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, 2006 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, without 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, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer x                 Accelerated filer ¨                 Non-accelerated filer ¨

 

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, 2006    $ 36,684,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at February 23, 2007      1,257,116,278


Table of Contents

TABLE OF CONTENTS

 

DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2006

 

Item


       Page

PART I.     
1.   BUSINESS    3
   

GENERAL

   3
   

U.S. FRANCHISED ELECTRIC AND GAS

   8
   

NATURAL GAS TRANSMISSION

   16
   

FIELD SERVICES

   19
   

COMMERCIAL POWER

   21
   

INTERNATIONAL ENERGY

   22
   

CRESCENT

   23
   

OTHER

   24
   

ENVIRONMENTAL MATTERS

   25
   

GEOGRAPHIC REGIONS

   25
   

EMPLOYEES

   25
   

EXECUTIVE OFFICERS OF DUKE ENERGY

   26
1A.   RISK FACTORS    27
1B.   UNRESOLVED STAFF COMMENTS    33
2.   PROPERTIES    34
3.   LEGAL PROCEEDINGS    37
4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS    38
PART II.     
5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES    39
6.   SELECTED FINANCIAL DATA    40
7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    41
7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    86
8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA    87
9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE    193
9A.   CONTROLS AND PROCEDURES    193
PART III.     
10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE    195
11.   EXECUTIVE COMPENSATION    195
12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS    195
13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE    195
14.   PRINCIPAL ACCOUNTING FEES AND SERVICES    195
PART IV.     
15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES    196
   

SIGNATURES

   197
   

EXHIBIT INDEX

    

 

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,” 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;

   

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

   

Industrial, commercial and residential growth in Duke Energy’s 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 operations, including the economic, operational and other effects of hurricanes and ice storms;

   

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

   

The extent of success in connecting and expanding electric markets;

   

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

   

The ability to successfully complete merger, acquisition or divestiture plans, including the prices at which Duke Energy is able to sell assets; and regulatory or other limitations imposed as a result of a merger.

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.


Table of Contents

PART I

 

Item 1. Business.

 

GENERAL

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

In May 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they entered into a definitive merger agreement. Closing of the transaction occurred in the second quarter of 2006. The merger combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwest 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). On April 3, 2006, in accordance with their previously announced 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 transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004 and the financial position of Old Duke Energy as of 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.

In conjunction with Duke Energy’s merger with Cinergy, effective with the second quarter ended June 30, 2006, Duke Energy adopted new business segments that management believes properly align the various operations of Duke Energy with how the chief operating decision maker views the business. Duke Energy operates the following business units: U.S. Franchised Electric and Gas, Natural Gas Transmission, Field Services, Commercial Power, International Energy and Duke Energy’s 50% interest in the Crescent JV (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 units in deciding how to allocate resources and evaluate performance. All of the Duke Energy business units are considered reportable segments under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.” (See Note 3 to the Consolidated Financial Statements, “Business Segments,” for additional information, including financial information about each business unit and geographic areas.)

Prior to the September 2005 announcement of the exiting of the majority of former Duke Energy North America’s (DENA) businesses, former DENA’s operations were considered a separate reportable segment. The term DENA, as used throughout the Notes to Consolidated Financial Statements, refers to the former merchant generation operations in the Western and Eastern U.S., as well as operations in the Midwest and Southeast. Under Duke Energy’s new segment structure, the merchant generation operations of the Midwest and Southeast are presented in continuing operations as a component of the Commercial Power segment for all periods presented and the Western and Eastern operations are presented as a component of discontinued operations within Other for all periods presented. Prior to the change in business segments, former DENA’s continuing operations, which primarily include the merchant generation operations in the Midwest and Southeast, were included in Other in 2005 and as a component of the DENA segment in all prior periods, and discontinued operations were included in the former DENA segment for all periods.

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, Inc. (Duke Energy Ohio), Duke Energy Indiana, Inc. (Duke Energy Indiana) and Duke Energy Kentucky, Inc. (Duke Energy Kentucky). These electric and gas operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC), the Public Utilities Commission of Ohio (PUCO), the Indiana Utility Regulatory Commission (IURC) and the Kentucky Public Service Commission (KPSC).

 

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Natural Gas Transmission provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States, the Maritimes Provinces and the Pacific Northwest in the United States and Canada and in the province of Ontario in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC (DEGT). DEGT’s natural gas transmission and storage operations in the U.S. are primarily subject to the FERC’s and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). As discussed below, effective January 2, 2007, Duke Energy consummated its spin-off of the natural gas businesses (Spectra Energy Corp. (Spectra Energy)), which includes the Natural Gas Transmission business segment, to shareholders.

Field Services includes Duke Energy’s investment in DCP Midstream, LLC (formerly Duke Energy Field Services, LLC (DEFS)), which gathers, compresses, processes, transports, trades and markets, and stores natural gas. DEFS also fractionates, transports, gathers, treats, processes, trades and markets, and stores natural gas liquids (NGLs). DEFS is 50% owned by ConocoPhillips and 50% owned by Duke Energy. DEFS gathers raw natural gas through gathering systems located in major natural gas producing regions: Permian, Mid-Continent, East Texas-North Louisiana, South, Central, Rocky Mountain, and Gulf Coast. As discussed below, effective January 2, 2007, Duke Energy consummated its spin-off of Spectra Energy, which includes Duke Energy’s 50% ownership interest in DEFS, to shareholders.

In July 2005, Duke Energy completed the agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for it as an investment utilizing the equity method of accounting.

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, including Duke Energy’s 50% interest in DEFS, to shareholders. The new natural gas business, which is named Spectra Energy, consists principally of the operations of Spectra Energy Capital LLC (Spectra Energy Capital, formerly Duke Capital LLC), excluding certain operations which were transferred from Spectra Energy Capital to Duke Energy in December 2006, primarily International Energy and Duke Energy’s effective 50% interest in the Crescent JV. The use of the term Spectra Energy Capital relates to operations of the former Duke Capital LLC or the post-spin Spectra Energy Capital, as the context requires. Approximately $20 billion of assets, $13 billion of liabilities (which includes approximately $8.6 billion of debt issued by Spectra Energy Capital and its consolidated subsidiaries), and $7 billion of common stockholders’ equity were distributed from Duke Energy as of the date of the spin-off. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction.

The decision to spin off the natural gas businesses is expected to deliver long-term value to shareholders. The historical results of the natural gas businesses are expected to be treated as discontinued operations at Duke Energy in future periods beginning with the first quarter of 2007. The primary businesses remaining in Duke Energy post-spin are principally the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s 50% interest in the Crescent JV (see below).

Commercial Power owns, operates and manages non-regulated merchant 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 also develops and implements customized energy solutions. 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 merchant generation assets that were a portion of former DENA. Commercial Power’s assets comprise approximately 8,100 megawatts of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with base-load and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the Rate Stabilization Plan (RSP). For more information on the RSP, see “Commercial Power” section below.

International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. 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, Mexico, and Greece.

Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.

 

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On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create a joint venture of Crescent (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.

The remainder of Duke Energy’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes the following:

   

The remaining portion of Duke Energy’s business formerly known as DENA, including its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. Duke Energy also participates in Duke Energy Trading and Marketing, LLC (DETM). DETM is 40% owned by ExxonMobil Corporation and 60% owned by Duke Energy. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. 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”). In addition, management will continue to wind down the limited remaining operations of DETM. The results of operations for most of former DENA’s businesses which Duke Energy has exited have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all years presented.

   

Certain unallocated corporate costs, certain discontinued hedges, DukeNet Communications, LLC (DukeNet), Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, Cinergy’s equity financing business and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD). 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. Bison also participates in reinsurance activities with certain third parties, on a limited basis. Cinergy has a business which invests in start up businesses utilizing new energy technologies as well as technologies utilizing energy infrastructure, such as broadband over power line services. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation (Fluor). During 2003, Duke Energy and Fluor announced that they would dissolve D/FD and adopted a plan for an orderly wind-down of D/FD’s business. The wind-down has been substantially completed as of December 31, 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

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.

 

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PART I

 

Terms used to describe Duke Energy’s business are defined below.

Accrual Model of Accounting (Accrual Model). An accounting term used by Duke Energy to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided, the associated delivery period occurs or there is hedge ineffectiveness. As discussed further in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within U.S. Generally Accepted Accounting Principles (GAAP), Duke Energy’s application of this term could differ from that of other companies.

Allowance for Funds Used During Construction (AFUDC). An accounting convention of regulators that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

British Thermal Unit (Btu). A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.

Cubic Foot (cf). The most common unit of measurement of gas volume; the amount of natural gas required to fill a volume of one cubic foot under stated conditions of temperature, pressure and water vapor.

Decommissioning. The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of the license. Nuclear power plants are required by the Nuclear Regulatory Commission (NRC) to set aside funds for their decommissioning costs during operation.

Derivative. A financial instrument or contract in which its price is based on the value of underlying securities, equity indices, debt instruments, commodities or other benchmarks or variables. Often used to hedge risk, derivatives involve the trading of rights or obligations, but not the direct transfer of property. Gains or losses on derivatives are often settled on a net basis.

Distribution. The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.

Energy Marketing. Identification and execution of physical energy related transactions, generally with customized provisions to meet the needs of the customer or supplier, throughout the supply chain.

Environmental Protection Agency (EPA). The U.S. agency that is responsible for researching and setting national standards for a variety of environmental programs, and delegates to states the responsibility for issuing permits and for monitoring and enforcing compliance.

Federal Energy Regulatory Commission (FERC). The U.S. agency that regulates the transportation of electricity and natural gas in interstate commerce and authorizes the buying and selling of energy commodities at market-based rates.

Forward Contract. A contract in which the buyer is obligated to take delivery, and the seller is obligated to deliver a specified amount of a commodity with a predetermined price formula on a specified future date, at which time payment is due in full.

Fractionation/Fractionate. The process of separating liquid hydrocarbons from natural gas into propane, butane, ethane and other related products.

Futures Contract. A contract, usually exchange traded, in which the buyer is obligated to take delivery and the seller is obligated to deliver a fixed amount of a commodity at a predetermined price on a specified future date.

Gathering System. Pipeline, processing and related facilities that access production and other sources of natural gas supplies for delivery to mainline transmission systems.

Generation. The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in gigawatt-hours.

Independent System Operator (ISO). An entity that acts as the transmission provider for a regional transmission system, providing customers access to the system and clearing all bi-lateral contract requests for use of the electric transmission system. An ISO also shares responsibility for maintaining bulk electric system reliability.

Integrated Resource Planning. The process typically utilized by regulated utilities in conjunction with state regulatory bodies for forecasting and planning the need for generation and transmission facilities.

Light-off Fuel. Fuel oil used to light the coal prior to generating electricity.

Liquefied Natural Gas (LNG). Natural gas that has been converted to a liquid by cooling it to minus 260 degrees Fahrenheit.

 

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Liquidity. The ease with which assets or products can be traded without dramatically altering the current market price.

Local Distribution Company (LDC). A company that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or gas for ultimate consumption.

Mark-to-Market Model of Accounting (MTM Model). An accounting term used by Duke Energy to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations. As discussed further in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” this term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within GAAP, Duke Energy’s application of this term could differ from that of other companies.

Natural Gas. A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.

Natural Gas Liquids (NGLs). Liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane.

No-notice Bundled Service. A pipeline delivery service which allows customers to receive or deliver gas on demand without making prior nominations to meet service needs and without paying daily balancing and scheduling penalties.

Novation. The substitution of a new obligation or contract for an old one by the mutual agreement of all parties concerned.

Nuclear Regulatory Commission (NRC). The U.S. agency responsible for regulating the Nation’s civilian use of byproduct, source, and special nuclear materials to ensure adequate protection of public health and safety, to promote the common defense and security, and to protect the environment. The NRC’s scope of responsibility includes regulation of: commercial nuclear power reactors, including nonpower research, test and training reactors; fuel cycle facilities, including medical, academic and industrial uses of nuclear materials; and the transport, storage and disposal of nuclear materials and waste.

Origination. Identification and execution of physical energy related transactions, generally with customized provisions to meet the needs of the customer or supplier, throughout the supply chain.

Option. A contract that gives the buyer a right but not the obligation to purchase or sell an underlying asset at a specified price at a specified time.

Peak Load. The amount of electricity required during periods of highest demand. Peak periods fluctuate by season, generally occurring in the morning hours in winter and in late afternoon during the summer.

Portfolio. A collection of assets, liabilities, transactions, or trades.

Regional Transmission Organization (RTO). An independent entity which is established to have “functional control” over utilities’ transmission systems, in order to expedite transmission of electricity. RTO’s typically operate markets within their territories.

Reliability Must Run. Generation that an ISO determines is required to be on-line to meet applicable reliability criteria requirements.

Residue Gas. Gas remaining after the processing of natural gas.

Spark Spread. The difference between the value of electricity and the value of the gas required to generate the electricity at a specified heat rate.

Swap. A contract to exchange cash flows in the future according to a prearranged formula.

Throughput. The amount of natural gas or NGLs transported through a pipeline system.

Tolling. Arrangement whereby a buyer provides fuel to a power generator and receives generated power in return for a specified fee.

Transmission System (Electric). An interconnected group of electric transmission lines and related equipment for moving or transferring electric energy in bulk between points of supply and points at which it is transformed for delivery over a distribution system to customers, or for delivery to other electric transmission systems.

Transmission System (Natural Gas). An interconnected group of natural gas pipelines and associated facilities for transporting natural gas in bulk between points of supply and delivery points to industrial customers, LDCs, or for delivery to other natural gas transmission systems.

Volatility. An annualized measure of the fluctuation in the price of an energy contract.

Watt. A measure of power production or usage equal to one joule per second.

 

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PART I

 

The following sections describe the business and operations of each of Duke Energy’s business segments. (For more information on the operating outlook of Duke Energy and its 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 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. U.S. Franchised Electric and Gas also transports and sells natural gas. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky collectively referred to as Duke Energy Midwest). Its service area covers about 47,000 square miles with an estimated population of 10 million in central and western North Carolina, western South Carolina, southwestern Ohio, 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 146,700 miles of distribution lines and a 20,700-mile transmission system. U.S. Franchised Electric and Gas provides domestic regulated transmission and distribution services for natural gas to approximately 500,000 customers via approximately 8,900 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 Carolinas’ economy. Other sectors such as information, financial and real estate services are growing.

The textile industry, rubber and plastic products, chemicals and computer products are the most significant contributors to the area’s manufacturing output and Duke Energy Carolinas’ industrial sales revenue for 2006. Motor vehicle parts, building materials and electrical & electronic equipment manufacturing also have a strong impact in the area’s economic growth and the region’s industrial sales. The textile industry, while in decline, is the largest industry served in the Carolinas.

Duke Energy Carolinas has business development strategies to leverage the competitive advantages of North Carolina and South Carolina to attract and expand advanced manufacturing business in the region’s service territory. These competitive advantages, including a quality workforce, strong educational institutions and superior transportation infrastructure, were key factors in bringing in new customers in the plastics, pharmaceuticals, building materials and data processing industries. The success in attracting new companies as well as expanding the operations of existing customers substantially offsets the sales declines in the textile and furniture industries in 2006.

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’s business development strategies leveraged the competitive advantages of Indiana 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.

Duke Energy Ohio and Duke Energy Kentucky’s service area has a diversified commercial and industrial presence. Major components of the economy include manufacturing, real estate & rental leasing, wholesale trade, financial and insurance services, retail trade, education, healthcare and professional/business services. Cincinnati 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 are the most significant contributors to the area’s manufacturing output and Duke Energy Ohio and Duke Energy Kentucky’s industrial sales revenue for 2006. Food, beverage and tobacco, fabricated metals, and electronics also have a strong impact on the area’s economic growth and the region’s industrial sales.

 

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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 were key factors in attracting new customers in the transportation, food manufacturing, chemical manufacturing, plastics and data processing industries.

The number of residential and commercial customers within the U.S. Franchised Electric and Gas’ service territory continues to increase. Sales to these customers are increasing due to the growth in these sectors. As sales to residential and commercial customers increase, the consistent level of sales to industrial customers becomes a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales.

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

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

 

LOGO

 

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LOGO

 

Energy Capacity and Resources

Electric energy for U.S. Franchised Electric and Gas’ customers is generated by three nuclear generating stations with a combined net capacity of 5,020 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, 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 5,245 MW and two combined cycle (CC) stations burning natural gas or synthetic gas with a combined net capacity of 560 MW. The CT stations include the 2006 acquisition of the Rockingham CT facility (825 MW) from Dynegy Power Marketing, Inc. The acquisition was completed November 10, 2006 and was the most recent addition to U.S. Franchised Electric and Gas’ resource capability. 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.

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.

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 2006, approximately 98.8% of the total generated energy came from U.S Franchised Electric and Gas’ low-cost, efficient nuclear and coal

 

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units (51.9% coal and 46.9% nuclear). The remaining energy needs were supplied by hydroelectric, CT and CC generation or economical purchases from the wholesale market.

Hydroelectric (both conventional and pumped storage) in the Carolinas and gas/oil CT and CC stations in both the Carolinas and Midwest operate primarily during the peak-hour load periods (at peaking levels) when customer loads are rapidly changing. CT’s and CC’s produce energy at higher production costs than either nuclear or coal, but are less expensive to build and maintain, and can be rapidly started or stopped as needed to meet changing customer loads. Hydroelectric units produce low-cost energy, but their operations are limited by the availability of water flow.

U.S. Franchised Electric and Gas’ major pumped-storage hydroelectric facilities offer the added flexibility of using low-cost off-peak energy to pump water that will be stored for later generation use during times of higher-cost on-peak generation periods. These facilities allow U.S. Franchised Electric and Gas to maximize the value spreads between different high- and low-cost generation periods.

U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territory. Long-term projections indicate a need for significant capacity additions, which may include new nuclear, coal and integrated gasification combined cycle (IGCC) facilities. 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. For example, Duke Energy Carolinas filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) on June 2, 2006 for regulatory approval to build the Cliffside Project consisting of two 800 MW supercritical coal units at the existing Cliffside Steam Station, located in Rutherford and Cleveland Counties of North Carolina. Steps are also being taken to maintain the option to bring the Cliffside project on-line as early as 2011. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. The NCUC stated that it will issue a full order in the near future. Duke Energy will review the NCUC’s order, once issued, and determine whether to proceed with the Cliffside Project or consider other alternatives, including additional gas fired generation. In September 2006, Duke Energy Indiana and Vectren Energy Delivery of Indiana, Inc. filed a joint petition with the IURC seeking a CPCN for constructing a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. In addition, Duke Energy Carolinas is preparing an application for a Combined Construction and Operating License from the NRC, with the objective of potentially bringing a new nuclear facility on line by 2016. Although U.S. Franchised Electric and Gas is progressing with these efforts, final decisions regarding the development of new power facilities will be driven by realized demand, market conditions and other strategic considerations.

In evaluating the construction of several large, new electric generating plants in North Carolina, South Carolina, and Indiana, Duke Energy has begun to see significant increases in the estimated costs of these projects driven by strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. In October 2006, Duke Energy made a filing with the NCUC related to the Duke Energy Carolinas’ request for a CPCN for the Cliffside project. In this filing, Duke Energy stated that due to the rising costs described above, the cost of building the Cliffside units could be approximately $3 billion, excluding allowance for funds used during construction (AFUDC). The costs described above are expected to continue to increase causing the overall cost of the Cliffside project to increase, until such time as the NCUC issues a CPCN and Duke Energy is able to enter into definitive agreements with necessary material and service providers. In November 2006, Duke Energy 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.

Duke Energy Indiana’s estimated costs associated with the potential construction of an IGCC plant in Indiana have also increased. Duke Energy Indiana’s publicly filed testimony with the IURC on October 24, 2006 indicates that industry (Electric Power Research Institute) estimates of total capital requirement 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 owner’s specific site costs).

 

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, 2006.

 

    

Generation by Source

(Percent)


   Cost of Delivered Fuel per Net
Kilowatt-hour Generated (Cents)


     2006

   2005 (d)

   2004 (d)

   2006

   2005 (d)

   2004 (d)

Coal

   63.4    52.5    52.2    2.16    2.14    1.84

Nuclear(a)

   35.1    45.7    45.9    0.42    0.41    0.41

Oil and gas(b)

   0.6    0.1    0.2    12.67    28.83    16.79
    
  
  
              

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

   99.1    98.3    98.3    1.61    1.36    1.20

Hydroelectric(c)

   0.9    1.7    1.7               
    
  
  
              
     100.0    100.0    100.0               
    
  
  
              

 

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(a) Statistics related to nuclear generation and all fuels reflect U.S. Franchised Electric and Gas’ 12.5% ownership interest in the Catawba Nuclear Station.
(b) Cost statistics include amounts for light-off fuel at U.S. Franchised Electric and Gas’ coal-fired stations.
(c) Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.
(d) Excludes the Midwest.

 

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 2007 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 Midwest is primarily produced in Indiana, Illinois, and Kentucky. U.S. Franchised Electric and Gas has an adequate supply of coal to fuel its current and projected operations.

The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Carolinas is approximately 1%, however, as several Carolinas coal plants 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 emission allowances on the open market, this satisfies the current emission limitations for sulfur dioxide for existing facilities in the Carolinas and Midwest.

Gas. U.S. Franchised Electric and Gas is responsible for the purchase and the subsequent delivery of natural gas to native load customers in 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 2006, firm supply purchase commitment agreements provided approximately 91% 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 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, 2006, Duke Energy Ohio and Duke Energy Kentucky, combined, had hedged approximately 73% of their winter 2006/2007 base load requirements.

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   2011   2011   2009   2015
McGuire   2011   2011   2009   2015
Catawba   2011   2011   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 (DCS)) 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.

 

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, 2006, the inventory balance for U.S. Franchised Electric and Gas was approximately $795 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 have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to insure against public liability claims resulting from nuclear incidents to the full limit of liability, 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 2006, Duke Energy expensed approximately $48 million and contributed approximately $48 million of cash to the Nuclear Decommissioning Trust Funds (NDTF) for decommissioning costs; these amounts are presented in the Consolidated Statements of Cash Flows in Purchases of available-for-sale securities within Cash Flows from Investing Activities. The $48 million was contributed entirely to the funds reserved for contaminated costs. Contributions were discontinued to the funds reserved for non-contaminated costs since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,775 million as of December 31, 2006 and $1,504 million as of December 31, 2005. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds (asset).

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. Management 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 spent 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 U.S. Department of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent 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 spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke

 

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Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. The matter has been stayed pending the result of ongoing settlement negotiations between Duke Energy and the DOE. Duke Energy will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for expected future disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel used in electric generation and purchased power. Duke Energy expects resolution of this matter in the first quarter of 2007.

Duke Energy has experienced numerous claims relating to damages for personal 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 during the 1960s and 1970s. Duke Energy has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within Investments and Other Assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage, are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

 

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 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 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.

Duke Energy Ohio operates under the RSP Market Based Standard Service Offer (MBSSO) which was approved by the PUCO in November 2004, and which provides price certainty through December 31, 2008. In March 2005, the Office of the Ohio Consumers’ Counsel (OCC) appealed the PUCO’s approval of the MBSSO and in November 2006, the Ohio Supreme Court remanded the PUCO’s order approving the MBSSO for further evidentiary support and explanation, and to require Duke Energy Ohio to disclose certain confidential commercial agreements between Duke Energy Ohio and other parties previously requested by the OCC. Hearings on remand are expected to occur in March 2007. A major feature of the MBSSO is the Provider of Last Resort (POLR) Charge. Duke Energy Ohio has been collecting a POLR charge from non-residential customers since January 1, 2005, and from residential customers since January 1, 2006. The POLR 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) for the first 25% of residential load and 50% of non-residential load to 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 unavoidable (or non-by-passable).

   

System Reliability Tracker - intended to provide actual cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs. This charge is non-by-passable for residential load and by-passable for non-residential load under certain circumstances.

   

Rate Stabilization Charge - intended to compensate Duke Energy Ohio for maintaining a fixed price through 2008. This charge is by-passable by the first 25% of residential load and 50% of non-residential load to switch.

 

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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, all FERC approved transmission costs, and all congestion costs allocable to retail ratepayers that are provided service by Duke Energy Ohio.

 

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 FERC and the State Utility Commissions, except for the PUCO, also have authority over the construction and operation of U.S. Franchised Electric and Gas’ facilities. Certificates of public convenience and necessity issued by the FERC and 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.

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 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.)

 

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 repeals the Public Utility Holding Company Act (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 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. Duke Energy does not believe that the appeals of these rulemakings will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

The Energy Policy Act of 1992 and subsequent rulemakings and events initiated the opening of wholesale energy markets to competition. Open access transmission for wholesale transmission provides energy suppliers and load serving entities, including U.S. Franchised Electric and Gas and wholesale customers located in the U.S. Franchised Electric and Gas service area, with opportunities to purchase, sell and deliver capacity and energy at market based prices, which can lower overall costs to retail customers.

Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana are transmission owners in a regional transmission organization operated by the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a non-profit organization which maintains functional control over the combined transmission systems of its members. In 2005, the Midwest ISO began administering an energy market within its footprint.

 

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As a result of previous FERC rulemakings related to RTOs, Duke Energy Carolinas and the franchised electric units of Carolina Power & Light Company (now Progress Energy Carolinas) and South Carolina Electric & Gas Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO responsible for the functional control of the companies’ combined transmission systems. As of December 31, 2006, Duke Energy Carolinas had a net investment of $41 million in GridSouth, including carrying costs calculated through December 31, 2002. This amount is included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. Due to regulatory uncertainty, development of the GridSouth implementation project was suspended in 2002. In 2005, the companies notified the FERC that they had discontinued the GridSouth project. Management expects it will recover its investment in GridSouth.

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 (LMP) (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. Under the proposal, Duke Energy Carolinas will remain 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 has 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 at this time 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 and 2034. 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, 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 have 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 EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

 

NATURAL GAS TRANSMISSION

As previously discussed, effective January 2, 2007, Duke Energy consummated its spin-off of the natural gas transmission businesses (Spectra Energy), which includes the Natural Gas Transmission segment, to shareholders. The following business description of Natural Gas Transmission relates to 2006 and is not intended to describe the business subsequent to the spin-off on January 2, 2007.

Natural Gas Transmission provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States, the Maritimes Provinces and the Pacific Northwest in the United States and Canada and in the province of Ontario in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through DEGT.

Natural Gas Transmission’s pipeline systems consist of more than 17,500 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to our markets. For 2006, Natural Gas Transmission’s

 

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proportional throughput for its pipelines totaled 3,248 trillion British thermal units (TBtu), compared to 3,410 TBtu in 2005. This includes throughput on Natural Gas Transmission’s wholly owned U.S. and Canadian pipelines and its proportional share of throughput on pipelines that are not wholly owned. A majority of Natural Gas Transmission’s contracted transportation volumes are under long-term firm service agreements with LDC customers in the pipelines’ market areas. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users, and both firm and interruptible transportation services are provided to various customers on a short-term or seasonal basis. In the course of providing transportation services, Natural Gas Transmission also processes natural gas on its U.S. system. Demand on Natural Gas Transmission’s pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters. (For detailed descriptions of Natural Gas Transmission’s pipeline systems, see “Properties—Natural Gas Transmission”.)

Natural Gas Transmission, through Market Hub Partners (MHP), wholly owns natural gas salt cavern storage facilities in Southeast Texas and Louisiana. MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern Transmission, L.P. (Texas Eastern) and East Tennessee Natural Gas, LLC (ETNG), subsidiaries of Natural Gas Transmission, also provide firm and interruptible open-access storage services. Storage is offered as a stand-alone unbundled service or as part of a no-notice bundled service with transportation. ETNG also connects to Saltville Gas Storage Company L.L.C. and Early Grove Storage Company, subsidiaries of Natural Gas Transmission. These underground reservoir and salt cavern storage facilities are located in Virginia and provide storage services to customers in the Southeastern United States.

Natural Gas Transmission provides retail distribution services through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to approximately 1.3 million residential, commercial and industrial customers in Northern, Southwestern and Eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas markets of Ontario, Quebec and the Central and Eastern United States.

Natural Gas Transmission owns and operates gathering pipelines and gas processing plants in Western Canada through its British Columbia Pipeline System (BC Pipeline) operations and provides services primarily to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulphide and other substances. Where required, these facilities remove various NGLs. Natural Gas Transmission’s Empress system assets located in Western Canada provide extraction, storage, transportation, distribution and marketing of NGLs in Canada and the U.S. Natural Gas Transmission also provides gathering and processing services through its 46% interest in the Canadian Midstream operations in Western Canada that are owned by Spectra Energy Income Fund (Income Fund), formerly Duke Energy Income Fund. Natural Gas Transmission continues to operate and manage this business.

 

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LOGO

 

Competition

Natural Gas Transmission’s transportation, storage and gas gathering and processing businesses compete with similar facilities that serve its supply and market areas in the transportation, storage, gathering and processing of natural gas. The principal elements of competition are rates, terms of service, flexibility and reliability of service.

Natural gas competes with other forms of energy available to Natural Gas Transmission’s customers and end-users, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

 

Regulation

Most of Natural Gas Transmission’s pipeline and storage operations in the U.S. are regulated by the FERC. The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of rates for services. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—Natural Gas Transmission.”) The FERC also regulates the construction of U.S. interstate pipelines and storage facilities, including extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to oversight by state regulatory commissions.

FERC regulations restrict U.S. interstate pipelines from sharing transmission or customer information with energy affiliates and require that U.S. interstate pipelines function independently of their energy affiliates. These regulations affect the activities of non-regulated affiliates with Natural Gas Transmission.

The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transportation of gas by intrastate pipelines.

Natural Gas Transmission’s U.S. operations 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.) Natural Gas Transmission’s interstate natural gas pipelines are also subject to the regulations of the DOT concerning pipeline safety.

 

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The natural gas transmission, storage and distribution operations in Canada are subject to regulation by the NEB and provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, regulating the operations of facilities and construction of any additional facilities. Natural Gas Transmission’s federally regulated gathering and processing facilities and business in Western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints basis for rates associated with that business. Similarly, the rates charged by the Midstream operation for gathering and processing services in Western Canada are regulated on a complaints basis by applicable provincial regulators. The Empress NGL businesses are not under any form of rate regulation.

 

FIELD SERVICES

As previously discussed, effective January 2, 2007, Duke Energy consummated the spin-off of the natural gas transmission businesses (Spectra Energy), including Duke Energy’s investment in DEFS, to shareholders. The following business description of Field Services relates to 2006 and is not intended to describe the business subsequent to the spin-off on January 2, 2007.

Field Services includes Duke Energy’s investment in DEFS, which gathers, compresses, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, gathers, treats, processes, trades and markets, and stores NGLs. In July 2005, Duke Energy completed the disposition of its 19.7% interest in DEFS, which resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. The DEFS disposition transaction included the transfer to Duke Energy of DEFS’ Canadian Midstream business. Additionally, the disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS was no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The Canadian Midstream business and the Empress System have been transferred to the Natural Gas Transmission segment. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), the general partner of TEPPCO Partners L.P. (TEPPCO LP), and Duke Energy sold its limited partner interest in TEPPCO LP., in each case to Enterprise GP Holdings LP (EPCO), an unrelated third party.

In 2005, DEFS formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an IPO transaction in December 2005. As a result, DEFS has a 42 percent ownership interest in DCPLP, consisting of a 40 percent limited partner ownership interest and a 2 percent general partner ownership interest. DEFS owns 100 percent of the general partner of DCPLP.

DEFS operates in sixteen states in the United States (Alabama, Arkansas, Colorado, Kansas, Louisiana, Maine, Massachusetts, Mississippi, New Mexico, New York, Oklahoma, Pennsylvania, Texas, Rhode Island, Vermont and Wyoming). DEFS’ gathering systems include connections to several interstate and intrastate natural gas and NGL pipeline systems and one natural gas storage facility. DEFS gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian, Mid-Continent, East Texas-North Louisiana, South, Central, Rocky Mountain and Gulf Coast. DEFS owns or operates approximately 56,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.

DEFS’ natural gas processing operations separate raw natural gas that has been gathered on its own systems and third-party systems into condensate, NGLs and residue gas. DEFS processes the raw natural gas at 53 natural gas processing facilities.

The NGLs separated from the raw natural gas are either sold and transported as NGL raw mix, or further separated through a fractionation process into their individual components (ethane, propane, butane and natural gasoline) and then sold as components. DEFS fractionates NGL raw mix at six processing facilities that it owns and operates and at four third-party-operated facilities in which it has an ownership interest. In addition, DEFS operates a propane wholesale marketing business. DEFS sells NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small, regional retail propane distributors. Substantially all of its NGL sales are at market-based prices.

The residue gas separated from the raw natural gas is sold at market-based prices to marketers and end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. DEFS markets residue gas directly or through its wholly owned gas marketing company and its affiliates. DEFS also stores residue gas at its 8 billion-cubic-foot (Bcf) natural gas storage facility.

DEFS uses NGL trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage its price risk and to provide additional services to its customers. Asset-based gas trading and marketing activities are supported by ownership of the Spindletop storage facility and various intrastate pipelines which provide access to market centers/hubs such as Katy, Texas, and the Houston Ship Channel. DEFS undertakes these NGL and gas trading activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. DEFS believes there are additional opportunities to grow its services with its customer base.

 

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The following map includes DEFS’ natural gas gathering systems, intrastate pipelines, regional offices and supply areas.

 

LOGO

DEFS’ operating results are significantly impacted by changes in average NGL, natural gas and crude oil prices, which increased approximately 10%, decreased approximately 15% and increased approximately 15%, respectively, in 2006 compared to 2005. DEFS closely monitors the risks associated with these price changes, using NGL and crude forward contracts to mitigate the effect of such fluctuations on operating results. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk” for a discussion of DEFS’ exposure to changes in commodity prices.)

 

Competition

In gathering and processing natural gas and in marketing and transporting natural gas and NGLs, DEFS competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas gatherers, and brokers, marketers and distributors of natural gas supplies. Competition for natural gas supplies is based primarily on the reputation, efficiency and reliability of operations, the availability of gathering and transportation to high-demand markets, the pricing arrangement offered by the gatherer/processor and the ability of the gatherer/processor to obtain a satisfactory price for the producer’s residue gas and extracted NGLs. Competition for sales to customers is based primarily upon reliability, services offered, and price of delivered natural gas and NGLs.

 

Regulation

The intrastate natural gas and NGL pipelines owned by DEFS are subject to state regulation. To the extent that the natural gas intrastate pipelines provide services under Section 311 of the Natural Gas Policy Act of 1978, they are also subject to FERC regulation. The interstate natural gas pipeline owned and operated by DEFS is subject to FERC regulation, but its natural gas gathering and processing activities are not subject to FERC regulation.

DEFS is subject to the jurisdiction of the EPA and state and local environmental agencies. (For more information, see “Environmental Matters” in this section.) DEFS’ natural gas transmission pipelines and some gathering pipelines are also subject to the regulations of the DOT, and in some cases, state agencies, concerning pipeline safety.

 

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COMMERCIAL POWER

Commercial Power owns, operates and manages non-regulated merchant 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 also develops and implements customized energy solutions. 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 merchant generation assets that were a portion of former DENA. Commercial Power’s assets are comprised of approximately 8,100 net megawatts of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with base-load and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the RSP described below. See Item 2. “Properties” for further discussion of the generating facilities.

 

LOGO

Commercial Power, through Duke Energy Generation Services (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. DEGS also owns coal-based synthetic fuel production facilities which convert coal feedstock into synthetic fuel for sale to third parties. The synthetic fuel produced in these facilities qualifies for tax credits through 2007 in accordance with Internal Revenue code Section 29/45K if certain requirements are satisfied.

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.

 

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

 

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competition in the energy marketing business. Commercial Power’s main competitors include public utilities, wholesale power, coal and natural gas marketers and other merchant generation companies in the Midwestern United States, financial institutions and hedge funds engaged in energy commodity marketing and trading.

Duke Energy Ohio operates under the RSP MBSSO which was approved by the PUCO in November 2004, and which provides price certainty through December 31, 2008. In March 2005, the OCC appealed the PUCO’s approval of the MBSSO and in November 2006, the Ohio Supreme Court remanded the PUCO’s order approving the MBSSO for further evidentiary support and explanation, and to require Duke Energy Ohio to disclose certain confidential commercial agreements between Duke Energy Ohio and other parties previously requested by the OCC. Hearings on remand are expected to occur in March 2007. A major feature of the MBSSO is the POLR Charge. Duke Energy Ohio has been collecting a POLR charge from non-residential customers since January 1, 2005, and from residential customers since January 1, 2006. The POLR 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) for the first 25% of residential load and 50% of non-residential load to 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 unavoidable (or non-by-passable).

   

System Reliability Tracker - intended to provide actual cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs. This charge is non-by-passable for residential load and by-passable for non-residential load under certain circumstances.

   

Rate Stabilization Charge - intended to compensate Duke Energy Ohio for maintaining a fixed price through 2008. This charge is by-passable by the first 25% of residential load and 50% of non-residential load to switch.

   

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, all FERC approved transmission costs, and all congestion 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.

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. and Canada. 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 leading regional producer of methanol and methyl tertiary butyl ether (MTBE), Compania de Servicios de Compresion de Campeche, S.A. (Campeche), located in the Cantarell oil field in the Bay of Campeche, Mexico, which compresses and dehydrates natural gas and extracts NGL’s, 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.

 

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International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and large industrial companies. International Energy’s current strategy is focused on optimizing the value of its current Latin American portfolio.

International Energy owns, operates or has substantial interests in approximately 3,996 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including non-generation facilities in Saudi Arabia, Mexico and Greece.

 

LOGO

 

In December 2006, Duke Energy engaged in discussions with a potential buyer of International Energy’s assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International.

 

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, LDCs 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 base-load 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.)

 

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.

 

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Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. As of December 31, 2006, Crescent owned 1.1 million square feet of commercial, industrial and retail space, with an additional 0.3 million square feet under construction. This portfolio included 0.5 million square feet of office space, 0.5 million square feet of warehouse space and 0.4 million 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 three multi-family communities at December 31, 2006, including two operating properties and one property under development. As of December 31, 2006, Crescent also managed approximately 6,217 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. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

 

OTHER

The remainder of Duke Energy’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes the operations discussed below.

Other includes the remaining portion of Duke Energy’s business formerly known as DENA, including its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. Duke Energy also participates in DETM. DETM is 40% owned by ExxonMobil Corporation and 60% owned by Duke Energy. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management retained former DENA’s Midwestern generation assets (which are included in the Commercial Power segment), consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the merger with Cinergy provided a sustainable business model for those assets. The exit plan was completed in the second quarter of 2006.

The results of operations of former DENA’s Western and Eastern United States generation assets, including related commodity contracts, the divested Ft. Frances generation assets, contracts related to former DENA’s energy marketing and management activities and certain general and administrative costs, are required to be presented as discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

During 2006, Other also included certain unallocated corporate costs, certain discontinued hedges, DukeNet, Duke Energy’s 50% interest in D/FD, Cinergy’s equity financing business and Bison. Duke Energy had exited the merchant finance business at Duke Capital Partners LLC (DCP) as of the end of 2005 and all of the results of operations for DCP for the years ended December 31, 2005 and 2004 have been classified as discontinued operations.

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.

During 2003, Duke Energy determined that it would exit the refined products business at Duke Energy Merchants, LLC (DEM) in an orderly manner. As of December 31, 2006, DEM has completed the exit of its business. DEM previously engaged in commodity buying and selling, and risk management and financial services in non-regulated energy commodity markets other than physical natural gas and power (such as petroleum products). The results of operations for DEM have been classified as discontinued operations for all periods presented.

D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor. During 2003, Duke Energy and Fluor announced that they would dissolve D/FD, and adopted a plan for an orderly wind-down of D/FD’s business. The wind-down has been substantially completed as of December 31, 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

 

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Cinergy has a business which invests in start up businesses utilizing new energy technologies as well as technologies utilizing energy infrastructure, such as broadband over power line services.

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. Bison also participates in reinsurance activities with certain third parties, on a limited basis.

 

Competition and Regulation

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

 

ENVIRONMENTAL MATTERS

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

   

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

   

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

   

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

   

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

   

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 freezes 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 sulfur dioxide (SO2) and nitrogen oxides (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).

(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 units 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 “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, 2006, Duke Energy had approximately 25,600 employees. A total of approximately 6,600 operating and maintenance employees were represented by unions.

 

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EXECUTIVE OFFICERS OF DUKE ENERGY

HENRY B. BARRON JR., 56, Group Executive and Chief Nuclear Officer. Mr. Barron assumed his current position in November 2006. Prior to that, he served as Group Vice President, Nuclear Generation and Chief Nuclear Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Barron served as Group Vice President, Nuclear Generation and Chief Nuclear Officer of Duke Energy since March 2004. Prior to that, he served as Executive Vice President, Nuclear Generation of Duke Energy from January 2004 to March 2004, Senior Vice President, Nuclear Operations of Duke Energy from September 2002 to January 2004 and Vice President, McGuire Nuclear Station of Duke Energy from March 1999 to September 2002.

LYNN J. GOOD, 47, Senior Vice President and Treasurer. Ms. Good assumed her current position in December 2006. 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. And, prior to that, she was a partner with the international accounting firm Arthur Anderson LLP from 1992 to May 2002.

DAVID L. HAUSER, 55, 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.

MARC E. MANLY, 54, 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. Prior to that, Mr. Manly served as Managing Director, Law and Governmental Affairs, General Counsel and Corporate Secretary of NewPower Holdings, Inc. from April 2000 to August 2002. On June 11, 2002, New Power Holdings, Inc. and its affiliates, TNPC Holdings, Inc. and the NewPower Company, filed a petition for relief under Chapter 11 of The United States Bankruptcy Code.

WILLIAM R. McCOLLUM JR, 55, Group Executive and Chief Regulated Generation Officer. Mr. McCollum assumed his current position in November 2006. Prior to that, he served as Group Vice President, Regulated Fossil/Hydro Generation since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. McCollum served as Vice President, Strategy and Business Development for Duke Energy Carolinas since January 2005. Prior to that, Mr. McCollum served as Senior Vice President, Nuclear Support of Duke Energy from September 2002 to January 2005 and Vice Presdient, Oconee Nuclear Station of Duke Energy from March 1999 to September 2002.

THOMAS C. O’CONNOR, 51, Group Executive and President, Commercial Businesses. Mr. O’Connor assumed his current position in October 2006. Prior to that he served as Group Executive and Chief Operating 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. O’Connor served as President and Chief Executive Officer of Duke Energy Gas Transmission since December 2002. He has also served in leadership positions with Duke Energy’s pipeline operations since 1994.

JAMES E. ROGERS, 59, 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, 56, 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.

RUTH G. SHAW, 58, Executive Advisor to the Chairman, President and Chief Executive Officer. Dr. Shaw assumed her current position in October 2006. Prior to that she served as Group Executive, Public Policy and President, Duke Nuclear since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Dr. Shaw served as President and Chief Executive Officer, Duke Energy Carolinas since February 2003. Prior to that Dr. Shaw served as Executive Vice President and Chief Administrative Officer of Duke Energy Carolinas from 1997 to February 2003

 

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B. KEITH TRENT, 47, Group Executive and Chief Strategy and Policy Officer. Mr. Trent assumed his current position in October 2006. 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. Prior to that Mr. Trent served as a partner in the law firm Snell, Brannian & Trent since October 1991.

JAMES L. TURNER, 47, Group Executive and President, U.S. Franchised Electric and Gas. Mr. Turner assumed his current position in October 2006. 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, 48, 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 are elected annually by the Board of Directors. They serve until the first meeting of the Board of Directors following the annual meeting of shareholders and 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.

 

The risk factors discussed herein relate specifically to risks associated with Duke Energy subsequent to the spin-off of its natural gas businesses in January 2007. Accordingly, risks associated with the Spectra Energy businesses are not discussed in this section.

 

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.

 

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

 

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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 future price and inflationary increases in the cost of such expenditures as well as the risk of recovering such costs in a timely manner which could materially impact Duke Energy’s financial condition, results of operations or cash flows.

During the three-year period from 2007 to 2009, Duke Energy anticipates annual capital expenditures of approximately $3.5 billion, for a total of approximately $10 billion. Duke Energy has begun to see significant increases in the estimated costs of these capital projects as a result of strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. Increases in costs related to materials and services required to expand and modernize Duke Energy’s generation fleet as well as Duke Energy’s ability to recover these costs in a timely manner could materially impact Duke Energy’s consolidated financial condition, 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; however, not all markets are as open and accessible as needed. If transmission is disrupted, or if transmission capacity is inadequate, Duke Energy’s ability to sell and deliver products may be hindered. Such disruptions could also hinder Duke Energy from providing electricity to Duke Energy’s retail electric customers and may materially adversely affect Duke Energy’s business.

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 purchase 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 purchase 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 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.

 

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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 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.

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, the entity would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Further, if its short-term debt rating were to fall, the entity’s access to the commercial paper market could be significantly limited. Any downgrade or other event negatively affecting the credit ratings of Duke Energy’s subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase Duke Energy’s need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.

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

 

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

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

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

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

 

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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 $7 million. The consolidated balance sheets would be negatively impacted by such a devaluation by approximately $120 million through cumulative currency translation adjustments.

 

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, 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 complies with the minimum funding requirements as of September 30, 2006, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $500 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,

 

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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 CO2) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances.

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

 

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

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

 

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

Duke Energy is subject to numerous legal proceedings. 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.

 

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Lower demand for the electricity Duke Energy sells and lower prices for electricity result from multiple factors that affect the markets where Duke Energy sells electricity including:

   

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 generate hydroelectric energy;

   

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 merchant energy operations;

   

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

   

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

 

   

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

   

electric generation capacity surpluses which cause Duke Energy’s merchant 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.

FERC has established certain market screens it employs to assess generation market power. Certain of these screens are difficult for a franchised utility to pass. In an order issued on June 30, 2005 the FERC revoked the authority for Duke Energy Carolinas to make wholesale power sales within its control area at market-based rates based on the FERC’s determination that Duke Energy Carolinas failed one of the applicable market screens. Under the FERC’s order, Duke Energy Carolinas must pay partial refunds and may prospectively make wholesale power sales within its control area only at cost-based rates.

 

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Certain events in the energy markets beyond Duke Energy’s control have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets and could result in new laws or regulations which could have a negative impact on Duke Energy’s results of operations.

Due to certain events in the energy markets, regulated energy companies have been under increased scrutiny by regulatory bodies, capital markets and credit rating agencies. This increased scrutiny could lead to substantial 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 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 and more restrictive policy terms.

 

Item 1B. Unresolved Staff Comments.

None.

 

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Item 2. Properties.

 

U.S. FRANCHISED ELECTRIC AND GAS

As of December 31, 2006, 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 5,245 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


  

Gross

MW


  

Net

MW


   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  

Lincoln CT

   1,267    1,267    Natural gas/Fuel oil    NC    100  

Allen

   1,145    1,145    Coal    NC    100  

Bad Creek

   1,360    1,360    Hydro    SC    100  

Rockingham CT

   825    825    Natural gas/Fuel oil    NC    100  

Cliffside

   760    760    Coal    NC    100  

Jocassee

   680    680    Hydro    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  

Mill Creek CT

   596    596    Natural gas/Fuel oil    SC    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  

Lee CT

   84    84    Natural gas/Fuel oil    SC    100  

Dan River CT

   85    85    Natural gas/Fuel oil    NC    100  

Other small hydro (27 plants)

   651    651    Hydro    NC/SC    100  

Midwest:

                          

Gibson(A)

   3,132    2,820    Coal    IN    100  

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 (Units 5 and 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    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

   30,064    27,590                 
    
  
                

 

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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) Included in Assets Held for Sale

In addition, as of December 31, 2006, U.S. Franchised Electric and Gas owned approximately 20,700 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 1,700 miles of 345 kilovolts, 3,300 miles of 230 kilovolts, 8,800 miles of 100 to 161 kilovolts, and 6,300 miles of 13 to 69 kilovolts. U.S. Franchised Electric and Gas also owned approximately 146,700 conductor miles of electric distribution lines, including 102,900 miles of overhead lines and 43,800 miles of underground lines, as of December 31, 2006 and approximately 8,900 miles of gas mains and service lines. As of December 31, 2006, the electric transmission and distribution systems had approximately 2,300 substations. U.S. Franchised Electric and Gas also owns three underground caverns with a total storage capacity of approximately 23 million gallons of liquid propane. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants store propane and, when needed, vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

Substantially all of Duke Energy Carolinas’ electric plant in service is mortgaged under the indenture relating to Duke Energy’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.)

 

NATURAL GAS TRANSMISSION

As discussed in Item 1. “Business”, effective January 2, 2007, Duke Energy consummated the spin-off of its natural gas businesses, which includes the Natural Gas Transmission segment, to shareholders.

Texas Eastern’s gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, one with three large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,600 miles of pipeline and 73 compressor stations.

Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 500 miles of Texas Eastern’s pipeline system and has an ownership interest in a processing plant in Southern Louisiana.

Texas Eastern has two joint-venture storage facilities in Pennsylvania and one wholly owned and operated storage field in Maryland. Texas Eastern’s total working capacity in these three fields is 75 Bcf.

Algonquin connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to Maritimes & Northeast Pipeline. The system consists of approximately 1,100 miles of pipeline with six compressor stations.

ETNG’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,400 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with 18 compressor stations. ETNG has an LNG storage facility in Tennessee with a total working capacity of 1.2 Bcf. East Tennessee also connects to Saltville Gas Storage Company and Virginia Gas Storage Company. These natural gas storage fields are located in the state of Virginia and have a working gas capacity of approximately 5 Bcf.

Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, Maritimes & Northeast) transmission system (approximately 78% owned by Duke Energy) extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. It has two compressor stations on the system.

The British Columbia Pipeline System consists of two divisions. The field services division operates more than 1,840 miles of gathering pipelines in British Columbia, Alberta, the Yukon Territory and the Northwest Territories, as well as 22 field compressor stations; four gas processing plants located in British Columbia near Fort Nelson, Taylor, Chetwynd and in the Sikanni area Northwest of Fort St. John, and three elemental sulphur recovery plants located at Fort Nelson, Taylor and Chetwynd. Total contractible capacity is approximately 2.0 Bcf of residue gas per day. The pipeline division has approximately 1,740 miles of transmission pipelines in British Columbia and Alberta, as well as 18 mainline compressor stations.

 

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The Empress system is a collection of midstream assets involved in the extraction, storage, transportation, distribution and marketing of NGLs in Canada and the U.S. Assets include, among other things, an ownership interest in an NGL extraction plant on the TransCanada Alberta system, a liquids transmission pipeline, seven terminals along the pipe, two storage facilities, a fractionation facility, and an integrated NGL marketing and gas supply business. Total processing capacity of the Empress system is 2.4 Bcf of gas per day. The Empress system is located in Western Canada.

The DEGT Midstream operations are located in Western Canada and include thirteen natural gas processing plants and over 1,000 miles of natural gas gathering pipelines located in Western Canada.

Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas’ distribution system consists of approximately 22,000 miles of distribution pipelines. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 150 Bcf in 20 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of pipeline and six mainline compressor stations.

MHP owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 31 Bcf. The Moss Bluff facility consists of three storage caverns located in Southeast Texas and has access to five pipeline systems. The Egan facility consists of three storage caverns located in South Central Louisiana and has access to eight pipeline systems.

Natural Gas Transmission also has a 50 percent investment in Gulfstream Natural Gas System, LLC (Gulfstream), a 691-mile interstate natural gas pipeline system owned and operated jointly by Duke Energy and The Williams Company, Inc.

(For a map showing natural gas transmission and storage properties, see “Business—Natural Gas Transmission” earlier in this section.)

 

FIELD SERVICES

(For information and a map showing Field Services’ properties, see “Business—Field Services” earlier in this section.)

 

COMMERCIAL POWER

The following table provides information about Commercial Power’s merchant generation portfolio as of December 31, 2006. The MW displayed in the table below are based on summer capacity.

 

Name


  

Gross

MW


  

Net

MW


   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)(1)

   1,080    720    Steam    Coal    OH    64

W.C. Beckjord(1)

   1,124    862    Steam    Coal    OH    37.5

W.M. Zimmer(1)

   1,300    605    Steam    Coal    OH    46.5

J.M. Stuart

   2,340    912    Steam    Coal    OH    39

Killen(1)

   600    198    Steam    Coal    OH    33

Conesville(1)

   780    312    Steam    Coal    OH    40

Brownsville

   466    466    Simple Cycle    Natural gas    TN    100
    
  
                   

Total

   11,874    8,099                    
    
  
                   

 

(1) Commercial Power 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, 2006.

 

Name


    

Gross

MW


    

Net

MW


     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

     509      508      Hydro/Diesel      Peru      100  

DEI Guatemala

     250      250      Fuel Oil/Diesel      Guatemala      100  

DEI El Salvador

     291      263      Fuel Oil/Diesel      El Salvador      90  

Electroquil

     181      149      Diesel      Ecuador      82  

Aguaytia

     177      117      Natural Gas      Peru      66  

Empresa Electrica Corani

     147      74      Hydro      Bolivia      50  
      
    
                      

Total

     4,438      3,996                       
      
    
                      

In December 2006, Duke Energy engaged in discussions with a potential buyer of International Energy’s assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International.

International Energy also owns a 25% equity interest in NMC. In 2006, the NMC produced approximately 850 thousand metric tons of methanol and 1 million metric tons of MTBE. In addition, International Energy owns a 50% equity interest in the Campeche natural gas processing and compression facility. Campeche has an installed processing capacity of 270 MMcf/d. International Energy also 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

(For information regarding the properties of the business unit now known as Other, see “Business—Other” earlier in this section.)

 

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.”

 

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

At the Duke Energy Corporation Annual Meeting of Shareholders on October 24, 2006, shareholders elected Roger Agnelli, Paul M. Anderson, William Barnet, III, G. Alex Bernhardt, Sr., Michael G. Browning, Phillip R. Cox, William T. Esrey, Ann Maynard Gray, James H. Hance, Jr., Dennis R. Hendrix, Michael E.J. Phelps, James T. Rhodes, James E. Rogers, Mary L. Schapiro and Dudley S. Taft to serve as directors until the next annual meeting of shareholders and until such Director’s successor is duly elected and qualified. Below is a tabulation of votes with respect to each nominee for director at the meeting:

 

Nominee


   For

   Against/Withheld

Roger Agnelli

   947,929,162    155,182,625

Paul M. Anderson

   1,075,040,338    28,071,449

William Barnet, III

   1,079,646,448    23,465,339

G. Alex Bernhardt, Sr.

   1,075,727,658    27,384,129

Michael G. Browning

   1,072,347,645    30,764,142

Phillip R. Cox

   1,064,593,023    38,518,764

William T. Esrey

   1,073,809,374    29,302,413

Ann Maynard Gray

   1,068,607,394    34,504,393

James H. Hance, Jr.

   1,072,614,825    30,496,962

Dennis R. Hendrix

   1,072,182,705    30,929,082

Michael E. J. Phelps

   752,240,344    350,871,443

James T. Rhodes

   1,079,877,900    23,233,887

James E. Rogers

   1,074,300,198    28,811,589

Mary L. Schapiro

   1,076,085,064    27,026,723

Dudley S. Taft

   1,062,145,116    40,966,671

In addition, shareholders at the meeting also approved the Duke Energy Corporation 2006 Long-Term Incentive Compensation Plan. There were 750,402,214 shares voted for the plan, 88,378,012 shares voted against the plan, and 15,211,175 shares abstained.

And, shareholders at the meeting also ratified the selection of Deloitte & Touche LLP to act as independent auditors for Duke Energy Corporation for 2006. There were 1,072,065,312 shares voted for the proposal, 20,828,427 shares voted against the proposal and 10,218,046 shares abstained.

 

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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. As of February 23, 2007, there were approximately 175,252 common stockholders of record.

 

Common Stock Data by Quarter

 

     2006

     2005

          Stock Price
Range(a)


          Stock Price
Range(a)


     Dividends
Per Share
   High    Low     

Dividends

Per Share

   High    Low

First Quarter

   $ 0.31    $ 29.77    $ 27.38      $ 0.275    $ 28.20    $ 24.37

Second Quarter(b)

     0.63      29.85      26.94        0.585      29.98      27.34

Third Quarter

          30.98      28.84             30.55      27.84

Fourth Quarter(b)

     0.32      34.50      29.82        0.310      29.35      25.06

 

(a) Stock prices represent the intra-day high and low stock price.
(b) Dividends paid in September 2006 and December 2006 were 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 2006 trading ranges above 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, future dividends paid on Duke Energy common stock are expected to be less than the 2006 dividend of $1.26 per share as dividends are anticipated to be split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximates the former total dividend of Duke Energy. Duke Energy expects to continue its policy of paying regular cash dividends, although there is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition. Future dividends are subject to declaration by the Board of Directors.

 

Issuer Purchases of Equity Securities for Fourth Quarter of 2006

None.

Duke Energy previously announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment, primarily due to the merger with Cinergy. At the time of suspension, Duke Energy had repurchased 32.6 million shares of common stock for approximately $0.9 billion. During the first quarter of 2006, Duke Energy announced the commencement of up to $1 billion of additional share repurchases under the previously announced plan. During the first six months of 2006, Duke Energy repurchased approximately 17.5 million shares of common stock for approximately $0.5 billion. In June 2006, in connection with the plan to spin off Duke Energy’s natural gas businesses to Duke Energy shareholders, the share repurchase program was suspended. At the time of suspension, Duke Energy had repurchased approximately 50 million shares of common stock for approximately $1.4 billion under this repurchase plan. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses has been completed. As of December 31, 2006, the dollar value of shares that may yet be purchased under the plan is approximately $1.1 billion.

 

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Item 6. Selected Financial Data.(a)

 

     2006     2005     2004     2003(c)     2002  
     (in millions, except per-share amounts)  

Statement of Operations

                                        

Operating revenues

   $ 15,184     $ 16,297     $ 19,596     $ 17,623     $ 14,757  

Operating expenses

     12,493       13,416       16,441       16,632       12,313  

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

     201       191       192       84       106  

Gains (losses) on sales of other assets and other, net

     276       534       (416 )     (199 )     32  

Operating income

     3,168       3,606       2,931       876       2,582  

Other income and expenses, net

     1,008       1,809       304       550       352  

Interest expense

     1,253       1,066       1,282       1,331       1,116  

Minority interest expense

     61       538       200       62       91  

Earnings from continuing operations before income taxes

     2,862       3,811       1,753       33       1,727  

Income tax expense (benefit) from continuing operations

     843       1,282       507       (52 )     544  

Income from continuing operations

     2,019       2,529       1,246       85       1,183  

(Loss) income from discontinued operations, net of tax

     (156 )     (701 )     244       (1,246 )     (149 )

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

     1,863       1,828       1,490       (1,161 )     1,034  

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

           (4 )           (162 )      

Net income (loss)

     1,863       1,824       1,490       (1,323 )     1,034  

Dividends and premiums on redemption of preferred and preference stock

           12       9       15       13  

Earnings (loss) available for common stockholders

   $ 1,863     $ 1,812     $ 1,481     $ (1,338 )   $ 1,021  


Ratio of Earnings to Fixed Charges(d)

     3.2       4.7       2.3       (b)     2.0  

Common Stock Data

                                        

Shares of common stock outstanding(e)

                                        

Year-end

     1,257       928       957       911       895  

Weighted average—basic

     1,170       934       931       903       836  

Weighted average—diluted

     1,188       970       966       904       838  

Earnings per share (from continuing operations)

                                        

Basic

   $ 1.73     $ 2.69     $ 1.33     $ 0.09     $ 1.41  

Diluted

     1.70       2.60       1.29       0.09       1.41  

(Loss) earnings per share (from discontinued operations)

                                        

Basic

   $ (0.14 )   $ (0.75 )   $ 0.26     $ (1.39 )   $ (0.19 )

Diluted

     (0.13 )     (0.72 )     0.25       (1.39 )     (0.19 )

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

                                        

Basic

   $ 1.59     $ 1.94     $ 1.59     $ (1.30 )   $ 1.22  

Diluted

     1.57       1.88       1.54       (1.30 )     1.22  

Earnings (loss) per share

                                        

Basic

   $ 1.59     $ 1.94     $ 1.59     $ (1.48 )   $ 1.22  

Diluted

     1.57       1.88       1.54       (1.48 )     1.22  

Dividends per share

     1.26       1.17       1.10       1.10       1.10  

Balance Sheet

Total assets

   $ 68,700     $ 54,723     $ 55,770     $ 57,485     $ 60,122  

Long-term debt including capital leases, less current maturities

   $ 18,118     $ 14,547     $ 16,932     $ 20,622     $ 20,221  

 

(a) Significant transactions reflected in the results above include: 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 DEFS effective July 1, 2005 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2005 DEFS sale of TEPPCO (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”) and 2004 DENA sale of the Southeast plants (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).
(b) Earnings were inadequate to cover fixed charges by $241 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. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for further discussion.)
(d) Includes pre-tax gains of approximately $0.9 billion, net of minority interest, related to the sale of TEPPCO GP and LP in 2005 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).
(e) 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”).

 

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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, 2006, 2005 and 2004.

 

EXECUTIVE OVERVIEW

2006 Objectives. Duke Energy’s objectives for 2006, as outlined in the 2006 Charter, consisted of the following:

   

Establish an industry-leading electric power platform through successful execution of the merger with Cinergy;

   

Deliver on the 2006 financial objectives and position Duke Energy for growth in 2007 and beyond;

   

Complete the exit of the former DENA business and pursue strategic portfolio opportunities;

   

Build a high-performance culture focused on safety, diversity and inclusion, employee development, leadership and results; and

   

Build credibility through leadership on key policy issues, transparent communications and excellent customer service.

During 2006, management executed on its objectives primarily through strategically completed and pending acquisitions, as well as dispositions of certain businesses with higher risk profiles, such as the former DENA operations outside the Midwest and the Cinergy commercial marketing and trading businesses. During 2006, Duke Energy created a business model that would give both Duke Energy’s electric and gas businesses stand-alone strength and additional scope and scale along with steady and stable earnings growth.

On April 3, 2006, Duke Energy and Cinergy consummated the previously announced merger, which combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger with Cinergy increased the size and scope of Duke Energy’s electric utility operations. Duke Energy management expects to achieve numerous synergies, both immediately and over time, in all regions impacted by the merger.

As a result of the additional size and scope of the electric utility operations discussed above, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders, which was completed on January 2, 2007. The new natural gas company, Spectra Energy, consists of Duke Energy’s Natural Gas Transmission business segment, including Union Gas, as well as Duke Energy’s 50-percent ownership interest in DEFS. The spin off of the natural gas business is expected to deliver long-term value to shareholders as the two stand-alone companies are expected to be able to more easily participate in growth opportunities in their own industries as well as the gas and power industry consolidations.

In connection with the effort to reduce the risk profile of Duke Energy and to focus on businesses that can be expected to contribute steady, stable earnings growth, during 2006 Duke Energy finalized the sale of the former DENA power generation fleet outside of the Midwest to LS Power and the sale of the Cinergy commercial marketing and trading business to Fortis, a Benelux-based financial services group (Fortis).

Additionally, the Board of Directors of Duke Energy authorized management to explore the potential value of bringing in a joint venture partner at Crescent to expand the business and create a platform for increased growth. On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create the Crescent JV with MS Members. As a result of the Crescent transaction, Duke Energy no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently accounts for its investment in the Crescent JV utilizing the equity method of accounting.

After completion of the spin-off of the natural gas businesses, the primary businesses remaining in Duke Energy in 2007 are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV, which management currently expects to continue to be a reportable business segment.

Duke Energy announced an agreement with Southern Company to evaluate the potential construction of a new nuclear power plant at a site jointly owned in Cherokee County, South Carolina. Additionally, Duke Energy continues to evaluate other opportunities to re-invest in the electric utility operations, by modernizing older coal-fired plants in the Carolinas and exploring the replacement of an aging coal plant in Indiana with a coal gasification plant. Also, during the fourth quarter of 2006, Duke Energy closed on a transaction to acquire from Dynegy a 825 megawatt power plant located in Rockingham County, North Carolina. This peaking plant, which will primarily be used during times of high electricity demand, generally in the winter and summer months, will provide customers with competitively priced peaking capacity and helps to ensure Duke Energy can meet growing customer demands for electricity in the foreseeable future. Additionally, in

 

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December 2006 Duke Energy entered into an agreement to increase its ownership interest in the Catawba Nuclear Station for a purchase price of approximately $158 million. The purchase is subject to regulatory approvals and other conditions precedent and is expected to close prior to September 30, 2008.

Effective with the third quarter 2006, the Board of Directors of Duke Energy approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share. Additionally, during 2006 Duke Energy repurchased approximately 17.5 million shares of its common stock for approximately $500 million. In connection with the above mentioned plan to spin off Duke Energy’s natural gas businesses to Duke Energy shareholders, the share repurchase program was suspended. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases subsequent to the spin-off of the natural gas businesses on January 2, 2007.

2006 Financial Results. For the year-ended December 31, 2006, Duke Energy reported earnings available for common stockholders of $1,863 million and basic and diluted earnings per share (EPS) of $1.59 and $1.57, respectively, as compared to reported earnings available for common stockholders of $1,812 million and basic and diluted EPS of $1.94 and $1.88, respectively, for the year-ended December 31, 2005. Earnings available for common stockholders for 2006 as compared to 2005 were fairly flat; however, basic and diluted EPS were negatively impacted by the issuance of approximately 313 million shares in April 2006 in connection with the Cinergy merger. The highlights for 2006 include the following:

   

U.S. Franchised Electric and Gas experienced higher earnings in 2006 primarily as a result of the addition of the former Cinergy regulated utility operations in the Midwest. These higher results were partially offset by milder weather, the impact of rate reductions related to Cinergy merger approvals, and lower bulk power marketing results in the Carolinas.

   

Natural Gas Transmission’s results were flat from 2005 to 2006, but were affected by strong commodity prices related to processing activities and higher operating and maintenance expenses.

   

Field Services experienced lower earnings in 2006 primarily as a result of the 2005 gains on the sale of the TEPPCO investments and the transfer of a 19.7 percent interest in DEFS to ConocoPhillips in July 2005, which resulted in the deconsolidation of the investment in DEFS. Results in 2006 were favorably affected by strong commodity prices.

   

Commercial Power experienced higher earnings in 2006 primarily as a result of the addition of the former Cinergy non-regulated generation operations in the Midwest, partially offset by the impacts of unfavorable purchase accounting charges as a result of recognizing the Cinergy assets and liabilities at their estimated fair values as of the date of merger.

   

International Energy experienced lower earnings in 2006 primarily as a result of 2006 non-cash charges related to a settlement related to the Citrus litigation, an impairment charge related to the investment in Campeche, and an impairment charge related to the sale of Bolivian assets.

   

Crescent experienced higher earnings in 2006 primarily as a result of the gain recognized on the joint venture transaction in September 2006, which resulted in the deconsolidation of Duke Energy’s investment in the Crescent JV.

   

Other experienced higher losses in 2006 primarily as a result of 2006 charges related to contract settlement negotiations, and costs to achieve the Cinergy merger and the spin-off of the natural gas businesses.

   

Income tax expense from continuing operations was lower in 2006 as a result of a decrease in earnings from continuing operations before income taxes and a reduction in the effective tax rate. The reduction in the effective tax rate was primarily a result of favorable tax settlements on research and development costs and nuclear decommissioning costs, tax benefits related to the impairment of the investment in Bolivia, and tax credits recognized on synthetic fuel operations.

   

During 2006, Duke Energy recognized net of tax losses of $156 million in discontinued operations, as compared to net of tax losses of $701 million in 2005. During 2006, Duke Energy completed the exit of the former DENA operations outside the Midwest region and recognized additional losses as a result of sales of certain contracts. Additionally, during 2006 Duke Energy exited the Cinergy commercial marketing and trading business.

2007 Objectives. As a result of the initiatives accomplished during 2006 and the spin-off of the natural gas businesses on January 2, 2007, Duke Energy is positioned as a lower-risk business with steady earnings growth potential. For 2007, management of Duke Energy is 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;

 

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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.

Duke Energy’s consolidated earnings during 2007 are anticipated to be reduced principally as a result of the spin-off of the natural gas businesses on January 2, 2007. Excluding the impacts of the spin-off of the natural gas businesses, earnings are anticipated to be favorably affected by the following factors: a full year of earnings from the Midwest operations acquired from Cinergy, realization of cost savings as the regulatory rate reductions shared with ratepayers will phase-out in 2007, customer sales growth, capital reinvestments and regulatory initiatives.

The majority of expected earnings in 2007 are anticipated to be contributed from U.S. Franchised Electric and Gas, which consists of Duke Energy’s regulated businesses operating a net 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 substantially all of the sales of electricity coming from coal and nuclear generation facilities. Commercial Power has net capacity of approximately 8,100 megawatts of unregulated generation, of which approximately 4,100 megawatts serves retail customers under the Rate Stabilization Plan in Ohio. Approximately 75% of International Energy’s net capacity of approximately 4,000 megawatts of installed generation capacity in Latin America consists of baseload hydroelectric capacity that carries a low level of dispatch risk; in addition, for 2007 over 90% of International Energy’s contractible capacity in Latin America is either currently contracted or receives a system capacity payment.

Duke Energy’s total dividends and dividends per share in 2007 will be lower than in 2006 as a result of the spin-off of the natural gas businesses on January 2, 2007. Future dividends are expected to grow in connection with any earnings growth.

During the three-year period from 2007 to 2009, Duke Energy anticipates annual capital expenditures of approximately $3.5 billion, for a total of approximately $10 billion. These expenditures are principally related to expansion plans, environmental spending related to Clean Air requirements, nuclear fuel, as well as maintenance costs. Current estimates are that Duke Energy’s regulated generation capacity will need to increase by approximately 6,400 megawatts over the next ten years, with the majority being in North and South Carolina and the remainder being in Indiana. 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 may include a new IGCC plant in Indiana, a new coal unit (or units) at Duke Energy’s existing Cliffside facility in North Carolina, new gas-fired generation units and costs related to the evaluation of the potential construction of a new nuclear power plant in Cherokee County, South Carolina as well as normal additions due to system growth. Costs related to environmental spending are expected to decrease over the three-year period as the upgrades to comply with the new environmental regulations are completed. Duke Energy does not anticipate any additional capital investment related to its investment in the Crescent JV. Duke Energy does not currently anticipate funding 2007 capital expenditures with the issuance of common equity, 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 significant risk to Duke Energy is the ability to recover in a timely manner costs related to such expansion. In Indiana, Duke Energy has been given approval to recover its development costs for the new IGCC plant. In North and South Carolina, Duke Energy will pursue legislation to provide for construction work in progress recovery for the additional unit (or units) at the Cliffside facility as well as the proposed nuclear power plant. Additionally, Duke Energy is attempting to obtain assurance of recovery of development costs related to the proposed nuclear power plant. 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 November 2006, Duke Energy 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 an effort to respond to concerns over climate change, the U.S. Congress recently discussed various proposals to reduce or cap carbon dioxide and other greenhouse gas emissions. Any legislation enacted as a result of these efforts could involve a market based cap and trade program. Duke Energy is also focusing on energy efficiency initiatives in an effort to reduce emissions.

Duke Energy’s current regulatory initiatives primarily include obtaining the timely recovery of invested capital and pursuing a regulatory extension of the Rate Stabilization Plan in Ohio through 2010 as well as being a proponent of cost-effective energy efficiency initiatives. In North Carolina, Duke Energy is required by June 1, 2007 to file a rate case or show that a price adjustment is not required. During 2006, Duke Energy filed for an increase in its base electric rates in Kentucky. In December 2006, the Kentucky Public Service Commission approved an annual rate increase of $49 million to be effective January 1, 2007.

 

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New energy legislation has been introduced in the current South Carolina legislative session which includes 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 Carolina’s SO2 and NOx control technologies. The legislation also includes provisions to provide cost recovery assurance for upfront 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 or coal baseload generation through annual riders. Similar legislation is being discussed in North Carolina and may be introduced in the 2007 legislative session.

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 2007 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.

Duke Energy’s 2007 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 regulations 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. With the 2006 sales of former DENA’s assets outside the Midwestern United States, including substantially all the derivative portfolio, and Cinergy’s marketing and trading operation, Duke Energy expects a less volatile earnings pattern going forward.

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, 2006 as Compared to December 31, 2005. Consolidated operating revenues for 2006 decreased $1,113 million, compared to 2005. This change was driven by:

   

A $5,530 million decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

   

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.

 

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Partially offsetting these decreases in revenues were:

   

An approximate $3,891 million increase due to the merger with Cinergy

   

A $468 million increase at Natural Gas Transmission due primarily to Canadian assets (approximately $281 million), primarily higher processing revenues on the Empress System, favorable Canadian dollar foreign exchange impacts (approximately $157 million), and recovery of higher natural gas commodity costs (approximately $146 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas, partially offset by lower gas usage due to unseasonably warmer weather (approximately $186 million)

   

A $216 million increase at International Energy due primarily to higher revenues in Peru from increased ownership and resulting consolidation of Aguaytia (approximately $118 million), higher energy prices in El Salvador (approximately $40 million), favorable results in Brazil, primarily foreign exchange rate impacts (approximately $31 million) and higher electricity volumes and prices in Argentina (approximately $27 million), and

   

An approximate $130 million increase in Other related to the prior year impact of mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”) from February 22, 2005 to June 30, 2005. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to these discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations.

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating revenues for 2005 decreased $3,299 million, compared to 2004. This change was driven by:

   

A $5,380 million decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

   

An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk discussed above.

Partially offsetting these decreases in revenues were:

   

An approximate $850 million increase at Field Services, excluding the impact of the deconsolidation of DEFS, due primarily to higher average commodity prices, primarily NGL and natural gas in the first six months of 2005

   

A $704 million increase at Natural Gas Transmission due primarily to new Canadian assets (approximately $269 million), primarily the Empress System, favorable foreign exchange rates (approximately $153 million) as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses), higher natural gas prices that are passed through to customers (approximately $152 million), an increase related to U.S. business operations (approximately $60 million) driven by higher rates and contracted volumes and increased gas distribution revenues (approximately $36 million), resulting from higher gas usage in the power market

   

A $363 million increase at U.S. Franchised Electric and Gas due primarily to increased sales to retail and wholesale customers as a result of warmer weather, more efficient performance of the generation fleet, and customer growth, coupled with an increase in fuel rates primarily as a result of higher coal costs in 2005 and increased market prices for wholesale power

   

A $126 million increase at International Energy due primarily to favorable foreign exchange rate changes in Brazil, and higher energy prices and volumes, and

   

A $58 million increase at Crescent due primarily to higher residential developed lot sales.

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

 

Consolidated Operating Expenses

 

Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating expenses for 2006 decreased $923 million, compared to 2005. The change was primarily driven by:

   

An approximate $5,090 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

   

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, and

 

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An approximate $120 million decrease associated with the prior year recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”).

Partially offsetting these decreases in expenses were:

   

An approximate $3,430 million increase due to the merger with Cinergy

   

A $447 million increase at Natural Gas Transmission due primarily to Canadian assets (approximately $189 million), primarily the Empress System, increased natural gas prices at Union Gas (approximately $146 million), resulting from high natural gas prices passed through to customers without a mark-up at Union Gas, higher operating and maintenance, including pipeline integrity and project development expenses (approximately $133 million), Canadian dollar foreign exchange impacts (approximately $124 million), partially offset by lower gas purchase costs at Union Gas resulting primarily from unseasonably warmer weather (approximately $157 million)

   

A $341 million increase at International Energy due primarily to higher costs in Peru (approximately $109 million), driven primarily by increased ownership and resulting consolidation of Aguaytia, a reserve related to a settlement made in conjunction with the Citrus litigation (approximately $100 million), higher fuel prices and increased consumption in El Salvador (approximately $38 million), unfavorable exchange rates, increased regulatory fees and higher purchased power costs in Brazil (approximately $34 million), an increase in Mexico due to an impairment of a note receivable from Campeche (approximately $33 million), and impairments in Bolivia (approximately $28 million)

   

An $179 million increase in Other due primarily to costs to achieve the Cinergy merger and the anticipated spin-off of Duke Energy’s natural gas businesses (approximately $128 million and $58 million, respectively), a reserve charge related to contract settlement negotiations (approximately $65 million), partially offset by decreases due to the continued wind-down of the former DENA businesses (approximately $47 million), and

   

An approximate $115 million increase at Duke Energy Carolinas driven primarily by increased fuel expenses, due primarily to higher coal costs ($188 million) and increased purchase power expense resulting primarily from less generation availability during 2006 as a result of outages at base load stations ($42 million), partially offset by lower regulatory amortization, due primarily to reduced amortization of compliance costs related to clean air legislation ($86 million), and decreased operating and maintenance expense, due primarily to a December 2005 ice storm.

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating expenses for 2005 decreased $3,025 million, compared to 2004. The change was primarily driven by:

   

A $5,072 million decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

   

An approximate $100 million decrease in operating expenses at Commercial Power, mainly resulting from the sale of the Southeast Plants.

Partially offsetting these decreases in expenses were:

   

An approximate $675 million increase in operating expenses at Field Services driven primarily by higher average NGL and natural gas prices in the first six months of 2005

   

A $640 million increase at Natural Gas Transmission due primarily to new Canadian assets (approximately $272 million), primarily gas purchase costs associated with the Empress System, increased natural gas prices at Union Gas (approximately $152 million, which is offset in revenues), foreign exchange impacts (approximately $118 million) as discussed above (offset by currency impacts to revenues), and increased gas purchases for distribution (approximately $43 million) primarily due to higher gas usage in the power market

   

A $346 million increase in operating expenses at U.S. Franchised Electric and Gas due primarily to increased fuel expenses, driven by higher coal costs and increased generation to meet customer demand, and increased operating and maintenance expenses due primarily to increased planned outage and maintenance at generating plants, planned maintenance to improve reliability of distribution and transmission equipment, and higher storm charges in 2005, driven primarily by an ice storm in December 2005

   

An approximate $120 million increase related to the recognition of unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”)

 

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An approximate $75 million charge to increase liabilities associated with mutual insurance companies in 2005

   

A $74 million increase at International Energy due primarily to higher fuel prices, increased fuel volumes purchased, higher maintenance costs and the impact of foreign exchange rate changes in Brazil, offset by decreased power purchase obligations in Brazil, and

   

A $64 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison.

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 $201 million in 2006, $191 million in 2005, and $192 million in 2004. 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. The gain in 2004 was driven primarily by pre-tax gains from commercial land and project sales in the Washington D.C. area and pre-tax gains from the sales of surplus legacy land.

 

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

Consolidated gains (losses) on sales of other assets and other, net was a gain of $276 million for 2006, a gain of $534 million for 2005, and a loss of $416 million for 2004. 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 $250 million), and gains on settlements of customers’ transportation contracts at Natural Gas Transmission (approximately $28 million), partially offset by Commercial Power’s losses on sales of emission allowances (approximately $29 million). The gain in 2005 was due primarily to the pre-tax gain resulting from the DEFS disposition transaction (approximately $575 million), partially offset by net pre-tax losses at Commercial Power, principally the termination of DENA structured power contracts in the Southeast region (approximately $75 million). The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at Commercial Power, and the termination and sale of DETM contracts ($65 million) in Other.

 

Consolidated Operating Income

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated operating income decreased $438 million, compared to 2005. Decreased operating income was primarily related to an approximate $575 million gain in 2005 resulting from the DEFS disposition transaction, the impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to approximately $440 million for 2005, an approximate $190 million of cost in 2006 to achieve the Cinergy merger and the anticipated spin-off of Duke Energy’s natural gas businesses, and approximately $165 million of charges in 2006 related to settlements and contract negotiations. Partially offsetting these decreases were an approximately $461 million of operating income generated by legacy Cinergy in 2006 as a result of the merger, an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent and an approximate $250 million negative impact to operating income in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated operating income increased $675 million, compared to 2004. Increased operating income was due primarily to the gain in 2005 resulting from the DEFS disposition transaction and the charge in 2004 associated with the sale of the Southeast Plants in 2005, partially offset by charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, charges in 2005 related to the termination of structured power contracts in the Southeast region and increased liabilities associated with mutual insurance companies.

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, 2006 as Compared to December 31, 2005. For 2006, consolidated other income and expenses decreased $801 million, compared to 2005. The decrease was due primarily to the $1,245 million pre-tax gains on sales of equity investments recorded in 2005, primarily associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, partially offset by an increase of approximately $253 million in equity in earnings of unconsolidated affiliates due primarily to the deconsolidation of DEFS starting July 1, 2005 and an increase of approximately $115 million of interest income resulting primarily from favorable income tax settlements in 2006.

 

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Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated other income and expenses increased $1,505 million, compared to 2004. The increase was due primarily to the $1,245 million pre-tax gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, equity income of $292 million for the investment in DEFS subsequent to the deconsolidation of DEFS, effective July 1, 2005, slightly offset by the realized and unrealized pre-tax losses recognized in 2005 on certain derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Energy. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to the Field Services discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations, while from February 22, 2005 to June 30, 2005 these mark-to-market changes were classified in Non-regulated electric, natural gas, natural gas liquids and other revenues on the Consolidated Statements of Operations.

 

Consolidated Interest Expense

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated interest expense increased $187 million, compared to 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy (an approximate $228 million impact), partially offset by reduced interest expense associated with DEFS, which was deconsolidated on July 1, 2005 (an approximate $82 million impact).

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated interest expense decreased $216 million, compared to 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004 (an approximate $140 million impact) and the deconsolidation of DEFS effective July 1, 2005 (an approximate $80 million impact).

 

Consolidated Minority Interest Expense

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated minority interest expense decreased $477 million, compared to 2005. This decrease primarily resulted from the 2005 gain associated with the sale of TEPPCO GP and the impact of deconsolidation of DEFS effective July 1, 2005.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated minority interest expense increased $338 million, compared to 2004. This increase was driven primarily by increased earnings at DEFS in the first six months of 2005 as a result of the sale of TEPPCO GP and higher commodity prices, offset by the impact of the deconsolidation of DEFS effective July 1, 2005.

 

Consolidated Income Tax Expense from Continuing Operations

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated income tax expense from continuing operations decreased $439 million, compared to 2005. This decrease primarily resulted from lower pre-tax earnings, due primarily to the 2005 gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP as discussed above, offset by the 2006 gain on Crescent. The effective tax rate decreased in 2006 (29%) compared to 2005 (34%). The lower effective tax rate for year ended December 31, 2006 as compared to December 31, 2005 was primarily due to favorable tax settlements on research and development costs and nuclear decommissioning costs, tax benefits related to the impairment of an investment in Bolivia, and reserves and tax credits recognized on synthetic fuel operations.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated income tax expense from continuing operations increased $775 million, compared to 2004. The increase in income tax expense from continuing operations is primarily a result of $2,058 million in higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP, Duke Energy’s limited partner interest in TEPPCO LP and the DEFS disposition transaction (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Other than the increase from higher pre-tax earnings, the increase in income tax expense from continuing operations is due to an increase in the effective tax rate, which was approximately 34% in 2005, as compared to approximately 29% in 2004. The increase in the effective tax rate was due primarily to the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in 2004 and a $20 million tax benefit in 2004 recognized in connection with the prior year formation of Duke Energy Americas, LLC, partially offset by the $45 million taxes recorded in 2004 on the repatriation of foreign earnings that was expected to occur in 2005 associated with the American Jobs Creation Act of 2004.

 

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

Consolidated (loss) income from discontinued operations was ($156) million for 2006, ($701) million for 2005, and $244 million for 2004. These amounts represent results of operations and gains (losses) on dispositions related primarily to former DENA’s assets and

 

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contracts outside the Midwestern and Southeastern United States, which are included in Other, and Cinergy commercial marketing and trading operations, which are included in Commercial Power, (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The 2006 amount is primarily comprised of approximately $140 million of after-tax losses associated with certain contract terminations or sales at former DENA, 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, 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 an approximate $550 million non-cash, after-tax charge (approximately $900 million pre-tax) for the impairment of assets, and the discontinuance 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 AOCI related to discontinued cash flow hedges related to the former DENA operations.

The 2004 amount is primarily comprised of a $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business, and an approximate $117 million after-tax gain on the sale of two partially constructed merchant power plants in the western United States offset by operating losses at the western and northeast merchant power plants.

 

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 47, “Accounting for Conditional Asset Retirement Obligations,” in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Duke Energy.

 

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 new segment structure.

As discussed 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. Previously, the continuing operations of the former DENA segment were included as a component of Other in 2005 and as a component of the former DENA segment in prior periods.

 

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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,

 
     2006

    2005

    Variance
2006 vs
2005


    2004

    Variance
2005 vs
2004


 
     (in millions)  

U.S. Franchised Electric and Gas

   $ 1,811     $ 1,495     $ 316     $ 1,467     $ 28  

Natural Gas Transmission

     1,438       1,388       50       1,329       59  

Field Services(a)

     569       1,946       (1,377 )     367       1,579  

Commercial Power(b)

     21       (118 )     139       (479 )     361  

International Energy

     139       314       (175 )     222       92  

Crescent(c)

     532       314       218       240       74  
    


 


 


 


 


Total reportable segment EBIT

     4,510       5,339       (829 )     3,146       2,193  

Other(b)

     (581 )     (518 )     (63 )     (207 )     (311 )
    


 


 


 


 


Total reportable segment and other EBIT

     3,929       4,821       (892 )     2,939       1,882  

Interest expense

     (1,253 )     (1,066 )     (187 )     (1,282 )     216  

Interest income and other(d)

     186       56       130       96       (40 )
    


 


 


 


 


Consolidated earnings from continuing operations before income taxes

   $ 2,862     $ 3,811     $ (949 )   $ 1,753     $ 2,058  
    


 


 


 


 


 

(a) In July 2005, Duke Energy completed the agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.
(b) 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.
(c) 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.
(d) Other includes foreign currency transaction gains and losses and additional minority interest expense not allocated to the segment results.

 

Minority interest expense as shown and discussed 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,

     2006

   2005

   Variance
2006 vs.
2005


    2004

   Variance
2005 vs.
2004


     (in millions, except where noted)

Operating revenues

   $ 8,098    $ 5,432    $ 2,666     $ 5,069    $ 363

Operating expenses

     6,319      3,959      2,360       3,613      346

Gains (losses) on sales of other assets and other, net

          7      (7 )     3      4
    

  

  


 

  

Operating income

     1,779      1,480      299       1,459      21

Other income and expenses, net

     32      15      17       8      7
    

  

  


 

  

EBIT

   $ 1,811    $ 1,495    $ 316     $ 1,467    $ 28
    

  

  


 

  

Duke Energy Carolinas GWh sales(a)

     82,652      85,277      (2,625 )     82,708      2,569

Duke Energy Midwest GWh sales(a)(b)

     46,069             46,069               

 

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

 

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The following table shows the percentage changes in GWh sales and average number of customers for Duke Energy Carolinas. The table below excludes amounts related to legacy Cinergy since results of operations of Cinergy are only included from the date of acquisition and thereafter.

Increase (decrease) over prior year


     2006

     2005

     2004

 

Residential sales

     (1.2 )%    3.7 %    5.1 %

General service sales

     1.4 %    1.9 %    3.5 %

Industrial sales

     (3.8 )%    1.1 %    1.8 %

Wholesale sales

     (38.7 )%    38.0 %    (26.1 )%

Total Duke Energy Carolinas salesa

     (3.1 )%    3.1 %    (0.1 )%

Average number of customers

     2.0 %    2.0 %    1.7 %

 

a

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.

 

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 offsetting these increases were:

   

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 offsetting these increases were:

   

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

   

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.

 

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Other income and expenses. The increase in Other income and expenses resulted primarily from an increase in allowance for funds used during construction 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.

 

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. U.S. Franchised Electric and Gas will continue to provide strong cash flows from operations to Duke Energy. 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. Rate reductions for merger savings will primarily cease in the second quarter of 2007. In addition, U.S. Franchised Electric and Gas’ results will be affected by its flexibility to vary the amortization expenses associated with the North Carolina clean air legislation. U.S. Franchised Electric and Gas amortization expense related to this clean air legislation totals $863 million from inception, with $311 million recorded in 2005 and $225 million recorded in 2006. At least $185 million of amortization will be recognized in 2007 in order to recognize the minimum cumulative amortization of approximately $1.05 billion required by the end of 2007.

Various regulatory activities will continue in 2007, including a North Carolina rate review and filings for certification for new generation and approval of various costs to be recovered in trackers. The outcomes of these matters will impact future earnings and cash flows for U.S. Franchised Electric and Gas. As a result of additional costs and synergies that are expected from the merger with Cinergy as well as the uncertainty related to the regulatory activities mentioned above, U.S. Franchised Electric and Gas is unable to estimate reported segment EBIT for 2007 and beyond. However, segment EBIT for 2007 is expected to be higher than in 2006 primarily due to a full-year of contributions from Cinergy’s regulated operations and the expectation for more normalized weather in U.S. Franchised Electric and Gas’ service territories.

 

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

   

A $137 million increase in fuel revenues, due primarily to increased GWh sales to retail and wholesale customers and increased fuel rates for retail customers due primarily to increased coal costs. Sales to retail customers increased by approximately 2%, while sales to wholesale customers increased by approximately 40% resulting in significantly more fuel revenue collections from those customers. The delivered cost of coal in 2005 is approximately $7 per ton higher than in 2004

   

A $109 million increase in wholesale power revenues, net of the impact of sharing of profits from wholesale power sales with industrial customers in North Carolina ($37 million), due primarily to increased sales volumes and higher market prices, approximately $42 million and $104 million, respectively. Wholesale GWh sales increased by approximately 40% due to strong demand driven by favorable weather, more efficient performance by the generation fleet in 2005 and alleviation of coal constraints that limited wholesale sales opportunities in 2004. Gross margin increased by $11,000 per GWh, an 80% increase, due to higher average market rates for power resulting primarily from energy supply disruptions and record natural gas prices in 2005

   

A $55 million increase in GWh sales to retail customers due to favorable weather conditions during the latter half of the year. Weather statistics in 2005 for cooling degree days were approximately 7% better than normal as compared to 1% below normal in 2004, 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 Franchised Electric’s service territory. The number of customers in 2005 increased by approximately 43,000 compared to 2004.

Operating Expenses. The increase was driven primarily by:

   

A $176 million increase in fuel expenses, due primarily to higher coal costs and increased generation to meet the strong demand of retail and wholesale customers. Total generation increased by 4% compared to 2004 and generation fueled by coal accounted for more than 50 percent of total generation during both periods. The delivered cost of coal in 2005 is approximately $7 per ton higher than the same period in 2004

 

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A $134 million increase in operating and maintenance expenses, due primarily to increased planned outage and maintenance at generating plants, planned maintenance to improve the reliability of distribution and transmission equipment and employee wages and benefits

   

A $29 million increase due to higher storm charges in 2005. The increase is primarily due to a December 2005 ice storm ($46 million), which resulted in outages for approximately 700,000 customers. This is partially offset by charges for Hurricane Ivan in September 2004 ($11 million) and a wind storm in March 2004 ($7 million), and

   

A $14 million increase 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, 2005, donations totaled $28 million, while for the same period in 2004, donations totaled $14 million.

EBIT. The increase in EBIT resulted primarily from increased sales to wholesale customers, net of sharing, increased sales to retail customers due to favorable weather in 2005, and continued growth in the number of residential and general service customers in 2005. These changes were partially offset by increased operating and maintenance expenses, including storm costs.

 

Natural Gas Transmission

 

     Years Ended December 31,

 
     2006

   2005

   Variance
2006 vs
2005


    2004

   Variance
2005 vs
2004


 
     (in millions, except where noted)  

Operating revenues

   $ 4,523    $ 4,055    $ 468     $ 3,351    $ 704  

Operating expenses

     3,162      2,715      447       2,075      640  

Gains (losses) on sales of other assets and other, net

     47      13      34       17      (4 )
    

  

  


 

  


Operating income

     1,408      1,353      55       1,293      60  

Other income and expenses, net

     69      65      4       63      2  

Minority interest expense

     39      30      9       27      3  
    

  

  


 

  


EBIT

   $ 1,438    $ 1,388    $ 50     $ 1,329    $ 59  
    

  

  


 

  


Proportional throughput, TBtu(a)

     3,248      3,410      (162 )     3,332      78  

 

(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges.

 

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

Operating Revenues. The increase was driven primarily by:

   

A $281 million increase due to Canadian assets purchased in August 2005, primarily higher processing revenues on the Empress System as a result of commodity prices

   

A $157 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses),

   

A $146 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas. This revenue increase is offset in expenses

   

A $27 million increase in U.S. business operations driven by increased processing revenues associated with transportation, and

   

A $26 million increase from completed and operational pipeline expansion projects in the U.S.

Partially offsetting these increases was:

   

A $186 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to warmer weather compared to 2005.

Operating Expenses. The increase was driven primarily by:

 

   

A $189 million increase in gas purchase cost associated with the Empress System

   

A $146 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

   

A $133 million increase primarily related to increased operating and maintenance expenses on pipeline and storage operations, including pipeline integrity and project development expenses, higher insurance premiums, and benefit costs, and

   

A $124 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above).

 

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Partially offsetting these increases were:

   

A $157 million decrease in gas purchase costs at Union Gas, primarily resulting from lower gas usage due to unseasonably warmer weather, and

   

A $15 million decrease related to the resolution in 2006 of prior tax years’ ad valorem tax issues.

Gains (Losses) on Sales of Other Assets and Other, net. The increase was driven primarily by a $28 million gain in 2006 on the settlement of a customer’s transportation contract, and a $5 million gain on the sale of Stone Mountain assets in 2006.

Other Income and Expenses, net. The increase was driven primarily a pre-tax SAB No. 51 gain of $15 million related to the Income Fund’s issuance of additional units of the Canadian income trust fund, partially offset by a construction fee received in 2005 from an affiliate as a result of the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream), 50% owned by Duke Energy, and Natural Gas Transmission’s 50% share of operating and maintenance expenses in 2006 on the Southeast Supply Header project.

EBIT. The increase in EBIT is due primarily to the increase in processing earnings (primarily Empress System), the gain on settlement of a customer’s transportation contract, U.S. business expansion, the gain on the Income Fund’s issuance of additional units of the Canadian income trust fund, a gain on a property insurance settlement and the strengthening Canadian currency, partially offset by increased operating and maintenance expenses, and lower Union results primarily due to weather.

 

Matters Impacting Future Natural Gas Transmission Results

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. This transaction was effective January 2, 2007. The new natural gas company, Spectra Energy, principally consists of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50-percent ownership interest in DEFS. The historical results of the natural gas businesses are expected to be treated as discontinued operations at Duke Energy in future periods beginning with the first quarter of 2007. As a result of the spin-off, Duke Energy’s future results of operations will not include the operations of Spectra Energy.

 

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

   

A $269 million increase due to new Canadian assets, primarily the Empress System

   

A $153 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

   

A $152 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas. This revenues increase is offset in expenses

   

A $60 million increase for U.S. business operations driven by higher rates at Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M & N Pipeline) and favorable commodity prices on natural gas processing activities

   

A $36 million increase in gas distribution revenues, primarily due to higher gas usage in the power market, and

   

A $20 million increase from completed and operational pipeline expansion projects in the U.S.

Operating Expenses. The increase was driven primarily by:

 

   

A $272 million increase due to new Canadian assets, primarily gas purchase costs associated with the Empress System

 

   

A $152 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

   

A $118 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above)

   

A $43 million increase in gas purchases for distribution, primarily due to higher gas usage in the power market, and

   

A $23 million increase related to the 2004 resolution of ad valorem tax issues in various states.

Other Income and Expenses, net. The increase was driven primarily by the successful completion of the Gulfstream Phase II project which went into service in February 2005 and increased volumes at Gulfstream, resulting in a $11 million increase in Gas Transmission’s 50% equity earnings and a $5 million construction fee received from an affiliate. These increases were partially offset by a $16 million gain in 2004 on the sale of equity investments, primarily due to the resolution of contingencies related to prior year sales.

EBIT. The increase in EBIT was due primarily to earnings from U.S. business expansion projects, improved U.S. operations and favorable foreign exchange rate impacts from the strengthening Canadian currency, partially offset by the 2004 resolution of ad valorem tax issues.

 

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Field Services

 

     Years Ended December 31,

 
     2006

    2005

   Variance
2006 vs
2005


    2004

   Variance
2005 vs
2004


 
     (in millions, except where noted)  

Operating revenues

   $     $ 5,530    $ (5,530 )   $ 10,044    $ (4,514 )

Operating expenses

     5       5,215      (5,210 )     9,489      (4,274 )

Gains (losses) on sales of other assets and other, net

           577      (577 )     2      575  
    


 

  


 

  


Operating income

     (5 )     892      (897 )     557      335  

Equity in earnings of unconsolidated affiliates(a)

     574       292      282            292  

Other income and expenses, net

           1,259      (1,259 )     37      1,222  

Minority interest expense

           497      (497 )     227      270  
    


 

  


 

  


EBIT

   $ 569     $ 1,946    $ (1,377 )   $ 367    $ 1,579  
    


 

  


 

  


Natural gas gathered and processed/transported, TBtu/d(b)

     6.8       6.8            6.8       

NGL production, MBbl/d(c)

     361       353      8       356      (3 )

Average natural gas price per MMBtu(d)

   $ 7.23     $ 8.59    $ (1.36 )   $ 6.14    $ 2.45  

Average NGL price per gallon(e)

   $ 0.94     $ 0.85    $ 0.09     $ 0.68    $ 0.17  

 

(a) Includes Duke Energy’s 50% equity in earnings of DEFS net income subsequent to the deconsolidation of DEFS effective July 1, 2005. Results of DEFS prior to July 1, 2005 are presented on a consolidated basis.
(b) Trillion British thermal units per day
(c) Thousand barrels per day
(d) Million British thermal units. Average price based on NYMEX Henry Hub
(e) Does not reflect results of commodity hedges

In July 2005, Duke Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction) and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for DEFS as an investment utilizing the equity method of accounting (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

 

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

 

Operating Revenues. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Operating expenses for 2005 were also impacted by approximately $120 million of losses recognized due to the reclassification of pre-tax unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges.

Gains (losses) on sales of other assets and other, net. The decrease was due primarily to an approximate pre-tax gain of $575 million on the DEFS disposition transaction in the prior year.

Equity in Earnings of Unconsolidated Affiliates. The increase is due to Duke Energy’s 50% of equity in earnings of DEFS’ net income for the twelve months ended December 31, 2006 as compared to equity in earnings of DEFS’ net income for the six months ended December 31, 2005. DEFS’ earnings during the twelve months ended December 31, 2006 have continued to be favorably impacted by increased NGL and crude oil prices as compared to the prior period, as well as increased trading and marketing gains due primarily to changes in natural gas prices and the timing of derivative and inventory transactions.

Other Income and Expenses, net. The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. In 2005, DEFS had a pre-tax gain on the sale of its wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP of $1.1 billion, and Duke Energy had a pre-tax gain on the sale of its limited partner interest in TEPPCO LP of approximately $97 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.

Minority Interest Expense. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Minority interest expense for 2005 was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion, as discussed above.

 

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EBIT. The decrease in EBIT from 2006 to 2005 resulted primarily from the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP in 2005 and gain on the DEFS disposition transaction in 2005, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50%. These decreases were partially offset by increased NGL and crude oil prices in 2006 as compared to the prior year.

 

Matters Impacting Future Field Services Results

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. This transaction was effective January 2, 2007. The new natural gas company, Spectra Energy, principally consists of Duke Energy’s Natural Gas Transmission business segment, including Union Gas, and Duke Energy’s 50-percent ownership interest in DEFS. The historical results of the natural gas businesses are expected to be treated as discontinued operations at Duke Energy in future periods beginning with the first quarter of 2007. As a result of the spin-off, Duke Energy’s future results of operations will not include the operations of Spectra Energy.

 

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. This decrease was partially offset by increased revenues of approximately $850 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to a $0.14 per gallon increase in average NGL prices and a $0.66 per MMBtu increase in average natural gas prices. Subsequent to June 2005, Duke Energy’s 50% of equity in earnings related to its investment in DEFS are included in Equity in Earnings of Unconsolidated Affiliates.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Subsequent to June 2005, the results of DEFS are included in Equity in Earnings of Unconsolidated Affiliates. This decrease was partially offset by:

   

Increased operating expense of approximately $675 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices, and

   

An approximate $120 million increase due to the reclassification of pre-tax unrealized losses in AOCI during the first quarter 2005 as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). After the discontinuance of these hedges, changes in their fair value are being recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from the Field Services’ results.

Gains (losses) on sales of other assets and other, net. The increase was primarily due to an approximate pre-tax gain of $575 million on the DEFS disposition transaction.

Equity in earnings of unconsolidated affiliates. The increase was driven by the equity in earnings of $292 million for Duke Energy’s investment in DEFS subsequent to the completion of the DEFS disposition transaction and related deconsolidation. DEFS earnings during the six months ended December 31, 2005 have continued to be favorably impacted by increased commodity prices. These increases were partially offset by higher operating costs and pipeline integrity work as well as lower volumes due in part to hurricane interruptions.

Other Income and Expenses, net. The increase was driven primarily by an approximate $1.1 billion pre-tax gain in 2005 on the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Duke Energy’s limited partner interest in TEPPCO LP of approximately $100 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party. The gain was partially offset by a $33 million decrease in earnings from equity method investments, primarily as a result of the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense. The increase was due primarily to the minority interest impact of the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion as well as increased earnings at DEFS during the six months ended June 30, 2005 due to commodity price increases. This increase was partially offset by the DEFS disposition transaction and the related deconsolidation of Duke Energy’s investment in DEFS effective July 1, 2005.

EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, the gain as a result of the DEFS disposition transaction and favorable effects of commodity price increases, partially offset by the impact

 

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of Duke Energy’s decreased ownership percentage resulting from the completion of the DEFS disposition transaction. Also, during the first three months of 2005, Duke Energy discontinued certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). As a result of the discontinuance of these cash flow hedges and hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Field Services during the year ended December 31, 2005. Field Services’ future results are subject to volatility for factors such as commodity price changes.

 

Supplemental Data

Below is supplemental information for DEFS operating results subsequent to deconsolidation on July 1, 2005:

 

(in millions)


   Twelve Months Ended
December 31, 2006


   Six Months Ended
December 31, 2005


Operating revenues

   $ 12,335    $ 7,463

Operating expenses

     11,063      6,814
    

  

Operating income

     1,272      649

Other income and expenses, net

     9      1

Interest expense, net

     119      62

Income tax expense

     23      4
    

  

Net income

   $ 1,139    $ 584
    

  

 

Commercial Power

 

     Years Ended December 31,

 
     2006

    2005

    Variance
2006 vs
2005


   2004

    Variance
2005 vs
2004


 
     (in millions, except where noted)  

Operating revenues

   $ 1,402     $ 148     $ 1,254    $ 179     $ (31 )

Operating expenses

     1,395       200       1,195      302       (102 )

Gains (losses) on sales of other assets and other, net

     (23 )     (70 )     47      (359 )     289  
    


 


 

  


 


Operating income

     (16 )     (122 )     106      (482 )     360  

Other income and expenses, net

     37       4       33      3       1  
    


 


 

  


 


EBIT

   $ 21     $ (118 )   $ 139    $ (479 )   $ 361  
    


 


 

  


 


Actual plant production, GWh(a)

     17,640       1,759       15,881      3,343       (1,584 )

Net proportional megawatt capacity in operation

     8,100       3,600       4,500      3,600        

 

(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, 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 $1,240 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 $1,185 million).

 

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Gain (losses) 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 and an approximate $6 million gain on the sale of the Pine Mountain synthetic fuel facility in 2006, 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 by 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 $69 million).

 

Matters Impacting Future Commercial Power Results

Commercial Power’s current strategy is focused on maximizing the returns and cash flows from its current portfolio. Results for Commercial Power are sensitive to changes in power supply, power demand and fuel prices.

Segment EBIT for 2007 is expected to be higher than in 2006 primarily due to the impacts of a full year of contributions from Cinergy’s Midwestern non-regulated generation portfolio, impacts of purchase accounting from the Cinergy merger, and the recovery of under-collected fuel costs in 2006. Future results for Commercial Power are subject to volatility due to the over or under-collection of fuel costs since Commercial Power is not subject to regulatory accounting pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” In addition, the outcome of the remand hearing by the Ohio Supreme Court in regard to the Rate Stabilization Plan (RSP) with the PUCO could affect the current tariff structure of the RSP.

 

Year Ended December 31, 2005 as compared to December 31, 2004

Operating Revenues. The decrease was driven primarily by the sale of the Southeast plants in 2004, including losses in 2005 associated with structured power contracts in the Southeast.

Operating Expenses. The decrease was driven primarily by the sale of the Southeast plants in 2004 and lower operating expenses in the Midwest, including:

   

$61 million decrease in operations and maintenance costs, including general and administrative expenses, and depreciation expenses, and

   

$38 million decrease in fuel costs.

Gains (losses) on sales of other assets and other, net. The 2005 loss was due primarily to an approximate $75 million pre-tax charge related to the termination of structured power contracts in the Southeastern Region. The 2004 results include pre-tax losses of approximately $360 million associated with the sale of the Southeast Plants.

EBIT. EBIT loss decreased driven by the loss recognized in 2004 on the sale of the Southeast Plants and decreased operating costs and lower general and administrative expense, as outlined above.

 

International Energy

 

     Years Ended December 31,

 
     2006

    2005

   Variance
2006 vs
2005


    2004

    Variance
2005 vs
2004


 
     (in millions, except where noted)  

Operating revenues

   $ 961     $ 745    $ 216     $ 619     $ 126  

Operating expenses

     877       536      341       462       74  

Gains (losses) on sales of other assets and other, net

     (1 )          (1 )     (3 )     3  
    


 

  


 


 


Operating income

     83       209      (126 )     154       55  

Other income and expenses, net

     76       117      (41 )     78       39  

Minority interest expense

     20       12      8       10       2  
    


 

  


 


 


EBIT

   $ 139     $ 314    $ (175 )   $ 222     $ 92  
    


 

  


 


 


Sales, GWh

     20,424       18,213      2,211       17,776       437  

Net proportional megawatt capacity in operation(a)

     3,996       3,937      58       4,139       (202 )

 

(a) Excludes discontinued operations

 

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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, 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 (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) 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 (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”)

   

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

   

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

   

A $28 million increase in Bolivia due primarily to impairment charges as a result of the sale of assets in Bolivia, which was completed in February 2007.

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 (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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

 

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. Results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact International Energy 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 periods of inflation 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. In periods of deflation, revenue is negatively impacted and interest expense is positively impacted.

International Energy’s Argentine operations are participating in a government sponsored project to construct and operate additional gas-fired generation capacity in Argentina. International Energy’s future results of operations may be impacted by the Argentine government’s ability to successfully carry out this project and provide an adequate return to entities participating in the project.

 

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

   

A $32 million increase in Brazil due to favorable exchange rates, higher average energy prices, partially offset by lower sales volumes

   

A $31 million increase in El Salvador due to higher power prices and a favorable change in regulatory price bid methodology

   

A $28 million increase in Argentina due primarily to higher power prices and hydroelectric generation

   

A $14 million increase in Ecuador mainly due to higher volumes resulting from a lack of water for hydro competitors

 

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A $12 million increase in Guatemala due to higher power prices, and

   

An $8 million increase in Peru due to favorable hydrological conditions and higher power prices.

Operating Expenses. The increase was driven primarily by:

   

A $29 million increase in El Salvador due primarily to higher fuel oil prices, increased fuel oil volumes purchased and increased transmission costs

   

A $26 million increase in Ecuador due to higher maintenance, higher diesel fuel prices, increased diesel fuel volumes purchased and a prior year credit related to long term service contract termination

   

A $15 million increase in Guatemala due to higher fuel prices and increased fuel volumes purchased, in addition to higher operations and maintenance costs

   

A $14 million increase in Brazil due to unfavorable exchange rates and an increase in regulatory and transmission fees, partially offset by lower power purchase obligations, and

   

A $14 million increase in Argentina due to higher power purchase volumes and prices.

Partially offsetting these increases were;

   

A $13 million decrease related to a 2004 charge for the disposition of the ownership share in Compania de Nitrogeno de Cantarell, S.A. de C.V. (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico in 2004, and

   

A $10 million decrease in general and administrative expenses primarily due to lower corporate overhead allocations and compliance costs.

Other Income and Expenses, net. The increase was driven primarily by a $55 million increase in equity earnings from the NMC investment driven by higher product margins, offset by a $20 million equity investment impairment related to Campeche in 2005.

EBIT. The increase was due primarily to favorable pricing and hydrological conditions in Peru and Argentina, favorable exchange rates in Brazil and higher equity earnings from NMC, absence of a charge associated with the disposition of the ownership share in Cantarell recorded in 2004, partially offset by an equity investment impairment related to Campeche in 2005.

 

Crescent(a)

 

     Years Ended December 31,

 
     2006

   2005

   Variance
2006 vs
2005


    2004

    Variance
2005 vs
2004


 
     (in millions)  

Operating revenues

   $ 221    $ 495    $ (274 )   $ 437     $ 58  

Operating expenses

     160      399      (239 )     393       6  

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

     201      191      10       192       (1 )

Gains (losses) on sales of other assets and other, net

     246           246              
    

  

  


 


 


Operating income

     508      287      221       236       51  

Equity in earnings of unconsolidated affiliates

     15           15              

Other income and expenses, net

     14      44      (30 )     3       41  

Minority interest expense

     5      17      (12 )     (1 )     18  
    

  

  


 


 


EBIT

   $ 532    $ 314    $ 218     $ 240     $ 74  
    

  

  


 


 


 

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

 

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 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).

 

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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.

Gains (Losses) 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 (see Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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.

 

Matters Impacting Future Crescent Results

In September 2006, Duke Energy closed an agreement to create a joint venture of Crescent and sold an effective 50% interest in Crescent to the MS Members. 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 $1.19 billion was immediately distributed to Duke Energy. Subsequent to the sale, Duke Energy deconsolidated its investment in the Crescent JV and has accounted for the investment under the equity method of accounting. The combination of Duke Energy’s reduction in ownership and the increased interest expense at Crescent JV as a result of the debt transaction, the impacts of which will be reflected in Duke Energy’s future equity earnings, will likely significantly impact the amount of equity earnings of the Crescent JV that Duke Energy will recognize in future periods. Since the Crescent JV will capitalize interest as a component of project costs, the impacts of the interest expense on Duke Energy’s equity earnings will be recognized as projects are sold by the Crescent JV.

 

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by a $64 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina and the LandMar affiliate in Northeastern and Central Florida.

Operating Expenses. The increase was driven primarily by a $30 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above along with an $11 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. The increases were offset by a $16 million impairment charge in 2005 related to the Oldfield residential project near Beaufort, South Carolina as compared to $50 million in impairment and bad debt charges in 2004 related to the Twin Creeks residential project in Austin, Texas and The Rim project in Payson, Arizona.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by:

 

   

A $37 million decrease in real estate land sales primarily due to the $45 million gain on the sale of the Alexandria tract in the Washington, D.C. area in 2004, and

   

A $33 million decrease in commercial project sales primarily due to the $20 million gain on the sale of a commercial project in the Washington, D.C. area in 2004.

Partially offsetting these decreases were;

   

A $37 million increase in multi-family sales primarily due to the $15 million gain on a land sale in Charlotte, North Carolina and a $19 million gain on a project sale in Jacksonville, Florida in 2005, and

   

A $32 million increase in surplus land sales primarily due to a $42 million gain from a large land sale in Lancaster County, South Carolina in 2005.

Other Income and Expenses, net. The increase was 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.

Minority Interest Expense. The increase in minority interest (benefit) expense is primarily due to increased earnings from the LandMar affiliate.

EBIT. The increase was primarily due to income related to a distribution from an interest in a portfolio of commercial office buildings, a large land sale in Lancaster County, South Carolina, increased multi-family and residential developed lot sales offset by a decrease in commercial land and project sales due primarily to the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in 2004.

 

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Supplemental Data

 

Below is supplemental information for Crescent operating results subsequent to deconsolidation on September 7, 2006:

    

September 7
through

December 31,
2006


       (in millions)

Operating revenues

   $ 179

Operating expenses

   $ 152

Operating income

   $ 27

Net income

   $ 30

 

Other

 

     Years Ended December 31,

 
     2006

    2005

    Variance
2006 vs
2005


    2004

    Variance
2005 vs
2004


 
     (in millions)  

Operating revenues

   $ 142     $ 72     $ 70     $ 191     $ (119 )

Operating expenses

     735       556       179       388       168  

Gains (losses) on sales of other assets and other, net

     8       8             (76 )     84  
    


 


 


 


 


Operating income

     (585 )     (476 )     (109 )     (273 )     (203 )

Other income and expenses, net

     (5 )     (39 )     34       41       (80 )

Minority interest expense (benefit)

     (9 )     3       (12 )     (25 )     28  
    


 


 


 


 


EBIT

   $ (581 )   $ (518 )   $ (63 )   $ (207 )   $ (311 )
    


 


 


 


 


 

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

Operating Revenues. The increase was driven primarily by:

   

An approximate $130 million increase as a result of the prior year impact of realized and unrealized mark-to-market losses on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were accounted for as Operating Revenues prior to the deconsolidation of DEFS, effective July 1, 2005.

Partially offsetting this increase was:

   

A $43 million decrease due to the sale of Duke Project Services Group, Inc. (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

   

A $58 million increase due to costs-to-achieve in 2006 related to the spin-off of Duke Energy’s natural gas businesses, and

   

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

Partially offsetting these increases were:

   

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.

Other Income and Expenses, net. The increase was driven primarily by an approximate $45 million favorable variance resulting from the realized and unrealized mark-to-market impacts associated with certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DEFS, effective July 1, 2005.

EBIT. The decrease was due primarily to the increase in charges in 2006 associated with Cinergy merger and natural gas business spin-off costs-to-achieve, and a charge for contract settlement negotiations. These decreases were partially offset by an increase due to realized and unrealized mark-to-market impacts of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk.

 

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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. Costs associated with achieving the spin-off of the gas business and the Cinergy merger, and the wind-down of DETM could also impact future earnings for Other.

 

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The decrease was driven primarily by:

   

An approximate $130 million decrease as a result of the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”), and

   

An approximate $48 million decrease primarily due to the wind-downs of DETM and former DENA businesses.

Partially offsetting these decreases was:

   

A $21 million mark-to-market gain in 2005 related to former DENA’s hedge discontinuance in the Southeast.

Operating Expenses. The increase was driven primarily by:

   

An approximate $75 million charge to increase liabilities associated with mutual insurance companies in 2005

   

A $64 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Energy subsidiaries, and

   

A $26 million increase in corporate governance costs in 2005.

Partially offsetting these increases was:

   

A $35 million decrease primarily associated with the continued wind-down of DETM.

Gains (losses) on sales of other assets and other, net. The 2004 loss was due primarily to approximately $65 million ($39 million net of minority interest expense) of pre-tax losses associated with the sale and terminations of DETM contracts.

Other Income and Expenses, net. The decrease was driven primarily by an approximate $64 million decrease as a result of the realized and unrealized mark-to-market impact on discontinued hedges related to Field Services’ commodity price risk. (See Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

Minority Interest Expense. The change was due primarily to the continued wind-down of DETM.

EBIT. The decrease was due primarily to the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, the reversal of insurance reserves at Bison in 2004 and the increase in liabilities associated with mutual insurance companies in 2005.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

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

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

 

Regulatory Accounting

Duke Energy accounts for certain of its regulated operations (primarily U.S. Franchised Electric and Gas and Natural Gas Transmission) 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 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

 

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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, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment, nuclear decommissioning costs and amortization of regulatory assets. Total regulatory assets were $4,072 million as of December 31, 2006 and $2,319 million as of December 31, 2005. Total regulatory liabilities were $3,058 million as of December 31, 2006 and $2,338 million as of December 31, 2005. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)

 

Long-Lived Asset Impairments and Assets Held For Sale

Duke Energy evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. For long-lived assets, impairment would exist when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset’s carrying value is adjusted to its estimated fair value. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future cash flows.

Duke Energy uses the best information available to estimate fair value of its long-lived assets and may use more than one source. Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power or natural gas costs of fuel over periods of time consistent with the useful lives of the assets or changes in the real estate market. Management’s intent to use or dispose of assets is subject to re-evaluation and can change over time.

A change in Duke Energy’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Energy considers various factors when determining if impairment tests are warranted, including but not limited to:

   

Significant adverse changes in legal factors or in the business climate;

   

A current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

   

An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

   

Significant adverse changes in the extent or manner in which an asset is used or in its physical condition or a change in business strategy;

   

A significant change in the market value of an asset; and

   

A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

Judgment is also involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” (SFAS No. 144)

During 2006 and 2005, Duke Energy recorded impairments on several of its long-lived assets. (For discussion of these impairments, see Note 12 to the Consolidated Financial Statements, “Impairments, Severance and Other Charges.”)

Duke Energy may dispose of certain other assets in addition to the assets classified as held for sale at December 31, 2006. Accordingly, based in part on current market conditions in the merchant energy industry, it is reasonably possible that Duke Energy’s current estimate of fair value of its long-lived assets being considered for sale at December 31, 2006 and its other long-lived assets, could change and that change may impact the consolidated results of operations. In addition, Duke Energy could decide to dispose of additional assets in future periods, at prices that could be less than the book value of the assets.

Duke Energy uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FAS 144 in Determining Whether to Report Discontinued Operations,” to determine whether components of Duke Energy that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash

 

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flows. Additionally, pursuant to EITF 03-13, Duke Energy must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the assets sold must have been eliminated from Duke Energy’s ongoing operations (i.e. Duke Energy does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales, are reflected as (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairments and other charges in the Consolidated Statements of Operations.

 

Impairment of Goodwill

At December 31, 2006 and 2005, Duke Energy had goodwill balances of $8,175 million and $3,775 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, 2006 relates to the acquisition of Cinergy in April 2006, whose assets are primarily included in the U.S. Franchised Electric and Gas and Commercial Power segments, and the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002, whose assets are primarily included within the Natural Gas Transmission segment. The remainder relates to International Energy’s Latin American operations. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Duke Energy performs an annual goodwill impairment test and updates the test 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. As a result of the 2006 impairment test required by SFAS No. 142, Duke Energy did not record any impairment on its goodwill.

Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.

 

Revenue Recognition

Unbilled and Estimated Revenues. Revenues on sales of electricity, primarily at U.S. Franchised Electric and Gas, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered but not billed. Differences between actual and estimated unbilled revenues are immaterial and are a result of customer mix.

Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services (prior to deconsolidation on July 1, 2005), are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.

Trading and Marketing Revenues. The recognition of income in the Consolidated Statements of Operations for derivative activity is primarily dependent on whether the Accrual Model or MTM Model is applied. While the MTM Model is the default method of accounting for all derivatives, SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) allows for the use of the Accrual Model for derivatives designated as hedges and certain scope exceptions, including the normal purchase and normal sale exception. Duke Energy designates a derivative as a hedge or a normal purchase or normal sale contract in accordance with internal hedge guidelines and the requirements provided by SFAS No. 133. (For further information regarding the Accrual Model or MTM Model, see “Risk Management Accounting” below. For further information regarding the presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.)

 

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Risk Management Accounting

Duke Energy uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations: the MTM Model and the Accrual Model. As further discussed in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” the MTM Model is applied to trading and undesignated non-trading derivative contracts, and the Accrual Model is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. For the three years ended December 31, 2006, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and the EITF.

Under the MTM Model, an asset or liability is recognized at fair value on the Consolidated Balance Sheets and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations during the current period. While former DENA was the primary business segment that used this accounting model, the U.S. Franchised Electric and Gas, Commercial Power and Field Services segments, as well as Other, have historically had certain transactions subject to this model. For the years ended December 31, 2006, 2005 and 2004, Duke Energy applied the MTM Model to its derivative contracts, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below).

The MTM Model is applied within the context of an overall valuation framework. All new and existing transactions are valued using approved valuation techniques and market data, and discounted using a risk-free based interest rate [i.e.- London Interbank Offered Rate (LIBOR) or US Treasury Rate]. When available, quoted market prices are used to measure a contract’s fair value. However, market quotations for certain energy contracts may not be available for illiquid periods or locations. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. While volatility and correlation are the most subjective components, the price curve is generally the most significant component affecting the ultimate fair value for a contract subject to the MTM Model. Prices for illiquid periods or locations are established by extrapolating prices for correlated products, locations or periods. These relationships are routinely re-evaluated based on available market data, and changes in price relationships are reflected in price curves prospectively. Consideration may also be given to the analysis of market fundamentals when developing illiquid prices. A deviation in any of the components affecting fair value may significantly affect overall fair value.

Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Operations. 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. However, due to the nature and number of variables involved in estimating fair values, and the interrelationships among these variables, sensitivity analysis of the changes in any individual variable is not considered to be relevant or meaningful.

Validation of a contract’s calculated fair value is performed by an internal group independent of Duke Energy’s deal origination areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, prices and other variables. Validation of a contract’s fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.

For certain derivative instruments, Duke Energy applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133. The use of hedge accounting and the normal purchase and normal sales exemption provide effectively for the use of the Accrual Model. Under this model, there is generally no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs (settlement).

Hedge accounting treatment may be used when Duke Energy contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment may be used when Duke Energy holds firm commitments or asset positions and enters into transactions that “hedge” the risk that the price of a commodity, such as natural gas or electricity, may change between the contract’s inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, as not all of Duke Energy’s hedges relate to the exact location being hedged, a certain degree of hedge ineffectiveness may be recognized in the Consolidated Statements of Operations.

The normal purchases and normal sales exception, as provided in SFAS No. 133 as amended and interpreted by Derivative Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” (DIG Issue No. C15) and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative

 

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Instruments and Hedging Activities,” (SFAS No. 149) indicates that no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Energy’s case, the delivery of power). On a limited basis, Duke Energy applies the normal purchase and normal sales exception to certain contracts. To the extent that the hedge is perfectly effective, income statement recognition for the contract will be the same under either model.

In addition to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, the Accrual Model also encompasses non-derivative contracts used for commodity risk management purposes. For these non-derivative contracts, there is no recognition in the Consolidated Statements of Operations until the service is provided or delivery occurs.

As a result of the September 2005 decision to pursue the sale or other disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States, Duke Energy discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September 2005.

For additional information regarding risk management activities, see “Quantitative and Qualitative Disclosures about Market Risk”. The “Quantitative and Qualitative Disclosures about Market Risk” include daily earnings at risk information related to commodity derivatives recorded using the MTM Model and an operating income sensitivity analysis related to hypothetical changes in certain commodity prices recorded using the Accrual Model.

 

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.” 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). (See Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans.”)

Funding requirements for defined benefit plans are determined by government regulations, not SFAS No. 87. Duke Energy made voluntary contributions of $124 million in 2006, zero in 2005 and $250 million in 2004 to its U.S. plan. Duke Energy anticipates making a contribution of approximately $150 million to the U.S. plan in 2007. Duke Energy made contributions to the Westcoast DB plans of approximately $44 million in 2006, $42 million in 2005 and $26 million in 2004. As a result of the spin-off of the natural gas businesses, Duke Energy has no future obligations to make contributions to the Westcoast DB plans. Duke Energy made contributions to the Westcoast DC plans of approximately $4 million in 2006, $3 million in 2005 and $3 million in 2004. As a result of the spin-off of the natural gas businesses, Duke Energy has no future obligations to make contributions to the Westcoast DC plans.

The calculation of pension expense, other post-retirement 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 for 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 U.S. Plans

Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain non-contributory defined benefit retirement plans (U.S. Plans). The U.S. 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 U.S. employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain U.S. 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.

 

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Duke Energy’s U.S. Plans recognized pre-tax pension cost of $80 million, pre-tax non-qualified pension cost of $11 million and pre-tax other post-retirement benefits cost of $76 million in 2006. In 2007, Duke Energy’s U.S. pension cost is expected to be approximately $5 million lower, non-qualified pension cost is expected to be $1 million lower and other post-retirement benefits cost is expected to be $16 million lower primarily as a result of the spin-off of the natural gas businesses.

For both pension and other post-retirement plans, Duke Energy assumed that its U.S. plan’s assets would generate a long-term rate of return of 8.5% as of September 30, 2006. The assets for Duke Energy’s U.S. pension and other post-retirement plans are maintained by 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 Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.2% for U.S. equities, 1.8% 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 2006, pre-tax pension expense would have been higher by approximately $8 million and pre-tax other post-retirement expense would have been higher by approximately $1 million. If Duke Energy had used a long-term rate of 8.75% pre-tax pension expense would have been lower by approximately $8 million and pre-tax other post-retirement expense would have been lower by approximately $1 million.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 5.75% as of September 30, 2006. Duke Energy discounted its future U.S. pension and other post-retirement obligations using rates of 5.50% as of September 30, 2005 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 a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. Lowering the discount rates by 0.25% would have decreased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Increasing the discount rates by 0.25% would have increased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Lowering the discount rates by 0.25% would have increased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% would have decreased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million.

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 September 30, 2006, the medical care trend rates were 8.50%, which grades to 4.75% by 2013. As of September 30, 2006, the prescription drug trend rate was 13.00%, which grades to 4.75% 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 $6 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 $5 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.

 

Westcoast Plans

Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings. Westcoast also provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan applied to employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.

 

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Westcoast recognized pre-tax pension cost of $22 million, pre-tax non-qualified pension cost of $6 million and pre-tax other post-retirement benefits cost of $12 million in 2006. In 2007, As a result of the spin-off of the natural gas businesses, Duke Energy will not incur any future pension costs associated with the Westcoast plan.

The expected long-term rate of return for the Westcoast plans assets was 7.25% as of September 30, 2006. The Westcoast plans assets for registered pension plans are maintained by 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. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification.

The expected long-term rate of return of 7.25% and 7.50% as of September 30, 2006 and 2005, respectively, for the Westcoast 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 2.5% for Canadian equities, 1.3% for U.S. equities, 1.4% for Europe, Australasia and Far East equities, and 2.0% for fixed income securities. For 2006, the expected long-term rate of return used to calculate pension expense was 7.5%. Lowering the expected rate of return on assets by 0.25% (from 7.50% to 7.25%) would have increased Westcoast’s 2006 pre-tax pension expense by approximately $1 million. Increasing the expected rate of return by 0.25% (from 7.50% to 7.75%) would have decreased Westcoast’s 2006 pre-tax pension expense by approximately $1 million. The Westcoast other post-retirement plan does not hold any assets.

Westcoast discounted its future pension and other post-retirement obligations using a rate of 5.00% as of September 30, 2006 and 2005. For Westcoast, the discount rate used to determine the pension and other post-retirement obligations is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For 2006, the discount rate used to calculate pension expense was 5.00%. Lowering the discount rate by 0.25% (from 5.00% to 4.75%) would have increased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Increasing the discount rate by 0.25% (from 5.00% to 5.25%) would have decreased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Lowering the discount rate by 0.25% (from 5.00% to 4.75%) would have increased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% (from 5.00% to 5.25%) would have decreased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million.

The Westcoast post-retirement plans use a medical care trend rate which reflects the near and long-term expectation of increases in medical costs. As of September 30, 2006, the health care trend rates were 8.00%, which grades to 5.00% by 2009. If Westcoast had used a health care trend rate one percentage point higher, pre-tax other post-retirement expense would have been higher by $2 million. If Westcoast had used a health care trend rate one percentage point lower, pre-tax other post-retirement expense would have been lower by less than $1 million.

 

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

Duke Energy will rely primarily upon cash flows from operations, as well as its cash, cash equivalents and short-term investments to fund its liquidity and capital requirements for 2007. The current cash, cash equivalents and short-term investments and future cash generated from operations may be used by Duke Energy to continue with its February 2005 announced plan to periodically repurchase up to an aggregate of $2.5 billion of common stock over a three year period. In June 2006, the share repurchase plan was suspended. At the time of the suspension of the repurchase plan, Duke Energy had repurchased approximately 50 million shares of common stock for approximately $1.4 billion since inception of the repurchase plan. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses. In addition, Duke Energy’s future cash flows will be negatively impacted by the spin-off of the natural gas businesses effective January 2, 2007. For the year ended December 31, 2006, operating, investing and financing cash flows provided/(used) by the natural gas businesses, including distributions from Duke Energy’s 50% investment in DEFS, were approximately $1.7 billion, $(0.6) billion and $(0.2) billion, respectively.

A material adverse change in operations or available financing may impact Duke Energy’s ability to fund its current liquidity and capital resource requirements.

Duke Energy currently anticipates net cash provided by operating activities in 2007 to be lower than in 2006, primarily as a result of the following:

   

Lower operating cash flows as a result of the spin-off of the natural gas businesses, as discussed above; and,

 

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Lower operating cash flows due to the sale of an effective 50% interest in the Crescent JV in September 2006.

These lower operating cash flows are expected to be partially offset by the following:

 

   

Lower costs incurred related to the merger with Cinergy; and,

   

Higher operating results of legacy Cinergy businesses as a result of ownership for the entire year 2007.

Additionally, Duke Energy anticipates funding its defined benefit pension plans with approximately $150 million of cash during 2007, as compared to $172 million during 2006.

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 2007 capital and investment expenditures of approximately $3.3 billion, primarily consisting of approximately:

   

$2.8 billion at U.S. Franchised Electric and Gas, including $0.4 billion of North Carolina Clean Air Expenditures

   

$0.3 billion at Commercial Power

   

$0.2 billion combined at International Energy and Other

Duke Energy continues to focus on reducing risk and restructuring 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 85 percent of total projected 2007 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2007 capital and investment expenditures include approximately $1.5 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.7 billion of environmental expenditures, and approximately $0.6 billion of expansion capital. Duke Energy’s U.S. Franchised Electric and Gas business segment is evaluating the construction of several large, new electric generating plants in North Carolina, South Carolina, and Indiana. During this evaluation process, Duke Energy has begun to see significant increases in the estimated costs of these projects driven by strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. In October 2006, Duke Energy made a filing with the NCUC related to the Duke Energy Carolinas’ request for a CPCN for the Cliffside project. In this filing, Duke Energy stated that due to the rising costs described above, the cost of building the Cliffside units could be approximately $3 billion, excluding AFUDC. The costs described above are expected to continue to increase causing the overall cost of the Cliffside project to increase, until such time as the NCUC issues a CPCN and Duke Energy is able to enter into definitive agreements with necessary material and service providers. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. The NCUC stated that it will issue a full order in the near future. Duke Energy will review the NCUC’s order, once issued, and determine whether to proceed with the Cliffside Project or consider other alternatives, including additional gas fired generation. Duke Energy is attempting to obtain approval for the upfront recovery of development costs related to a proposed nuclear power plant. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state regulators. In November 2006, Duke Energy 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 Integrated Gasification on Combined Cycle (IGCC) plant in Indiana.

Duke Energy Indiana’s estimated costs associated with the potential construction of an IGCC plant in Indiana have also increased. Duke Energy Indiana’s publicly filed testimony with the Indiana Utility Regulatory Commission indicates that industry (EPRI) total capital requirement estimates 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 owner’s specific site costs).

Duke Energy anticipates its debt to total capitalization ratio to be approximately 38% by the end of 2007, as compared to 43% at the end of 2006. This reduction is primarily due to the impacts of the spin-off the natural gas businesses in 2007. Duke Energy does not expect its total debt balance (including outstanding commercial paper balances) to change significantly in 2007, excluding the impacts of approximately $8.6 billion of debt transferred to Spectra Energy as a result of the spin-off of the natural gas businesses.

Excluding the debt which was transferred in connection with the spin-off of the natural gas businesses on January 2, 2007, Duke Energy has expected debt maturities of approximately $1.1 billion in 2007. Duke Energy expects to refinance approximately $0.5 billion of these maturities. Based upon anticipated 2007 cash flows from operations and capital expenditure and dividend payment plans, Duke Energy expects to increase outstanding commercial paper balances by approximately $0.6 billion during 2007. Current total available capacity under Duke Energy’s commercial paper facilities is sufficient to meet these additional requirements.

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

 

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dialogue with the credit rating agencies, and believes that the current credit ratings are positioned for potential improvement evidenced by positive outlooks at Duke Energy and most of its subsidiaries.

 

Operating Cash Flows

Net cash provided by operating activities was $3,748 million in 2006 compared to $2,818 million in 2005, an increase 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,

   

Collateral received by Duke Energy (approximately $540 million) in 2006 from Barclays, partially offset by

   

The settlement of the payable to Barclays (approximately $600 million) in 2006, and

   

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

Net cash provided by operating activities was $2,818 million in 2005 compared to $4,168 million in 2004, a decrease of $1,350 million. The decrease in cash provided by operating activities was due primarily to the following:

   

Approximately $750 million of additional net cash collateral posted by Duke Energy during 2005 attributable to increased crude oil prices, as well as increases to the forward market prices of power,

   

An approximate $900 million increase in taxes paid, net of refunds, in 2005, and,

 

   

The impacts of the deconsolidation of DEFS effective July 1, 2005.

These decreases were offset by an increase in cash provided due to an approximate $234 million decrease in contributions to company-sponsored pension plans in 2005.

 

Investing Cash Flows

Net cash used in investing activities was $1,328 million in 2006 compared to $126 million in 2005, an increase in cash used of $1,202 million. Net cash used in investing activities was $126 million in 2005 compared to $793 million in 2004, a decrease in cash used of $667 million.

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

 

Capital and Investment Expenditures by Business Segment

 

     Years Ended December 31,

     2006

   2005

   2004

     (in millions)

U.S. Franchised Electric and Gas(a)

   $ 2,381    $ 1,350    $ 1,126

Natural Gas Transmission

     790      930      544

Field Services(b)

          86      202

Commercial Power

     209      2      7

International Energy

     58      23      28

Crescent(c)(d)

     507      599      568

Other

     131      29      54
    

  

  

Total consolidated

   $ 4,076    $ 3,019    $ 2,529
    

  

  

 

(a) Amounts include capital expenditures associated with North Carolina clean-air legislation of $403 million in 2006, $310 million in 2005 and $106 million in 2004 which are included in Capital Expenditures within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows.
(b) As a result of the deconsolidation of DEFS, effective July 1, 2005, Field Services amounts for 2005 only include DEFS capital and investment expenditures for periods prior to July 1, 2005.
(c) Amounts include capital expenditures associated with residential real estate of $322 million for the period from January 1, 2006 through the date of deconsolidation (September 7, 2006), $355 million in 2005, and $322 million in 2004 which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows.
(d) As a result of the deconsolidation of Crescent, effective September 7, 2006, Crescent amounts for 2006 only include Crescent capital and investment expenditures for periods prior to September 7, 2006.

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, primarily 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,

 

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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 operations outside of the Midwestern United States, Cinergy’s commercial marketing and trading business operations, 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 DEFS disposition transaction.

The decrease in cash used in investing activities in 2005 as compared to 2004 is primarily due to the following:

   

An increase in proceeds from the sale of assets in 2005 as compared to 2004. Asset sales activity in 2005 of approximately $2.4 billion primarily involved the disposition of the investments in TEPPCO as well as the DEFS disposition transaction. Asset sales activity in 2004 of approximately $1.6 billion primarily involved the sales of the Asia-Pacific Business, Southeast Plants and Moapa and Luna partially completed facilities; and,

   

Decreased amounts of cash invested in short-term investments in 2005 as compared to 2004.

These decreases were partially offset by the following:

   

Increased capital and investment expenditures, excluding Crescent’s residential real estate investments, of $460 million primarily as a result of the approximate $230 million acquisition of the Empress System at Natural Gas Transmission and an increase in expenditures associated with North Carolina clean-air legislation.

 

Financing Cash Flows and Liquidity

Duke Energy’s consolidated capital structure as of December 31, 2006, including short-term debt, was 43% debt, 55% common equity and 2% minority interests. The fixed charges coverage ratio, calculated using SEC guidelines, was 3.2 times for 2006, which includes a pre-tax gain of approximately $250 million on the sale of an effective 50% interest in Crescent, 4.7 times for 2005, which includes a pre-tax gain on the sale of TEPPCO GP and LP of approximately $0.9 billion, net of minority interest, and 2.3 times for 2004.

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.

Net cash used in financing activities was $2,717 million in 2005 compared to $3,278 million in 2004, a decrease of $561 million. The change was due primarily to the following:

   

Approximately $3.0 billion of lower redemptions, net of paydowns, of long-term debt, commercial paper, notes payable, preferred and preference stock, and preferred stock of a subsidiary during 2005 as compared to 2004 as a result of an effort to reduce debt balances in 2004.

This decrease was partially offset by:

   

Approximately $2.6 billion of lower proceeds from common stock transactions during 2005, primarily driven by the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004 for total proceeds of $1.7 billion and the repurchase of 32.6 million shares of common stock for $933 million in 2005.

With cash, cash equivalents and short-term investments on hand at December 31, 2006 of approximately $2.5 billion and a more stable portfolio of businesses, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy is evaluating these options and will determine the best economic decision to meet the needs of shareholders and the long-term financial strength of Duke Energy.

 

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Significant Financing Activities—Year Ended 2006. During the year ended December 31, 2006, Duke Energy’s consolidated credit capacity increased by approximately $842 million, primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $590 million of other bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Energy’s reduced liquidity needs as a result of exiting the former DENA business.

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 has repurchased approximately 17.5 million shares of its common stock for approximately $500 million.

In November 2006, 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.

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.

During October 2006, the $130 million bi-lateral credit facility at Spectra Energy Capital was cancelled. In addition, the remaining $120 million bi-lateral credit facility was cancelled in November 2006 and reissued at Duke Energy for the same amount with the same terms and conditions.

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%.

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. As a result of the sale of additional Trust Units, Duke Energy recognized an approximate $15 million U.S. Dollar pre-tax SAB No. 51 gain on the sale of subsidiary stock. The proceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. Subsequent to this transaction, Duke Energy had an approximate 46% ownership interest in the Income Fund.

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

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

During the second, third and fourth quarters of 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold during each respective quarter. Holders of the convertible debt were able to exercise their right to convert on or prior to each quarter end. During the second and third quarters, approximately $632 million of debt was converted into approximately 26.7 million shares of Duke Energy Common Stock. At December 31, 2006, the balance of the convertible debt is approximately $110 million.

Significant Financing Activities—Year Ended 2005. In connection with the up to $2.5 billion share repurchase program announced in February 2005, Duke Energy entered into an accelerated share repurchase transaction. Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share (total of approximately $834 million, including approximately $10 million in commissions and other fees). The final settlement with the investment bank occurred on September 22, 2005 for approximately $25 million in cash. The final settlement price was the difference between the initial settlement price of $27.46 per share and the volume weighted average price per share of actual shares purchased by the investment bank of $28.42 per share. Duke Energy also entered into a separate open-market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of May 9, 2005 (the date Duke

 

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and Cinergy announced a merger agreement), Duke Energy had already repurchased 2.6 million shares of its common stock through the separate open-market purchase plan at a weighted average price of $28.97 per share. In May 2005, in connection with the anticipated merger with Cinergy, Duke Energy suspended additional repurchases under the open market purchase plan. For the year ended December 31, 2005 a total of 32.6 million shares of common stock were repurchased under both share repurchase programs for approximately $933 million.

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.

In November 2005, International Energy issued floating rate debt in Guatemala for $87 million (in USD) and in El Salvador for $75 million (in USD). 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%.

In August 2005, DEI 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.

During the first quarter of 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

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.

Preferred and Preference Stock of Duke Energy. 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.

Available Credit Facilities and Restrictive Debt Covenants. Duke Energy’s 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, 2006, 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.

(For information on Duke Energy’s credit facilities as of December 31, 2006, see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)

Credit Ratings. Duke Energy and certain subsidiaries each hold credit ratings by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s). In addition, certain subsidiaries transferred to Spectra Energy hold credit ratings by DBRS (formerly Dominion Bond Rating Service). Actions taken by ratings agencies subsequent to January 2, 2007 related to businesses transferred to Spectra Energy are not reflected herein since such actions have no impact on the ongoing operations of Duke Energy post spin-off.

In May 2006, S&P changed the outlook of Duke Energy and all of its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively M&N Pipeline) and DETM from stable to positive reflecting Duke Energy’s announcement to sell Cinergy’s commercial trading and marketing operations.

In April 2006, following the completion of Duke Energy’s merger with Cinergy, S&P removed Cinergy and its subsidiaries from credit-watch negative where they had been placed in May 2005 following the Cinergy merger announcement. S&P lowered Cinergy’s Corporate Credit Rating (CCR) consistent with Duke Energy’s CCR as disclosed in the table below. As a result of Cinergy’s lower CCR, S&P lowered the senior unsecured credit rating of Cinergy Corp. reflecting the structural subordination of its debt. In addition, S&P reassessed its view of the structural subordination for the debt outstanding at Spectra Energy Capital, Duke Energy Ohio, Duke Energy Indiana, and Duke Energy Kentucky and assigned the senior unsecured credit ratings at these entities equal to Duke Energy’s CCR. This resulted in the senior unsecured credit rating of Spectra Energy Capital being raised one ratings level to BBB and no changes to the senior unsecured

 

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ratings of Duke Energy Ohio, Duke Energy Indiana, and Duke Energy Kentucky as disclosed in the table below. At the same time, S&P assigned a senior unsecured credit rating to Duke Energy Carolinas equal to Duke Energy’s CCR and left the credit ratings of the Spectra Energy Capital subsidiaries (Texas Eastern Transmission, LP, Westcoast, Union Gas and M&N Pipeline) and DETM unchanged. At the completion of S&P’s April action, all the credit ratings were on stable outlook. S&P last affirmed its credit ratings for M&N Pipeline in July 2006 where they have remained unchanged with a stable outlook for the last several years.

In April 2006, upon Duke Energy’s completion of the merger with Cinergy, Moody’s upgraded the credit ratings of Duke Energy Carolinas (formerly rated as Duke Energy by Moody’s prior to the merger), Spectra Energy Capital and Texas Eastern Transmission, LP one ratings level each and assigned an issuer rating to New Duke Energy. The credit ratings resulting from the April action are as disclosed in the table below, except for businesses transferred to Spectra Energy entities as discussed above. The credit ratings of Spectra Energy Capital and Texas Eastern Transmission, LP were Baa2 and Baa1 respectively following Moody’s April action. Moody’s concluded their April action placing New Duke Energy and Duke Energy Carolinas on positive outlook and Spectra Energy Capital and Texas Eastern Transmission, LP on stable outlook. Moody’s also confirmed all of Cinergy and its subsidiaries credit ratings and changed the outlook to positive with the exception of Duke Energy Indiana, which was left on stable outlook. Moody’s noted in their April action the substantial reduction in business and operating risk of Duke Energy Carolinas from the distribution of its ownership in Spectra Energy Capital to a new holding company (New Duke Energy) and the substantial reduction in business and operating risk of Spectra Energy Capital through the restructuring of its ownership in DEFS and the divestiture of the former DENA merchant generation assets and trading book. Moody’s also noted the upgrade at Texas Eastern Transmission, LP in parallel to its parent Spectra Energy Capital.

In August 2005, Moody’s concluded a review of M&N Pipeline and downgraded the credit ratings one ratings level to A2 concluding this action with a stable outlook. Moody’s action was primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. In August 2006, Moody’s revised the outlook for Maritimes & Northeast Pipeline, LLC to negative, noting the potential for a somewhat weaker shipper profile resulting from a recently announced expansion project on the U.S. portion of the pipeline.

The most recent rating action by DBRS occurred in June 2006 when DBRS confirmed the stable trend of Westcoast, Union Gas and M&N Pipeline following Duke Energy’s announcement of the separation of the electric and gas businesses. Each of the credit ratings assigned by DBRS to these entities has remained unchanged for the last several years with a stable trend.

The following table summarizes the February 1, 2007 credit ratings from the agencies retained by Duke Energy, its principal funding subsidiaries and Duke Energy’s trading and marketing subsidiary DETM.

 

Credit Ratings Summary as of February 1, 2007

 

    

Standard

and
Poor’s


    

Moody’s
Investor

Service


Duke Energy(a)

   BBB      Baa2

Duke Energy Carolinas, LLC(b)

   BBB      A3

Cinergy(b)

   BBB-      Baa2

Duke Energy Ohio, Inc.(b)

   BBB      Baa1

Duke Energy Indiana, Inc.(b)

   BBB      Baa1

Duke Energy Kentucky, Inc.(b)

   BBB      Baa1

Duke Energy Trading and Marketing, LLC(c)

   BBB-      Not applicable

 

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

These entities credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, while maintaining the strength of their current balance sheets. These credit ratings could be negatively impacted if as a result of market conditions or other factors, these entities are unable to maintain their current balance sheet strength, or if earnings and cash flow outlook materially deteriorates.

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. On November 18, 2005, Duke Energy announced it signed an agreement to transfer substantially all of the former DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays acquired substantially all of former DENA’s outstanding gas and power derivatives contracts

 

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which essentially eliminated Duke Energy’s credit, collateral, market and legal risk associated with former DENA’s derivative trading positions effective on the date of signing. Substantially all of the underlying contracts have been transferred to Barclays.

Duke Energy operated a commercial marketing and trading business that was acquired as part of the merger with Cinergy in April 2006. In June 2006, Duke Energy announced it had reached an agreement to sell Cinergy’s commercial marketing and trading business, as well as associated contracts. The sale closed in October 2006 and, upon closing, the buyer assumed the credit, collateral, market and legal risk associated with the trading positions acquired.

A reduction in the credit rating of Duke Energy to below investment grade as of December 31, 2006 would have resulted in Duke Energy posting additional collateral of up to approximately $377 million, including impacts of Cinergy and excluding any collateral requirements associated with the spin-off of the natural gas businesses in January 2007. The majority of this collateral is related to outstanding surety bonds.

Duke Energy would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities. Additionally, if credit ratings for Duke Energy or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to fully quantify, in addition to the posting of additional collateral and segregation of cash described above.

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, 2006, Duke Energy had $13 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 $23 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. As of December 31, 2006, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $2,467 million in gross proceeds from debt and other securities, which include approximately $925 million of effective registrations at legacy Cinergy. Additionally, as of December 31, 2006, Duke Energy had 935 million Canadian dollars (approximately U.S. $807 million) available under Canadian shelf registrations for issuances in the Canadian market. Of the 935 million Canadian dollars available under Canadian shelf registrations, 500 million expires in May 2008 and 435 million expires in August 2008. Amounts available under U.S. and Canadian shelf registrations of approximately $592 million and 935 million Canadian dollars, respectively, relate to businesses included in the spin-off of the natural gas businesses on January 2, 2007 and, accordingly, are not available to Duke Energy subsequent to the consummation of the spin-off.

Duke Energy expects to continue its policy of paying regular cash dividends. There is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition. Duke Energy has paid quarterly cash dividends for 81 consecutive years. Dividends on common and preferred stocks in 2007 are expected to be paid on March 15, June 18, September 17 and December 17, subject to the discretion of the Board of Directors.

Prior to June 2004, Duke Energy’s Investor Direct Choice Plan allowed investors to reinvest dividends in common stock and to purchase common stock directly from Duke Energy. In June 2004, Duke Energy changed the method of dividend reinvestment to open market purchases. There were no issuances of common stock under the plan in either 2006 or 2005. Issuances of common stock under the plan were $36 million in 2004.

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy. There were no issuances of common stock under the plan in 2006 or 2005. Issuances of common stock under the plan were $51 million in 2004. Duke Energy also issues shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $126 million in 2006, approximately $39 million for 2005 and approximately $12 million for 2004.

 

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, debt guarantees, surety bonds and indemnifications. These arrangements are largely entered into by Duke Energy, Spectra Energy Capital and Cinergy. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.)

 

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

In contemplation of the spin-off of the natural gas businesses on January 2, 2007, certain guarantees that were previously 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 45 and, therefore, were not recognized in the Consolidated Balance Sheets. Guarantees issued by Spectra Energy Capital or Natural Gas Transmission 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.

Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky have an agreement to sell certain of their accounts receivable and related collections. Cinergy formed Cinergy Receivables to purchase, 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 does not consolidate Cinergy Receivables 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 our sales of accounts receivable, see Note 23 to the Consolidated Financial Statements, “Variable Interest Entities.”

Cinergy holds interests in variable interest entities (VIEs), consolidated and unconsolidated, as defined by FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.” For further information, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.

Duke Energy does not have any other material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee arrangements. (For additional information on these commitments, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies” and Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications.”)

 

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. The table below excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt, as well as future obligations of businesses included in the spin-off of Spectra Energy on January 2, 2007. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2007.

 

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Contractual Obligations as of December 31, 2006

 

     Payments Due By Period

     Total

  

Less than 1

year

(2007)


  

2-3 Years

(2008 &

2009)


  

4-5 Years

(2010 &

2011)


  

More than

5 Years

(Beyond

2012)


     (in millions)

Long-term debt(a)

   $ 17,879    $ 1,695    $ 3,504    $ 1,749    $ 10,931

Capital leases(a)

     113      15      36      25      37

Operating leases(b)

     522      86      150      101      185

Purchase Obligations:(g)

                                  

Firm capacity payments(c)

     51      18      18      15     

Energy commodity contracts(d)

     5,189      1,872      1,901      918      498

Other purchase obligations(e)

     2,065      912      778      39      336

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

     4,724      425      816      908      2,575
    

  

  

  

  

Total contractual cash obligations

   $ 30,543    $ 5,023    $ 7,203    $ 3,755    $ 14,562
    

  

  

  

  

 

(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount includes interest payments over life of debt or capital lease.
(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, refining 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. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2006. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties.
(e) Includes 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 nuclear plant refurbishments, environmental projects on fossil facilities, pipeline and real estate projects, and major maintenance of certain merchant plants. Amount excludes certain open purchase orders for services that are provided on demand, and the timing of the purchase can not be determined.
(f) Includes expected retirement plan contributions for 2007 (see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans”), certain estimated executive benefits, 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 $2,301 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,775 million at December 31, 2006. 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 22 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also amount 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. Liabilities Associated with Assets Held for Sale (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) are also excluded as Duke Energy expects these liabilities will be assumed by the buyer upon sale of the assets.
(g) Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table.

 

Quantitative and Qualitative Disclosures About Market Risk

 

Risk and Accounting 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 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.

See “Critical Accounting Policies—Risk Management Accounting and Revenue Recognition—Trading and Marketing Revenues” for further discussion of the accounting for derivative contracts.

Disclosures about market risks related to businesses transferred to Spectra Energy in January 2007 are not reflected herein since such exposures have no impact on the ongoing operations of Duke Energy post spin-off.

 

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Commodity Price Risk

Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy related assets. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including swaps, futures, forwards and options. (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 independent of 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 output and production of assets.

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. (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.”)

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, DIG Issue No. C15 and SFAS No. 149. 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 decisions in 2004 to sell former DENA Southeast Plants, reduce former DENA’s interest in partially completed plants and sale or disposition 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 MTM Model for these contracts and resulted in recording substantial unrealized losses that had not previously been recognized in the Consolidated Financial Statements.

Generation Portfolio Risks. Duke Energy is primarily exposed to market price fluctuations of wholesale power and natural gas 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. Modeled forecasts of future generation output, fuel requirements, and emission allowance requirements are based on forward power, fuel and emission allowance markets. The component pieces of the portfolio are bought and sold based on this model in order to manage the economic value of the portfolio, where such market transparency exists. The generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations. Based on a sensitivity analysis as of December 31, 2006 and 2005, it was estimated that a ten percent price change per mega-watt hour in wholesale power prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $30 million in 2007 and $20 million in 2006, respectively. Based on a sensitivity analysis as of December 31, 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 $15 million in 2007.

 

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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 is 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. Duke Energy has retained the Midwestern generation assets in the Commercial Power segment, representing approximately 3,600 megawatts of power generation (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions” for further details on the completed Cinergy merger).

Trading and Undesignated Contracts. The risk in the trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk (VaR) model to determine the potential one-day favorable or unfavorable VaR calculation. Duke Energy’s VaR amounts for commodity derivatives recorded using the MTM Model are not material as a result of management decisions to dispose of certain businesses with higher risk profiles, including the former DENA operations outside the Midwestern United States and the Cinergy commercial marketing and trading businesses. In connection with the effort to reduce the risk profile, during 2006 Duke Energy finalized the sale of the former DENA power generation fleet outside of the Midwest to LS Power and sold the Cinergy commercial marketing and trading business to Fortis. Subsequent to the sales of both trading businesses, Duke Energy no longer uses VaR as a trading portfolio measure.

Other Commodity Risks. Duke Energy, through Commercial Power, owns coal-based synthetic fuel production facilities which convert coal feedstock into synthetic fuel for sale to third parties. The synthetic fuel produced at these facilities qualifies for tax credits (through 2007) in accordance with Internal Revenue Code Section 29/45K if certain requirements are satisfied. The Internal Revenue Code provides for a phase-out of synthetic fuel tax credits if the average annual wellhead oil prices increase above certain levels. If Commercial Power were to operate its synthetic fuel facilities based on December 31, 2006 prices throughout the entire forthcoming year, yet crude oil prices were to rise such that the tax credit is completely phased-out, projected net income in 2007 would be negatively impacted by approximately $100 million. Duke Energy is unlikely to experience a loss of this magnitude because the exposure to synthetic fuel tax credit phase-out is monitored and Duke Energy may choose to reduce or cease synthetic fuel production depending on the expectation of any potential tax credit phase-out. Duke Energy may also reduce its exposure to crude prices through the execution of derivative transactions. The objective of these activities is to reduce potential losses incurred if the reference price in a year exceeds a level triggering a phase-out of synthetic fuel tax credits.

Pre-tax income for 2007 or 2006 was also not expected to be materially impacted as of December 31, 2006 or 2005 for exposures to other commodities’ price changes. These hypothetical 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.

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., Canada 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.

 

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The following table represents Duke Energy’s distribution of unsecured credit exposures at December 31, 2006, including Spectra Energy businesses. These credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are presented net of collateral, and take into account contractual netting rights.

 

Distribution of Enterprise Credit Exposures

As of December 31, 2006

 

     % of Total

 

Investment Grade—Externally Rated

   75 %

Non-Investment Grade—Externally Rated

   7  

Investment Grade—Internally Rated

   8  

Non-Investment Grade—Internally Rated

   10  
    

Total

   100 %
    

“Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally Rated” represents those relationships which have no rating by a major credit rating agency. For those relationships, Duke Energy utilizes appropriate risk rating methodologies and credit scoring models to develop an internal risk rating which is intended to map to an external rating equivalent. The total of the unsecured credit exposure included in the table above represents approximately 59% of the gross fair value of Duke Energy’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheets at December 31, 2006.

Duke Energy had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable and unrealized gains on mark-to-market and hedging transactions at December 31, 2006. Excluding the businesses transferred to Spectra Energy in January 2007, the split between investment grade and non-investment grade would have been approximately 70% and 30%, respectively. 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 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, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2006. 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.

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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Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and cover normal purchases and normal sales, hedging contracts, and optimization contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. If Duke Energy or its affiliates have a credit rating downgrade, it could result in reductions in Duke Energy’s unsecured thresholds granted by counterparties. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy and its affiliates. (See “Liquidity and Capital Resources—Financing Cash Flows and Liquidity” for additional discussion of downgrades.)

 

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 percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, 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, 2006, it was estimated that if market interest rates average 1% higher (lower) in 2007 than in 2006, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $3 million, excluding interest rate risk related to businesses transferred to Spectra Energy in January 2007. Comparatively, based on a sensitivity analysis as of December 31, 2005, 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 $9 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, 2006 and 2005. The decrease in interest rate sensitivity was primarily due to the exclusion of interest rate risk, principally subsidiary debt and swaps, related to businesses transferred to Spectra Energy. 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, 2006 and 2005, these funds were invested primarily in domestic and international equity securities, fixed-rate, fixed-income securities and cash and cash equivalents. 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 results of operations. Earnings or losses of the fund will ultimately impact the amount of costs recovered from 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’s costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans.

 

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. 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.

 

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In 2007, 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, 2006 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 $7 million to Duke Energy’s Consolidated Statements of Operations in 2007. The Consolidated Balance Sheet would be negatively impacted by approximately $120 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2006 as a result of a 10% devaluation in the currency exchange rates.

 

OTHER ISSUES

Spin-off of the Natural Gas Businesses. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The spin-off was effective January 2, 2007. The new natural gas company, which is named Spectra Energy, principally consists of Duke Energy’s Natural Gas Transmission business segment, which includes Union Gas, and also includes Duke Energy’s 50% ownership interest in DEFS. Approximately $20 billion of assets, $13 billion of liabilities (which includes approximately $8.6 billion of debt issued by Spectra Energy Capital and its consolidated subsidiaries) and $7 billion of common stockholders’ equity were distributed from Duke Energy as of the date of the spin-off. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. As a result of the spin-off transaction, on January 2, 2007, in lieu of adjusting the conversion ratio of the convertible debt, Duke Energy issued approximately 2.4 million shares of Spectra Energy common stock to holders of Duke Energy’s convertible senior notes due 2023, consistent with the terms of the debt agreements. The issuance of Spectra Energy shares to the convertible debt holders is expected to result in a pretax charge in the range of $20 million to $30 million in Duke Energy’s 2007 consolidated statement of operations. The historical results of the natural gas businesses are expected to be treated as discontinued operations at Duke Energy in future periods beginning with the first quarter of 2007. The primary businesses remaining in Duke Energy post-spin are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV. The decision to spin off the natural gas business is expected to deliver long-term value to shareholders.

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. FERC’s enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the Duke Energy and Cinergy merger, as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions.” 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. The greenhouse gas policy of the United States currently favors voluntary actions to reduce emissions and continued research and technology development over near-term mandatory greenhouse gas emission reduction requirements. Although several bills have been introduced in Congress that would mandate greenhouse gas emission reductions, none have advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. While it is possible 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. Several Northeastern states and California are in the process of developing their own mandatory greenhouse gas emission reduction programs; none of which will impact Duke Energy’s operations.

Duke Energy supports the enactment of U.S. federal legislation that would require a gradual transition to a lower carbon-intensive economy. Legislation preferably would be in the form of a federal-level carbon tax or cap-and-trade based program. Duke Energy, believing that it is in the best interest of its investors and customers to do so, is actively participating in the evolution of federal policy on this important issue.

Duke Energy’s proactive role in climate change policy debates in the United States does not change the uncertainty around such policy. Due to the speculative outlook regarding U.S. federal policy, Duke Energy cannot estimate the potential effect of future U.S. greenhouse gas policy on its future consolidated results of operations, cash flows or financial position. Duke Energy will assess and respond to the potential implications of U.S. greenhouse gas policy for its business operations if policy becomes sufficiently developed and certain to support a meaningful assessment.

 

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This disclosure related to the global climate change excludes developments in Canada due to the spin-off of Duke Energy’s natural gas businesses on January 2, 2007.

(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, 2006:

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

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

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. However, in some cases, the application of SFAS No. 157 may change Duke Energy’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Duke Energy, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. Duke Energy is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows 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 cannot currently estimate the impact of SFAS No. 159 on its consolidated results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Duke Energy has concluded there is a level of uncertainty with respect to the recognition in Duke Energy’s financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Duke Energy will implement FIN 48 effective January 1, 2007. The implementation is expected to result in a cumulative effect adjustment to beginning Retained Earnings on the Consolidated Statement of Common Stockholders’ Equity and Comprehensive Income (Loss) in the first quarter 2007 in the range of $15 million to $30 million. Corresponding entries will impact a variety of balance sheet line items, including Deferred Income Taxes, Taxes Accrued, Other Liabilities, and Goodwill. Upon implementation of FIN 48, Duke Energy will reflect interest expense related to taxes as Interest Expense, in the Consolidated Statement of Operations. In addition, subsequent accounting for FIN 48 (after January 1, 2007) will involve an evaluation to determine if any changes have occurred that would impact the existing uncertain tax positions as well as

 

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determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations, with offsetting impacts to the balance sheet line items described above. Because of the spin-off of Spectra Energy in the first quarter of 2007, certain liabilities and deferred tax assets related to uncertain tax positions filed on Spectra Energy tax returns will be removed from Duke Energy’s balance sheet. Uncertain tax positions on consolidated or combined tax returns filed by Duke Energy which are indemnified by Spectra Energy will be recorded as receivables from Spectra Energy.

FASB Staff Position (FSP) No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230—A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Duke Energy as of January 1, 2007. The impact to Duke Energy of applying FSP No. FAS 123(R)-5 in subsequent periods will be dependent upon the nature of any modifications to Duke Energy’s share-based compensation awards.

FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP AUG AIR-1). In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Duke Energy as of January 1, 2007 and will be applied and retrospectively for all financial statements presented. Duke Energy does not anticipate the adoption of FSP No. AUG AIR-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy does not anticipate the adoption of EITF No. 06-3 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance—Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4” (EITF No. 06-5). In June 2006, the EITF reached a consensus on the accounting for corporate-owned and bank-owned life insurance policies. EITF No. 06-5 requires that a policyholder consider the cash surrender value and any additional amounts to be received under the contractual terms of the policy in determining the amount that could be realized under the insurance contract. Amounts that are recoverable by the policyholder at the discretion of the insurance company must be excluded from the amount that could be realized. Fixed amounts that are recoverable by the policyholder in future periods in excess of one year from the surrender of the policy must be recognized at their present value. EITF No. 06-5 is effective for Duke Energy as of January 1, 2007 and must be applied as a change in accounting principle through a cumulative-effect adjustment to retained earnings or other components of equity as of January 1, 2007. Duke Energy does not anticipate the adoption of EITF No. 06-5 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-6, “Debtor's Accounting for a Modification (or Exchange) of Convertible Debt Instruments” (EITF No. 06-6). In November 2006, the EITF reached a consensus on EITF No. 06-6. EITF No. 06-6 addresses how a modification of a debt instrument (or

 

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an exchange of debt instruments) that affects the terms of an embedded conversion option should be considered in the issuer's analysis of whether debt extinguishment accounting should be applied, and further addresses the accounting for a modification of a debt instrument (or an exchange of debt instruments) that affects the terms of an embedded conversion option when extinguishment accounting is not applied. EITF No. 06-6 applies to modifications (or exchanges) occurring in interim or annual reporting periods beginning after November 29, 2006, regardless of when the instrument was originally issued. Early application is permitted for modifications (or exchanges) occurring in periods for which financial statements have not been issued. There were no modifications to, or exchanges of, any of Duke Energy’s debt instruments within the scope of EITF No. 06-6 in 2006. EITF No. 06-6 is effective for Duke Energy beginning January 1, 2007. The impact to Duke Energy of applying EITF No. 06-6 in subsequent periods will be dependent upon the nature of any modifications to, or exchanges of, any debt instruments within the scope of EITF No. 06-6. Refer to Note 15, “Debt and Credit Facilities.”

 

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:

 

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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.

As discussed in Note 1 to the consolidated financial statements, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans as a result of adopting Statement of Financial Accounting Standard No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.

As discussed in Notes 1 and 25 to the consolidated financial statements, the Company’s spin-off of the natural gas businesses was completed on January 2, 2007.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ DELOITTE & TOUCHE LLP

 

Charlotte, North Carolina

March 1, 2007

 

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DUKE ENERGY CORPORATION

Consolidated Statements of Operations

(In millions, except per-share amounts)

 

     Years Ended December 31,

 
     2006     2005     2004  

Operating Revenues

                        

Non-regulated electric, natural gas, natural gas liquids, and other

   $ 3,158     $ 7,212     $ 11,322  

Regulated electric

     7,678       5,406       5,041  

Regulated natural gas and natural gas liquids

     4,348       3,679       3,233  

Total operating revenues

     15,184       16,297       19,596  

Operating Expenses