so executed and delivered, each such counterpart shall be deemed an original and all such counterparts shall be deemed one and the same document. Transmission of images of signed signature pages by facsimile, e-mail or other electronic means shall have the same effect as the delivery of manually signed documents in person.

60

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

24.12 Confidentiality. Use and disclosure of Confidential Information (as defined in the Confidentiality Agreement) in the performance of this Agreement shall be governed by the Confidentiality Agreement.

24.13 Business Practices. Contractor and its representatives have not made any payment, and Contractor will not, and Contractor will direct its employees, agents, and Subcontractors, and their employees or agents to not, make any payment to any government official (including any officer or employee of any Government Authority) to influence his, her, or its decision or to gain any other advantage for Owner or Contractor in connection with the Services to be performed hereunder. None of Contractor, its Subcontractors, nor any of their employees or agents shall take any action that violates the United States Foreign Corrupt Practices Act or any similar applicable Law. Contractor shall immediately notify Owner of any violation of this covenant. Owner and its representatives have not made any payment, and Owner will not, and Owner will direct its employees, agents, and their employees or agents to not, make any payment to any government official (including any officer or employee of any Government Authority) to influence his, her, or its decision or to gain any other advantage for Contractor or Owner in connection with the Services to be performed hereunder. Neither Owner nor any of its employees or agents shall take any action that violates the United States Foreign Corrupt Practices Act or any similar applicable Law. Owner shall immediately notify Contractor of any violation of this covenant.

24.14 Covenant of Good Faith and Fair Dealing. Without limiting any rights and obligations as specifically set forth herein, each of the Parties agrees that the obligation of good faith and fair dealing, as applied to contracts governed by the laws of the State of New York is imposed by this Agreement on such Party in its performance, execution and enforcement of this Agreement. This provision is not a choice of law provision but is definitional for purposes of the obligation of good faith.

61

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

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 INDIANA, INC.		BECHTEL POWER CORPORATION
By:	/s/ James L. Turner	By:	/s/ Jack Futcher
Name:	James L. Turner	Name:	Jack Futcher
Title:	Pres & COO, USFE&G	Title:	President

EXHIBIT A

***

EXHIBIT B

EDWARDSPORT

IGCC

Project

Communication and

Management Protocol

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Contains confidential information proprietary to Duke Energy and/or Bechtel which may only be used, reproduced, or disclosed outside of such companies pursuant to the terms of the confidentiality agreement between Duke Energy and Bechtel.

1. PROJECT MANAGEMENT PLAN

The description of the Scope of Services provided by Contractor is contained in the Project Scope Book attached as Exhibit A to the Agreement. The purpose of this Project Communication and Management Protocol (“CM Protocol”) is to further delineate the division of responsibilities identified in the organization chart attached as Exhibit F to the Agreement, generally describe the roles and responsibilities of the Shared Services team and establish an overall communications protocol.

When used in this CM Protocol, capitalized terms are intended to have the same meaning as defined in the Agreement.

1.1. Organization

The Owner will be the overall program manager for the Project and retain control of the Site. Contractor has clear boundaries for its scope of work and for the construction area Contractor is managing. The integrated Owner/Contractor organization chart can be found in Exhibit F to the Agreement which depicts both the home office and Site organizations.

1.1.1. Contractor Project Organization

Contractor will lead the team that is responsible for the coordination and execution of the CM ISBL Work. Owner personnel supporting these activities will function as Borrowed Employees. The ISBL Construction Manager will be an integral participant in the overall Site Management Team (defined below).

The Contractor’s Scope of Services is organized along Contractor’s traditional EPCM large project structure which will be integrated into Owner’s overall Project organization. In general, engineering and procurement activities will be performed in the Houston office for the gasification island and in the Frederick office for the power island. Construction will be performed on a construction management basis using qualified local, regional, and national contractors. Start up activities are to be performed by an Owner-led integrated field site organization. The key Contractor positions (and general description of authority and roles) are as follows:

PROJECT DIRECTOR (***)

• Overall signature authority for all aspects of the Project (as it relates to CM ISBL Work)

• Copied on correspondence as indicated in Section 1.2.1 of this CM Protocol and in accordance with a communications and distribution matrix currently being developed by the Parties

• Signature authority for Agreement requirements (such as Change Orders) and all other issues relating to the Agreement

3

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

PROJECT MANAGER (***)

• Responsible for overall CM ISBL Work and day-to-day project execution with respect to the CM ISBL Work

• Primary contact for all Agreement requirements

• Signature authority for Agreement requirements (such as Change Orders)

• Management of the Agreement

• Overall signature authority for all aspects of the Project (as it relates to CM ISBL Work)

• Copied on correspondence as indicated in Section 1.2.1 of this CM Protocol and in accordance with a communications and distribution matrix currently being developed by the Parties

• Liaison for Borrowed Employees

PROJECT ENGINEERS (***)

• Responsible to Project Manager for day-to-day project technical execution for respective areas

• Primary contact for Engineering Services matters with Owner, Managed Vendors, and GE

• Contact (with Project Manager) for technical requirements related to Agreement

• Copied on all correspondence ( in accordance with a communications and distribution matrix currently being developed by the Parties) relating to technical matters with Owner, Managed Vendors and GE

PROJECT PROCUREMENT MANAGER (***)

• Responsible to Project Manager for day-to-day project procurement activities

• Primary contact for Procurement Services matters with Owner and Managed Vendors

• Contact (with Project Manager) for Procurement Services requirements related to Agreement

• Copied on all correspondence (in accordance with a communications and distribution matrix currently being developed by the Parties ) relating to procurement matters with Owner and Managed Vendors

PROJECT CONTRACTS MANAGER (***)

• Responsible to Project Manager for day-to-day contracts activities

• Primary contact for Owner Service Contracts matters with Owner and Managed Vendors

• Contact (with Project Manager) for Owner Service Contracts requirements related to Agreement

• Copied on all correspondence ( in accordance with a communications and distribution matrix currently being developed by the Parties) relating to Owner Service Contracts matters with Owner and Managed Vendors

ISBL CONSTRUCTION MANAGER (***)

• Responsible to Project Manager for day-to-day CM ISBL Work at Site

4

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

• Primary interface with Owner and Owner’s Project Director-Project Execution, Managed Vendors and GE for CM ISBL Work at Site

• Contact (with Project Manager) for CM ISBL Work requirements related to Agreement

• Copied on all correspondence ( in accordance with a communications and distribution matrix currently being developed by the Parties) relating to CM ISBL Work with Owner, Managed Vendors and GE

1.1.2 Owner Project Organization

Owner’s Project General Manager will have responsibility for the overall Project. Owner’s Project Director – Project Execution will have overall authority to direct activities at the Site. Owner will lead the OSBL construction team, which is responsible for the coordination and execution of the OSBL Work (as defined in Part I Section 2.3 of the Scope Book). Contractor personnel supporting these functions will serve as Borrowed Employees. The OSBL Construction Manager will be an integral participant in the overall Site Management Team. Owner will commission and start-up the Facility. The key Owner positions (and general description of authority and roles) are as follows:

VICE PRESIDENT MAJOR PROJECTS (***):

• Signature authority for Agreement requirements (such as Change Orders) and all other issues relating to the Agreement

• Overall signature authority for all aspects of the Project

PROJECT GENERAL MANAGER (***):

• Responsible for overall Project

• Primary contact for the Agreement

• Signature authority for Agreement requirements (such as Change Orders) and all other issues relating to the Agreement

• Management of the Agreement

• Overall signature authority for all aspects of the Project

• Copied on correspondence as indicated in Section 1.2.1 of this CM Protocol and in accordance with a communications and distribution matrix currently being developed by the Parties

• Liaison for Borrowed Employees

PROJECT DIRECTOR-ENGINEERING & TECHNICAL (***):

• Signature authority for the following areas:

• Engineering Services

• Procurement Services for Owner Equipment until delivered to the Site

• Engineering and specifications

• Contract administration of Owner Equipment

• All expediting, quality assurance and technical evaluation

• Traffic and logistics of Owner Equipment

• Invoice approval

• Owner Services - Bechtel home office technical specifications

5

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

PROJECT DIRECTOR-PROJECT EXECUTION (***)

• Signature authority for the following areas:

• CM ISBL Work

• Owner Services

• Procurement of all Owner Services

• Contract administration of Owner Services

• Invoice approval

• Overall management of Site execution

• Shared Services

• Management of all Shared Services Teams

• Management of all Site services

• OSBL Work

• Administrative issues relating to Borrowed Employees

MANAGING DIRECTOR – SOURCING & MATERIALS MANAGEMENT (***)

• Approval of all bidders

• Approval of bid documents prior to submittal to bidders

• Approval of any changes to pro forma terms

• Approval of any variations to the bid documents

• Final award

1.1.3 Shared Services Team

The Shared Services team will be responsible for supporting both Construction Managers (ISBL and OSBL). Lead positions in the Shared Services team will be responsible for developing and implementing the appropriate strategy for their respective functional area across the Project as well as efficient utilization of resources within the functional area. Owner will also appoint personnel in a “shadow role” within the Shared Services team. Personnel in such “shadow role” will assist the Project in a program oversight role, auditing to insure that the work is completed in a manner consistent with the Agreement, this CM Protocol, and Owner policies, as applicable.

Owner will manage the Shared Services which consist of the following functions:

• Quality Assurance

• Project Support Services (Cost/Document Control/IT Support)

• Commissioning and Start Up

• Environmental Safety and Health

• Contract Management

• Site Materials Management

• Project Schedule Management

Quality Assurance

6

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

• The Quality Assurance Team will perform and manage quality activities at the Site. The Quality Assurance Team will verify and monitor all contractors’ (including Managed Vendors’ and GE’s ) and their subcontractors’ adherence with the Quality Assurance Plan. Quality assurance audits supplemented with surveillances will be conducted by the Quality Assurance Team to verify the Project’s conformance to approved policies, procedures and instructions, including: review and status of contractor processes and procedures, independent verification of work being performed, and ensuring completed work is fully compliant with the design requirements; provided, however, that the day-to-day quality surveillances of the CM ISBL Work will be performed by Contractor. All inspections will be documented, and corrective work, if any, will be authorized by appropriate personnel. The key position within the Quality Assurance Team is:

Quality Program Coordinator:

• Maintains and verifies implementation of the Quality Assurance Plan for the Project. Manages and coordinates the Quality Assurance Plan activities associated with one or more functions in engineering, environmental, procurement, construction, testing, and operations. Advises Site Management Team of Project quality assurance problems and progress.

The Quality Program Coordinator will designate at least one individual from the Quality Assurance Team to take day-to-day direction from the ISBL Construction Manager.

Project Support Services (Cost/Document Control/IT Support)

The Project Support Services Team will perform Site services for cost engineering, document control and IT support as follows:

Cost Engineering

Responsible for the overall cost control, cost analysis, performance, and estimating functions for the Site.

Document Control

Responsible for the overall management and control of design documents for the Site.

IT Support

Responsible for the overall information technology support for the Site, including equipment purchase and maintenance and system set-up.

The key position within the Project Support Services Team is:

Project Support Services Manager:

7

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

• Directs cost estimating, analysis, controls, maintenance, monitoring, and impact identification, and supports recovery plan development activities. Directs the preparation and presentation of Project estimates and cost forecasts. Supports Project organizational and administrative activities. Provides generally non-routine cost engineering/planning. Identifies, analyzes, and provides solutions to cost engineering problems. Directs IT support, IT equipment purchase and maintenance, and systems setup. Directs field document controls systems and processes. Advises Site Management Team of Project Support Services problems and progress.

The Project Support Services Manager will designate at least one individual from the Project Support Services Team to take day-to-day direction from the ISBL Construction Manager.

Commissioning and Start Up

• The Commissioning and Startup Team will be responsible for developing and implementing a strategy for the overall commissioning and startup of the entire Facility.

• Contractor will supply startup and operations personnel to the Commissioning and Startup Team as Borrowed Employees. The Contractor ISBL Systems Coordinator will mobilize to the Site to support commissioning, startup and operation activities of the CM ISBL Work.

The key position within the Commissioning and Start Up Team is:

Commissioning/Startup Manager

• Implements the strategy for the overall commissioning and startup of the entire Facility and manages and supervises all commissioning/startup activities and personnel (including those activities and startup personnel of Managed Vendors and GE) on the Project. Plans and directs startup assignments on the Project. Technical responsibility for organizing, executing, and coordinating these assignments. Makes day-to-day decisions within assigned area or project and makes recommendations to department or Project management regarding policy and procedure. Responsible for review of Project designs and recommendation of changes to design so that Project is safe and operable. Advises Site Management Team of commissioning and start up problems and progress.

Environmental, Safety and Health (ES&H)

• The Site ES&H Team is responsible for the implementation, management and enforcement of the Environmental, Safety and Health Plan for the Site; provided, however, that the day-to-day ES&H oversight of the CM ISBL Work will be performed by Contractor.

The key position in the ES&H Team is:

8

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

ES&H Manager

• Supervises the ES&H functions for the entire Project and interfaces with the Owner’s Senior Safety Professional on a periodic basis to assure common agreement on the various safety initiatives and hazard control methods. Advises Site Management Team of ES&H problems and progress.

The ES&H Manager will designate at least one individual from the ES&H Team to take day-to-day direction from the ISBL Construction Manager.

Contract Management

The Contract Management Team will administer contracts for the Site. Responsibilities include management of correspondence with contractors (including Managed Vendors), managing contractor change requests, evaluating proposed changes, preparing pre-mobilization checklists, and contract closeout.

The key position within the Contract Management Team is:

Contracts Manager

• Responsible for administering contracts at the Site including implementation of the Owner Project Group work process procedures and automated contract management systems. Responsible for the training of personnel assigned to support contract administration. Advises Site Management Team of contracts problems and progress.

The Contracts Manager will designate at least one individual from the Contract Management Team to take day-to-day direction from the ISBL Construction Manager.

Site Materials Management

The Materials Management Team is responsible for materials management for the Site including furnishing current status of equipment and material at the Site and will act as liaison between Site and off Site procurement in coordination of these efforts. The Materials Management Team will be responsible for the receipt inspection; resolution of unsatisfactory, overage, shortage, and damage reports; Site materials management; Site traffic and logistics management; storage and maintenance; inventory control; and issuance of equipment and materials to contractors. The Materials Management Team will also be responsible for procurement of miscellaneous material not included on the Material Assignment Schedule.

The key position within the Materials Management Team is:

Director of Materials Management:

9

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

• Leads the Project and field materials management activities to ensure the overall organizational effectiveness among all functions responsible for the materials management process. Establishes policy and monitors and approves the development of automated and manual material management and inventory control systems. Plans, directs, coordinates, and monitors personnel actions for material management staff. Advises Site Management Team of material management problems and progress.

The Director of Materials Management will designate at least one individual from the Materials Management Team to take day-to-day direction from the ISBL Construction Manager.

Project Schedule Management

• The Project Schedule Management Team is responsible for creating, managing, statusing, and issuing the Project Schedule and other general planning and scheduling activities at the Site.

• As the construction contract packages are awarded, the Project Schedule Management Team will incorporate contractors’ approved level 3 schedules into the Project Schedule. The Project Schedule Management Team will, on a weekly basis, receive inputs from the Contractor (which consists of the Contractor EP Schedule) and other contractors for integration into the Project Schedule and will subsequently status the Project Schedule and report status and variances to Contractor and others as applicable. The Project Schedule Management Team will lead the development and coordination of any required recovery plan.

• The key position within the Project Schedule Management Team is:

Project Schedule Manager:

• Supervises the creating, managing, statusing, and issuing of the Project Schedule and other general planning and scheduling activities at the Site. Advises Site Management Team of Project scheduling problems and progress.

The Project Schedule Manager will designate at least one individual from the Project Schedule Management Team to take day-to-day direction from the ISBL Construction Manager.

1.1.4. Joint Owner/Contractor Teams

The Owner and Contractor will establish certain committees and teams to assist with Project management. The Steering Committee will be established and perform in accordance with the terms of the Agreement. The Parties will also establish a Site Management Team to perform the overall execution, functional, and administrative management of the day-to-day work activities at the Site. The Site Management Team is an integrated Owner/Contractor leadership team and will consist of the following functional managers:

• Project Director-Project Execution

10

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

• CM ISBL Construction Manager

• OSBL Construction Manager

• Engineering Manager

• Project Support Services Manager

• Quality Program Coordinator

• ES&H Manager

• Commissioning/Start-Up Manager

• Contracts Manager

• Director of Materials Management

• Project Schedule Manager

1.2. Communications Procedures

1.2.1. COMMUNICATIONS BETWEEN OWNER AND CONTRACTOR

Owner will have authority to direct all matters relating to the Project, subject to the communications protocol described below. Owner reserves the right to recommend or direct changes to the order and approach of the work by defined communications with the authorized Contractor representatives, as described below.

Subject to the final sentence of this paragraph, any “significant” communications must be delivered in writing by letter, transmitted via the designated Owner eRoom created solely for Contractor and Owner access (the “Duke/Bechtel eRoom”). Significant communications directed to Contractor will also be e-mailed to the Contractor’s Project Manager with copies to Contractor’s Project Director. Significant communications directed to Owner will also be e-mailed to Owner’s General Manager with copies to Owner’s Assistant General Counsel. Any formal notices that require service upon another Party (such as a notice of suspension, notice of breach, etc., in each case, a “Formal Notice”) shall be delivered in accordance with Section 24.9 of the Agreement.

Significant communications include the following:

• Communications that reflect the position of Owner or Contractor

• Original messages of policies or directives

• Communications that direct changes to the order and approach of Contractor’s Services that have a significant actual or potential effect on the cost, design, quality, safety, schedule, work process and procedures, or performance

• Communications relating to Changes or amendments to the Agreement

All “significant” communications issued by Owner will be issued by the authority of the Project General Manager or designee. All “significant” communications issued by Contractor will be issued by the authority of the Contractor Project Manager or designee. The Project General

11

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

Manager and the Contractor Project Manager may designate individuals, in writing, with a signature authority.

All Project communications between Contractor and Owner (other than any Formal Notice or technical data as described below) and all commercial data will be placed through the Duke/Bechtel eRoom. Contractor is responsible for issuance of commercial and technical data into the designated Owner eRoom.

Technical data will be placed by Contractor in the designated eRoom created solely for Owner, Contractor and GE access (“3-way eRoom”) which resides on the Owner’s server. This 3-Way eRoom is designed for the communication exchange between Owner/Contractor/General Electric for certain Contractor and Managed Vendor technical information.

1.2.2. COMMUNICATION TO MANAGED VENDORS

Contractor will be responsible for the day-to-day communication with Managed Vendors; provided, however that Owner reserves the right to communicate with all Managed Vendors at its discretion but will to the extent possible coordinate such communication with Contractor. The Contractor will copy the Owner on any of its correspondence with the Managed Vendors by issuing a copy to the Duke/Bechtel eRoom.

Contractor has established a Managed Vendor eRoom on Contractor’s server (“Vendor eRoom”) for exchanging technical data among the Managed Vendors for review and issuance. The Managed Vendors will issue all of their respective communications and related data to the Vendor eRoom. Contractor is responsible for issuing technical data received from the Managed Vendors to Owner into the 3-way eRoom. It is the intent of the Parties that Contractor will handle technical data received from GE in the same manner as technical data received from the Managed Vendors; ***.

1.2.3 SITE COMMUNICATION

In this integrated arrangement some Owner personnel will directly utilize Contractor applications within the Contractor network. Only Owner personnel authorized by Contractor (and identified as account holders for this purpose) utilizing Contractor managed devices will be allowed to connect directly to the Contractor network. Several Contractor applications will be made accessible via web based interfaces to authorized Owner personnel external to the Contractor network. Tools such as eRoom, CTI and BecTransfer will be enabled in this capacity.

12

RESTRICTED DUKE-BECHTEL CONFIDENTIAL INFORMATION

EXHIBIT C

***

EXHIBIT D

SITE DESCRIPTION

The Site shall mean that area of land located in Sections 1 and 12 of Township 04 North and Range 08 West in Vigo Township, Knox County, Indiana, and generally west of the West Fork of the White River, north of State Road 358, east of State Road 67, and south of the site of the existing Duke Energy Edwardsport Generating Station as shown on the attached drawing.

EXHIBIT E

LIST OF TECHNICAL DATA

1. Major foundation stress calculations (including electronic files)

2. Structural steel stress calculations (including electronic files)

3. Critical pipe stress calculations (including electronic files)

4. Electrical system calculations, e.g., short circuit, relay coordination, etc. (including electronic files)

EXHIBIT F

***

EXHIBIT G

***

EXHIBIT H

***

EXHIBIT I

***

EXHIBIT J

***

EXHIBIT K

***

EXHIBIT L

June 9, 2008

Bechtel Power Corporation

5275 Westview Drive

Frederick, MD 21703

Attn: Amos A. Avidan

Re: Confidentiality Agreement

Dear Amos:

Duke Energy Indiana, Inc. (“Duke”, which term shall, for purposes of this Agreement, include its affiliates and subsidiaries) and Bechtel Power Corporation (“Bechtel”, which term shall, for purposes of this Agreement, include its affiliates and subsidiaries) (Duke and Bechtel each a “Party” and collectively, the “Parties”), together with the General Electric Company (“GE”), previously entered into that certain Amended and Restated Confidentiality Agreement dated as of July 26, 2007 (the “Existing Confidentiality Agreement”), relating to disclosure of confidential information in connection with their respective preliminary work on the Edwardsport integrated gasification combined cycle facility (the “Project”). Further, the Parties previously entered into a Technical Services Agreement effective as of February 13, 2006, as amended by Amendment No. 1 dated May 30, 2006, and another Technical Services Agreement effective as of May 7, 2007 with respect to such preliminary work relating to the Project. The Parties are entering into negotiations relative to a definitive agreement between the Parties with respect to the Project and desire to enter into a third Technical Services Agreement, dated as of the date hereof, for purposes of undertaking additional work for the development and construction of the Facility. As a result of such third Technical Services Agreement, the Parties now desire to enter into this confidentiality letter agreement (this “Agreement”), in order, among other things, (i) for Duke to use the Confidential Information (as defined below) of Bechtel for the purposes of design, construction, maintenance, operation, repair, modification, licensing, simulation, commissioning and decommissioning of the Project, training, consultation and compliance with laws in respect of the Project, and otherwise for Duke’s internal business purposes and (ii) for Bechtel to use the Confidential Information of Duke for the purposes of fulfilling its contractual obligations to Duke in respect of the Project (such purposes described in the foregoing clauses (i) and (ii) of this paragraph, collectively, the “Purposes”). Each Party furnishing its Confidential Information shall be hereinafter referred to, with respect to such information, as the “Disclosing Party,” and each Party receiving such information shall be hereinafter referred to, with respect to such information, as the “Receiving Party”.

All information regarding a Party’s properties, employees, finances, businesses, operations, assets, prospects, financial affairs and proprietary technology furnished or disclosed by a Disclosing Party or its Representatives (as defined below) to the other Party, whether furnished or disclosed before or after the date hereof and regardless of the manner in which it is furnished or disclosed, that is: (i) written or electronic and clearly marked ‘Confidential’, ‘Proprietary’, ‘Bechtel Sulfur Confidential’ or ‘Bechtel Sulfur Information’¹, or (ii) if furnished or disclosed orally or visually, is identified by the Disclosing Party as being ‘Confidential’,

¹ Attachment No. 1 hereto contains a complete definition of “Bechtel Sulfur Information”.

‘Proprietary’, ‘Bechtel Sulfur Confidential’ or ‘Bechtel Sulfur Information’ at the time of such oral or visual disclosure and also identified as such in a writing or electronic message sent by the Disclosing Party and received by the Receiving Party within ten (10) days after such disclosure, such writing or electronic message setting forth (A) the date and approximate time of the oral or visual disclosure, (B) the names of the Representatives of each Party disclosing and receiving such oral or visual disclosure and (C) the information that was identified by the Disclosing Party at the time of oral or visual disclosure as being ‘Confidential’, ‘Proprietary’, ‘Bechtel Sulfur Confidential’ or ‘Bechtel Sulfur Information’ (such information described in the foregoing clauses (i) and (ii) of this paragraph, collectively, the “Confidential Information”). All such information disclosed by a Disclosing Party or its Representatives shall remain the Disclosing Party’s Confidential Information notwithstanding the inclusion of such information in summaries or other documents created by the other Party or its Representatives.

The term “Confidential Information” shall not include information that: (a) is or becomes available to the public other than as a result of a disclosure by the Receiving Party or any of its Representatives (as defined below) in breach of this Agreement or any previous agreement to which the Parties were previously bound , (b) was available to the Receiving Party on a non-confidential basis prior to its disclosure by the Disclosing Party or its Representatives from a person who was not known by the Receiving Party or any of its Representatives to be otherwise bound by a confidentiality agreement with the Disclosing Party or any of its Representatives, or otherwise under an obligation to the Disclosing Party or any of its Representatives not to transmit the information to the Receiving Party, (c) is developed independently by the Receiving Party or any of its Representatives without use or benefit of information disclosed by the Disclosing Party, or (d) becomes available to the Receiving Party on a non-confidential basis from a person other than the Disclosing Party or its Representatives who is not, to the best of the Receiving Party’s knowledge, otherwise bound by a confidentiality agreement with the Disclosing Party or any of its Representatives, or otherwise under an obligation to the Disclosing Party or any of its Representatives not to transmit the information to the Receiving Party. Specific information shall not be deemed to fall within one of the exceptions described in (a) through (d) above solely because it is contained in more general information that does fall within one of the aforementioned exceptions.

Subject to the immediately succeeding paragraph, unless otherwise agreed to in writing by a Disclosing Party, each Party agrees: (a) except as required by law, rule, applicable regulation, stock exchange rule or disclosure requirement of the Securities and Exchange Commission (collectively, “Law”), to keep all Confidential Information of the other Party confidential and not to disclose or reveal any such Confidential Information to any person other than to: (i) its directors, partners, officers and employees and those attorneys, accountants, financial advisors, consultants or other agents or advisors who are not officers or employees and who need to know such Confidential Information for such Party’s Purposes (such persons being collectively referred to herein as “Representatives”); (ii) in the case of Duke, Potential Participants (as defined below) who need to know such Confidential Information to evaluate participation in the Project and who have entered into a confidentiality agreement with Duke substantially in the form attached as Attachment No. 2 hereto; (iii) contractors and vendors of Duke who need to know Confidential Information of Bechtel for Duke’s Purposes and who have entered into a confidentiality agreement with Duke substantially in the form attached as Attachment No. 2 hereto; and (iv) contractors and vendors of Bechtel who need to know Confidential Information of Duke for Bechtel’s Purposes and who agree in writing to keep such

information confidential in accordance with the terms of this Agreement; and (b) not to use, and to take commercially reasonable efforts to cause its Representatives not to use, Confidential Information of the other Party for any purpose other than in connection with such Party’s Purposes. During the period prior to substantial completion of the construction of the Project, competitors of Bechtel identified in Schedule I attached hereto (each, a “Bechtel Competitor”) shall use any Confidential Information of Bechtel only for the purposes of providing technical or advisory services or off-site fabrication services in connection with the Project and shall have first entered into a confidentiality agreement with Duke substantially in the form attached as Attachment No. 3 hereto, and Duke shall permit disclosure only to those Bechtel Competitor employees in positions and in numbers appropriate to the scope of work contemplated (but in no event more than ten employees for any confidentiality agreement without the prior written consent of Bechtel, which consent shall not be unreasonably withheld). In no event shall Duke allow any Bechtel Competitor to access the Project data room containing Bechtel estimate data without the prior written consent of Bechtel. Each Party will be responsible for any breach of this paragraph by any of its Representatives. Each Party will be bound by the foregoing obligations of confidentiality hereunder for a period of five (5) years from the date hereof. With respect to Bechtel Sulfur Information, the Receiving Party’s obligation shall be evergreen, so long as such information shall not be available to the public, and have no termination.

In connection with the Project, Duke may deem it necessary or advisable to discuss the Project with one or more third parties with respect to such third parties’ potential participation with respect to the Project (each, a “Potential Participant”). In this regard, it may be necessary or advisable for Duke to disclose to a Potential Participant Bechtel’s Confidential Information. Bechtel hereby consents to any future discussions between Duke and any Potential Participants with respect to the Project and to the disclosure of Bechtel Confidential Information by Duke to any and all Potential Participants, so long as such Potential Participant has entered into a confidentiality agreement with Duke on the terms set forth in the preceding paragraph. Notwithstanding the foregoing, in the event that Duke does not pursue participation in the Project with a Potential Participant, but continues work on the Project with Bechtel, Duke agrees not to thereafter disclose, and will direct its Representatives not to thereafter disclose, to such Potential Participant any further Confidential Information of Bechtel, subject to the exceptions set forth in this Agreement.

The Parties acknowledge and agree that Bechtel and GE are parties to an agreement protecting the confidentiality of each of their respective Confidential Information. Accordingly, and notwithstanding anything to the contrary herein, (a) Duke and its Representatives shall be free to disclose Bechtel’s Confidential Information (unless marked “Restricted Duke-Bechtel Information” or something substantially similar that indicates that disclosure to GE is not permitted), including Bechtel Sulfur Information, to GE and its affiliates without first entering into any agreement therewith regarding protection of Bechtel’s Confidential Information and (b) Duke shall have no liability to Bechtel or to any third party for the failure or alleged failure of GE or any of its affiliates to protect the confidentiality of Bechtel’s Confidential Information.

In the event that a Receiving Party or any of its Representatives is legally compelled, pursuant to a subpoena, civil investigative demand, regulatory demand or other process or Law, to disclose any Confidential Information of the other Party, such Receiving Party agrees

that it will provide the Disclosing Party with prompt notice of such request or requirement (if legally permissible to do so) to enable the Disclosing Party, at the Disclosing Party’s sole expense, to seek an appropriate protective order or other remedy, to consult with the Receiving Party with respect to the Disclosing Party taking steps to resist or narrow the scope of such request or legal process, or to waive compliance, in whole or in part, with the terms of this Agreement. In any such event, the Receiving Party will use commercially reasonable efforts to ensure that all such Confidential Information of the other Party that is so disclosed will be accorded confidential treatment and shall furnish only that portion of such Confidential Information that the Receiving Party is advised by counsel is legally required. If, in the absence of a protective order, the Receiving Party or any of its Representatives is compelled to disclose Confidential Information of the other Party as a matter of Law, the Receiving Party shall disclose only that part of such Confidential Information as is required by Law to be disclosed (in which case, prior to such disclosure, the Receiving Party will, to the extent practicable and permissible, advise and consult with the Disclosing Party and its counsel as to such disclosure and the nature and wording of such disclosure), and, to the extent practical in the circumstances, the Receiving Party will use its reasonable efforts to obtain confidential treatment for any Confidential Information so disclosed.

In connection with the Project, Duke may deem it necessary or advisable to discuss certain matters relating to the Project with the Midwest Independent System Operator (MISO), the Indiana Utility Regulatory Commission (IURC), the Indiana Department of Environmental Management (IDEM), the Indiana Office of Utility Consumer Counselor (OUCC), the federal Environmental Protection Agency (EPA), or other similar entity whose involvement or approval is necessary or prudent for carrying out the Project or the work required by other agreements between the Parties. In this regard, it may be necessary or prudent for Duke to disclose to such persons the proposed terms thereof or Bechtel’s Confidential Information. In holding such discussions, Duke undertakes to convey to such persons the importance of maintaining confidentiality with respect to the matters that are discussed. Accordingly, Bechtel hereby consents to discussions between the foregoing persons, on the one hand, and Duke and its Representatives, on the other, regarding regulatory matters pertinent to the Project and Duke may disclose Confidential Information of Bechtel to MISO, IURC, IDEM, OUCC, EPA or other similar entity in such discussions.

Each Receiving Party acknowledges that Confidential Information is and at all times remains the sole and exclusive property of the Disclosing Party, and the Disclosing Party has the exclusive right, title and interest to its Confidential Information. No right or license, by implication or otherwise, is granted by the Disclosing Party as a result of disclosure of Confidential Information under this Agreement, but such right or license may arise as specified in any prior or future agreements between the Parties.

Each Receiving Party acknowledges that no Disclosing Party nor any of its Representatives, by its signature below, makes any express or implied representation or warranty as to the accuracy or completeness of its Confidential Information, and each Receiving Party agrees that none of such persons, by sole reason of this Agreement, shall have any liability to any Receiving Party or any of its Representatives relating to or arising from the use of any Confidential Information by the Receiving Party or its Representatives or for any errors therein or omissions therefrom. For the avoidance of doubt, the foregoing shall not negate or restrict any express or implied representation or warranty relating to the accuracy or completeness of a

Party’s Confidential Information arising as specified in any other agreements between the Parties.

This Agreement binds the Parties only with respect to the matters expressly set forth herein and nothing in this Agreement shall bind any of the Parties to other specific terms or conditions relating to the Project. Neither of the Parties is bound or committed to negotiate or consummate the Project by virtue of this Agreement unless and until a definitive agreement on such matters between the Parties has been executed and delivered on behalf of each such Party by its duly authorized officer.

Each Receiving Party is aware, and will advise its Representatives who are informed of the matters that are the subject of this Agreement, of the restrictions imposed by the United States securities laws on the purchase or sale of securities by any person who has received material, non-public information from the issuer of such securities and on the communication of such information to any other person when it is reasonably foreseeable that such other person is likely to purchase or sell such securities in reliance upon such information. Each Receiving Party hereby confirms that it, and its Representatives, will take any action necessary to prevent the use of any information about any Disclosing Party in a way which might violate any antitrust or other applicable Law.

Notwithstanding anything to the contrary herein, Duke shall have the right to permit visitors to tour the Edwardsport integrated gasification combined cycle facility without entering into any confidentiality agreement with such visitors prior to such tour.

It is understood that the covenants of this Agreement and the Confidential Information disclosed are special, unique and of extraordinary character. Each Disclosing Party may be irreparably harmed by a breach of this Agreement by a Receiving Party, and the use of the Confidential Information for the business purposes of any person other than the Disclosing Party may enable such person to compete unfairly with the Disclosing Party. Without prejudice to the rights and remedies otherwise available to each of the Parties, each Party shall be entitled to seek equitable relief by way of injunction or otherwise if another Party or any of its Representatives breaches or threatens to breach any of the provisions of this Agreement. It is further understood and agreed that no failure or delay by a Party in exercising any right, power or privilege hereunder shall operate as a waiver thereof, nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any right, power or privilege hereunder.

Each Party shall be responsible for the costs and expenses incurred by it and its Representatives in carrying out the purposes of this Agreement.

This Agreement shall be governed by and construed in accordance with the laws of the State of Indiana applicable to contracts executed in and to be performed in that state.

This Agreement shall be binding on the Parties and their respective successors and permitted assigns. Any assignment of this Agreement, in whole or in part, by either Party without the prior written consent of the other Party hereto shall be null and void ab initio.

This Agreement is solely for the benefit of the Parties, and this Agreement shall not be deemed to confer upon or give to any third party any remedy, claim of liability or reimbursement, cause of action or other right.

If any provision of this Agreement is held by a court of competent jurisdiction to be invalid, illegal or unenforceable, the remainder of the provisions of this Agreement shall remain in full force and effect. The Parties shall endeavor in good faith negotiations to replace any invalid, illegal or unenforceable provision with a valid, legal and enforceable provision, the effect of which comes as close as possible to that of the invalid, illegal or unenforceable provision.

No modification of this Agreement or waiver of the terms and conditions hereof shall be binding upon the Parties, unless approved in a writing signed by each of the Parties.

This Agreement contains the entire agreement among the parties concerning the subject matter hereof and supersedes any and all previous understandings or agreements, whether written or oral, pertaining to said subject matter, including the Existing Confidentiality Agreement, which is hereby terminated with respect to Duke and Bechtel without surviving obligations. This Agreement may be executed in counterparts, each of which shall be an original, but all of which together shall constitute one and the same agreement.

Bechtel shall not, and shall not permit any of its Representatives to, issue any press or publicity release, concerning this Agreement, the Project or any other agreement between the Parties relating to the Project without the express prior written consent of Duke, which shall not be unreasonably withheld.

Please acknowledge your agreement to the foregoing by countersigning this Agreement in the space provided below and returning to the undersigned a fully executed original copy of this Agreement.

Sincerely,

DUKE ENERGY INDIANA, INC.
By:	/s/ W. Michael Womack
Name:	W. Michael Womack
Title:	Vice President

Accepted and Agreed as of the date first written above:

BECHTEL POWER CORPORATION
By:	/s/ Amos A. Avidan
Name:	Amos A. Avidan
Title:	IGCC/Gasification Operations Manager

Attachment No. 1 – Definition of “Bechtel Sulfur Information”

“Bechtel Sulfur Information” means Bechtel’s information relating to processes for the conversion of hydrogen sulfide to elemental sulfur in an environmentally acceptable manner, including but not limited to, Claus sulfur recovery, tail gas treating, and thermal oxidizing.

Attachment No. 2 – Form of Confidentiality Agreement (non-competitors)

Form Non-Disclosure and Secrecy Agreement

THIS NON-DISCLOSURE AND SECRECY AGREEMENT (this “Agreement”) is entered into as of the      day of                     , 20        , between Duke Energy Indiana, Inc., an Indiana corporation having its principal place of business in Charlotte, North Carolina (“Duke Energy”), and                                         , a                          [corporation] having its principal place of business in                          (the “Company”). Duke Energy and the Company shall sometimes be individually referred to herein as a “Party” and collectively as “Parties.”

R E C I T A L S:

A. Duke Energy is developing an integrated gasification combined cycle facility in Edwardsport, Indiana (the “Facility”).

B. Duke Energy and the Company are engaged in, or intend to engage in, discussions pursuant to which [(a) Duke Energy may engage the Company to construct, operate, maintain, modify, repair, test, train, commission, decommission, license or inspect the Facility, or (b) the Company may consider purchasing all or a portion of the Facility]. [Tailor to purposes in connection with the Company.]

C. The Parties acknowledge that each Party may make available to the other Party, from time to time, in connection with the aforementioned purposes, certain Confidential Information (as defined below), including Confidential Information belonging to General Electric Company or its affiliates (collectively, “GE”) or Bechtel Power Corporation or its affiliates (collectively, “Bechtel”) that is disclosed by Duke Energy, GE or Bechtel, as applicable, to the Company.

NOW, THEREFORE, in consideration of the premises and the mutual promises and covenants hereinafter set forth and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged by each Party, the Parties, intending to be legally bound, agree as follows:

1. Definitions. As used in this Agreement,

(a) “Confidential Information” means all nonpublic information disclosed by, or on behalf of, a Party (or, with respect to disclosures of GE or Bechtel nonpublic information to the Company, GE or Bechtel, as applicable) (the “Disclosing Party”) to the other Party (the “Receiving Party”) or its Representatives (as defined below), whether disclosed before or after the date hereof (including any information disclosed under any previous confidentiality agreements) and regardless of the manner or format of such disclosure, that: (a) is designated in writing as “confidential,” “proprietary,” “GE Gasification Information,” “Bechtel Sulfur Information,” or similar designation by the Disclosing Party at the time of written disclosure; (b) a reasonable person in the power generation industry would understand to be confidential or proprietary by virtue of its nature; or (c) is orally or visually disclosed and confirmed and designated by the Disclosing Party to be “confidential” or “proprietary” in writing within thirty

(30) days after such oral or visual disclosure. Once orally or visually disclosed information has been designated as “Confidential” or as a similar designation, all future disclosures of such information shall be protected, regardless of whether such future disclosures are marked or designated as “Confidential” or with a similar designation. “Confidential Information” shall not include any information that: (i) was publicly available prior to disclosure thereof to a Receiving Party or its Representatives by a Disclosing Party; (ii) becomes publicly available after disclosure thereof to a Receiving Party or its Representatives by a Disclosing Party other than as a result of a public disclosure by such Receiving Party or its Representatives; (iii) is at the time of its disclosure to a Receiving Party or its Representatives, or becomes thereafter, available to the Receiving Party or its Representatives on a non-confidential basis from a source other than the Disclosing Party and such source is not, to the best of the Receiving Party’s knowledge, subject to a confidentiality obligation to the Disclosing Party regarding such information; (iv) is independently developed by a Receiving Party or its Representatives without reference to the Disclosing Party’s Confidential Information; or (v) is approved for disclosure in writing by the Disclosing Party. Specific information shall not be excluded from the above obligations merely because it is embraced by more general information excluded under items (i), (ii) or (iii) above. A specific combination of features or items shall not be so excluded unless the specific combination itself falls within items (i), (ii) or (iii) above; and

(b) “GE Gasification Information” has the meaning set forth on Schedule A hereto, which is hereby incorporated by reference into this Agreement; and

(c) “Bechtel Sulfur Information” has the meaning set forth on Schedule B hereto, which is hereby incorporated by reference into this Agreement; and

(d) “Representative” means (i) any affiliate, director, officer, employee, agent, advisor or other representative of a Disclosing Party or Receiving Party, as the case may be, and (ii) any contractor or vendor who needs to know the Confidential Information to construct, operate, maintain, modify, repair, test, train, commission, decommission, license or inspect the Facility and who enters into a Non-Disclosure and Secrecy Agreement with the Receiving Party in substantially the form hereof with Duke Energy, as well as GE and Bechtel, as third party beneficiaries thereof.

2. Non-Disclosure. Subject to Section 4 below, the Receiving Party shall (a) take reasonable precautions to prevent unauthorized disclosure or use of Confidential Information disclosed to it by, or on behalf of, the Disclosing Party, such precautions taken being at least as great as the precautions taken by the Receiving Party to protect its own Confidential Information (but in no case less than reasonable care), and (b) not disclose Confidential Information disclosed to it or its Representatives by, or on behalf of, the Disclosing Party to any third party (other than Duke Energy’s Representatives) without the Disclosing Party’s prior written authorization. Notwithstanding the foregoing, the Receiving Party may disclose Confidential Information of the Disclosing Party to any Representative of the Receiving Party, provided that the Receiving Party agrees to be responsible for each such Representative’s compliance with the terms hereunder binding on the Receiving Party. Duke Energy and the Company agree that Bechtel and GE are third party beneficiaries of this Agreement.

3. Authorized Uses. The Receiving Party and its Representatives shall use any Confidential Information disclosed to them by, or on behalf of, the Disclosing Party only (a) to the extent required to construct, operate, maintain, modify, repair, test, train, commission, decommission, license or inspect the Facility or (b) in the consideration of purchasing all or a portion of the Facility.

4. Required Disclosure. Notwithstanding anything to the contrary in this Agreement, a Receiving Party or its Representatives may disclose Confidential Information disclosed to it by, or on behalf of, the Disclosing Party if required, according to a good faith belief by Receiving Party’s or its Representative’s legal counsel, by law, legal process or a government authority. If a Receiving Party or its Representative is legally compelled to disclose Confidential Information disclosed to it by, or on behalf of, the Disclosing Party, or if such disclosure is necessary in order to comply with laws or obtain or maintain governmental approvals, applications or exemptions, the Receiving Party or its Representative must provide (if legally permissible to do so) the Disclosing Party with as much advance written notice as practicable to afford the Disclosing Party the opportunity to seek a protective order or other remedy to prevent disclosure. If such protective order or other remedy is not obtained, the Receiving Party or its Representative, as applicable, shall furnish only that portion of the Confidential Information disclosed to it by, or on behalf of, the Disclosing Party that is required in the opinion of its legal counsel and shall cooperate with the Disclosing Party, at the Disclosing Party’s expense, to enable the Disclosing Party to obtain a protective order or other reliable assurance that confidential treatment will be accorded the same.

5. Grantbacks. In the event the Company should obtain a patent, trade secret, or other intellectual property right, including, without limitation, an improvement to or a modification of GE Gasification Information, or equipment or materials used therein, based on or resulting from access to or use of Confidential Information of GE furnished by Duke Energy or GE, the Company agrees to grant and hereby grants an irrevocable, royalty-free, non-exclusive license to GE under such patent and/or such other intellectual property right, together with the right to extend such license to licensees of GE, all without accounting to the Company therefor.

6. Return or Destruction of Confidential Information. If any Party decides that it does not wish to continue discussions with respect to the Facility, such Party will promptly notify the other Party of that decision by giving a written termination notice. In such case or at any time for any reason, upon the written request of the Disclosing Party, the Receiving Party will, and will cause its Representatives to, promptly, (i) deliver to the Disclosing Party all original Confidential Information (whether written or electronic) furnished to the Receiving Party or its Representatives by or on behalf of the Disclosing Party, and (ii) if specifically requested by the Disclosing Party, destroy any copies of such Confidential Information (including any extracts therefrom); provided, however, so long as the Company is not in breach of any term of this Agreement with respect to Confidential Information of GE or Bechtel, the Company shall not be required to return or destroy Confidential Information at the request of GE or Bechtel, as applicable, to the extent the Company requires such Confidential Information to perform its obligations with respect to the Facility. Upon written request of the Disclosing Party for any reason, the Receiving Party shall, and shall cause its Representatives to, cause one of its duly authorized officers to certify in writing to the Disclosing Party that the requirements of the

preceding sentence have been satisfied in full. Notwithstanding the termination of any discussions with respect to the Facility or the return or destruction of any Confidential Information, the Receiving Party will continue to be bound by terms of this Agreement as provided herein.

7. Miscellaneous.

(a) Neither this Agreement nor any right, remedy, obligation or liability arising hereunder shall be assigned by any Party (whether by operation of law or otherwise), and any such assignment shall be null and void, except with the prior written consent of the other Party. Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns.

(b) The Parties acknowledge and agree that no failure or delay by a Party in exercising any right or privilege hereunder shall operate as a waiver thereof. The provisions of this Agreement may be modified or waived only in writing signed by the Party from whom compliance is sought.

(c) The Company agrees that neither GE nor Bechtel (i) makes any warranty to the Company as to the accuracy or completeness of the Confidential Information of GE or Bechtel; or (ii) shall have any liability to the Company resulting from the use of any Confidential Information of GE or Bechtel.

(d) This Agreement shall be governed by and construed in accordance with the laws of the State of Indiana, without regards to the principles of conflicts of laws thereof.

(e) This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. A facsimile of any signature shall have the same force and effect as an original.

(f) Each Party acknowledges and agrees that money damages would not be a sufficient remedy for any breach of this Agreement by such Party and that the other Party shall be entitled to seek equitable relief, including seeking an injunction and specific performance, as a remedy for any such breach. Such remedies shall not be deemed to be the exclusive remedies for a breach of this Agreement, but shall be in addition to all other remedies available at law or equity.

(g) This Agreement constitutes the entire agreement between the Parties with respect to the subject matter herein and supersedes and cancels any prior agreements, representations, warranties, or communications, whether oral or written, between the Parties relating to the subject matter herein.

(h) A Receiving Party shall: (i) notify the Disclosing Party immediately upon discovery of any unauthorized disclosure or use of Confidential Information disclosed by, or on behalf of, the Disclosing Party; and (ii) cooperate, without charge, with reasonable efforts by the

Disclosing Party to regain possession of such Confidential Information, prevent further breaches of this Agreement or prevent further unauthorized uses or disclosures of such Confidential Information.

(i) As between the Disclosing Party and the Receiving Party, the Disclosing Party shall remain the owner of all rights in Confidential Information disclosed by, or on behalf of, the Disclosing Party. Except for the limited right to use such Confidential Information for the purposes set forth in Section 3 above, nothing in this Agreement grants any express, implied or other license or right in such Confidential Information to the Receiving Party.

(j) The foregoing confidentiality obligations shall commence on the date hereof and shall end five (5) years thereafter, except with respect to GE Gasification Information and Bechtel Sulfur Information, for which such confidentiality obligations shall be evergreen and shall have no expiration.

(k) If any provision of this Agreement or portion thereof is found to be invalid, illegal or unenforceable, then, notwithstanding such invalidity, illegality or unenforceability, the illegal or unenforceable provision or portion shall be deemed to be deleted from this Agreement and the remaining provisions shall continue in full force and effect. The Parties specifically acknowledge that the absence of a time limitation in this Agreement is reasonable and properly required for the protection of each Confidential Information disclosed by each Party hereunder. In the event that the absence of such limitation is deemed by a court of competent jurisdiction to cause this Agreement to be invalid or unenforceable, then the Parties specifically intend for such court to impose any such time limitation as such court shall deem reasonable.

IN WITNESS WHEREOF, each party hereto has executed this Agreement, or caused this Agreement to be executed on its behalf, all as of the day and year first above written.

Duke Energy Indiana, Inc.

By:

Name:

Title:

The Company:

By:

Name:

Title:

SCHEDULE A

“GE Gasification Information” shall mean Confidential Information provided, directly or indirectly, by Duke Energy to the Company that is proprietary solely to GE, marked as “GE Gasification Information” or similar term and that describes: (1) the manufacture of synthesis gas (hydrogen and carbon monoxide) in a secret and proprietary process; and (2) its integration with other elements for: (a) electric power generation; (b) high purity hydrogen production; and (c) carbon capture, as described below.

(1) The manufacture of synthesis gas in this context refers to the following:

Processes for producing synthesis gas, also known as reducing gas, or fuel gas, via the partial oxidation of solid, liquid and/or gaseous hydrocarbonaceous feedstocks, or combinations thereof, with oxygen, such as in the form of high purity oxygen, enriched air, or air, for the handling, preparation, and introduction of the feeds into the synthesis gas generation process, including any temperature moderators, such as steam, water, nitrogen, or carbon dioxide, for heating, cooling or recovering waste energy from feed, internal, or product streams, for separating contaminants from the synthesis gas, or otherwise purifying or processing the synthesis gas for its end use, and for recovering and processing the contaminants and waste solids for recycle, for disposal, or to form useful byproducts. Quantities, pressures, temperatures, compositions, and certain physical and chemical properties of each of the associated streams are included in this definition. The configuration of control systems that monitor or govern the flow of these streams and the operation of the process, as well as the process design of the equipment and the mechanical design of the GE proprietary equipment used in and for these processes, are also included.

(2) The integration of the gasification process with:

(a) that for electric power generation in this context refers to the following:

(i) Processes for heat exchange between the gasification section, the air separation unit (ASU), and the combined-cycle power island utilizing steam, syngas, and water. Quantities, compositions, pressures, and temperatures of each of these streams are included in this definition. Configuration of control systems that monitor or govern the flow of these streams, as well as the thermal design of the Heat Recovery Steam Generator and other heat exchange equipment are also included.

(ii) Processes that utilize and integrate the flow of compressed air between the gasification, ASU, and power plant sections and processes that utilize flows of diluents to the syngas fed to the combustion turbine. This includes the exchange of air and fuel diluent streams between the gasification section, the ASU, and the combustion turbine including these streams’ quantities, temperatures, pressures, and compositions. The configuration of control systems that monitor or govern these streams are also included in this definition. Fuel diluent streams are those streams that

are used to enhance the power plant’s output and to reduce emissions of NOx from the combustion turbine. These diluent streams may include, but are not limited to, nitrogen, steam, water, and carbon dioxide.

(iii) Control systems configuration and execution, including software that is involved in the feedback, feed-forward, and hybrid systems that govern the relationship of fuel flow, oxygen flow, diluent flow, and power plant output.

(b) that for hydrogen production in this context refers to the following:

Processes that increase the yield of hydrogen in the synthesis gas by reacting steam or water with carbon monoxide in the synthesis gas to form additional hydrogen, for separating and concentrating the hydrogen to form one or more gaseous streams of higher hydrogen purity, such as high purity hydrogen, for modifying the pressure of the feed and product streams, for heating, cooling or recovering waste energy from feed, intermediate, or product streams, for recycling hydrogen and non-hydrogen containing gases to increase the net yield of hydrogen, and for otherwise purifying, or removing or recovering contaminants from hydrogen-enriched and other product gases, including the synthesis gas. Quantities, pressures, temperatures, and the compositions of each of the associated streams are included in this definition. Control systems that monitor or govern the flow of these streams and the operation of the process, as well as the mechanical design of the equipment used in and for these processes, are also included.

(c) that for carbon capture in this context refers to shift conversion, purification, membrane separation, acid gas removal and/or compression including any means or methods for integrating said combination, and any modifications or improvements to any of the foregoing for the purpose of producing carbon dioxide.

For the avoidance of doubt, the physical byproducts of sulfur and slag are not included within the definitions of “GE Gasification Information” or “Confidential Information.”

SCHEDULE B

“Bechtel Sulfur Information” means Bechtel’s information relating to processes for the conversion of hydrogen sulfide to elemental sulfur in an environmentally acceptable manner, including but not limited to, Claus sulfur recovery, tail gas treating, and thermal oxidizing.

Attachment No. 3 – Form of Confidentiality Agreement (competitors)

FORM OF CONFIDENTIALITY AGREEMENT [COMPETITORS]

This CONFIDENTIALITY AGREEMENT (this “Agreement”) is made on                      200    , (“Effective Date”) by and between Duke Energy Indiana, Inc., an Indiana corporation having its principal place of business in Charlotte, North Carolina (“Duke Energy”), and [            ] (“RECIPIENT”) with its principal place of business at [            ] (collectively the “Parties” and each individually, a “Party”). In consideration of disclosure of Confidential Information (as defined below) to RECIPIENT, RECIPIENT agrees as follows:

SECTION 1 Purpose

1.1 RECIPIENT has been engaged by Duke Energy to assist Duke Energy in [tasks relating to the construction, licensing, commissioning, operation, repairs, maintenance, modification or decommissioning of, or training with respect to,] the integrated gasification combined cycle coal-fired electrical generation facility [to be constructed] at the Edwardsport site in Knox County, Indiana (the “Facility”) and, in such capacity, RECIPIENT may come into possession of Confidential Information as hereinafter defined. [NARROW PURPOSE FOR ENGAGEMENT]

SECTION 2 Definitions and Rules of Interpretation

2.1 Capitalized terms used but not otherwise defined in this Agreement have the meanings set forth in this Section 2.1:

“Affiliate” means any Person that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with a Party. For purposes of this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities or otherwise.

“Confidential Information” means any and all information received by or otherwise made available to RECIPIENT or any of its employees (whether before or after the Effective Date) which is marked as being confidential to Bechtel Power Corporation (“Bechtel”).

“Person” means, unless otherwise specified, a natural person, corporation, society, partnership, joint venture, unincorporated association or consortium or other entity, including a governmental authority.

2.2 Headings and captions in this Agreement have been inserted for ease of reference only and shall not be used in the construction or interpretation of this Agreement.

SECTION 3 Term of Agreement; Survival of Obligations

3.1 This Agreement shall be effective as of the Effective Date and the confidentiality obligations set out in Section 4 shall cease to be effective after the expiry of five (5) years from the Effective Date, except with respect to Bechtel Sulfur Information, for which such confidentiality obligations shall, as long as such information shall not be available to the public, be evergreen and shall have no expiration. “Bechtel Sulfur Information” means Bechtel’s information relating to processes for the conversion of hydrogen sulfide to elemental sulfur in an environmentally acceptable manner, including but not limited to, Claus sulfur recovery, tail gas treating, and thermal oxidizing.

SECTION 4 Undertakings of RECIPIENT

4.1 RECIPIENT shall keep all Confidential Information confidential and shall not disclose Confidential Information to any Person, including any Affiliate of RECIPIENT, except as permitted under Section 5.

4.2 RECIPIENT shall protect the Confidential Information against disclosure and shall exercise no lesser security measures and degree of care in relation to the Confidential Information than (a) a reasonable Person under similar circumstances would exercise in relation to its own confidential information, and (b) RECIPIENT uses to protect its own confidential information of a like nature.

4.3 No right, license or other interest is granted to RECIPIENT in relation to the Confidential Information except as expressly set forth in this Agreement, and RECIPIENT shall not use Confidential Information for any purpose except as contemplated by Section 1.1.

4.4 RECIPIENT shall ensure that each Person to whom Confidential Information is disclosed (other than pursuant to Section 5.2) complies with the terms of this Agreement and shall require that any such Person enters into an acknowledgement of the terms of this Agreement in the form attached to this Agreement (“Acknowledgement”) as a condition to disclosure of such Confidential Information. Without limiting the foregoing, and notwithstanding any confidentiality agreement entered into by any of RECIPIENT’s employees with RECIPIENT or Bechtel, RECIPIENT shall be and remain fully liable for the acts or omissions of its employees with respect to Confidential Information and any disclosure or use of Confidential Information in violation of the terms of this Agreement.

4.5 RECIPIENT shall keep all Confidential Information, as well as all information, documentation or other materials bearing or incorporating any Confidential Information, both physically and electronically separate from other documents of RECIPIENT in such a manner to limit the potential for disclosure (inadvertent or otherwise) to others who have not similarly executed an Acknowledgment. In no event shall RECIPIENT use any Confidential Information for any commercial or competitive purpose, except as contemplated by Section 1.1.

SECTION 5 Permitted Disclosures

5.1 RECIPIENT may disclose Confidential Information to its employees who have signed the Acknowledgement, but only to the extent such disclosure is required for the purpose contemplated by Section 1.1.

5.2 RECIPIENT may disclose Confidential Information to the extent such disclosure is required by any applicable law or regulation or court or other governmental authority of competent jurisdiction provided that any such disclosure shall be limited to the specific part of the Confidential Information required to be disclosed. Immediately upon RECIPIENT becoming aware that it is required, or may become required, to disclose Confidential Information for such reason, RECIPIENT shall (if legally permissible) give prompt written notice to Bechtel of such requirement or potential requirement and RECIPIENT shall assist, at Bechtel’s expense, in connection with Bechtel’s pursuit of legal remedies in order to limit the extent of Confidential Information required to be disclosed. RECIPIENT and Bechtel shall use commercially reasonable efforts to limit or prevent any further disclosure of Confidential Information required to be disclosed and to ensure that such Confidential Information is accorded confidential status and treatment by the court or other governmental authority in question.

5.3 RECIPIENT shall have no obligation of confidentiality with respect to Confidential Information that RECIPIENT can demonstrate: (a) was already in RECIPIENT’s possession at the time of its disclosure pursuant to this Agreement and which was not acquired, directly or indirectly, from Bechtel under obligation of confidentiality; (b) is or becomes a matter of public knowledge through no fault of RECIPIENT or any of its employees; (c) is lawfully received by RECIPIENT from a Person other than Bechtel in circumstances not involving a breach of any confidentiality obligation; or (d) is independently developed by RECIPIENT without benefit of disclosure pursuant to this Agreement.

SECTION 6 Other Undertakings of the Parties

6.1 At any time upon the written request of Bechtel or Duke Energy, RECIPIENT and its employees shall promptly deliver to Bechtel or Duke Energy (as applicable), or if directed by Bechtel or Duke Energy destroy by shredding or incineration, all Confidential Information received in written, electronic or other tangible form, including copies, reproductions, computer diskettes or written materials containing Confidential Information; provided, however, so long as the RECIPIENT is not in breach of any term of this Agreement with respect to Confidential Information, RECIPIENT shall not be required to return or destroy Confidential Information at the request of Bechtel to the extent RECIPIENT requires such Confidential Information to perform its obligations with respect to the Facility. To the extent that any other notes, analyses, compilations or studies in the possession of RECIPIENT or its employees contain Confidential Information, such notes, analyses, compilations or

studies shall be destroyed to that same extent and such destruction shall be confirmed by RECIPIENT in writing to Bechtel.

6.2 RECIPIENT shall immediately notify Duke Energy and Bechtel in the event that it becomes aware of any violation of the terms of this Agreement by it or its employees and shall assist Bechtel, at RECIPIENT’s own expense, in taking measures to protect the Confidential Information from further use or disclosure.

6.3 All Confidential Information shall at all times be subject to the export control laws and regulations of the United States Government. RECIPIENT agrees that no Confidential Information, or any product thereof, shall be exported or re-exported by RECIPIENT or its employees directly or indirectly from the USA, unless permitted by U.S. export control laws and regulations. The obligations of RECIPIENT under this Section 6.3 shall survive any termination, expiration or discharge of any other contract obligations.

SECTION 7 Non-Compliance with this Agreement

7.1 The Parties acknowledge and agree that money damages would be both incalculable and an inadequate remedy for any breach of this Agreement by RECIPIENT or RECIPIENT’s employees and that any such breach would cause each of Bechtel and Duke Energy irreparable harm. Accordingly, the Parties agree that in the event of any breach or threatened breach of this Agreement, each of Bechtel and Duke Energy, in addition to any other remedies it may have at law, shall be entitled, without the requirement of posting a bond or other security, to equitable and injunctive relief, including specific performance, against RECIPIENT and RECIPIENT’s employees.

SECTION 8 Miscellaneous

8.1 Except as otherwise expressly agreed in writing, neither Duke Energy nor Bechtel make any representations or warranties with regard to the substance, content, accuracy or completeness of Confidential Information disclosed. Except as otherwise expressly agreed in writing, neither Duke Energy, Bechtel nor any of their respective Affiliates shall have any liability to RECIPIENT or any of its employees arising out of or resulting from any disclosure of Confidential Information or any alleged reliance on or use of any Confidential Information, whether such liability arises or is alleged to arise in contract (including by way of indemnity), tort (including negligence), misrepresentation, by way of contribution, or otherwise.

8.2 The rights and remedies contained in this Agreement are cumulative and not exclusive of rights and remedies provided by applicable law. Any failure to exercise or delay in exercising any right or remedy provided by this Agreement or by applicable law shall not constitute a waiver of such right or remedy or a waiver of any other right or remedy provided by this Agreement or by applicable law. No single or partial exercise of a right or remedy provided by this Agreement or by applicable law shall prevent a further exercise of such right or remedy or the exercise of another right or remedy provided under this Agreement or applicable law.

8.3 All additions, amendments, waivers or modifications to this Agreement shall be made in writing and shall be signed by the Parties or, in the case of a waiver, the waiving Party.

8.4 This Agreement shall be governed by, and construed in accordance with, the laws of Indiana (without giving effect to the principles thereof relating to conflicts of law).

8.5 If any provision of this Agreement shall be determined by a governmental authority of competent jurisdiction to be invalid or unenforceable for any reason, the validity or enforceability of the remaining provisions of this Agreement, or any portions or applications thereof, shall not be affected by the invalidity or unenforceability of any other provision of this Agreement, and any invalid or unenforceable provision shall be deemed severed from the remainder of this Agreement. In such an event, the Parties shall use commercially reasonable efforts to negotiate an equitable adjustment to this Agreement with a view toward achieving the original purpose and intent of this Agreement.

8.6 Neither Party shall assign this Agreement, or its rights or obligations hereunder, in whole or in part to any other Person without the prior written consent of the other Party.

8.7 This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and permitted assigns.

8.8 This Agreement represents the entire agreement between the Parties with respect to the matters referred to herein and supersedes all prior written and oral understandings pertaining to the matters referred to herein.

8.9 This Agreement may be executed in any number of counterparts, each of which when executed and delivered shall be an original, but all of which shall constitute one and the same instrument.

8.10 Bechtel is an intended third party beneficiary of this Agreement, entitled to enforce its provisions against RECIPIENT.

[execution page follows]

IN WITNESS WHEREOF, the Parties have duly executed this Confidentiality Agreement as of the date first above written.

Duke Energy Indiana, Inc.	[            ]
Authorized Corporate	Authorized Corporate
Officer Signature	Officer Signature
Printed Officer’s Name	Printed Officer’s Name
Printed Officer’s Title	Printed Officer’s Title

FORM OF “ACKNOWLEDGEMENT”

ACKNOWLEDGEMENT OF                                                      

I,                                                       , in consideration for receiving “Confidential Information”, as such term is defined in the Confidentiality Agreement (the “Agreement”) dated                         , 2008, between Duke Energy Indiana, Inc. and                                                       ( “Employer”), hereby acknowledge that I have read the Agreement, that I understand the obligations contained therein, and that I agree to personally abide by the terms thereof.

I specifically agree that I will not disclose such Confidential Information to any other employee or agent of Employer or any affiliate of Employer, other than an employee of Employer who has similarly executed an Acknowledgement in the same form as this Acknowledgement.

By:

Name:

Title:

Date:

Schedule I – Bechtel Competitors

The following entities and their affiliates (excluding independent contractors engaged by Duke for a Duke Purpose prior to such independent contractors becoming an affiliate of any of the following entities) constitute “Bechtel Competitors”:

• ***

• ***

• ***

EX-12

Exhibit No. 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,
	2008		2007		2006		2005		2004
	(dollars in millions)
Earnings as defined for fixed charges calculation
Add:
Pre-tax income from continuing operations(a)	$	1,993	$	2,078	$	1,421	$	1,169	$	723
Fixed charges		883		797		1,382		1,159		1,433
Distributed income of equity investees		195		147		893		473		140
Deduct:
Preference security dividend requirements of consolidated subsidiaries		—		—		27		27		31
Interest capitalized(b)		93		71		56		23		18
Total earnings (as defined for the Fixed Charges calculation)	$	2,978	$	2,951	$	3,613	$	2,751	$	2,247
Fixed charges:
Interest on debt, including capitalized portions	$	834	$	756	$	1,311	$	1,096	$	1,365
Estimate of interest within rental expense		49		41		44		36		37
Preference security dividend requirements of consolidated subsidiaries		—		—		27		27		31
Total fixed charges	$	883	$	797	$	1,382	$	1,159	$	1,433
Ratio of earnings to fixed charges		3.4		3.7		2.6		2.4		1.6

(a) Excludes minority interest expense 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:

1388368 Ontario Inc. (Ontario)	Cinergy Mexico Limited, LLC (Delaware)
3036243 Nova Scotia Company (Canada—Nova Scotia)	Cinergy Mexico Marketing & Trading, LLC (Delaware)
Advance SC LLC (South Carolina)	Cinergy Origination & Trade, LLC (Delaware)
Aguaytia Energy del Peru S.R. Ltda (Peru)	Cinergy Power Generation Services, LLC (Delaware)
Aguaytia Energy, LLC (Delaware)	Cinergy Power Investments, Inc. (Ohio)
Antelope Ridge Gas Processing Plant	Cinergy Receivables Company LLC (Delaware)
Attiki Denmark ApS (Denmark)	Cinergy Retail Power General, Inc. (Texas)
Bison Insurance Company Limited (Bermuda)	Cinergy Retail Power Limited, Inc. (Delaware)
Brown County Landfill Gas Associates, L.P. (Delaware)	Cinergy Retail Power, L.P. (Delaware)
Brownsville Power I, LLC (Delaware)	Cinergy Risk Solutions Ltd. (Vermont)
BSPE General, LLC (Texas)	Cinergy Solutions—Utility, Inc. (Delaware)
BSPE Holdings, LLC (Delaware)	Cinergy Solutions Limited Partnership (Ontario)
BSPE Limited, LLC (Delaware)	Cinergy Solutions Partners, LLC (Delaware)
BSPE, L.P. (Delaware)	Cinergy Technology, Inc. (Indiana)
Cadence Network, Inc. (Delaware)	Cinergy Two, Inc. (Delaware)
Caldwell Power Company (North Carolina)	Cinergy UK, Inc. (Delaware)
Catawba Manufacturing and Electric Power Company (North Carolina)	Cinergy Wholesale Energy, Inc. (Ohio)
Centra Gas Toluca S. de R.L. de C.V. (Mexico)	Cinergy-Centrus Communications, Inc. (Delaware)
CGP Global Greece Holdings, SA (Greece)	Cinergy-Centrus, Inc. (Delaware)
Cinergy Capital & Trading, Inc. (Indiana)	CinFuel Resources, Inc. (Delaware)
Cinergy Climate Change Investments, LLC (Delaware)	CinPower I, LLC (Delaware)
Cinergy Corp. (Delaware)	Claiborne Energy Services, Inc. (Louisiana)
Cinergy General Holdings, LLC (Delaware)	Comercializadora Duke Energy de Centro America, Limitada (Guatemala)
Cinergy Global (Cayman) Holdings, Inc. (Cayman Islands)	Commercial Electricity Supplies Limited (England)
Cinergy Global Ely, Inc. (Delaware)	Compania de Servicios de Compresion de Campeche, S.A. de C.V. (Mexico)
Cinergy Global Hellas S.A. (Greece)	Countryside Landfill Gasco, LLC (Delaware)
Cinergy Global Holdings, Inc. (Delaware)	CRE, LLC (Delaware)
Cinergy Global Power (UK) Limited (England)	CSCC Holdings Limited Partnership (Canada - British Columbia)
Cinergy Global Power Africa (Proprietary) Limited (South Africa)	CSGP General, LLC (Texas)
Cinergy Global Power Iberia, S.A. (Spain)	CSGP Limited, LLC (Delaware)
Cinergy Global Power Services Limited (London, England)	CSGP of Southeast Texas, LLC (Delaware)
Cinergy Global Power, Inc. (Delaware)	CSGP Services, L.P. (Delaware)
Cinergy Global Resources, Inc. (Delaware)	CST General, LLC (Texas)
Cinergy Global Trading Limited (England)	CST Green Power, L.P. (Delaware)
Cinergy Global Tsavo Power (Cayman Islands)	CST Limited, LLC (Delaware)
Cinergy Holdings BV (Netherlands)	CTE Petrochemicals Company (Cayman Islands)
Cinergy Investments, Inc. (Delaware)	D/FD Holdings, LLC (Delaware)
Cinergy Limited Holdings, LLC (Delaware)	D/FD Operating Services LLC (Delaware)
Cinergy Mexico General, LLC (Delaware)	DE Fossil-Hydro Engineering, Inc. (North Carolina)
Cinergy Mexico Holdings, LP (Delaware)	DE Marketing Canada Ltd. (Canadian Federal)

DE Nuclear Engineering, Inc. (North Carolina)	Duke Energy Carolinas Plant Operations, LLC (Delaware)
DE Operating Services, LLC (Delaware)	Duke Energy Carolinas, LLC (North Carolina)
DE Power Generating, LLC (Delaware)	Duke Energy Development Pty Ltd (Australia)
DEGS Biogas, Inc. (Delaware)	Duke Energy Egenor S. en C. por A. (Peru)
DEGS EPCOM College Park, LLC (Delaware)	Duke Energy Electroquil Partners (Delaware)
DEGS GASCO, LLC (Delaware)	Duke Energy Engineering, Inc. (Ohio)
DEGS O&M, LLC (Delaware)	Duke Energy Finance Canada Limited Partnership (Alberta, Canada)
DEGS of Boca Raton, LLC (Delaware)	Duke Energy Fossil-Hydro California, Inc. (Delaware)
DEGS of Cincinnati, LLC (Ohio)	Duke Energy Fossil-Hydro, LLC (Delaware)
DEGS of Delta Township, LLC (Delaware)	Duke Energy Generating S.A. (Argentina)
DEGS of Lansing, LLC (Delaware)	Duke Energy Generation Services Holding Company, Inc. (Delaware)
DEGS of Monaca, LLC (Delaware)	Duke Energy Generation Services, Inc. (Delaware)
DEGS of Narrows, LLC (Delaware)	Duke Energy Global Markets, Inc. (Nevada)
DEGS of Oklahoma, LLC (Delaware)	Duke Energy Greenleaf, LLC (Delaware)
DEGS of Parlin, LLC (Delaware)	Duke Energy Group Holdings, LLC (Delaware)
DEGS of Philadelphia, LLC (Delaware)	Duke Energy Group, LLC (Delaware)
DEGS of Rock Hill, LLC (Delaware)	Duke Energy Hydrocarbons Canada Limited Partnership (Canada)
DEGS of San Diego, Inc. (Delaware)	Duke Energy Hydrocarbons Investments Ltd. (Canada—Alberta)
DEGS of Shreveport, LLC (Delaware)	Duke Energy Indiana, Inc. (Indiana)
DEGS of South Charleston, LLC (Delaware)	Duke Energy Industrial Sales, LLC (Delaware)
DEGS of St. Bernard, LLC (Delaware)	Duke Energy Interamerican Holding Company LDC (Cayman Islands)
DEGS of St. Paul, LLC (Delaware)	Duke Energy International (Europe) Holdings ApS (Denmark)
DEGS of Tuscola, Inc. (Delaware)	Duke Energy International (Europe) Limited (United Kingdom)
Delta Township Utilities, LLC (Delaware)	Duke Energy International Argentina Holdings (Cayman Islands)
DENA Asset Partners, L.P. (Delaware)	Duke Energy International Argentina Marketing/Trading (Bermuda) Ltd. (Bermuda)
DENA Partners Holding, LLC (Delaware)	Duke Energy International Asia Pacific Ltd. (Bermuda)
DETM Marketing Northeast, LLC (Delaware)	Duke Energy International Bolivia Holdings No. 1, LLC (Delaware)
DETMI Management, Inc. (Colorado)	Duke Energy International Bolivia Investments No. 1 Limited (Cayman Islands)
Dixilyn-Field (Nigeria) Limited (Nigeria)	Duke Energy International Bolivia Investments No. 2 Limited (Cayman Islands)
Dixilyn-Field Drilling Company (Delaware)	Duke Energy International Brasil Commercial, Ltda. (Brazil)
Dixilyn-Field International Drilling Company, S.A. (Panama)	Duke Energy International Brasil Holdings, LLC (Delaware)
DTMSI Management Ltd. (Alberta, Canada)	Duke Energy International Brazil Holdings Ltd. (Bermuda)
Duke Broadband, LLC (Delaware)	Duke Energy International del Ecuador Cia. Ltda. (Ecuador)
Duke Canada Ltd. (Alberta, Canada)	Duke Energy International El Salvador Comercializadora de El Salvador, S.A. de C.V. (El Salvador)
Duke Capital Partners, LLC (Delaware)	Duke Energy International El Salvador Investments No. 1 Ltd (Bermuda)
Duke Communication Services Caribbean Ltd. (Bermuda)	Duke Energy International El Salvador Investments No. 1 y Cia. S. enC. de C.V. (El Salvador)
Duke Communication Services, Inc. (North Carolina)	Duke Energy International El Salvador, S en C de CV (El Salvador)
Duke Communications Holdings, Inc. (Delaware)	Duke Energy International Electroquil Holdings, LLC (Delaware)
Duke Energy Allowance Management, LLC (Delaware)	Duke Energy International Espana Holdings, S.L.U. (Spain)
Duke Energy Americas, LLC (Delaware)	Duke Energy International Finance (UK) Limited (United Kingdom)
Duke Energy Business Services LLC (Delaware)	Duke Energy International Guatemala Holdings No. 1, Ltd. (Bermuda)

Duke Energy International Guatemala Holdings No. 2, Ltd. (Bermuda)	Duke Energy Providence, LLC (Delaware)
Duke Energy International Guatemala Holdings No. 3 (Cayman Islands)	Duke Energy Receivables Finance Company, LLC (Delaware)
Duke Energy International Guatemala Limitada (Guatemala)	Duke Energy Registration Services, Inc. (Delaware)
Duke Energy International Guatemala y Compania Sociedad en Comandita por Acciones (Guatemala)	Duke Energy Retail Sales, LLC (Delaware)
Duke Energy International Investments No. 2 Ltd. (Bermuda)	Duke Energy Royal, LLC (Delaware)
Duke Energy International Latin America, Ltd. (Bermuda)	Duke Energy Services Canada Ltd. (Alberta, Canada)
Duke Energy International Mexico, S.A. de C.V. (Mexico)	Duke Energy Services Ireland Limited (Republic of Ireland)
Duke Energy International Netherlands Financial Services B.V. (Netherlands)	Duke Energy Services, Inc. (Delaware)
Duke Energy International Operaciones Guatemala Limitada (Guatemala)	Duke Energy Shared Services, Inc. (Delaware)
Duke Energy International Peru Inversiones No. 1, S.R.L. (Peru)	Duke Energy St. Francis, LLC (Delaware)
Duke Energy International Peru Investments No. 1, Ltd. (Bermuda)	Duke Energy Supply Chain Services, LLC (Delaware)
Duke Energy International PJP Holdings (Mauritius) Ltd. (Republic of Mauritius)	Duke Energy Trading and Marketing, LLC (Delaware)
Duke Energy International PJP Holdings, Ltd. (Bermuda)	Duke Energy Trading Exchange, LLC (Delaware)
Duke Energy International Pty Ltd (Australia)	Duke Engineering & Services (Europe) Inc. (Delaware)
Duke Energy International Services (UK) Limited (United Kingdom)	Duke Engineering & Services International, Inc. (Cayman Islands)
Duke Energy International Southern Cone SRL (Argentina)	Duke Investments, LLC (Delaware)
Duke Energy International Trading and Marketing (UK) Limited (United Kingdom)	Duke Java, Inc. (Nevada)
Duke Energy International Transmision Guatemala Limitada (Guatemala)	Duke Project Services Australia Pty Ltd (Australia)
Duke Energy International Uruguay Holdings, LLC (Delaware)	Duke Project Services, Inc. (North Carolina)
Duke Energy International Uruguay Investments, S.R.L. (Uruguay)	Duke Supply Network, LLC (Delaware)
Duke Energy International, Brasil Ltda. (Brazil)	Duke Technologies, Inc. (Delaware)
Duke Energy International, Geracao Paranapanema S.A. (Brazil)	Duke Trading Do Brasil Ltda. (Brazil)
Duke Energy International, LLC (Delaware)	Duke Ventures II, LLC (Delaware)
Duke Energy Kentucky, Inc. (Kentucky)	Duke Ventures, LLC (Nevada)
Duke Energy Lantana, LLC (Delaware)	Duke/Fluor Daniel (North Carolina)
Duke Energy Marketing America, LLC (Delaware)	Duke/Fluor Daniel Caribbean, S.E. (Puerto Rico)
Duke Energy Marketing Canada Corp. (Delaware)	Duke/Fluor Daniel El Salvador S.A. de C.V. (El Salvador)
Duke Energy Marketing Corp. (Nevada)	Duke/Fluor Daniel International (Nevada)
Duke Energy Marketing Limited Partnership (Alberta, Canada)	Duke/Fluor Daniel International Services (Nevada)
Duke Energy Merchant Finance, LLC (Delaware)	Duke/Fluor Daniel International Services (Trinidad) Ltd. (Trinidad and Tobago)
Duke Energy Merchants Investments (UK) Limited (England and Wales)	Duke/Louis Dreyfus LLC (Nevada)
Duke Energy Merchants Trading and Marketing (UK) Limited (England)	Duke-Cadence, Inc. (Indiana)
Duke Energy Merchants UK LLP (England and Wales)	DukeNet Communication Services, LLC (Delaware)
Duke Energy Merchants, LLC (Delaware)	DukeNet Communications, LLC (Delaware)
Duke Energy Moapa, LLC (Delaware)	Duke-Reliant Resources, Inc. (Delaware)
Duke Energy Murray Operating, LLC (Delaware)	DukeTec I, LLC (Delaware)
Duke Energy North America, LLC (Delaware)	DukeTec II, LLC (Delaware)
Duke Energy Ohio, Inc. (Ohio)	DukeTec, LLC (Delaware)
Duke Energy One, Inc. (Delaware)	Eastman Whipstock do Brasil Ltda. (Brazil)
Duke Energy Peru Holdings S.R.L. (Peru)	Eastman Whipstock, S.A. (Argentina)
Duke Energy Power Assets Holding, Inc. (Colorado)	Eastover Land Company (Kentucky)
Eastover Mining Company (Kentucky)	National Methanol Company (IBN SINA) (Saudi Arabia)
Electroguayas, Inc. (Cayman Islands)	NorthSouth Insurance Company Limited (Bermuda)

Electroquil, S.A. (Guayaquil, Ecuador)	Oak Mountain Products, LLC (Delaware)
Empresa Electrica Corani, S.A. (Bolivia)	Ohio River Valley Propane, LLC (Delaware)
Energy Pipelines International Company (Delaware)	P.I.D.C. Aguaytia, LLC (Delaware)
EnerVest Olanta, LLC (Texas)	Pan Service Company (Delaware)
Environmental Wood Supply, LLC (Minnesota)	PanEnergy Corp (Delaware)
Eteselva S. R. L. (Peru)	Peru Energy Holdings, LLC (Delaware)
eVent Resources Holdings LLC (Delaware)	Power Construction Services Pty Ltd. (Western Australia)
eVent Resources I LLC (Delaware)	Reliant Services, LLC (Indiana)
Fiber Link, LLC (Indiana)	Seahorse do Brasil Servicos Maritimos Ltda. (Brazil)
Fort Drum Cogenco, Inc. (New York)	South Construction Company, Inc. (Indiana)
Gas Integral S.R.L. (Peru)	South Houston Green Power, L.P. (Delaware)
Generadora La Laguna Duke Energy International Guatemala y Cia., S.C.A. (Guatemala)	Southeastern Energy Services, Inc. (Delaware)
GNE Holdings, LLC (Delaware)	Southern Power Company (North Carolina)
Green Power G.P., LLC (Texas)	Spruce Mountain Investments, LLC (Delaware)
Green Power Holdings, LLC (Delaware)	Spruce Mountain Products, LLC (Delaware)
Green Power Limited, LLC (Delaware)	St. Paul Cogeneration, LLC (Minnesota)
Greenville Gas and Electric Light and Power Company (South Carolina)	SUEZ/VWNA/DEGS of Lansing, LLC (Delaware)
Hidroelectrica Cerros Colorados, S.A. (Argentina)	SUEZ-DEGS of Lansing, LLC (Delaware)
IGC Aguaytia Partners, LLC (Cayman Islands)	SUEZ-DEGS of Orlando, LLC (Delaware)
II Tryon Investment Trading Society (North Carolina)	SUEZ-DEGS, LLC (Delaware)
Inversiones Duke Bolivia S.A. (Bolivia)	SYNCAP II, LLC (Delaware)
KO Transmission Company (Kentucky)	TEC Aguaytia, Ltd. (Bermuda)
Lansing Grand River Utilities, LLC (Delaware)	Termoselva S. R. L. (Peru)
LH1, LLC (Delaware)	Texas Eastern (Bermuda) Ltd. (Bermuda)
Lizacorp S.A. (Ecuador)	Texas Eastern Arabian Ltd. (Bermuda)
MCP, LLC (South Carolina)	Tri-State Improvement Company (Ohio)
Miami Power Corporation (Indiana)	UK Electric Power Limited (England)
Midlands Hydrocarbons (Bangladesh) Limited (England)	Wateree Power Company (South Carolina)
Morris Gasco, LLC (Delaware)	Western Carolina Power Company (North Carolina)
MP Supply, Inc. (North Carolina)

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements No. 333-157405, 333-146483 and 333-132996 on Form S-3 and Registration Statements No. 333-132933 (including Post-effective Amendment No. 1 thereto), 333-134080, 333-141023 and 333-147132 on Form S-8 of our report dated February 27, 2009, 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, 2008.

/s/ DELOITTE & TOUCHE LLP

Charlotte, North Carolina

February 27, 2009

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in Registration Statements No. 333-157405, 333-146483 and 333-132996 on Form S-3 and Registration Statements No. 333-132933 (including Post-effective Amendment No. 1 thereto), 333-134080, 333-141023 and 333-147132 on Form S-8 of Duke Energy Corporation of our report dated March 7, 2008 relating to the consolidated financial statements and financial statement schedule of DCP Midstream, LLC and subsidiaries as of and for the years ended December 31, 2006 and 2005, appearing in this Annual Report on Form 10-K of Duke Energy Corporation for the year ended December 31, 2008.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

February 27, 2009

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, 2008

(Annual Report)

The undersigned Duke Energy Corporation, a Delaware corporation and certain of its officers and/or directors, do each hereby constitute and appoint David L. Hauser, 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, 2008, 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 19^th day of February, 2009.

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         James E. Rogers	Chairman, President and Chief Executive Officer (Principal Executive Officer and Director)
/S/    DAVID L. HAUSER         David L. Hauser	Group Executive and Chief Financial Officer (Principal Financial Officer)
/S/    STEVEN K. YOUNG         Steven K. Young	Senior Vice President and Controller (Principal Accounting Officer)
/S/    WILLIAM BARNET, III         William Barnet, III	(Director)
/S/    G. ALEX BERNHARDT, SR.         G. Alex Bernhardt, Sr.	(Director)
/S/    MICHAEL G. BROWNING         Michael G. Browning	(Director)
/S/    DANIEL R. DIMICCO         Daniel R. DiMicco	(Director)

/S/    ANN M. GRAY         Ann M. Gray	(Director)
/S/    JAMES H. HANCE, JR.         James H. Hance, Jr.	(Director)
/S/    JAMES T. RHODES         James T. Rhodes	(Director)
Philip R. Sharp	(Director)
/S/    DUDLEY S. TAFT         Dudley S. Taft	(Director)

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 2008 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 David L. Hauser, 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 2008 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 25, 2009, 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 27^th day of February, 2009.

/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 27, 2009

/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, David L. Hauser, 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 27, 2009

/S/    DAVID L. HAUSER        

David L. Hauser

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, 2008 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 27, 2009

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, 2008 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David L. Hauser, 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/    DAVID L. HAUSER        

David L. Hauser

Group Executive and Chief Financial Officer

February 27, 2009