10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

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

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.


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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.”

 

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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

 

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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

 

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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

 

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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.”)

 

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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.

 

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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.

 

LOGO

 

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LOGO

 

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.

 

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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

 

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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

 

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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

 

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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,

 

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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.

 

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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.

 

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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-

 

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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.

 

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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.

 

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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.

 

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

 

LOGO

 

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Through DEGS, Commercial Power is an on-site energy solutions and utility services provider. Primarily through joint ventures, DEGS engages in utility systems construction, operation and maintenance of utility facilities, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of usable energy from a single source. 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.

LOGO

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

 

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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.

 

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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.

 

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

 

LOGO

 

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.

 

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Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. 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.

 

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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 NOx from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). 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.

 

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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.

 

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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.

 

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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.

 

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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

 

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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 NOx, 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

 

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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;

 

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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.

 

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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

 

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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.)

 

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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.

 

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

Duke Energy’s common stock is listed for trading on the New York Stock Exchange (NYSE) (ticker symbol DUK). As of February 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.

 

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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.

 

LOGO

 

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.

 

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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  

 

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(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.

 

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

 

INTRODUCTION

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

 

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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,

 

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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

 

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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.

 

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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.

 

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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

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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

 

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

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

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

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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

 

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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

 

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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-

 

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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).

 

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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.

 

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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.

 

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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.

 

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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.

 

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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

 

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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.

 

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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.”

 

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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.

 

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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.

 

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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.”

 

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Contractual Obligations

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

 

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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

 

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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

 

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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.

 

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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

 

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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 110th 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 110th 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 111th Congress multiple committees will be involved in crafting GHG legislation, which will make the process of developing GHG legislation potentially more challenging.

 

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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.

 

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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 111th 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.

 

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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.”

 

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Item 8. Financial Statements and Supplementary Data.

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of Duke Energy Corporation

Charlotte, North Carolina

 

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (the “Company”) as of December 31, 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

 

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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

 

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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

 

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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

 

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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