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, 2007 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, 2007    $ 23,017,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at February 22, 2008      1,262,865,450


Table of Contents

TABLE OF CONTENTS

 

DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2007

 

Item

        Page
PART I.   
1.    BUSINESS    3
  

GENERAL

   3
  

U.S. FRANCHISED ELECTRIC AND GAS

   7
  

COMMERCIAL POWER

   19
  

INTERNATIONAL ENERGY

   21
  

CRESCENT

   23
  

OTHER

   23
  

ENVIRONMENTAL MATTERS

   23
  

GEOGRAPHIC REGIONS

   24
  

EMPLOYEES

   24
  

EXECUTIVE OFFICERS OF DUKE ENERGY

   24
1A.    RISK FACTORS    25
1B.    UNRESOLVED STAFF COMMENTS    32
2.    PROPERTIES    32
3.    LEGAL PROCEEDINGS    34
4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS    34
PART II.   
5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES    35
6.    SELECTED FINANCIAL DATA    37
7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    39
7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    75
8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA    76
9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE    173
9A.    CONTROLS AND PROCEDURES    173
PART III.   
10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE    174
11.    EXECUTIVE COMPENSATION    174
12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS    174
13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE    174
14.    PRINCIPAL ACCOUNTING FEES AND SERVICES    174
PART IV.   
15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES    175
  

SIGNATURES

   176
  

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 hurricanes, ice storms, 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;

   

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

Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is an energy company located 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 and the year ended December 31, 2005. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy hereinafter.

Cinergy, a Delaware corporation organized in 1993, owns all outstanding common stock of its public utility companies, Duke Energy Ohio, Inc. (Duke Energy Ohio) and Duke Energy Indiana, Inc. (Duke Energy Indiana), as well as other businesses including cogeneration and energy efficiency investments.

Duke Energy Ohio, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its wholly-owned subsidiary Duke Energy Kentucky, Inc. (Duke Energy Kentucky), in nearby areas of Kentucky. Its principal lines of business include generation, transmission, and distribution of electricity, the sale of and/or transportation of natural gas, and power marketing. The regulated operations of Duke Energy Ohio are included in the U.S. Franchised Electric and Gas business segment, whereas the unregulated portion of the business is included in the Commercial Power business segment.

Duke Energy Indiana, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in central, north central and southern Indiana. Its primary line of business is generation, transmission, and distribution of electricity.

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 (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). As discussed below, 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.

 

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At December 31, 2007, Duke Energy operated the following business segments, all of which are considered reportable segments under 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, International Energy and Duke Energy’s 50% interest in the Crescent Resources joint venture (Crescent JV or Crescent). Prior to Duke Energy’s sale of an effective 50% ownership interest in Crescent in September 2006 (see below), this segment represented Duke Energy’s 100% ownership of Crescent Resources, LLC. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business 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 3 to the Consolidated Financial Statements, “Business Segments.”

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

Commercial Power owns, operates and manages non-regulated 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 comprise approximately 8,020 megawatts 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). For more information on the RSP, see the “Commercial Power” section below. Commercial Power also develops and implements customized energy solutions. Commercial Power, through Duke Energy Generation Services, Inc. and its affiliates (DEGS), develops, owns and operates electric generation for large energy consumers, municipalities, utilities and industrial facilities. DEGS currently manages more than 6,600 megawatts of power generation at 23 facilities throughout the U.S. DEGS has 240 megawatts of wind energy under construction and well over 2,500 megawatts of wind energy projects in the development pipeline.

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.

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.

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.

 

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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, 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. 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.

Duke Energy is a Delaware corporation. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. The telephone number is 704-594-6200. Duke Energy electronically files reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies and amendments to such reports. The public may read and copy any materials that Duke Energy files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about Duke Energy, including its reports filed with the SEC, is available through Duke Energy’s web site at http://www.duke-energy.com. Such reports are accessible at no charge through Duke Energy’s web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.

 

GLOSSARY OF TERMS

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

Term or Acronym

  

Definition

AAC    Annually Adjusted Component
AFUDC    Allowance for Funds Used During Construction
AOCI    Accumulated Other Comprehensive Income
APB    Accounting Principles Board
Bison    Bison Insurance Company Limited
BPM    Bulk Power Marketing
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 JV
DCP Midstream    DCP Midstream, LLC (formerly Duke Energy Field Services, LLC)

 

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Term or Acronym

  

Definition

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
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
FASB    Financial Accounting Standards Board
FEED    Front End Engineering and Design Study
FERC    Federal Energy Regulatory Commission
FIN    Financial Accounting Standards Board Interpretation
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
LS Power    LS Power Equity Partners
MBSSO    Market Based Standard Service Offer
Mcf    Thousand cubic feet
Moody’s    Moody’s Investor Services
MSREF    Morgan Stanley Real Estate Fund V U.S., L.P.
MW    Megawatt
NCUC    North Carolina Utilities Commission
NDTF    Nuclear Decommissioning Trust Funds

 

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Term or Acronym

  

Definition

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
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
RSP    Rate Stabilization Plan
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
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 3 to the Consolidated Financial Statements, “Business Segments.”)

 

U.S. FRANCHISED ELECTRIC AND GAS

 

Service Area and Customers

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity 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

 

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about 47,000 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 3.9 million residential, commercial and industrial customers over 148,700 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 7,100 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and service lines. Electricity is also sold wholesale to incorporated municipalities and to public and private utilities. In addition, municipal and cooperative customers who purchased portions of the Catawba Nuclear Station may also buy power from a variety of suppliers, including Duke Energy Carolinas, through contractual agreements. For more information on the Catawba Nuclear Station joint ownership, see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating and Transmission Facilities.”

Duke Energy Carolinas’ service area has a diversified commercial and industrial presence. Manufacturing continues to be the largest contributor to the economy in the region. Other sectors such as finance, insurance and real estate services also constitute key components of the states’ gross domestic product.

The textile industry, rubber and plastic products, chemicals, and machinery and computer products were the most significant contributors to the area’s manufacturing output and Duke Energy Carolinas’ industrial sales revenue for 2007. Motor vehicle parts, paper, food and beverage, building materials and electrical and electronic equipment manufacturing also have a strong impact on the area’s economic growth and the region’s industrial sales. The textile industry, while in decline, is the largest industry served in both North Carolina and South Carolina (collectively referred to as the Carolinas).

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 business. These competitive advantages, including a quality workforce, strong educational institutions, superior transportation infrastructure and competitive electric rates 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, substantially offset the sales declines in the industries like textile and furniture in 2007.

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. Cincinnati, Ohio is positioned to become a healthcare hub and the presence of non-durable manufacturing makes the area less vulnerable to economic fluctuations than other areas.

The primary metals industry, transportation equipment, chemicals, and paper and plastics 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 2007. 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 businesses. 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 transportation, food manufacturing, chemical manufacturing, plastics and data processing industries.

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

Duke Energy Indiana 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, were key in attracting new customers and encouraging existing customer expansions. This ability to attract business investment in the service territory helped balance the slight decline in sales in the chemical, food and transportation equipment sector in 2007.

The number of residential and commercial 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. As sales to residential and commercial customers increase, the level of sales to industrial customers becomes a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales.

 

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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.

 

Duke Energy — Carolinas

Power Generation Regulated 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 5,020 megawatts (MW) (including Duke Energy’s 12.5% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with a combined net capacity of 13,552 MW (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 3,213 MW, fifteen combustion turbine (CT) stations burning natural gas, oil or other fuels with a combined net capacity of 5,241 MW and two combined cycle (CC) stations burning natural gas or synthetic gas with a combined net capacity of 560 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 2007, approximately 97.7% of the total generated energy came from U.S Franchised Electric and Gas’ low-cost, efficient nuclear and coal units (66.5% coal and 31.2% 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. In March 2006, Duke Energy Carolinas announced that it had entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. In May 2007, Duke Energy announced its intent to purchase Southern Company’s 500 MW interest in the proposed William States Lee III Nuclear Station, making the plant’s total output available to Duke Energy Carolinas’ electric customers. On December 13, 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 at the Cherokee County, South Carolina site. 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 27, 2008, Duke Energy Carolinas received confirmation from the NRC that its COL application has been accepted and docketed for the next stage of review. Also, on December 7, 2007, Duke Energy Carolinas filed applications with the NCUC and the PSCSC for approval of Duke Energy Carolinas’ decision to incur development costs associated with the proposed William States Lee III Nuclear Station. The NCUC had previously approved Duke Energy’s decision to incur the North Carolina allocable share of up to $125 million in development costs through 2007. The new requests cover a total of up to $230 million in pre-construction development costs through 2009, which is comprised of approximately $70 million incurred through December 31, 2007 plus an additional $160 million of anticipated costs in 2008 and 2009. The PSCSC has scheduled an evidentiary hearing on Duke Energy Carolinas’ application for April 17, 2008 and the NCUC has scheduled an evidentiary hearing for April 29, 2008. Also, in December 2006, Duke Energy announced an agreement to purchase a portion of Saluda River Electric Cooperative, Inc.’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy will pay approximately $158 million for the additional ownership interest of the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy will own approximately 19 percent of Catawba Nuclear Station. This transaction, which is expected to close prior to September 30, 2008, is subject to approval by various state and federal agencies.

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 February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. On March 21, 2007, the NCUC issued its Order, which 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 certain conditions including providing for updates on construction cost estimates. A group of environmental interveners filed a motion and supplemental motion for reconsideration in April 2007 and May 2007, respectively. Duke Energy opposed the motions and the NCUC denied the motions for reconsideration in June 2007. On January 31, 2008, Duke Energy Carolinas filed its updated cost estimate of $1.8 billion (excluding AFUDC of $600 million) 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 July 11, 2007, Duke Energy Carolinas entered into an 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 a new 800 MW coal unit, with the remainder related to a flue gas desulfurization system on an existing unit, at Cliffside. On January 29, 2008, the final air permit was issued by the North Carolina Department of Environment and Natural Resources (DENR).

On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 600-800 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 600-800 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 has consolidated its consideration of the two CPCN applications and scheduled an evidentiary hearing on the applications for March 11, 2008.

In August 2005, Duke Energy Indiana filed an application with the IURC for approval of study and preconstruction costs related to the joint development of an IGCC project with Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (Vectren). Duke Energy Indiana and Vectren reached a Settlement Agreement with the Indiana Office of Utility Consumer Counselor (OUCC) providing for the recovery of such costs if the IGCC project is approved and constructed and for the partial recovery of such costs if the IGCC project does not go forward. The IURC issued an order on July 26, 2006 approving the Settlement Agreement in its entirety.

 

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On September 7, 2006, Duke Energy Indiana and Vectren filed a joint petition with the IURC seeking CPCN’s 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 baseload 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. Duke Energy Indiana and Vectren filed their cases in chief with the IURC on October 24, 2006. As with Duke Energy Carolinas’ Cliffside project, Duke Energy Indiana’s estimated costs for the potential IGCC project have increased. Duke Energy Indiana’s publicly filed testimony with the IURC states that industry estimates (as provided by the Electric Power Research Institute (EPRI)) of total capital requirements for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owners’ specific site costs). 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 AFUDC). An evidentiary hearing was held June 18-22, 2007, and a public field hearing was held on August 29, 2007. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana CPCNs for the proposed IGCC project and approved the timely recovery of costs related to the project. The IURC also approved Duke Energy Indiana’s proposal to initiate a proceeding in May 2008 concerning proposals for the study of partial carbon capture, sequestration and/or enhanced oil recovery for the Edwardsport IGCC Project. The Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc., all intervenors in the CPCN proceeding, have appealed the IURC Order to the Indiana Court of Appeals. That appeal is pending. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management. In August 2007, Vectren withdrew its participation in the IGCC plant. Duke Energy Indiana is currently exploring its options, including assuming 100% of the plant capacity. Absent identification of an alternative joint owner, Duke Energy Indiana would own 100% of the IGCC plant capacity.

 

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, 2007.

 

     Generation by Source
(Percent)
   Cost of Delivered Fuel per Net
Kilowatt-hour Generated (Cents)
      2007    2006(e)    2005    2007    2006(e)    2005

Coal(a)

   66.5    63.4    52.5    2.20    2.16    2.14

Nuclear(b)

   31.2    35.1    45.7    0.38    0.42    0.41

Oil and gas(c)

   1.1    0.6    0.1    9.32    12.67    28.83
                       

All fuels (cost based on weighted average)(a)(b)

   98.8    99.1    98.3    1.71    1.61    1.36

Hydroelectric(d)

   1.2    0.9    1.7         
                       
   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% ownership interest in the Catawba Nuclear Station.
(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 2008 to 2016. U.S. Franchised Electric and Gas expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required as existing contracts expire, though prices will fluctuate over time as coal markets change. The coal purchased for the Carolinas is primarily produced from mines in eastern Kentucky, West Virginia and southwestern Virginia. The coal purchased for the 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 2008 operations and a significant portion of supply to fuel its projected 2009 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.

 

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Gas. U.S. Franchised Electric and Gas is responsible for the purchase and the subsequent delivery of natural gas to native load customers in the Midwest. U.S. Franchised Electric and Gas’ natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows U.S. Franchised Electric and Gas to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides U.S. Franchised Electric and Gas the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under U.S. Franchised Electric and Gas’ customer choice/gas transportation programs. In 2007, firm supply purchase commitment agreements provided approximately 97% 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 nine million gallons of liquid propane through a storage 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 25-75% of winter heating season baseload gas requirements and up to 25-50% of summer season baseload requirements up to three years in advance of the delivery month. Duke Energy Ohio and Duke Energy Kentucky use primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2007, Duke Energy Ohio and Duke Energy Kentucky, combined, had hedged approximately 52% of their winter 2007/2008 base 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. Developing nuclear generating fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and then the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

U.S. Franchised Electric and Gas has contracted for uranium materials and services required to fuel the Oconee, McGuire and Catawba Nuclear Stations in the Carolinas. Uranium concentrates, conversion services and enrichment services are primarily met through a diversified portfolio of long-term supply contracts. The contracts are diversified by supplier, country of origin and pricing. U.S. Franchised Electric and Gas staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements at Oconee, McGuire and Catawba in the near term, but so that its level of coverage decreases over time into the future. Due to the technical complexities of changing suppliers of fuel fabrication services, U.S. Franchised Electric and Gas generally sole sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

Based on current projections, U.S. Franchised Electric and Gas’ existing portfolio of contracts will meet the requirements of Oconee, McGuire and Catawba Nuclear Stations through the following years:

 

Nuclear Station

   Uranium Material    Conversion Service    Enrichment Service    Fabrication Service
Oconee    2012    2012    2009    2015
McGuire    2012    2012    2009    2015
Catawba    2012    2012    2009    2014

 

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After the years indicated above, a portion of the fuel requirements at Oconee, McGuire and Catawba are covered by long-term contracts. For requirements not covered under long-term contracts, Duke Energy believes it will be able to renew contracts as they expire, or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with uranium spot market purchases.

Duke Energy Carolinas has entered into a contract with Shaw AREVA MOX Services (MOX Services) (formerly Duke COGEMA Stone & Webster, LLC) under which Duke Energy Carolinas has agreed to prepare the McGuire and Catawba nuclear reactors for use of mixed-oxide fuel and to purchase mixed-oxide fuel for use in such reactors. Mixed-oxide fuel will be fabricated by MOX Services from the U.S. government’s excess plutonium from its nuclear weapons programs and is similar to conventional uranium fuel. Before using the fuel, Duke Energy Carolinas must apply for and obtain amendments to the facilities’ operating licenses from the NRC. On March 3, 2005, the NRC issued amendments to Catawba Nuclear Station’s operating licenses to allow the receipt and use of four mixed oxide fuel lead assemblies. These four lead assemblies completed their first cycle of irradiation on November 11, 2006 and have been inserted for a second cycle of irradiation in Unit 1 of the Catawba Nuclear Station.

Energy Efficiency. In May 2007, Duke Energy Carolinas filed an energy efficiency plan with the NCUC that recognizes energy efficiency as a reliable, valuable resource that is a “fifth fuel,” that should be part of the portfolio available to meet customers’ growing need for electricity along with coal, nuclear, natural gas, or renewable energy. The plan would compensate Duke Energy Carolinas for verified reductions in energy use and be available to all customer groups. The plan contains proposals for several different energy efficiency programs. Customers would pay for energy efficiency programs with an energy efficiency rider that would be included in their power bill and adjusted annually. The energy efficiency rider would be based on the avoided 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. A hearing is expected in 2008.

On September 28, 2007, Duke Energy Carolinas filed an application with the PSCSC seeking approval to implement new energy efficiency programs in South Carolina. Duke Energy Carolinas’ South Carolina application is based on the application filed in North Carolina. In advance of the evidentiary hearing held February 5-6, 2008, Duke Energy Carolinas reached settlement agreements with the South Carolina Office of Regulatory Staff (ORS), Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. Certain environmental groups that were also interveners on the proceeding did not join any of the settlements. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allows for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.

Implementation of these plans is subject to approval from the NCUC and PSCSC. As a result, Duke Energy is not able to estimate the impact this plan might have on its consolidated results of operations, cash flows, or financial position.

On July 11, 2007, the PUCO approved Duke Energy Ohio’s Demand Side Management/ Energy Efficiency Program (DSM Program). The DSM Program consists of ten residential and two commercial programs. Implementation of the programs has begun. The 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.

On October 19, 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 will be based on the avoided cost of generation not needed as a result of the success of Duke Energy Indiana’s energy efficiency programs. The IURC is expected to consider the petition in an evidentiary hearing in May 2008.

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. An order on the application is expected in the first quarter of 2008.

 

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Renewable Energy. Climate change concerns, as well as the high price of oil, 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. 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 that can be available as early as 2012.

 

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, 2007, the inventory balance for U.S. Franchised Electric and Gas was approximately $817 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

 

Insurance and Decommissioning

Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and the Catawba Nuclear Stations 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 full limit of liability, which is approximately $10.8 billion. See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Nuclear Insurance,” for more information.

In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. During 2007, Duke Energy expensed approximately $48 million and contributed approximately $48 million of cash to the Nuclear Decommissioning Trust Funds (NDTF) for decommissioning costs. The entire $48 million was contributed 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 funds was $1,929 million as of December 31, 2007 and $1,775 million as of December 31, 2006. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds Within Investments and Other Assets.

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s 12.5% ownership in Catawba Nuclear Station. The other joint owners of Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. The previous study, conducted in 1999, estimated a decommissioning cost of $1.9 billion ($2.2 billion in 2003 dollars at 3% inflation). The estimated increase is due primarily to inflation and cost increases for the size of the organization needed to manage the decommissioning project (based on current industry experience at facilities undergoing decommissioning). Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Duke Energy believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.

After 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 Department of Energy (DOE) for the disposal of used nuclear fuel. The DOE failed to begin accepting used nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. 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 are 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 6, 2007, Duke Energy Carolinas and the U.S. Department of Justice 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. Duke Energy will continue to safely manage its used nuclear fuel until the DOE accepts it.

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

 

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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 it is possible that claims will continue to be 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 reserve 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 financial position, cash flows, or results of operations 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 17 to the Consolidated Financial Statements, “Commitments and Contingencies—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. For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—U.S. Franchised Electric and Gas.” The State Utility Commissions, except for the PUCO, also have authority over the construction and operation of U.S. Franchised Electric 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.

 

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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), a settlement agreement among Duke Energy Carolinas, the NCUC 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. Under the Partial Settlement, Duke Energy Carolinas will 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 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 non-settled issues, 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 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 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. This order reaffirmed the prior tentative conclusion that the provisions of the Merger Order will not produce a fair sharing of the benefits of estimated merger savings between ratepayers and shareholders and that, for that reason, Duke Energy should be authorized to implement a 12-month increment rider to collect $80 million.

South Carolina passed new energy legislation which became effective May 3, 2007. Key elements of the legislation include expansion of the annual fuel clause mechanism to include recovery of costs of reagents (ammonia, limestone, etc.) that are consumed in the operation of Duke Energy Carolinas’ SO2 and nitrogen oxide (NOx) control technologies and the cost of certain emission allowances used to meet environmental requirements. The cost of reagents for Duke Energy Carolinas in 2008 is expected to be approximately $30 million. With the enactment of this legislation, Duke Energy Carolinas will be allowed to recover the South Carolina portion of these costs, incurred on or after May 3, 2007, through the fuel clause. The legislation also includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear base-

 

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load generation in rates during construction. The North Carolina General Assembly also passed comprehensive energy legislation in July 2007 that was signed into law by the Governor on August 20, 2007. The North Carolina legislation allows utilities to recover the costs of reagents and certain purchased power costs. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to construction work in progress for baseload plants in a rate case. The North Carolina legislation also establishes a renewable portfolio standard for electric utilities at 3% of energy output in 2012, rising gradually to 12.5% by 2021, and grants the NCUC authority to approve a rate rider to compensate utilities for energy efficiency programs that they implement. On August 23, 2007, the NCUC initiated a rulemaking proceeding to adopt new rules and modify existing rules, as appropriate, to implement the legislation. That proceeding is pending and final rules are expected in the first quarter 2008. At this time, Duke Energy is not able to estimate the impact these legislative initiatives might have on its consolidated results of operations, cash flows, or financial position.

On December 12, 2007, the PSCSC directed the ORS to provide a written report concerning the NCUC’s resolution of Duke Energy Carolinas’ rate application and its relevance to Duke Energy Carolinas’ rates in South Carolina. The ORS in turn requested information from Duke Energy Carolinas. After review of information supplied by Duke Energy Carolinas and several other documents related to the North Carolina rate case, and after conversations with the North Carolina Public Staff, the ORS filed its report with the PSCSC on January 31, 2008. The ORS concluded that the outcome of the North Carolina rate case had no bearing on Duke Energy Carolinas’ rates in South Carolina. The PSCSC has not yet responded to the report filed by the ORS.

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

On September 25, 2007, at the request of the Governor of Ohio, the Ohio Senate introduced a bill (SB 221) that proposes a comprehensive change to Ohio’s 1999 electric energy industry restructuring legislation. If enacted, SB 221 would expand the PUCO’s authority over generation to: implement the state’s revised energy policy; regulate electric distribution utility prices for standard service; and permit the PUCO to implement rules for advanced energy portfolio and energy efficiency standards, greenhouse gas emission reporting requirements, and pilot project carbon sequestration activities in conjunction with other state agencies. Under SB 221, electric distribution utilities have the ability to apply for PUCO approval of one of two generation pricing alternatives –a market option or an Electric Security Plan (ESP) option. The market option is based upon a competitive bidding process. The ESP option would allow for the recovery of specified costs. The PUCO, however, would have authority to disallow the market option and compel the ESP option. SB 221, if enacted, would limit the ability of a utility to transfer its dedicated generating assets to an exempt wholesale generator absent PUCO approval. SB 221 passed the Ohio Senate on October 31, 2007, and is currently pending before the Ohio House of Representatives.

 

Federal

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

The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 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 rulemakings as directed by the Energy Policy Act of 2005. These rule makings 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.

 

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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.

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

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

 

Other

U.S. Franchised Electric and Gas is subject to the NRC jurisdiction for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy’s three Oconee nuclear units through 2033 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 2008 and 2016 are in various stages of relicensing. Duke Energy expects to receive new licenses for all hydroelectric facilities with the exception of the Dillsboro Project, for which Duke Energy has filed an application to surrender the license. Duke Energy expects to remove this project’s dam and powerhouse, as part of the multi-stakeholder licensing agreement.

U.S. Franchised Electric and Gas is subject to the jurisdiction of the 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 non-regulated 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 are comprised of approximately 8,000 net megawatts 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 described below. See Item 2. “Properties” for further discussion of the generating facilities. Commercial Power also develops and implements customized energy solutions.

 

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LOGO

 

Commercial Power, through DEGS, is an on-site energy solutions and utility services provider. Primarily through joint ventures, DEGS engages in utility systems construction, operation and maintenance of utility facilities, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of usable energy from a single source. 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. Three of the development projects for a total of 240 MW of wind energy acquired from Tierra Energy are anticipated to be in commercial operation in late 2008 or 2009 and are currently under construction. DEGS also has over 2,500 MW of wind energy projects in the development pipeline.

DEGS also owns coal-based synthetic fuel (synfuel) production facilities which convert coal feedstock into synfuel for sale to third parties. The synfuel produced in these facilities qualified for tax credits through 2007 in accordance with Internal Revenue code Section 29/45K if certain requirements are satisfied. The production of synfuel was ceased at the end of 2007 upon the expiration of the tax credits.

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

In February 2008, Duke Energy entered into an agreement to sell its 480 MW natural gas-fired peaking generating station located near Brownsville, Tennessee to Tennessee Valley Authority. This transaction, which is subject to FERC and other regulatory approvals, is expected to close in the second quarter of 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.

 

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Duke Energy Ohio has been charging the MBSSO to non-residential customers since January 1, 2005 and to residential customers since January 1, 2006. The MBSSO charge consists of the following discrete charges:

   

Annually Adjusted Component - 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.

   

Infrastructure Maintenance Fund Charge - intended to compensate Duke Energy Ohio for committing its physical capacity. This charge is avoidable (or by-passable) only by non-residential customers that switch to an alternative electric service provider and agree to remain off the RSP.

   

System Reliability Tracker - intended to provide actual cost recovery for capacity purchases. This charge is by-passable only by non-residential load under certain circumstances.

   

Generation Prices and Fuel Recovery: A market price has been established for generation service. A component of the market price is a fuel cost recovery mechanism that is adjusted quarterly for fuel, emission allowances, and certain purchased power costs that exceed the amount originally included in the rates frozen in the Duke Energy Ohio transition plan. These new prices were applied to non-residential customers beginning January 1, 2005 and to residential customers beginning January 1, 2006.

   

Transmission Cost Recovery: A transmission cost recovery mechanism was established beginning January 1, 2005 for non-residential customers and beginning January 1, 2006 for residential customers. The transmission cost recovery mechanism 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.

 

Regulation

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

 

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International Energy owns, operates or has substantial interests in approximately 4,000 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including its interest in non-generation facilities in Saudi Arabia and Greece.

LOGO

In February 2007, International Energy closed the sale of its 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International.

International Energy had an investment in Compañia de Servicios de Compresión de Campeche, S.A. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. In August 2007, as a result of the expiration of a gas compression services agreement with the Mexican National Oil Company (PEMEX), ownership of the facility transferred to PEMEX.

 

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 hydro electric generation facilities which compete with other forms of electric generation available to International Energy’s customers and end-users, including natural gas and fuel oils. Economic activity, conservation, legislation, governmental regulations, weather and other factors affect the supply and demand for electricity in the regions served by International Energy.

International Energy’s operations are subject to both country-specific and international laws and regulations. (See “Environmental Matters” in this section.)

 

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CRESCENT

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

Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. As of December 31, 2007, Crescent owned 0.9 million square feet of commercial, industrial and retail space, with an additional 0.5 million square feet under construction. This portfolio included 0.7 million square feet of office space, 0.7 million square feet of warehouse space and 49 thousand square feet of retail space. Crescent’s residential developments include high-end country club and golf course communities, with individual lots sold to custom builders and tract developments sold to national builders. Crescent had two multi-family communities at December 31, 2007, including one operating property and one property under development. As of December 31, 2007, Crescent also managed approximately 122,608 acres of land.

 

Competition and Regulation

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

Crescent is subject to the jurisdiction of the EPA and state and local environmental agencies.

 

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, 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) and costs associated with certain corporate severance programs. 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.

 

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.

 

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

   

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

   

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

 

 

The North Carolina clean air legislation that froze electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of SO2 and 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 17 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively.)

Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our various business 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 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 3 and 8 to the Consolidated Financial Statements, “Business Segments” and “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” respectively.

 

EMPLOYEES

On December 31, 2007, Duke Energy had approximately 17,800 employees. A total of approximately 4,500 operating and maintenance employees were represented by unions.

 

EXECUTIVE OFFICERS OF DUKE ENERGY

STEPHEN G. DE MAY, 45, Vice President and Treasurer. 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. Prior to that Mr. De May served as Vice President, Business Unit Finance from November 2000 to February 2004.

LYNN J. GOOD, 48, 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, Vice President, Finance and Controller of Cinergy from November 2003 to August 2005 and Vice President, Financial Project Strategy of Cinergy from May 2003 to November 2003. Prior to that, Ms. Good was a partner with the international accounting firm Deloitte & Touche LLP in Cincinnati, Ohio from May 2002 to May 2003.

DAVID L. HAUSER, 56, Group Executive and Chief Financial Officer. Mr. Hauser assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Hauser served as Group Vice President and Chief Financial Officer of Duke Energy since March 2004 and as Acting Chief Financial Officer of Duke Energy from December 2003 to March 2004. Prior to that, he served as Senior Vice President and Treasurer of Duke Energy from July 1998 to December 2003.

DHIAA M. JAMIL, 51, 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.

 

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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.

JULIA S. JANSON, 43, Senior Vice President, Ethics and Compliance and Corporate Secretary. Ms. Janson assumed her current position in December 2006. Prior to that she served as Vice President, Corporate Secretary and Chief Ethics and Compliance Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Ms. Janson served as Chief Compliance Officer of Cinergy since 2004 and Corporate Secretary of Cinergy since 2000.

MARC E. MANLY, 55, Group Executive and Chief Legal Officer. Mr. Manly assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Manly served as Executive Vice President and Chief Legal Officer of Cinergy since November 2002.

JAMES E. ROGERS, 60, 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 and Senior Vice President, Human Resources of Duke Energy from January 2001 to March 2003.

B. KEITH TRENT, 48, 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, 48, 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, 49, Senior Vice President and Controller. Mr. Young assumed his current position in December 2006. Prior to that he served as Vice President and Controller since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Young served as Vice President and Controller of Duke Energy since June 2005. Prior to that Mr. Young served as Senior Vice President and Chief Financial Officer of Duke Energy Carolinas from March 2003 to June 2005 and as Vice President, Rates and Regulatory Affairs of Duke Energy Carolinas from March 1998 to March 2003.

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

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

 

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

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

 

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

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

Duke Energy’s ownership and operation of nuclear generation facilities requires Duke Energy to meet licensing and safety-related requirements imposed by the NRC. In the event of non-compliance, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending upon its assessment of the severity of the situation. Revised security and safety requirements promulgated by the 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 2008 to 2012, Duke Energy anticipates cumulative capital expenditures of approximately $23 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 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.

 

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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 results and business.

 

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

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

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

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

 

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

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

 

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

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

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

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

 

Duke Energy’s investments and projects located outside of the United States expose Duke Energy to risks related to laws of other countries, taxes, economic conditions, political conditions and policies of foreign governments. These risks may delay or reduce Duke Energy’s realization of value from Duke Energy’s international projects.

Duke Energy currently owns and may acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, regulatory, market and political conditions in some of the countries where Duke Energy has interests or in which Duke Energy may explore development, acquisition or investment opportunities could present risks related to, among others, Duke Energy’s ability to obtain financing on suitable terms, Duke Energy’s customers’ ability to honor their obligations with respect to projects and investments, delays in construction, limitations on Duke Energy’s ability to enforce legal rights, and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law, regulations, market rules or tax policy.

 

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

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

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

Duke Energy’s primary foreign currency rate exposure is expected to be to the Brazilian Real. A 10% devaluation in the currency exchange rate in all of Duke Energy’s exposure currencies would result in an estimated net loss on the translation of local currency earnings of approximately $10 million. The consolidated balance sheets would be negatively impacted by such a devaluation by approximately $145 million through cumulative currency translation adjustments.

 

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

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

 

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

Duke Energy’s costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and Duke Energy’s required or voluntary contributions made to the plans. While Duke Energy complied with the minimum funding requirements as of December 31, 2007, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $240 million. Without sustained growth in the pension investments over time to increase the value of Duke Energy’s plan assets and depending upon the other factors impacting Duke Energy’s costs as listed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations could have a material impact on Duke Energy’s cash flows, financial position or results of operations.

 

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

Duke Energy is subject to numerous environmental laws and regulations affecting many aspects of Duke Energy’s present and future operations, including air emissions (such as reducing 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 cash flows, financial position or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

There is growing consensus that some form of regulation will be forthcoming at the federal level with respect to greenhouse gas emissions (including 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.

 

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

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

 

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

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 fuel costs under a fuel adjustment clause, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations.

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

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;

 

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

   

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;

   

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

 

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

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

 

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 that could change the way Duke Energy is required to record revenues, expenses, assets and liabilities. These types of regulations could have a negative impact on Duke Energy’s financial position, cash flows or results of operations or access to capital.

 

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

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

The insurance industry has also been disrupted by these 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.

 

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Item 1B. Unresolved Staff Comments.

None.

 

Item 2. Properties.

 

U.S. FRANCHISED ELECTRIC AND GAS

 

As of December 31, 2007, U.S. Franchised Electric and Gas operated three nuclear generating stations with a combined net capacity of 5,020 MW (including a 12.5% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with a combined net capacity of 13,552 MW, thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined net capacity of 3,213 MW, fifteen CT stations with a combined net capacity of 5,241 MW and two CC stations with a combined net capacity of 560 MW. The stations are located in North Carolina, South Carolina, Indiana, Ohio and Kentucky. The MW displayed in the table below are based on summer capacity.

 

Name

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

Carolinas:

              

Oconee

   2,538    2,538    Nuclear    SC    100 %

Catawba

   2,258    282    Nuclear    SC    12.5  

Belews Creek

   2,270    2,270    Coal    NC    100  

McGuire

   2,200    2,200    Nuclear    NC    100  

Marshall

   2,110    2,110    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

   680    680    Hydro    SC    100  

Mill Creek CT

   596    596    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

   80    80    Natural gas/Fuel oil    SC    100  

Other small hydro (26 plants)

   651    651    Hydro    NC/SC    100  

Midwest:

              

Gibson(A)

   3,127    2,820    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

   500    500    Natural gas/Propane    OH    100  

Wheatland CT

   460    460    Natural gas    IN    100  

Noblesville CC

   285    285    Natural gas    IN    100  

Wabash River CC(D)

   275    275    Syn Gas/Natural gas    IN    100  

Miami Fort (Unit 6)

   163    163    Coal/Fuel oil    OH    100  

Edwardsport

   160    160    Coal    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

   30,055    27,586         
                  

 

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(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
(D) Wabash River Unit 1 is included in Assets Held for Sale

 

In addition, as of December 31, 2007, 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 148,700 conductor miles of electric distribution lines, including 102,900 miles of overhead lines and 45,800 miles of underground lines, as of December 31, 2007 and approximately 7,100 miles of gas mains and service lines. As of December 31, 2007, 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 nine million gallons of liquid propane through a storage 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 non-regulated generation portfolio as of December 31, 2007. 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    37.5  

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  

Brownsville

   466    466    Simple Cycle    Natural gas    TN    100  
                     

Total

   11,794    8,019            
                     

 

(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, 2007.

 

Name

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

Paranapanema

   2,307    2,112    Hydro    Brazil    95 %

Hidroelectrica Cerros Colorados

   576    523    Hydro/Natural Gas    Argentina    91  

Egenor

   502    501    Hydro/Diesel    Peru    100  

DEI Guatemala

   250    250    Fuel Oil/Diesel    Guatemala    100  

DEI El Salvador

   328    297    Fuel Oil/Diesel    El Salvador    90  

Electroquil

   181    150    Diesel    Ecuador    83  

Aguaytia

   177    135    Natural Gas    Peru    76  
                  

Total

   4,321    3,968         
                  

International Energy also owns a 25% equity interest in NMC. In 2007, NMC produced approximately 840 thousand 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.)

 

CRESCENT

 

(For information regarding Crescent’s properties, see “Business—Crescent” 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.

 

Item 3. Legal Proceedings.

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

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 will also contest 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 2007.

 

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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 (ticker symbol DUK). As of February 22, 2008, there were approximately 170,099 common stockholders of record.

 

Common Stock Data by Quarter

 

     2007      2006
          Stock Price
Range(a)
          Stock Price
Range(a)
    

Dividends
Per Share

   High    Low      Dividends
Per Share
   High    Low

First Quarter

   $ 0.21    $ 20.62    $ 18.40      $ 0.31    $ 29.77    $ 27.38

Second Quarter(b)

     0.43      21.30      18.06        0.63      29.85      26.94

Third Quarter

          19.90      16.91             30.98      28.84

Fourth Quarter(b)

     0.22      20.78      18.25        0.32      34.50      29.82

 

(a) Stock prices represent the intra-day high and low stock price.
(b) Dividends paid in September 2007 and December 2007 increased from $0.21 per share to $0.22 per share and dividends paid in September 2006 and December 2006 increased from $0.31 per share to $0.32 per share.

 

On January 2, 2007, Duke Energy consummated the spin-off of the natural gas businesses to shareholders. In connection with this transaction, Duke Energy distributed all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock. Subsequent to the distribution, the market price of Duke Energy common stock was significantly less than the trading ranges in 2006 due to the fact that a proportionate share of the value of Duke Energy stock prior to the spin-off was transferred to Spectra Energy. Additionally, dividends paid on Duke Energy common stock during 2007 of $0.86 per share were less than the 2006 dividend of $1.26 per share 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, subject to future adjustment by each company’s Board of Directors. In the second quarter of 2007, the Board of Directors increased the common stock dividend 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.

 

Issuer Purchases of Equity Securities for Fourth Quarter of 2007

There were no repurchases of equity securities during the fourth quarter of 2007.

In 2005, Duke Energy announced plans to execute up to approximately $2.5 billion of stock repurchases over a three year period. From the inception of the plan through December 31, 2007, Duke Energy has repurchased approximately $1.4 billion of common stock. As of December 31, 2007, the dollar value of shares that may yet be purchased under the plan is approximately $1.1 billion; however, Duke Energy does not currently anticipate future shares repurchases under this plan.

 

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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 period 2002 through 2007.

This performance chart assumes $100 invested on December 31, 2002 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, 2007. In June 2007, 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)

 

      2007     2006    2005     2004     2003(c)  
     (in millions, except per-share amounts)  

Statement of Operations

           

Total operating revenues

   $ 12,720     $ 10,607    $ 6,906     $ 6,357     $ 6,006  

Total operating expenses

     10,222       9,210      5,586       5,074       6,550  

Gains on sales of investments in commercial and multi-family real estate

           201      191       192       84  

(Losses) gains on sales of other assets and other, net

     (5 )     223      (55 )     (435 )     (202 )

Operating income (loss)

     2,493       1,821      1,456       1,040       (662 )

Total other income and expenses

     428       354      217       180       326  

Interest expense

     685       632      381       425       431  

Minority interest expense (benefit)

     2       13      24       (15 )     (79 )

Income (loss) from continuing operations before income taxes

     2,234       1,530      1,268       810       (688 )

Income tax expense (benefit) from continuing operations

     712       450      375       192       (288 )

Income (loss) from continuing operations

     1,522       1,080      893       618       (400 )

(Loss) income from discontinued operations, net of tax

     (22 )     783      935       872       (761 )

Income (loss) before cumulative effect of change in accounting principle

     1,500       1,863      1,828       1,490       (1,161 )

Cumulative effect of change in accounting principle, net of tax and minority interest

                (4 )           (162 )

Net income (loss)

     1,500       1,863      1,824       1,490       (1,323 )

Dividends and premiums on redemption of preferred and preference stock

                12       9       15  

Earnings (loss) available for common stockholders

   $ 1,500     $ 1,863    $ 1,812     $ 1,481     $ (1,338 )
   

Ratio of Earnings to Fixed Charges

     3.7       2.6      2.4       1.6       (b)

Common Stock Data

           

Shares of common stock outstanding(d)

           

Year-end

     1,262       1,257      928       957       911  

Weighted average—basic

     1,260       1,170      934       931       903  

Weighted average—diluted

     1,266       1,188      970       966       904  

Earnings (loss) per share (from continuing operations)

           

Basic

   $ 1.21     $ 0.92    $ 0.94     $ 0.65     $ (0.44 )

Diluted

     1.20       0.91      0.92       0.64       (0.44 )

(Loss) earnings per share (from discontinued operations)

           

Basic

   $ (0.02 )   $ 0.67    $ 1.00     $ 0.94     $ (0.86 )

Diluted

     (0.02 )     0.66      0.96       0.90       (0.86 )

Earnings (loss) per share (before cumulative effect of change in accounting principle)

           

Basic

   $ 1.19     $ 1.59    $ 1.94     $ 1.59     $ (1.30 )

Diluted

     1.18       1.57      1.88       1.54       (1.30 )

Earnings (loss) per share

           

Basic

   $ 1.19     $ 1.59    $ 1.94     $ 1.59     $ (1.48 )

Diluted

     1.18       1.57      1.88       1.54       (1.48 )

Dividends per share(e)

     0.86       1.26      1.17       1.10       1.10  

Balance Sheet

           

Total assets

   $ 49,704     $ 68,700    $ 54,723     $ 55,770     $ 57,485  

Long-term debt including capital leases, less current maturities

   $ 9,498     $ 18,118    $ 14,547     $ 16,932     $ 20,622  

 

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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 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2005 DENA disposition (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 deconsolidation of DCP Midstream effective July 1, 2005 (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 DEFS sale of TEPPCO (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) and 2004 sale of the former DENA Southeast plants.
(b) Earnings were inadequate to cover fixed charges by $746 million for the year ended December 31, 2003.
(c) As of January 1, 2003, Duke Energy adopted the remaining provisions of Emerging Issues Task Force (EITF) 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03) and SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). In accordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles.
(d) 2006 increase primarily attributable to issuance of approximately 313 million shares in connection with Duke Energy’s merger with Cinergy (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).
(e) 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, 2007, 2006 and 2005.

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

2007 Objectives. During 2007, management of Duke Energy focused on the following objectives, as outlined in the 2007 Charter:

   

Establish the identity and culture of the new Duke Energy, unifying its people, values, strategy, processes and systems;

   

Optimize its operations by focusing on safety, simplicity, accountability, inclusion, customer satisfaction, cost management and employee development;

   

Achieve public policy, regulatory and legislative outcomes that balance customers’ needs for reliable energy at competitive prices with shareholders’ expectation of superior returns;

   

Invest in energy infrastructure that meets rising customer demands for reliable energy in an energy efficient and environmentally sound manner; and

   

Achieve 2007 financial objectives and position Duke Energy to meet future growth targets.

With the completion of the spin-off of the natural gas businesses on January 2, 2007, Duke Energy began its first year as primarily an electric utility and met or exceeded most of its financial and non-financial objectives established for 2007. See “2007 Financial Results” below for discussion of Duke Energy’s 2007 financial results. Overall, during a year of record-breaking heat and an exceptional drought in the Carolinas, Duke Energy was able to meet its productivity challenges as the coal fleet experienced superior operational performance and three of Duke Energy’s nuclear units set new capacity factor records. Additionally, Duke Energy focused on regulatory and legislative initiatives that will allow Duke Energy to balance the need for cleaner, more efficient power sources with future energy needs of its customers.

Planning for future capital expansion was a primary focus in 2007. Over the next five years, Duke Energy plans to spend approximately $23 billion on capital expenditures, with approximately $19 billion anticipated to support the U.S. Franchised Electric and Gas segment. Of this amount, approximately 25% of this capital is expected to go towards new pulverized coal, IGCC, gas and renewable generation resources to meet growing customer demand. During 2007 and early 2008, Duke Energy achieved important milestones with various state and federal regulators related to future capital projects. In the Carolinas, the NCUC approved the construction of one 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 AFUDC. In January 2008, the North Carolina Department of Environment and Natural Resources issued the final air permit for Cliffside Unit 6, which was the last regulatory hurdle before construction could begin. Additionally, in December 2007, CPCN’s to build two 620 MW combined cycle natural gas-fired generating facilities, one each at the existing Dan River and Buck steam stations, were filed with the NCUC. 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 COL application with the NRC, which was approved in February 2008, and an Integrated Resource Plan with the NCUC and PSCSC. Duke Energy Carolinas also currently plans to file a CPCN related to the nuclear project in South Carolina during 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 IURC issued an order in November 2007 granting Duke Energy Indiana CPCN’s for the proposed 630 MW IGCC power plant at the Edwardsport Generating Station, which has an estimated cost of construction of approximately $2 billion, including AFUDC. The order also approved the timely recovery of costs related to the project. In January 2008, the Indiana Department of Environmental Management approved the air permit for the project, and major construction is expected to begin in the Spring of 2008. Duke Energy is assessing the potential for a joint owner for the facility, but could retain all of the plant capacity if a joint owner is not identified.

The continued development of renewable energy as part of Duke Energy’s generating portfolio was another primary focus of management during 2007. Climate change concerns, as well as the high price of oil, have sparked increased support for renewable

 

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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 response to this legislation, during 2007, Duke Energy Carolinas issued Request for Proposals (RFP) seeking bids for power generate from renewable energy sources, including sun, wind, water, organic matter and other sources. A similar RFP has also been issued by Duke Energy Ohio and Duke Energy Indiana. Additionally, in support of a strategy to increase its renewable energy portfolio in its unregulated businesses, Duke Energy acquired the wind power development assets of Energy Investor Funds from Tierra Energy in May 2007. Three of the development projects acquired from Tierra Energy are anticipated to be in commercial operation in late 2008 or 2009 and Duke Energy has already contracted to purchase wind turbines that are capable of generating approximately 240 MW when placed in commercial operation.

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, 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. The PSCSC and IURC have scheduled evidentiary hearings in 2008 to review these filings for South Carolina and Indiana, respectively. In advance of the evidentiary hearing held February 5-6, 2008 related to the South Carolina energy efficiency filing, a settlement agreement was reached with the South Carolina Office of Regulatory Staff, Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allow for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.

Duke Energy also participated in the development of energy legislation in various jurisdictions in 2007. Both North Carolina and South Carolina passed comprehensive energy legislation during 2007. This legislation includes provisions that will allow Duke Energy to recover new plant financing costs during the construction phase and allows recovery of costs of certain reagents used in emission removal. The North Carolina legislation also includes a renewable energy portfolio standard discussed above. Additionally, the Ohio Senate introduced Senate Bill 221 (SB 221), which proposes a comprehensive change to Ohio’s 1999 electric energy industry restructuring legislation. If enacted, SB 221 provides a workable framework for the development of new technologies, the building of new generation, environmental improvement, as well as energy efficiency. SB 221 is currently pending before the Ohio House of Representatives and could be enacted during the first quarter of 2008.

In the fourth quarter of 2007, Duke Energy Carolinas completed its first comprehensive rate case in North Carolina since 1991. Duke Energy Carolinas reached a settlement with interveners and the NCUC approved it. Overall, the rate settlement reduces customer rates in North Carolina without significantly impacting current earning levels. Although earnings levels will not be significantly impacted as a result of the rate settlement, future cash flows will be reduced as a result of a reduction in customer rates effective January 1, 2008. The decrease in revenues from the decrease in customer rates will be mostly offset by the discontinuance of amortization of clean air expenditures. Future clean air expenditures of approximately $700 million through 2010 will be capitalized as a component of rate base. Additionally, the PUCO affirmed Duke Energy Ohio’s RSP, which had been remanded by the Ohio Supreme Court to the PUCO for further consideration. The ruling maintained the current price and provided for continuation of the existing rate components, including the recovery of costs related to new pollution control equipment and capacity costs associated with power purchase contracts to meet customer demand, but provided customers an enhanced opportunity to avoid certain pricing components if they are served by a competitive supplier.

Overall, the regulatory and legislative accomplishments during 2007 have positioned Duke Energy well for 2008 and beyond.

2007 Financial Results. For the year-ended December 31, 2007, Duke Energy reported net income of $1,500 million and basic and diluted earnings per share (EPS) of $1.19 and $1.18, respectively, as compared to reported net income of $1,863 million and basic and diluted EPS of $1.59 and $1.57, respectively, for the year-ended December 31, 2006. EPS (basic and diluted) decreased for 2007 as compared to 2006, primarily due to lower net income, which is discussed below, and 2007 earnings per share being impacted by the dilutive effect of the issuance of approximately 313 million shares in April 2006 related to the Cinergy merger.

Income from continuing operations was $1,522 million for 2007, as compared to $1,080 million for 2006 due largely to the inclusion of Cinergy operations for a full year in 2007 versus nine months in the prior year. Total reportable segment EBIT increased from $2,553 million to $3,009 million. An increase for U.S. Franchised Electric and Gas of $494 million was primarily related to $218 million of first quarter 2007 EBIT contributed by Cinergy’s regulated Midwest operations for which there was zero in the comparable period of the prior year, as well as improved results in both the Carolinas and Midwest in 2007 due largely to favorable weather and additional long-term wholesale contracts, partially offset by higher operations and maintenance expense. Segment EBIT for Commercial Power increased

 

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$231 million due to improved retail electric margins resulting largely from timing of fuel and purchased power recoveries, higher overall prices and favorable weather, favorable mark-to-market results, and improved results from the Midwest gas-fired assets as a result of higher generation and capacity revenues, partially offset by higher operations and maintenance expense. Higher segment results at International Energy of $225 million are primarily a result of higher equity earnings at National Methanol Company (NMC), higher prices in Latin America and favorable foreign currency exchange impacts, as well as the absence of a $100 million litigation reserve and a $50 million impairment charge recorded in 2006. Segment results for Crescent decreased from $532 million in 2006 to $38 million in 2007, reflecting the $246 million gain on sale of an effective 50% interest in Crescent and the subsequent reduction in ownership from 100% to an effective 50% in September 2006, two large sales that occurred in the second quarter of 2006, lower residential developed lot sales in 2007 and an impairment charge on certain residential developments in 2007. In addition, losses at Other decreased as a result of lower costs related to captive insurance, lower merger costs, lower corporate governance costs and a benefit in 2007 related to contract settlement negotiations, partially offset by convertible debt costs of approximately $21 million related to the spin-off of Spectra Energy.

In addition to the increase in total reportable segment and Other EBIT, income from continuing operations for 2007 as compared to 2006 was negatively impacted by higher income tax expense from continuing operations and higher interest expense. Income tax expense from continuing operations increased as a result of higher pre-tax income and a higher effective tax rate in 2007 compared to 2006 largely due to certain favorable tax matters in 2006 that lowered the effective tax rate in 2006. Interest expense increased due primarily to the debt assumed from Cinergy. Partially offsetting these unfavorable results was higher 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, including a $19 million favorable impact related to the inclusion of amounts for legacy Cinergy for the first quarter of 2007 with no comparable amount in 2006.

More than offsetting the increase in income from continuing operations was a decrease in income from discontinued operations for 2007 as compared to 2006, primarily attributable to the classification of the results of operations for the natural gas businesses spun off on January 2, 2007 as discontinued operations for periods prior to the spin-off.

Duke Energy’s Direction in 2008 and Beyond. Management of Duke Energy is focusing on the following objectives in 2008 and beyond:

   

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;

   

Accept the reality of a carbon-constrained world and pursue low-carbon and no-carbon solutions for meeting future energy needs;

   

Finding a path to success during this era of rising costs by striving to control costs, run the businesses efficiently and provide excellent customer service; and

   

Meet 2008 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. While the drought conditions in the Carolinas did not significantly impact earnings in 2007, continued or sustained drought conditions could have a negative impact on earnings in 2008. Commercial Power has net capacity of approximately 8,000 megawatts of unregulated generation, of which approximately 4,000 megawatts serves retail customers under the RSP 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 2008 over 90% of International Energy’s contractible capacity in Latin America is either currently contracted or receives a system capacity payment.

As mentioned earlier, during the five-year period from 2008 to 2012, Duke Energy anticipates total capital expenditures of approximately $23 billion. Annual capital expenditures are currently estimated at approximately $5 billion in 2008-2011 and approximately $3 billion in 2012. These expenditures are principally related to expansion plans, maintenance costs, environmental spending related to Clean Air Act requirements and nuclear fuel. Current estimates are that Duke Energy’s regulated generation capacity will need to increase by approximately 7,700 megawatts over the next ten years, with the majority being in the Carolinas. 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 800 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.

 

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Additionally, Duke Energy is evaluating the potential construction of a new 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 International Energy, which will be funded with cash held or raised by International Energy, will primarily be for strategic growth opportunities, such as new hydro plants in Brazil, as well as maintenance on existing plants. Duke Energy does not anticipate any additional capital investment related to its investment in the Crescent JV.

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.

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 the Cliffside facility 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 response to concerns over climate change, the U.S. Congress has been discussing various proposals to reduce or cap CO2 and other greenhouse gas emissions. Any legislation enacted as a result of these efforts could involve a market based cap and trade program. In anticipation, Duke Energy is increasing focus on renewable energy and energy efficiency initiatives in an effort to reduce emissions. In addition to the wind assets purchased during 2007, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana have issued RFP’s for renewable energy sources that can be operational as early as 2012. Additionally, new energy efficiency plans were filed in North Carolina, South Carolina and Indiana and energy efficiency programs were expanded in both Kentucky and Ohio. Energy efficiency filings are expected to be made in Ohio and Kentucky in 2008. The energy efficiency plans filed in North Carolina, 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. The PSCSC and IURC have scheduled evidentiary hearings in 2008 to review these filings for South Carolina and Indiana, respectively. In advance of the evidentiary hearing held February 5-6, 2008 related to the South Carolina energy efficiency filing, a settlement agreement was reached with the South Carolina Office of Regulatory Staff, Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allow for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.

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, less cyclical businesses like U.S. Franchised Electric and Gas, and the traditionally higher-growth and more cyclical energy businesses like Commercial Power and International Energy. Additionally, Crescent’s portfolio strategy is diversified between residential, commercial and multi-family development. 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 2008 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 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.

If negative market conditions should persist over time and estimated cash flows over the lives of Duke Energy’s individual assets 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) or a change in fair value of assets held for sale could also result in impairments or losses.

 

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Duke Energy’s 2008 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 known exposures.

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

Duke Energy also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by cash flow from operations. An inability to access capital at competitive rates 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.

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, 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 approximately $1,408 million of revenues 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 no revenues were recognized in the comparable period of the prior year since the Cinergy merger occurred effective April 2006. Also contributing to the increase in revenues were:

   

A $576 million increase at U. S. Franchised Electric and Gas due primarily to increased fuel revenue from retail customers, higher sales volume as a result of favorable weather, increased wholesale power revenues due to increased sales volumes primarily due to additional long-term wholesale contracts in 2007, increase in retail rates and rate riders primarily related to 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 an increase related to the sharing of anticipated merger savings through rate decrement riders which was substantially completed prior to the third quarter of 2007;

   

A $208 million increase at Commercial Power due primarily to increased retail electric revenues principally related to the timing of collections on fuel and purchased power and increased retail demand resulting from favorable weather, and increased wholesale revenues due primarily to higher generation volumes resulting from favorable weather and higher tolling and capacity revenues, partially offset by net unfavorable mark-to-market results on non-qualifying power and capacity hedge contracts; and

   

A $117 million increase at International Energy due primarily to higher sales prices in Brazil and Peru, and favorable foreign currency exchange impacts compared to the prior year, primarily in Brazil.

Partially offset by:

   

A $221 million decrease at Crescent 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.

Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating revenues for 2006 increased $3,701 million, compared to 2005. This change was driven by:

   

An approximate $3,820 million increase due to the merger with Cinergy; and

   

A $216 million increase at International Energy due primarily to higher revenues in Peru from increased ownership and resulting consolidation of Aguaytia, higher energy prices in El Salvador, favorable results in Brazil, primarily foreign exchange rate impacts and higher electricity volumes and prices in Argentina.

 

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Partially offset by:

   

A $274 million decrease at Crescent due primarily to the deconsolidation of Crescent, effective September 7, 2006 and softening in the residential real estate market; and

   

A $69 million decrease in Other due primarily to the sale of Duke Project Services Group, Inc. (DPSG) in February 2006 and a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast.

For a more detailed discussion of operating revenues, see the segment discussions that follow.

 

Consolidated Operating Expenses

Year Ended December 31, 2007 as Compared to December 31, 2006. Consolidated operating expenses for 2007 increased $1,012 million, compared to 2006. This change was driven primarily by an approximate $1,160 million of expenses incurred 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 no expenses were incurred in the comparable period of the prior year since the Cinergy merger occurred effective April 2006. Excluding the above, consolidated operating expenses increased as a result of the following:

   

A $317 million increase at U.S. Franchised Electric and Gas due primarily to increased operating and maintenance expenses driven by higher wage and benefits costs, including increased short-term incentive costs, maintenance costs at fossil and nuclear generating plants, increased fuel expense driven by higher demand from retail customers resulting from favorable weather, and an increase in depreciation due to additional capital spending; and

   

An $18 million increase at Commercial Power due primarily to increased fuel expense and operating and maintenance expenses from the Midwest gas-fired generation assets due primarily to increased generation volumes in 2007 compared to 2006 and higher fuel and purchased power expenses due to increased retail sales volumes and plant outages in 2007, partially offset by net mark-to-market gains on non-qualifying fuel hedge contracts in 2007 compared to net losses in 2006 and lower losses from sales of fuel.

Partially offset by:

   

A $240 million decrease in Other due primarily to a 2006 charge and 2007 credits related to contract settlement negotiations, lower costs to achieve related to the Cinergy merger, lower costs related to Duke Energy’s captive insurance company driven by lower charges for mutual insurance exit obligations, and lower governance and other corporate costs, partially offset by a donation to the Duke Foundation;

   

A $160 million decrease at Crescent 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; and

   

A $62 million decrease at International Energy due primarily to a prior year reserve related to a settlement made in conjunction with the Citrus Trading Corporation (Citrus) litigation, a contract dispute between Citrus and Spectra Energy LNG Sales Inc. (formerly known as Duke Energy LNG Sales Inc.), an impairment charge on notes receivable from Campeche recorded in 2006, partially offset by unfavorable foreign currency exchange impacts, increased purchased power, general and administrative costs in Brazil, and higher fuel consumption in Guatemala due to higher generation and higher maintenance costs as a result of unplanned outages.

Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating expenses for 2006 increased $3,624 million, compared to 2005. The change was primarily driven by:

   

An approximate $3,326 million increase due to the merger with Cinergy;

   

A $312 million increase at International Energy due primarily to higher costs in Peru, driven primarily by increased ownership and resulting consolidation of Aguaytia, a reserve related to a settlement made in conjunction with the Citrus litigation, higher fuel prices and increased consumption in El Salvador, unfavorable exchange rates, increased regulatory fees and higher purchased power costs in Brazil and an impairment charge on notes receivable from a Mexican investment recorded in 2006;

   

A $132 million increase in Other due primarily to costs to achieve the Cinergy merger, a reserve charge related to contract settlement negotiations, partially offset by decreases due to the continued wind-down of the former DENA businesses; and

   

An approximate $115 million increase at Duke Energy Carolinas driven primarily by increased fuel expenses, due primarily to higher coal costs and increased purchase power expense resulting primarily from less generation availability during 2006 as a result of outages at base load stations, partially offset by lower regulatory amortization, due primarily to reduced amortization of compliance costs related to clean air legislation, and lower operating and maintenance expense, due primarily to a December 2005 ice storm.

 

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Partially offset by:

   

A $239 million decrease at Crescent due primarily to the deconsolidation of Crescent, effective September 7, 2006 and softening in the residential real estate market.

For a more detailed discussion of operating expenses, see the segment discussions that follow.

 

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 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, $201 million in 2006, and $191 million in 2005. 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. The gain in 2005 was driven primarily by pre-tax gains from the sales of surplus legacy land, particularly a large sale in Lancaster, South Carolina, commercial land sales, including a large sale near Washington, D.C. and multi-family project sales in North Carolina and Florida.

 

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

Consolidated (losses) gains on sales of other assets and other, net was a loss of $5 million for 2007, a gain of $223 million for 2006, and a loss of $55 million for 2005. The loss in 2007 was due primarily to losses related to Commercial Power’s sale of emission allowances. 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 (approximately $29 million). The loss in 2005 was due primarily to net losses at Commercial Power, principally the termination of DENA structured power contracts in the Southeast region (approximately $75 million).

 

Consolidated Operating Income

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated operating income increased $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.

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated operating income increased $365 million, compared to 2005. Increased operating income was primarily related to approximately $465 million of operating income generated by legacy Cinergy in 2006 as a result of the merger and an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent, partially offset by approximately $128 million of cost in 2006 to achieve the Cinergy merger and approximately $165 million of charges in 2006 related to settlements and contract negotiations.

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, 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.

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated other income and expenses increased $137 million, compared to 2005. The increase was due primarily to an increase of approximately $125 million of interest income resulting primarily from favorable income tax settlements in 2006.

 

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Consolidated Interest Expense

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.

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated interest expense increased $251 million, compared to 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy (approximately $227 million impact).

 

Consolidated Minority Interest Expense

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.

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated minority interest expense decreased $11 million, compared to 2005. This decrease was due primarily to lower earnings at Crescent’s LandMar affiliate in Florida, as a result of softening in the residential real estate market.

 

Consolidated Income Tax Expense from Continuing Operations

Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated income tax expense from continuing operations increased $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.

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated income tax expense from continuing operations increased $75 million, compared to 2005. This increase primarily resulted from higher pre-tax earnings, partially offset by favorable tax settlements on research and development costs and nuclear decommissioning costs, and tax benefits related to the impairment of an investment in Bolivia.

 

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

Consolidated (loss) income from discontinued operations was a loss of $22 million for 2007, income of $783 million for 2006, and income of $935 million for 2005. The 2006 and 2005 amounts include the after-tax earnings of Duke Energy’s natural gas businesses that were spun off to shareholders on January 2, 2007. The 2007, 2006 and 2005 amounts include results of operations and gains (losses) on dispositions related primarily to former DENA’s assets and contracts outside the Midwestern and Southeastern United States as a result of the 2005 decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, which are included in Other. The 2007 and 2006 amounts also include Cinergy commercial marketing and trading operations and synfuel operations, which are both included in Commercial Power. See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”.

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, 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.

The 2005 amount is primarily comprised of after-tax earnings of approximately $1,623 million related to the natural gas businesses, which includes $1,245 million of pre-tax gains on sales of equity investments, primarily associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP and an approximate $575 million gain resulting from the DEFS disposition transaction, an approximate $550 million non-cash, after-tax charge (approximately $900 million pre-tax) for the impairment of assets, and the dis-

 

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continuance of hedge accounting and the discontinuance of the normal purchase/normal sale exception for certain positions as a result of the decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Additionally, during 2005, Duke Energy recognized after-tax losses of approximately $250 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts related to the former DENA operations. These charges were offset by the recognition of after-tax gains of approximately $125 million (approximately $200 million pre-tax) related to the recognition of deferred gains in Accumulated Other Comprehensive Income (AOCI) related to discontinued cash flow hedges related to the former DENA operations.

 

Consolidated Cumulative Effect of Change in Accounting Principle, net of tax and minority interest

During 2005, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principle of $4 million as a reduction in earnings. The change in accounting principle related to the implementation of FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.

 

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 the gains and losses on foreign currency remeasurement, and interest and dividend income on those 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 3 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s segment structure.

As discussed above and in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, the continuing operations of the former DENA segment (which primarily include the operations of the Midwestern generation assets, former DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Commercial Power, except for DETM, which is in Other.

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,  
      2007     2006     Variance
2007 vs.
2006
    2005     Variance
2006 vs.
2005
 
     (in millions)  

U.S. Franchised Electric and Gas

   $ 2,305     $ 1,811     $ 494     $ 1,495     $ 316  

Commercial Power(a)

     278       47       231       (118 )     165  

International Energy

     388       163       225       309       (146 )

Crescent(b)

     38       532       (494 )     314       218  
                                        

Total reportable segment EBIT

     3,009       2,553       456       2,000       553  

Other(a)

     (298 )     (537 )     239       (347 )     (190 )
                                        

Total reportable segment EBIT and other

     2,711       2,016       695       1,653       363  

Interest expense

     (685 )     (632 )     (53 )     (381 )     (251 )

Interest income and other(c)

     208       146       62       (4 )     150  
                                        

Consolidated earnings from continuing operations before income taxes

   $ 2,234     $ 1,530     $ 704     $ 1,268     $ 262  
                                        

 

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(a) Amounts associated with former DENA’s operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.
(b) In September 2006, Duke Energy completed a joint venture transaction of Crescent. As a result, Crescent segment data 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) Interest income and other includes foreign currency transaction gains and losses and additional minority interest expense not allocated to the segment results.

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.

The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

 

U.S. Franchised Electric and Gas

 

     Years Ended December 31,  
      2007    2006    Variance
2007 vs.
2006
    2005    Variance
2006 vs.
2005
 
     (in millions, except where noted)  

Operating revenues

   $ 9,740    $ 8,098    $ 1,642     $ 5,432    $ 2,666  

Operating expenses

     7,488      6,319      1,169       3,959      2,360  

(Losses) gains on sales of other assets and other, net

                     7      (7 )
                                     

Operating income

     2,252      1,779      473       1,480      299  

Other income and expenses, net

     53      32      21       15      17  
                                     

EBIT

   $ 2,305    $ 1,811    $ 494     $ 1,495    $ 316  
                                     

Duke Energy Carolinas GWh sales(a)

     86,604      82,652      3,952       85,277      (2,625 )

Duke Energy Midwest GWh sales(a) (b)

     64,570      46,069      18,501            46,069  

Net proportional MW capacity in operation(c)

     27,586      27,590      (4 )     18,390      9,200  

 

(a) Gigawatt-hours (GWh)
(b) Relates to operations of former Cinergy from the date of acquisition and thereafter
(c) 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

   2007     2006     2005  

Residential sales(a)

   6.5 %   (1.2 )%   3.7 %

General service sales(a)

   5.4 %   1.4 %   1.9 %

Industrial sales(a)

   (2.3 )%   (3.8 )%   1.1 %

Wholesale sales

   40.9 %   (38.7 )%   38.0 %

Total Duke Energy Carolinas sales(b)

   4.8 %   (3.1 )%   3.1 %

Average number of customers

   2.0 %   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 for the nine months ended December 31, 2007 compared to the same period in the prior year.

 

Increase (decrease) over prior year

     Nine Months Ended
December 31, 2007
 

Residential sales(a)

     6.7 %

General service sales(a)

     6.3 %

Industrial sales(a)

     (0.4 )%

Wholesale sales

     7.7 %

Total Duke Energy Midwest sales(b)

     4.5 %

Average number of customers

     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, 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.

Partially offset by:

   

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 on-going 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.

 

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

U.S. Franchised Electric and Gas continues to increase its customer base, maintain low costs and deliver high-quality customer service in the Carolinas and Midwest. The residential and general service sectors are expected to grow. The industrial sector, particularly textile and housing related, was soft in 2007 and that trend is expected to continue in 2008. U.S. Franchised Electric and Gas will continue to provide strong cash flows from operations to Duke Energy, which will help fund the capital spending program in 2008. Changes in weather, wholesale power market prices, service area economy, generation availability and changes to the regulatory environment would impact future financial results for U.S. Franchised Electric and Gas.

 

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The impact of the North Carolina rate order resulting from the 2007 rate review ordered by the NCUC will also affect income for 2008 and future years. Particularly, retail base rates were lowered by $287 million, which was primarily offset by the elimination of clean air legislation amortization. For 2008 only, the NCUC also allowed a one time increment rider of $80 million related to merger savings. Legislation enacted in both North and South Carolina in 2007 will allow Duke Energy Carolinas to recover from retail customers more of the costs incurred for purchases of power and reagents needed to meet customer demand. Various regulatory activities will continue in 2008, including a review of Duke Energy Carolinas’ and Duke Energy Indiana’s proposed cost recovery methodology related to energy efficiency programs. Decisions on 2007 filings for certification for new generation are also expected. Duke Energy Ohio’s pending gas rate case could also impact future results through the increase of base rates.

The Southeastern United States continues to experience severe drought conditions brought about by a significant shortage of rainfall in the past several months. As a result of these conditions, water supplies in the reservoirs and lake systems that support many of Duke Energy Carolinas’ hydroelectric, nuclear, and fossil electric generation plants have declined and could continue to decline in the absence of more normal levels of rainfall. Duke Energy is analyzing long-term weather forecasts and developing plans to mitigate any potential operational impacts that continued severe drought conditions could cause; however, at this time we cannot determine if such impacts will have a material effect on Duke Energy.

 

Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues. The increase was driven primarily by:

   

A $2,651 million increase in regulated revenues due to the acquisition of Cinergy;

   

A $203 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs. The delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005, representing an approximately 20% increase; and

   

A $27 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in Duke Energy Carolinas’ service territory. The number of customers in 2006 increased by approximately 45,000 compared to 2005.

Partially offset by:

   

A $91 million decrease in wholesale power sales, net of the impact of sharing of profits from wholesale power sales with industrial customers in North Carolina ($40 million). Sales volumes decreased by approximately 39% primarily due to production constraints caused by generation outages and pricing;

   

A $77 million decrease related to the sharing of anticipated merger savings by way of a rate decrement rider with regulated customers in North Carolina and South Carolina. As a requirement of the merger, Duke Energy Carolinas is required to share anticipated merger savings of approximately $118 million with North Carolina customers and approximately $40 million with South Carolina customers over a one year period; and

   

A $32 million decrease in GWh sales to retail customers due to unfavorable weather conditions compared to the same period in 2005. Weather statistics in 2006 for heating degree days were approximately 9% below normal as compared to 2% above normal in 2005. Overall weather statistics for both heating and cooling periods in 2006 were unfavorable compared to the same periods in 2005.

Operating Expenses. The increase was driven primarily by:

   

A $2,245 million increase in regulated operating expenses due to the acquisition of Cinergy;

   

A $188 million increase in fuel expenses, due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation for year to date December 31, 2006 and 2005 and the delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005;

   

A $42 million increase in purchased power expense, due primarily to less generation availability during 2006 as a result of outages at base load stations; and

   

A $24 million increase in depreciation expense, due to additional capital spending.

Partially offset by:

   

An $86 million decrease in regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during 2006 as compared to the same period in 2005. Regulatory amortization expenses were approximately $225 million for the year ended December 31, 2006 as compared to approximately $311 million during the same period in 2005;

 

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A $39 million decrease in operating and maintenance expenses, due primarily to a December 2005 ice storm; and

   

A $15 million decrease in donations related to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina. For the year ended December 31, 2006, donations totaled $13 million, while for the same period in 2005, donations totaled $28 million.

Other income and expenses. The increase in Other income and expenses resulted primarily from an increase in AFUDC due mainly to the acquisition of the regulated operations of Cinergy.

EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy, lower regulatory amortization in North Carolina, increased demand from retail customers due to continued growth in the number of residential and general service customers and decreased operating and maintenance expense in the Carolinas. These changes were partially offset by lower wholesale power sales, net of sharing, rate reductions due to the merger, unfavorable weather conditions and increased purchased power expense in the Carolinas.

 

Commercial Power

 

     Years Ended December 31,
      2007     2006     Variance
2007 vs.
2006
    2005     Variance
2006 vs.
2005
     (in millions, except where noted)

Operating revenues

   $ 1,881     $ 1,331     $ 550     $ 148     $ 1,183

Operating expenses

     1,618       1,292       326       200       1,092

(Losses) gains on sales of other assets and other, net

     (7 )     (29 )     22       (70 )     41
                                      

Operating income

     256       10       246       (122 )     132

Other income and expenses, net

     22       37       (15 )     4       33
                                      

EBIT

   $ 278     $ 47     $ 231     $ (118 )   $ 165
                                      

Actual plant production, GWh(a)

     23,702       17,640       6,062       1,759       15,881

Net proportional megawatt capacity in operation

     8,019       8,100       (81 )     3,600       4,500

 

(a) Excludes discontinued operations

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, Commercial Power includes the operations of former DENA’s Midwestern generation assets and remaining Southeastern operations related to the assets which were disposed of in 2004. The results of former DENA’s discontinued operations, which are comprised of assets sold to LS Power, are presented in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in consolidated Results of Operations section titled “Consolidated (Loss) Income from Discontinued Operations, net of tax.”

 

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 offset by:

   

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.

 

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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 offset by:

   

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.

(Losses) Gains 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.

 

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 Duke Energy’s 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. Future results for Commercial Power are subject to volatility due to the over or under-collection of fuel and purchased power costs since Commercial Power’s Rate Stabilization Plan (RSP) market based standard service offer (MBSSO) is not subject to regulatory accounting pursuant to SFAS No. 71, “Accounting for Certain Types of Regulation” (SFAS No. 71). In addition, Commercial Power’s RSP expires on December 31, 2008. Duke Energy is currently working with the PUCO and the Ohio legislature to establish a rate structure beyond 2008. The outcome of this rate structure could impact the results of operations in future periods. Compared to 2006 and 2007, Commercial Power’s 2008 results will also be favorably impacted by the reduced impact of purchase accounting adjustments recorded in connection with the 2006 merger with Cinergy.

 

Year Ended December 31, 2006 as compared to December 31, 2005

Operating Revenues. The increase was primarily driven by the acquisition of Cinergy non-regulated generation assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005 (approximately $1,169 million). Operating revenues associated with the former DENA Midwest plants were approximately $14 million higher in 2006 compared to 2005 due primarily to higher average prices and slightly higher volumes.

Operating Expenses. The increase was primarily driven by the acquisition of Cinergy non-regulated generation assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005 (approximately $1,082 million). Operating expenses associated with the former DENA Midwest plants were approximately $10 million higher in 2006 compared to 2005 due primarily to higher fuel prices and slightly higher volumes.

(Losses) Gains on Sales of Other Assets and Other, net. The increase was driven primarily by an approximate $75 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region, partially offset by net losses of approximately $29 million on sales of emission allowances in 2006.

Other Income and Expenses, net. The increase is driven primarily by equity earnings of unconsolidated affiliates related to investments acquired in connection with the Cinergy merger in 2006.

EBIT. The increase was due primarily to the approximate $75 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region and the acquisition of Cinergy assets (approximately $95 million).

 

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International Energy

 

     Years Ended December 31,  
      2007    2006     Variance
2007 vs.
2006
    2005    Variance
2006 vs.
2005
 
     (in millions, except where noted)  

Operating revenues

   $ 1,060    $ 943     $ 117     $ 727    $ 216  

Operating expenses

     776      838       (62 )     526      312  

(Losses) gains on sales of other assets and other, net

          (1 )     1            (1 )
                                      

Operating income

     284      104       180       201      (97 )

Other income and expenses, net

     114      76       38       116      (40 )

Minority interest expense

     10      17       (7 )     8      9  
                                      

EBIT

   $ 388    $ 163     $ 225     $ 309    $ (146 )
                                      

Sales, GWh

     17,127      18,501       (1,374 )     17,587      914  

Net proportional megawatt capacity in operation(a)

     3,968      3,922       46       3,863      59  

 

(a) Excludes discontinued operations

 

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 offset by:

   

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 offset by:

   

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 National Methanol Company (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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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.

 

Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues. The increase was driven primarily by:

   

A $118 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) and an increase in Egenor due to higher sales volumes, offset by lower prices;

   

A $40 million increase in El Salvador due to higher energy prices;

   

A $31 million increase in Brazil due to the strengthening of the Brazilian Real against the U.S. dollar and higher average energy prices, partially offset by lower volumes; and

   

A $27 million increase in Argentina primarily due to higher electricity generation, prices and increased gas marketing sales.

Operating Expenses. The increase was driven primarily by:

   

A $109 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia and increased purchased power and fuel costs in Egenor;

   

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

   

A $38 million increase in El Salvador primarily due to higher fuel prices and increased fuel consumption;

   

A $34 million increase in Brazil due to the strengthening of the Brazilian Real against the U.S. dollar, increased regulatory fees, and purchased power costs; and

   

A $33 million increase in Mexico due to an impairment of a note receivable from Campeche.

Other Income and expenses, net. The decrease was primarily driven by a $26 million decrease in NMC due to lower MTBE margins and unplanned outages and a $12 million decrease as a result of consolidation of Aguaytia in 2006.

EBIT. The decrease in EBIT was primarily due to a litigation provision, an impairment in Mexico, lower margins at NMC, higher purchased power costs in Egenor, offset by favorable hydrology and pricing in Argentina.

 

Crescent(a)

 

     Years Ended December 31,  
      2007    2006    Variance
2007 vs.
2006
    2005    Variance
2006 vs.
2005
 
     (in millions)  

Operating revenues

   $    $ 221    $ (221 )   $ 495    $ (274 )

Operating expenses

          160      (160 )     399      (239 )

Gains on sales of investments in commercial and multi-family real estate

          201      (201 )     191      10  

(Losses) gains on sales of other assets and other, net

          246      (246 )          246  
                                     

Operating income

          508      (508 )     287      221  

Equity in earnings of unconsolidated affiliates

     38      15      23            15  

Other income and expenses, net

          14      (14 )     44      (30 )

Minority interest expense

          5      (5 )     17      (12 )
                                     

EBIT

   $ 38    $ 532    $ (494 )   $ 314    $ 218  
                                     

 

(a) In September 2006, Duke Energy completed a joint venture transaction at Crescent and deconsolidated its investment in Crescent due to reduction in ownership and its inability to exercise control. As a result, Crescent segment data includes Crescent as a consolidated wholly-owned subsidiary of Duke Energy for periods prior to September 7, 2006, and as an equity investment for the periods subsequent to September 7, 2006 and represents Duke Energy’s 50% of equity earnings in Crescent.

 

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EBIT. The decrease was due primarily to a $246 million gain on the sale of ownership interests in Crescent in the third quarter 2006 (see Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”); significant gains in the second quarter 2006, primarily an approximate $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. and an approximate $52 million gain on a land sale at Lake Keowee in northwestern South Carolina; lower residential developed lot sales; a $32 million impairment charge recorded in equity earnings for the fourth quarter 2007 related to certain of Crescent’s residential developments; and the inclusion of approximately $29 million of interest expense in Crescent’s equity earnings for 2007 compared to $6 million for 2006. Prior to the deconsolidation of Crescent, interest expense was not included in Crescent’s segment EBIT.

 

Matters Impacting Future Crescent Results

Crescent’s results are subject to volatility due to factors including its management’s portfolio allocation decisions, the strength of the real estate markets, the cost of construction materials and changes in interest rates. As discussed above, during 2007 Crescent recorded impairment charges on certain of its properties. The impairment charges reflect the current economic conditions in Crescent’s markets and its management’s current plans for the properties in its portfolio. Changes in factors such as further or prolonged deterioration in market conditions or changes regarding the timing or method for disposition of properties could result in future impairments being recorded by Crescent.

 

Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues. The decrease was driven primarily by the deconsolidation of Crescent effective September 7, 2006, as well as a $272 million decrease in residential developed lot sales, primarily due to decreased sales at the LandMar division in Florida.

Operating Expenses. The decrease was driven primarily by the deconsolidation of Crescent effective September 7, 2006, as well as a $187 million decrease in the cost of residential developed lot sales as noted above and a $16 million impairment charge in 2005 related to a residential community in South Carolina (Oldfield).

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by an $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. along with a $52 million land sale at Lake Keowee in northwestern South Carolina in 2006, partially offset by a $41 million land sale at Catawba Ridge in South Carolina in 2005, a $15 million gain on a land sale in Charlotte, North Carolina in 2005 and a $19 million gain on a project sale in Jacksonville, Florida in 2005.

(Losses) Gains on Sales of Other Assets and Other, net. The increase was due to an approximate $246 million pre-tax gain resulting from the sale of an effective 50% interest in Crescent.

Other Income and Expenses, net. The decrease is primarily due to $45 million in income related to a distribution from an interest in a portfolio of commercial office buildings in the third quarter of 2005.

EBIT. The increase was primarily due to the gain on sale of an ownership interest in Crescent, as noted above, as well as the sale of the Potomac Yard office buildings, partially offset by land and project sales in 2005 as discussed above.

 

Supplemental Data

Below is supplemental condensed summary financial information for Crescent stand-alone operating results subsequent to deconsolidation on September 7, 2006:

     Twelve
Months Ended
December 31,
2007
   September 7
through

December 31,
2006
     (in millions)

Operating revenues

   $ 536    $ 179

Operating expenses

   $ 415    $ 152

Operating income

   $ 121    $ 27

Net income

   $ 76    $ 30

 

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Other

 

     Years Ended December 31,  
      2007     2006     Variance
2007 vs.
2006
    2005     Variance
2006 vs.
2005
 
     (in millions)  

Operating revenues

   $ 167     $ 140     $ 27     $ 209     $ (69 )

Operating expenses

     467       707       (240 )     575       132  

(Losses) gains on sales of other assets and other, net

     2       8       (6 )     8        
                                        

Operating income

     (298 )     (559 )     261       (358 )     (201 )

Other income and expenses, net

     (1 )     13       (14 )     14       (1 )

Minority interest expense

     (1 )     (9 )     8       3       (12 )
                                        

EBIT

   $ (298 )   $ (537 )   $ 239     $ (347 )   $ (190 )
                                        

 

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

Operating Revenues. The increase was driven primarily by:

   

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 $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 offset by:

   

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 governmental subdivisions; and

   

A $12 million increase related to employee severance costs.

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 an increase in investment returns related to executive life insurance of $8 million.

EBIT. The improvement was due primarily to 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, partially offset by 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.

 

Matters Impacting Future Other Results

Future Other results may be subject to volatility as a result of losses insured by Bison and changes in liabilities associated with mutual insurance companies and the wind-down of DETM.

 

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Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues. The decrease was driven primarily by:

   

A $43 million decrease due to the sale of DPSG in February 2006; and

   

A $21 million decrease due to a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast.

Operating Expenses. The increase was driven primarily by:

   

A $128 million increase due to costs-to-achieve in 2006 related to the Cinergy merger;

   

A $65 million increase due to a charge in 2006 related to contract settlement negotiations; and

   

A $14 million increase in corporate governance and other costs due primarily to the merger with Cinergy in April 2006.

Partially offset by:

   

A $47 million decrease due to the continued wind-down of the former DENA businesses; and

   

A $45 million decrease due to the sale of DPSG.

EBIT. The decrease was due primarily to the increase in charges in 2006 associated with Cinergy merger and a charge for contract settlement negotiations.

 

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) 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 $2,645 million as of December 31, 2007 and $4,072 million as of December 31, 2006. Total regulatory liabilities were $2,674 million as of December 31, 2007 and $3,058 million as of December 31, 2006. Amounts at December 31, 2006 include balances related to the natural gas businesses that were spun off on January 2, 2007. For further information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

 

Goodwill Impairment Assessments

At December 31, 2007 and 2006, Duke Energy had goodwill balances of $4,642 million and $8,175 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, 2007 relates to the acquisition of Cinergy in April 2006, whose assets are primarily included in

 

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the U.S. Franchised Electric and Gas and Commercial Power segments. The remainder relates to International Energy’s Latin American operations. Goodwill at December 31, 2006 included approximately $3,523 million which primarily related to the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002 and was included in the spin-off of the natural gas businesses in January 2007. 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. 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 2007, 2006 or 2005 impairment tests required by SFAS No. 142.

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.

 

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, 2007 and 2006 was approximately $380 million and $330 million, respectively. The amount at December 31, 2006 excludes unbilled revenues related to the natural gas businesses transferred in January 2007, as discussed above.

 

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 $1,082 million and $1,159 million as of December 31, 2007 and 2006, respectively, and are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities. These reserves are based upon the minimum amount in Duke Energy’s best estimate of the range of loss of $1,082 million to $1,350 million for current and future asbestos claims through 2027. The reserves balance of $1,082 million as of December 31, 2007 consists of approximately $182 million related to known claimants and approximately $900 million related to unknown claimants. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe that we 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

 

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into the future and numerous other factors outside Duke Energy Carolinas’ control, management believes that it is reasonably possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves. While it is reasonably possible that such excess liabilities could be material to operating results in any given quarter or year, management does not believe that such excess liabilities would have a material adverse effect on Duke Energy’s long-term results of operations, liquidity, or consolidated financial position.

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. Through December 31, 2007, Duke Energy has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy considers the existence of uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier, and is not aware of such uncertainties as of December 31, 2007.

For further information, see Note 17 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).

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 $350 million in 2007, $124 million in 2006 and zero in 2005. Duke Energy does not anticipate making a contribution to its DB retirement plans in 2008. Additionally, during 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans.

 

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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 $80 million, pre-tax non-qualified pension cost of $14 million and pre-tax other post-retirement benefits cost of $85 million in 2007. In 2008, Duke Energy’s qualified pension cost is expected to be approximately $40 million lower than in 2007 as a result of the 2007 contribution to the qualified plans, non-qualified pension cost is expected to remain approximately the same as 2007 and other post-retirement benefits cost is expected to be approximately $27 million lower than in 2007 as a result of the aforementioned voluntary contribution to the other post-retirement benefit plans.

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, 2007. 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 4.3% for U.S. equities, 1.7% for Non U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.

If Duke Energy had used a long-term rate of 8.25% in 2007, pre-tax pension expense would have been higher by approximately $9 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 $9 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 6.00% as of December 31, 2007. Duke Energy discounted its future U.S. pension and other post-retirement obligations using rates of 5.75% as of September 30, 2006 for its non-legacy Cinergy business pension plans and 6.00% as of April 1, 2006 for its legacy Cinergy business pension plans. For legacy Cinergy plans, the discount rate reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy. Duke Energy determines the appropriate discount based on AA bond yields. The yield is selected based on bonds with cash flows that are similar to the timing and amount of the expected benefit payments under the plan. Lowering the discount rates by 0.25% would have decreased Duke Energy’s 2007 pre-tax pension expense by approximately $2 million. Increasing the discount rates by 0.25% would have increased Duke Energy’s 2007 pre-tax pension expense by approximately $2 million. Lowering the discount rates by 0.25% would have increased Duke Energy’s 2007 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% would have decreased Duke Energy’s 2007 pre-tax other post-retirement expense by less than approximately $1 million.

 

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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, 2007, the medical care trend rates were 8.00%, which grades to 5.00% by 2013. As of December 31, 2007, the prescription drug trend rate was 12.50%, 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 $5 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 $4 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 21 to the Consolidated Financial Statements, “Employee Benefit Plans.”

 

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

At December 31, 2007, Duke Energy had cash, cash equivalents and short-term investments of approximately $1.1 billion, partially offset by approximately $742 million of short-term notes payable and commercial paper. During 2008, Duke Energy will rely primarily upon cash flows from operations, borrowings and its existing cash, cash equivalents and short-term investments to fund its liquidity and capital requirements. 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 they 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 2008 capital and investment expenditures of approximately $5.1 billion, primarily consisting of:

   

$3.9 billion at U.S. Franchised Electric and Gas

   

$0.6 billion at Commercial Power

   

$0.4 billion at International Energy and

   

$0.2 billion at Other

Duke Energy continues to focus on reducing risk and positioning its business for future success and will invest principally in its strongest business sectors with an overall focus on positive net cash generation. Based on this goal, approximately 75 percent of total projected 2008 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2008 capital and investment expenditures include approximately $1.7 billion for system growth, $1.5 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.5 billion of environmental expenditures, and approximately $0.2 billion of nuclear fuel.

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 be approximately 40% by the end of 2008, as compared to approximately 35% at the end of 2007. This increase is primarily due to expected debt issuances in 2008, primarily to fund capital expenditures. Duke Energy expect its total debt balance (including outstanding commercial paper balances) to increase approximately $2.6 billion in 2008. Additionally, Duke Energy has expected debt retirements of approximately $2.0 billion in 2008, which includes scheduled maturities of approximately $1.5 billion and approximately $0.5 billion of early retirements of long-term debt that are expected to be refinanced. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage bonds. Proceeds from the issuance will be used to fund capital expenditures and general corporate purposes, including the repayment of commercial paper.

Based upon anticipated 2008 cash flows from operations, capital expenditure and dividend payments, Duke Energy expects to increase outstanding commercial paper balances during 2008; however, Duke Energy expects that the current total available capacity under its commercial paper facilities to be sufficient to meet any additional commercial paper requirements.

 

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Due to recent financial market developments, including certain liquidity issues within the short-term investment markets and a series of write-downs by some companies in the values of their investments in subprime U.S. mortgage-related assets, Duke Energy performed an assessment to determine the impact, if any, of current market developments on Duke Energy’s financial position.

As of December 31, 2007 and late February 2008, there were no investments in subprime mortgage-related assets within Duke Energy’s short-term investment balances. As of December 31, 2007, Duke Energy held approximately $430 million of investments in auction rate debt securities, substantially all of which were sold at auction in January 2008 at full principal amounts. Duke Energy made new investments in auction rate debt securities in January and February 2008, and as of late-February 2008, Duke Energy holds approximately $300 million of investments in auction rate debt securities. The vast majority of these investments are in U.S. Federal government backed student loans. As a result of the aforementioned credit market developments, these investments, which historically have provided short-term liquidity through a periodic auction process, have become increasingly illiquid as a result of failed auctions. Auction rate securities are designed such that interest rates on these instruments reset periodically through an auction process, so long as demand for the debt at the auction date is sufficient to cover the amount being submitted by the existing holders for auction. In the event demand is less than the amount being auctioned, a failed auction would occur and Duke Energy would begin receiving a higher interest rate on its investments in the auction rate debt at the failed-auction interest rate. As a result of recent auction failures, it is necessary for Duke Energy to hold these investments for longer periods of time than the historical short-term holding periods. However, Duke Energy does not currently believe there is any significant risk of credit default by the issuers and Duke Energy expects to be able to liquidate its holdings in the future at amounts approximating their current book value.

Duke Energy also performed an assessment of its investments held in trusts, including those that will be used to satisfy future obligations under its pension and other post-retirement benefit plans and future obligations to decommission Duke Energy Carolinas nuclear plants. Based on this assessment, it has been determined that an insignificant portion of the holdings within the trusts are directly invested in subprime mortgage-related assets or auction rate debt securities. Duke Energy does not believe that any decline in the fair value of these subprime mortgage-related assets or auction rate debt securities will have a material impact on its results of operations or its future cash funding requirements. Refer to Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information on the investment objectives of Duke Energy with respect to its pension and other post-retirement benefit plan assets, and to Item 1A. Risk Factors.

As of December 31, 2007 and mid-February 2008, Duke Energy had approximately $880 million of auction rate pollution control bonds outstanding. While these debt instruments are long-term in nature and cannot be put back to Duke Energy prior to maturity, the interest rates on these instruments are designed to reset periodically through an auction process. In February 2008, Duke Energy began to experience failed auctions for a portion of these debt instruments. When failed auctions occur on a series of this debt, Duke Energy is required to begin paying a failed-auction interest rate on the instrument. The failed-auction interest rate for the majority of the auction rate debt is 1.75 times one-month LIBOR. Payment of the failed-auction interest rates will continue until Duke Energy is able to either successfully remarket these instruments through the auction process or refund and refinance the existing debt through the issuance of an equivalent amount of tax exempt bonds. Duke Energy is currently pursuing a refunding and refinancing plan, which is subject to approval by applicable state or county financing authorities and utility regulators. If Duke Energy is unable to successfully refund and refinance these debt instruments, the impact of paying higher interest rates on the outstanding auction rate debt is not expected to materially effect Duke Energy’s overall financial position, results of operations or cash flows.

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 $2.65 billion, of which a portion is currently committed primarily to backstop Duke Energy’s commercial paper program.

Duke Energy monitors compliance with all debt covenants and restrictions and does not currently believe it will be in violation or breach of its debt covenants during 2008. 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 $3,208 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

 

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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.

Net cash provided by operating activities was $3,748 million in 2006 compared to $2,818 million in 2005, an increase in cash provided of $930 million. The increase in cash provided by operating activities was due primarily to the following:

   

The impacts of the merger with Cinergy, effective April 3, 2006, partially offset by

   

An approximate $400 million decrease due to the net settlement of the remaining former DENA contracts during 2006.

 

Investing Cash Flows

Net cash used in investing activities was $2,151 million in 2007, $1,328 million in 2006, and $126 million in 2005.

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

 

Capital and Investment Expenditures by Business Segment

 

     Years Ended December 31,
      2007    2006    2005
     (in millions)

U.S. Franchised Electric and Gas(a)

   $ 2,613    $ 2,381    $ 1,350

Natural Gas Transmission(b)

          790      930

Field Services(b)(c)

               86

Commercial Power

     442      209      2

International Energy

     74      58      23

Crescent(d)

          507      599

Other

     153      131      29
                    

Total consolidated

   $ 3,282    $ 4,076    $ 3,019
                    

 

(a) Amounts include capital expenditures associated with North Carolina clean air legislation of $418 million in 2007, $403 million in 2006 and $310 million in 2005, 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) Field Services amounts for 2005 only include capital and investment expenditures for periods prior to deconsolidation on July 1, 2005.
(d) Crescent amounts for 2006 only include capital and investment expenditures 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 and $355 million in 2005, which are 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 2007 as compared to 2006 is primarily due to the following:

   

Approximately $1.6 billion 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 $1.8 billion 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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The increase in cash used in investing activities in 2006 as compared to 2005 is primarily due to the following:

   

Increased capital and investment expenditures of $1,090 million, excluding Crescent’s residential real estate investment, primarily as a result of capital expenditures at U.S. Franchised Electric and Gas, in large part due to the acquisition of Cinergy in April 2006, the acquisition of the Rockingham facility in 2006 and increased expenditures associated with North Carolina clean air legislation, and,

   

Increased purchases of short-term investments of approximately $900 million in 2006 as compared to 2005, due primarily to the proceeds from the Crescent debt financing.

These increases were partially offset by the following:

   

An increase in proceeds received from asset sales in 2006 as compared to 2005. Asset sales activity in 2006 of approximately $2.9 billion primarily involved the disposal of the former DENA remaining operations outside of the Midwestern United States, CMT, as well as the Crescent JV transaction. Asset sales activity in 2005 of approximately $2.4 billion primarily involved the disposition of the investments in TEPPCO as well as the DCP Midstream disposition transaction.

 

Financing Cash Flows and Liquidity

Duke Energy’s consolidated capital structure as of December 31, 2007, including short-term debt, was 35% debt, 1% minority interest and 64% common equity. The fixed charges coverage ratio, calculated using SEC guidelines, was 3.7 times for 2007, 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, and 2.4 times for 2005.

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.

Net cash used in financing activities was $1,961 million in 2006 compared to $2,717 million in 2005, a decrease of $756 million. The change was due primarily to the following:

   

An approximate $1.1 billion increase in proceeds from the issuance of long-term debt in 2006, net of redemptions, due primarily to the approximate $1.2 billion of debt proceeds from the Crescent JV transaction, and

   

An approximate $400 million decrease in share repurchases under Duke Energy’s share repurchase plan.

These increases were partially offset by:

   

An approximate $400 million increase in dividends paid due to the increase in the quarterly dividend paid per share combined with a larger number of shares outstanding, primarily attributable to the 313 million shares issued in connection with the Cinergy merger, and

   

The repayment of approximately $400 million of notes payable and commercial paper in 2006 due primarily to proceeds received from asset sales.

At December 31, 2007, Duke Energy had cash, cash equivalents and short-term investments of approximately $1.1 billion, partially offset by approximately $742 million of short-term notes payable and commercial paper. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, the proceeds from which will be used to fund capital expenditures and general corporate purposes, including the repayment of commercial paper.

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

 

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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.

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 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” 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.

 

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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.

Significant Financing Activities—Year Ended 2005. During 2005, Duke Energy repurchased approximately 32.6 million shares of its common stock for approximately $933 million and paid dividends of approximately $1,105 million. Also, during the year ended December 31, 2005, approximately $28 million of convertible senior notes were converted into approximately 1 million shares of Duke Energy Common Stock.

In December 2005, the Income Fund, a Canadian income trust fund, was created which sold approximately 40% ownership in the Canadian Midstream operations for proceeds, net of underwriting discount, of approximately $110 million. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million. As discussed above, the Income Fund was included in the spin-off of the natural gas businesses in January 2007.

In December 2005, Duke Energy redeemed all Preferred and Preference stock without Sinking Fund Requirements for approximately $137 million and recognized an immaterial loss on the redemption.

In November 2005, International Energy issued floating rate debt in Guatemala for $87 million and in El Salvador for $75 million. These debt issuances have variable interest rate terms and mature in 2015.

On September 21, 2005, Union Gas entered into a fixed-rate financing agreement denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016 with an interest rate of 4.64%. This debt was included in the spin-off of the natural gas businesses in January 2007.

In August 2005, International Energy issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

In December 2004, Duke Energy reached an agreement to sell its partially completed Gray’s Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC. In 2004, Duke Energy terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.

Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2007, Duke Energy’s consolidated credit capacity decreased by approximately $1,468 million as a result of the spin-off of the natural gas businesses on January 2, 2007. In June 2007, Duke Energy closed on the syndication of an amended and restated credit facility, replacing the existing credit facilities totaling $2.65 billion with a 5-year, $2.65 billion master credit facility. Concurrent with the syndication of the master credit facility, Duke Energy established a new $1.5 billion commercial paper program at Duke Energy and terminated Cinergy’s previously existing commercial paper program. In addition, the commercial paper program at Duke Energy Carolinas was increased from $650 million to $700 million. For further information on Duke Energy’s credit facilities as of December 31, 2007, see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.”

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, 2007, Duke Energy was in compliance with those covenants. 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 May 2007, S&P upgraded Duke Energy and all its subsidiaries as a result of Duke Energy’s significant reduction in business risk, primarily through the disposal of its trading and marketing operations and merchant generation. In addition, S&P withdrew its rating on DETM.

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.

 

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The following table summarizes the February 1, 2008 credit ratings from the agencies retained by Duke Energy and its principal funding subsidiaries.

 

Credit Ratings Summary as of February 1, 2008

     Standard
and
Poor’s
   Moody’s
Investors

Service

Duke Energy Corporation(a)

   A-    Baa2

Duke Energy Carolinas, LLC(b)

   A-    A3

Cinergy Corp.(b)

   BBB+    Baa2

Duke Energy Ohio, Inc.(b)

   A-    Baa1

Duke Energy Indiana, Inc.(b)

   A-    Baa1

Duke Energy Kentucky, Inc.(b)

   A-    Baa1

 

(a) Represents corporate credit rating and issuer rating for S&P and Moody’s respectively
(b) Represents senior unsecured credit rating

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.

Clauses. Duke Energy may be required to repay certain debt should the credit ratings of Duke Energy Carolinas fall to a certain level at S&P or Moody’s. As of December 31, 2007, Duke Energy had $10 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 $21 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 82 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 2008.

Duke Energy issues shares of its common stock to meet certain employee benefit and long-term incentive obligations. Proceeds from issuances of common stock related to employee benefits, primarily employee exercises of stock options, were approximately $50 million in 2007, approximately $127 million in 2006 and approximately $41 million for 2005.

 

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 18 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

 

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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.

Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantee arrangements, 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 22 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 22 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 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”

 

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 2008.

 

Contractual Obligations as of December 31, 2007

 

     Payments Due By Period
     Total    Less than 1
year
(2008)
   2-3 Years
(2009 &
2010)
   4-5 Years
(2011 &
2012)
   More than
5 Years
(Beyond
2012)
     (in millions)

Long-term debt(a)

   $ 17,833    $ 2,120    $ 2,622    $ 2,909    $ 10,182

Capital leases(a)

     134      23      43      31      37

Operating leases(b)

     624      121      156      87      260

Purchase Obligations:(g)

              

Firm capacity payments(c)

     489      54      58      45      332

Energy commodity contracts(d)

     5,223      1,637      1,870      1,051      665

Other purchase obligations(e)(h)

     4,472      2,133      2,161      151      27

Other long-term liabilities on the Consolidated Balance Sheets(f)

     646      214      96      96      240
                                  

Total contractual cash obligations

   $ 29,421    $ 6,302    $ 7,006    $ 4,370    $ 11,743
                                  

 

(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount includes interest payments over life of debt or capital lease. Payment amounts exclude $900 million of debt issued by Duke Energy Carolinas in January 2008. Interest payments on variable rate debt instruments were calculated using interest rates derived from examination of the forward 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 17 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. Also includes firm capacity payments under electric power agreements entered into to meet U.S. Franchised Electric and Gas’ native load requirements.
(d) Includes contractual obligations to purchase physical quantities of electricity, coal and nuclear fuel. Amount includes 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, 2007. 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.

 

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(e) Includes U.S. Franchised Electric and Gas’ obligation to purchase an additional ownership interest in the Catawba Nuclear Station (see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating and Transmission Facilities”), as well as 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, and major maintenance of certain non-regulated plants. 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) Includes certain estimated executive benefit payments and contributions to the NDTF (see Note 7 to the Consolidated Financial Statements, “Asset Retirement 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. Asset retirement obligations recognized on the Consolidated Balance Sheets total $2,351 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,929 million at December 31, 2007. Amount excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 17 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, amount excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of other post-employment benefits (see Note 21 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 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 due to uncertainty of timing of future payments.
(g) 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.
(h) Includes approximately $1.2 billion of anticipated remaining costs associated with an engineering, procurement and construction services agreement executed during 2007 with an affiliate of The Shaw Group, Inc., for participation in the construction of Cliffside Unit 6 and a flue gas desulfurization system at an existing unit at Cliffside. Duke Energy has the right to terminate this agreement at any time for its convenience, subject to customary cancellation and demobilization charges in accordance with terms of the agreement.

 

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.

 

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 employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including 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 these 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 each month.

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

 

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and Hedging Activities.” 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. On a limited basis, U.S. Franchised Electric and Gas and Commercial Power apply the normal purchase and normal sales exception to certain contracts. Recognition for 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.

Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. However, Duke Energy’s decision to reduce former DENA’s interest in partially completed plants and the decision in 2005 to sell or otherwise dispose of substantially all of former DENA’s remaining physical and commercial assets outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Normal Purchases and Normal Sales below) required the reassessment of all associated derivatives, including normal purchases and normal sales. This required a change from the application of the Accrual Model to the Mark-to-Market (MTM) Model for these contracts and resulted in recording substantial unrealized losses that had not previously been recognized in the Consolidated Statements of Operations.

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 and are therefore accounted for using the MTM Model. These instruments are referred to as undesignated contracts (see Undesignated Contracts below).

Generation Portfolio Risks. 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, 2007 and 2006, it was estimated that a ten percent price change per mega-watt hour in forward wholesale power prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $24 million in 2008 and would have had a $38 million impact in 2007, 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, 2007 and 2006, it was estimated that a ten percent price change per MMBtu in natural gas prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $9 million in 2008 and would have had a $15 million impact in 2007, excluding the impact of mark-to-market changes on undesignated hedges relating to periods in excess of one year from the respective date.

Normal Purchases and Normal Sales. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States, approximately 6,100 megawatts of power generation, and certain contractual positions related to the Midwestern assets (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). As a result of this decision, Duke Energy recognized a pre-tax loss of approximately $1.9 billion in the third quarter of 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss was partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges.

Undesignated Contracts. Undesignated contracts executed to manage generation portfolio risks are 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, 2007 and 2006, 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 $16 million in 2008 and would have had a $22 million impact in 2007, 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, 2007 and 2006, 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 $14 million in 2008 and would have had a $12 million impact in 2007, resulting from the impact of mark-to-market changes on non-qualifying and undesignated coal contracts pertaining to periods in excess of one year from the respective date.

Other Commodity Risks. At December 31, 2007 and 2006, pre-tax income in 2008 and 2007 was not expected to be materially impacted for exposures to other commodities’ price changes.

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

 

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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.

 

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’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. Through December 31, 2007, Duke Energy has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy is not aware of any uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier.

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.

During 2006, Duke Energy finalized the sale of the former DENA portfolio of derivative contracts to Barclays Bank PLC and sold the Cinergy commercial marketing and trading business to Fortis, which eliminated Duke Energy’s credit, collateral, market and legal risk associated with these related trading positions.

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Spectra Energy Capital. Spectra Energy Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Spectra Energy Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of December 31, 2006 is approximately $200 million, including principal and interest payments. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2007, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2007. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Spectra Energy Capital has certain rights which should allow it to mitigate such loss. Subsequent to the spin-off the natural gas businesses, this guarantee remained with Spectra Energy Capital. However, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee. In January 2008, Calpine Corporation announced that it had successfully emerged from Chapter 11 bankruptcy protection and officially concluded its Chapter 11 reorganization.

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 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.

 

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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, and 15 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” and “Debt and Credit Facilities.”

Based on a sensitivity analysis as of December 31, 2007, it was estimated that if market interest rates average 1% higher (lower) in 2008 than in 2007, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $22 million. Comparatively, based on a sensitivity analysis as of December 31, 2006, had interest rates averaged 1% higher (lower) in 2006 than in 2005, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $3 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 investments, cash and cash equivalents outstanding as of December 31, 2007 and 2006. The increase in interest rate sensitivity is primarily due to a decrease in cash and short-term investment balances and a net increase in commercial paper borrowings. 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

Duke Energy maintains trust funds, as required by the NRC and the NCUC, to fund the costs of nuclear decommissioning (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations.”) As of December 31, 2007 and 2006, 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. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Accounting for nuclear decommissioning recognizes that costs are recovered through U.S. Franchised Electric and Gas’ rates, and fluctuations in equity prices or interest rates 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.

Bison, Duke Energy’s wholly owned captive insurance subsidiary, maintains investments to fund various business risks and losses, such as workers compensation, property, business interruption and general liability. Those investments are exposed to price fluctuations in equity markets and changes in interest rates.

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. Fluctuations in equity prices or interest rates could adversely affect Duke Energy’s consolidated financial position, results of operations and cash flows in future periods. See Note 21 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 2008, Duke Energy’s primary foreign currency rate exposures are expected to be the Brazilian Real and the Peruvian New Sol. A 10% devaluation in the currency exchange rates as of December 31, 2007 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 2008. The Consolidated Balance Sheet would be negatively impacted by approximately $145 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2007 as a result of a 10% devaluation in the

 

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currency exchange rates. As of December 31, 2006, a 10% devaluation in the currency exchange rates in all of Duke Energy’s exposure currencies was expected to result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $7 million to Duke Energy’s Consolidated Statements of Operations and a reduction of approximately $120 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 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 siting 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 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 emissions are produced from a wide variety of human activities. The U.S. EPA publishes an inventory of these emissions annually. 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. greenhouse gas emissions.

Duke Energy is adding approximately 60,000 new customers annually to its customer base of nearly four million in the Carolinas and the Midwest and making long-term decisions for how best to meet its customers’ growing demand for electricity. Duke Energy is moving ahead on multiple fronts – 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. Duke Energy needs regulatory certainty regarding U.S. climate change policy as it makes these investment decisions.

Duke Energy’s cost of complying with any federal greenhouse gas emissions law that may be enacted will depend on the design details of the program. The major design elements of a greenhouse gas cap-and-trade program that will most influence Duke Energy’s compliance costs include the required levels and timing of the cap, which will drive emission allowance prices, the emission sources covered under the cap, the number of allowances that Duke Energy is allocated on a year-to-year basis, the type of and effectiveness of the cost control mechanism employed by the program, and the availability and cost of technologies that Duke Energy can deploy to lower its emissions. Although it is likely that Congress will adopt some form of mandatory greenhouse gas emission reduction legislation in the future, the timing and specific requirements of any such legislation are highly uncertain, which means that potential future compliance costs for Duke Energy are also highly uncertain.

The 110th Congress is currently considering several potential U.S. policy responses to the climate change issue. In 2007, nearly a dozen bills were introduced in the Senate calling for mandatory limits on U.S. greenhouse gas emissions through use of a cap-and-trade program. The key differences in the bills are the sources whose emissions would be regulated, the rate at which emissions would be required to be reduced, the number of emission allowances that would be distributed at no cost to sources whose emissions would be regulated, and the method of protecting the economy from potentially high and unexpected program costs.

On December 5, 2007, the Senate Environment and Public Works Committee reported out S. 2191 - America’s Climate Security Act of 2007 – sponsored by Senators Joseph Lieberman of Connecticut and John Warner of Virginia. The bill, which now awaits Senate floor action, proposes an economy-wide greenhouse gas reduction program to begin in 2012. Several bills have also been introduced in the House of Representatives but none has yet received subcommittee or committee approval. It is unlikely that legislation establishing a mandatory federal greenhouse gas emission reduction program will be enacted in 2008.

Duke Energy supports the enactment of federal greenhouse gas cap-and-trade legislation that would apply 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 ready for wide-scale deployment.

 

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New technologies for reducing CO2 emissions from coal - chief among them carbon capture and sequestration - are not expected to be developed and ready for deployment by 2012 when the Lieberman-Warner legislation, if passed, would take effect. This would pose a challenge to Duke Energy’s ability to utilize all of its current coal-fired generating capacity if the legislation is enacted in its current form. This could challenge Duke Energy’s ability to meet the growing electricity demand of its customers at a reasonable cost. Duke Energy’s deployment of renewable generation, along with its customer energy-efficiency initiative would help, but would not be enough. If the cap is too stringent in the early years of the program, Duke Energy’s compliance options could be limited to purchasing emission allowances and/or relying on existing natural gas generation to replace coal generation. Achieving a large fuel switch from coal to natural gas in less than four years is not practical and, on a national scale, is not good public policy. Such a shift would significantly increase natural gas prices, posing an economic hardship to millions of natural gas customers.

Compliance cost estimates are very sensitive to various highly uncertain assumptions, including allowance prices. Under the proposed S. 2191 legislation, in addition to allowances allocated at no cost, Duke Energy currently estimates the costs of purchasing needed allowances to cover Duke Energy’s projected emissions in 2012 could range from approximately $930 million to $2.8 billion. Actual costs could be higher or lower than these estimates. Duke Energy would seek to recover its compliance costs through appropriate regulatory mechanisms in the jurisdictions in which it operates. Under a compliance scenario where Duke Energy continues to purchase allowances to meet its compliance obligation, annual allowance purchase costs would increase over time as the number of allowances Duke Energy is allocated under the proposed legislation decreases and allowance prices increase as the cap tightens.

At some point in the future it would be expected that Duke Energy would begin 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 to reduce emissions when technologies become available. 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 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.

In addition to relying on new technologies to reduce its CO2 emissions, Duke Energy is seeking regulatory approval 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.

(For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 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, 2007:

SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. The application of SFAS No. 157 may change Duke Energy’s current practice for measuring fair values under other accounting pronouncements that require fair value measurements. For Duke Energy, SFAS No. 157 is effective as of January 1, 2008. In February 2008, the FASB issued FASB Staff Position (FSP) No. 157-2, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. Duke Energy does not expect to report any material cumulative-effect adjustment to beginning retained earning as is required by SFAS No. 157 for certain limited matters. Duke Energy continues to monitor additional proposed interpretative guidance regarding the application of SFAS No. 157. To date, no matters have been identified regarding implementation of SFAS No. 157 that would have any material impact on Duke Energy’s consolidated results of operations or financial position.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159). In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Duke Energy does not currently have any financial assets or financial liabilities for which the provisions of SFAS No. 159 have been elected. However, in the future, Duke Energy may elect to measure certain financial instruments at fair value in accordance with this standard.

 

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

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. 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. Duke Energy is currently evaluating the impact of adopting SFAS No. 160.

 

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, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, 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 schedule, 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 schedule 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 1 to the consolidated financial statements, the Company’s spin-off of the natural gas business was completed on January 2, 2007.

 

/s/ DELOITTE & TOUCHE LLP

 

Charlotte, North Carolina

February 29, 2008

 

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Consolidated Statements of Operations

(In millions, except per-share amounts)

 

     Years Ended December 31,  
      2007     2006     2005  

Operating Revenues

      

Regulated electric

   $ 8,976     $ 7,678     $ 5,406  

Non-regulated electric, natural gas, and other

     3,024       2,542       1,500  

Regulated natural gas

     720       387        

Total operating revenues

     12,720       10,607       6,906  

Operating Expenses

      

Fuel used in electric generation and purchased power

     3,946       3,372       1,579  

Operation, maintenance and other

     3,324       3,420       2,533  

Cost of natural gas and coal sold

     557       339       9  

Depreciation and amortization

     1,746       1,545       1,123  

Property and other taxes

     649       534       327  

Impairments and other charges

                 15  

Total operating expenses

     10,222       9,210       5,586  

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

           201       191  

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

     (5 )     223       (55 )

Operating Income

     2,493       1,821       1,456  

Other Income and Expenses

      

Equity in earnings of unconsolidated affiliates

     157       123       124  

Losses on sales and impairments of equity investments

           (20 )     (20 )

Other income and expenses, net

     271       251       113  

Total other income and expenses

     428       354       217  

Interest Expense

     685       632       381  

Minority Interest Expense

     2       13       24  

Income From Continuing Operations Before Income Taxes

     2,234       1,530       1,268  

Income Tax Expense from Continuing Operations

     712       450       375  

Income From Continuing Operations

     1,522       1,080       893  

(Loss) Income From Discontinued Operations, net of tax

     (22 )     783       935  

Income Before Cumulative Effect of Change in Accounting Principle

     1,500       1,863       1,828  

Cumulative Effect of Change in Accounting Principle, net of tax and minority interest

                 (4 )

Net Income

     1,500       1,863       1,824  

Dividends and Premiums on Redemption of Preferred and Preference Stock

                 12  

Earnings Available For Common Stockholders

   $ 1,500     $ 1,863     $ 1,812  
   

Common Stock Data

      

Weighted-average shares outstanding

      

Basic

     1,260       1,170       934  

Diluted

     1,266       1,188       970  

Earnings per share (from continuing operations)

      

Basic

   $ 1.21     $ 0.92     $ 0.94  

Diluted

   $ 1.20     $ 0.91     $ 0.92  

(Loss) earnings per share (from discontinued operations)

      

Basic

   $ (0.02 )   $ 0.67     $ 1.00  

Diluted

   $ (0.02 )   $ 0.66     $ 0.96  

Earnings per share (before cumulative effect of change in accounting principle)

      

Basic

   $ 1.19     $ 1.59     $ 1.94  

Diluted

   $ 1.18     $ 1.57     $ 1.88  

Earnings per share

      

Basic

   $ 1.19     $ 1.59     $ 1.94  

Diluted

   $ 1.18     $ 1.57     $ 1.88  

Dividends per share

   $ 0.86     $ 1.26     $ 1.17  

 

See Notes to Consolidated Financial Statements

 

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Consolidated Balance Sheets

(In millions)

 

     December 31,
      2007    2006

ASSETS

     

Current Assets

     

Cash and cash equivalents

   $ 678    $ 948

Short-term investments

     437      1,514

Receivables (net of allowance for doubtful accounts of $67 at December 31,
2007 and $94 at December 31, 2006)

     1,767      2,256

Inventory

     1,012      1,358

Assets held for sale

     2      28

Other

     1,029      943

Total current assets

     4,925      7,047

Investments and Other Assets

     

Investments in unconsolidated affiliates

     696      2,305

Nuclear decommissioning trust funds

     1,929      1,775

Goodwill

     4,642      8,175

Intangibles, net

     720      905

Notes receivable

     153      224

Assets held for sale

     115      134

Other

     2,953      2,556

Total investments and other assets

     11,208      16,074

Property, Plant and Equipment

     

Cost

     46,056      58,330

Less accumulated depreciation and amortization

     14,946      16,883

Net property, plant and equipment

     31,110      41,447

Regulatory Assets and Deferred Debits

     

Deferred debt expense

     255      320

Regulatory assets related to income taxes

     552      1,361

Other

     1,654      2,451

Total regulatory assets and deferred debits

     2,461      4,132

Total Assets

   $ 49,704    $ 68,700
 

 

See Notes to Consolidated Financial Statements

 

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Consolidated Balance Sheets—(Continued)

(In millions, except per-share amounts)

 

     December 31,
      2007     2006

LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY

    

Current Liabilities

    

Accounts payable

   $ 1,585     $ 1,686

Notes payable and commercial paper

     742       450

Taxes accrued

     383       434

Interest accrued

     145       302

Liabilities associated with assets held for sale

     114       26

Current maturities of long-term debt

     1,526       1,605

Other

     1,213       2,110

Total current liabilities

     5,708       6,613

Long-term Debt

     9,498       18,118

Deferred Credits and Other Liabilities

    

Deferred income taxes

     4,751       7,003

Investment tax credit

     161       175

Liabilities associated with assets held for sale

     3       18

Asset retirement obligations

     2,351       2,301

Other

     5,852       7,565

Total deferred credits and other liabilities

     13,118       17,062

Commitments and Contingencies

    

Minority Interests

     181       805

Common Stockholders’ Equity

    

Common Stock, $0.001 par value, 2 billion shares authorized; 1,262 million and 1,257 million shares outstanding at December 31, 2007 and December 31, 2006, respectively

  

 

1

 

 

 

1

    

Additional paid-in capital

     19,933       19,854

Retained earnings

     1,398       5,652

Accumulated other comprehensive (loss) income

     (133 )     595

Total common stockholders’ equity

     21,199       26,102

Total Liabilities and Common Stockholders’ Equity

   $ 49,704     $ 68,700
 

 

See Notes to Consolidated Financial Statements

 

79


Table of Contents

PART II

DUKE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(In millions)

 

     Years Ended December 31,  
      2007     2006     2005  

CASH FLOWS FROM OPERATING ACTIVITIES

      

Net income

   $ 1,500     $ 1,863     $ 1,824  

Adjustments to reconcile net income to net cash provided by operating activities

      

Depreciation and amortization (including amortization of nuclear fuel)

     1,888       2,215       1,884  

Cumulative effect of change in accounting principle

                 4  

Gains on sales of investments in commercial and multi-family real estate

           (201 )     (191 )

Losses (gains) on sales of equity investments and other assets

     10       (365 )     (1,771 )

Impairment charges

           48       159  

Deferred income taxes

     669       250       282  

Minority Interest

     2       61       538  

Equity in earnings of unconsolidated affiliates

     (157 )     (732 )     (479 )

Contributions to company-sponsored pension and other post-retirement benefit plans

     (412 )     (172 )     (45 )

(Increase) decrease in

      

Net realized and unrealized mark-to-market and hedging transactions

           (134 )     443  

Receivables

     (240 )     844       (249 )

Inventory

     (36 )     (24 )     (80 )

Other current assets

     (22 )     1,276       (944 )

Increase (decrease) in

      

Accounts payable

     (172 )     (1,524 )     117  

Taxes accrued

     (134 )     (69 )     53  

Other current liabilities

     (321 )     (594 )     622  

Capital expenditures for residential real estate

           (322 )     (355 )

Cost of residential real estate sold

           143       294  

Other, assets

     739       1,005       193  

Other, liabilities

     (106 )     180       519  

Net cash provided by operating activities

     3,208       3,748       2,818  

CASH FLOWS FROM INVESTING ACTIVITIES

      

Capital expenditures

     (3,125 )     (3,381 )     (2,327 )

Investment expenditures

     (91 )     (89 )     (43 )

Acquisitions, net of cash acquired

     (66 )     (284 )     (294 )

Cash acquired from acquisition of Cinergy

           147        

Purchases of available-for-sale securities

     (23,639 )     (33,436 )     (40,317 )

Proceeds from sales and maturities of available-for-sale securities

     24,613       32,596       40,131  

Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable

     154       2,861       2,375  

Proceeds from the sales of commercial and multi-family real estate

           254       372  

Settlement of net investment hedges and other investing derivatives

     (10 )     (163 )     (296 )

Distributions from equity investments

           152       383  

Purchases of emission allowances

     (103 )     (228 )     (18 )

Sales of emission allowances

     52       194        

Withdrawal of restricted funds held in trust

     68       47        

Other

     (4 )     2       (92 )

Net cash used in investing activities

     (2,151 )     (1,328 )     (126 )

CASH FLOWS FROM FINANCING ACTIVITIES

      

Proceeds from the:

      

Issuance of long-term debt

     823       2,369       543  

Issuance of common stock related to employee benefit plans

     50       127       41  

Payments for the redemption of:

      

Long-term debt

     (1,248 )     (2,098 )     (1,346 )

Convertible notes

     (110 )            

Preferred stock of a subsidiary

           (12 )     (134 )

Decrease in cash overdrafts

     (2 )     (2 )      

Notes payable and commercial paper

     617       (412 )     165  

Distributions to minority interests

     (52 )     (304 )     (861 )

Contributions from minority interests

     68       247       779  

Cash distributed to Spectra Energy

     (395 )            

Dividends paid

     (1,089 )     (1,488 )     (1,105 )

Repurchase of common shares

           (500 )     (933 )

Proceeds from Duke Energy Income Fund

           104       110  

Other

     11       8       24  

Net cash used in financing activities

     (1,327 )     (1,961 )     (2,717 )

Changes in cash and cash equivalents included in assets held for sale

           (22