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Duke Energy Corporation 10-K 2010
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, 2009 or

 

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

For the transition period from                      to                     

Commission file number 1-32853

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   20-2777218

(State or other jurisdiction of

incorporation or organization)

  (I.R.S. Employer Identification No.)
526 South Church Street, Charlotte, North Carolina   28202-1803
(Address of principal executive offices)   (Zip Code)

704-594-6200

(Registrant’s telephone number, including area code)

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

 

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

            Large accelerated filer x

  

Accelerated filer ¨

            Non-accelerated filer ¨

  

Smaller reporting company ¨

(Do not check if a smaller reporting company)

  

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x

 

Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at June 30, 2009

  
   $    18,836,000,000

Number of shares of Common Stock, $0.001 par value, outstanding at February 22, 2010.

  
   1,309,314,484


Table of Contents

TABLE OF CONTENTS

DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2009

 

Item

       Page

 

PART I.     
1.   BUSINESS    3
 

GENERAL

   3
 

U.S. FRANCHISED ELECTRIC AND GAS

   8
 

COMMERCIAL POWER

   17
 

INTERNATIONAL ENERGY

   21
 

OTHER

   22
 

ENVIRONMENTAL MATTERS

   22
 

GEOGRAPHIC REGIONS

   22
 

EMPLOYEES

   22
 

EXECUTIVE OFFICERS OF DUKE ENERGY

   22
1A.   RISK FACTORS    23
1B.   UNRESOLVED STAFF COMMENTS    27
2.   PROPERTIES    28
3.   LEGAL PROCEEDINGS    30
4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS    30
PART II.     
5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES    31
6.   SELECTED FINANCIAL DATA    33
7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    35
7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    64
8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA    65
9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE    154
9A.   CONTROLS AND PROCEDURES    154
PART III.     
10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE    155
11.   EXECUTIVE COMPENSATION    155
12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS    155
13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE    155
14.   PRINCIPAL ACCOUNTING FEES AND SERVICES    155
PART IV.     
15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES    156
  SIGNATURES    157
  EXHIBIT INDEX    E-1

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” “target,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

 

   

State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, as well as rulings that affect cost and investment recovery or have an impact on rate structures;

 

   

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

 

   

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

 

   

Additional competition in electric markets and continued industry consolidation;

 

   

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

 

   

The influence of weather and other natural phenomena on Duke Energy’s operations, including the economic, operational and other effects of storms, hurricanes, droughts and tornados;

 

   

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

 

   

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

 

   

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

 

   

The results of financing efforts, including Duke Energy’s ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Energy’s credit ratings and general economic conditions;

 

   

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

 

   

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

 

   

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

 

   

Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop domestic and international power and other projects;

 

   

Construction and development risks associated with the completion of Duke Energy’s capital investment projects in existing and new generation facilities, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards, as well as the ability to recover costs from customers in a timely manner or at all;

 

   

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

 

   

The ability to successfully complete merger, acquisition or divestiture plans.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.



Table of Contents

PART I

Item 1. Business.

GENERAL

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

Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy, for purposes of this discussion regarding the merger). In the second quarter of 2006, Duke Energy and Cinergy Corp. (Cinergy) consummated a merger which combined the Duke Energy and Cinergy regulated franchises, as well as deregulated generation in the Midwestern United States. On April 3, 2006, in accordance with the merger agreement, Old Duke Energy and Cinergy merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). As a result of the merger transaction, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares of Duke Energy common stock. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, named Spectra Energy Corp. (Spectra Energy), including its wholly-owned subsidiary Spectra Energy Capital, LLC (Spectra Energy Capital, formerly Duke Capital LLC). The natural gas businesses spun off primarily consisted of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DCP Midstream, LLC (DCP Midstream, formerly Duke Energy Field Services, LLC), which was part of the Field Services business segment.

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former Duke Energy North America’s (DENA) remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006. Certain assets of the former DENA business were transferred to the Commercial Power business segment and certain operations that Duke Energy continues to wind-down are in Other.

Business Segments. At December 31, 2009, Duke Energy operated the following business segments, all of which are considered reportable segments under the applicable accounting rules: U.S. Franchised Electric and Gas, Commercial Power and International Energy. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business segments in deciding how to allocate resources and evaluate performance. For additional information on each of these business segments, including financial and geographic information about each reportable business segment, see Note 2 to the Consolidated Financial Statements, “Business Segments.”

The following is a brief description of the nature of operations of each of Duke Energy’s reportable business segments, as well as Other.

U.S. Franchised Electric and Gas. U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, southwestern Ohio, central, north central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, LLC (Duke Energy Carolinas), the regulated transmission and distribution operations of Duke Energy Ohio, Inc. (Duke Energy Ohio), Duke Energy Indiana, Inc. (Duke Energy Indiana) and Duke Energy Kentucky, Inc. (Duke Energy Kentucky). These electric and gas operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC), the Public Utilities Commission of Ohio (PUCO), the Indiana Utility Regulatory Commission (IURC) and the Kentucky Public Service Commission (KPSC). The substantial majority of U.S. Franchised Electric and Gas’ operations are regulated and, accordingly, these operations qualify for regulatory accounting treatment.

Commercial Power. Commercial Power owns, operates and manages power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power’s generation operations in the Midwest consist of generation assets located in Ohio, acquired from Cinergy in April 2006, which are dedicated under the Electric Security Plan (ESP), and the five Midwestern gas-fired non-regulated generation assets that were a portion of the former DENA operations, which are dispatched into wholesale markets. Commercial Power’s assets, excluding wind energy generation assets, comprise approximately 7,550 net megawatts (MW) of power generation primarily located in the Midwestern U.S. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Effective January 1, 2009, approximately half of Commercial Power’s Ohio-based generation assets operate under an ESP, which expires on December 31, 2011. Prior to the ESP, these generation assets had been contracted through the Rate Stabilization Plan (RSP), which expired on December 31, 2008. As a result of the approval of the ESP, certain of Commercial Power’s operations qualified for regulatory accounting treatment effective December 17, 2008. For more information on the RSP and ESP, as well as the reapplication of regulatory accounting to certain of its operations, see the “Commercial Power” section below. Commercial Power also has a retail sales subsidiary, Duke Energy Retail Sales (DERS), which is certified by the PUCO as a Competitive Retail Electric Service (CRES) provider in Ohio. DERS serves retail electric customers in Southwest, West Central and Northern Ohio with generation and other energy services at competitive rates. During 2009, due to increased levels of customer switching as a result of the competitive markets in Ohio, DERS has focused on acquiring customers that had previously been served by Duke Energy Ohio under the ESP, as well as those previously served by other Ohio franchised utilities. Through Duke Energy Generation Services, Inc. and its affiliates (DEGS), Commercial Power develops, owns and operates electric generation for large energy consumers, municipalities, utilities and industrial facilities. DEGS currently manages 6,150 MW of power generation at 21 facilities throughout the U.S. In addition, DEGS engages in the development, construction and operation of wind energy projects. Currently, DEGS has over 5,000 MW of wind energy projects in the development pipeline with approximately 735 net MW of wind generating capacity in operation as of December 31, 2009. DEGS is also developing transmission, solar and biomass projects.

International Energy. International Energy principally owns, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through Duke Energy International, LLC (DEI) and its affiliates and its activities target power generation in Latin America. Through its wholly-owned subsidiary Aguaytia Energy del Perú S.R.L. Ltda. (Aguaytia) and its equity method investment in National Methanol Company (NMC), which is located in Saudi Arabia, International Energy also engages in the production of natural liquid gas and methanol and methyl tertiary butyl ether (MTBE). Additionally, International Energy had an equity method investment in Attiki Gas Supply S.A. (Attiki), a natural gas distributor in Greece, which it decided to abandon, along with the related non-recourse debt, in December 2009.

 

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Other. The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned captive insurance subsidiary, Duke Energy’s effective 50% interest in the Crescent JV (Crescent) and DukeNet Communications, LLC (DukeNet) and related telecom businesses. Additionally, Other includes the remaining portion of Duke Energy’s business formerly known as DENA that was not exited or transferred to Commercial Power, primarily Duke Energy Trading and Marketing, LLC (DETM), which is 60% owned by Duke Energy and 40% owned by Exxon Mobil Corporation and management is currently in the process of winding down.

Unallocated corporate costs include certain costs not allocable to Duke Energy’s reportable business segments, primarily governance costs, costs to achieve mergers and divestitures (such as the Cinergy merger and spin-off of Spectra Energy) and costs associated with certain corporate severance programs. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. Crescent, which develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern U.S, filed Chapter 11 petitions in a U.S. Bankruptcy Court in June 2009. As a result of recording its proportionate share of impairment charges recorded by Crescent during 2008, the carrying value of Duke Energy’s investment balance in Crescent is zero and Duke Energy discontinued applying the equity method of accounting to its investment in Crescent in the third quarter of 2008 and has not recorded its proportionate share of any Crescent earnings or losses since the third quarter of 2008. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Southeast U.S., serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations.

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

GLOSSARY OF TERMS

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

 

Term or Acronym    Definition
AAC    Annually Adjusted Component
ADEA    Age Discrimination in Employment
AEP    American Electric Power Company, Inc.
AFUDC    Allowance for Funds Used During Construction
Aguaytia    Aguaytia Energy del Perú S.R.L. Ltda.
ANEEL    Brazilian Electricity Regulatory Agency
AOCI    Accumulated Other Comprehensive Income
ASC    Accounting Standards Codification
ASU    Accounting Standards Update
Attiki    Attiki Gas Supply S.A.
Bison    Bison Insurance Company Limited
BPM    Bulk Power Marketing
CAA    Clean Air Act
CAIR    Clean Air Interstate Rule
Catamount    Catamount Energy Corporation
CC    Combined Cycle
Cinergy Receivables    Cinergy Receivables Company, LLC

 

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Term or Acronym    Definition
CMP    Central Maine Power Company
CT    Combustion Turbine
Cinergy    Cinergy Corp.
CO2    Carbon Dioxide
COL    Combined Construction and Operating License
CPCN    Certificate of Public Convenience and Necessity
Crescent    Crescent JV
CWIP    Construction Work-in-Progress
DAQ    Division of Air Quality
DB    Defined Benefit Pension Plan
DCP Midstream    DCP Midstream, LLC (formerly Duke Energy Field Services, LLC)
DECE    Duke Energy Commercial Enterprises, Inc.
DEGS    Duke Energy Generation Services, Inc.
DEI    Duke Energy International, LLC
DEIGP    Duke Energy International Geracao Paranapenema S.A.
DENA    Duke Energy North America
DENR    Department of Environment and Natural Resources
DERF    Duke Energy Receivables Finance Company, LLC
DERS    Duke Energy Retail Sales
DETM    Duke Energy Trading and Marketing, LLC
DOE    Department of Energy
DRIP    Dividend Reinvestment Plan
DSM    Demand Side Management
Duke Energy    Duke Energy Corporation (collectively with its subsidiaries)
Duke Energy Carolinas    Duke Energy Carolinas, LLC
Duke Energy Indiana    Duke Energy Indiana, Inc.
Duke Energy Kentucky    Duke Energy Kentucky, Inc.
Duke Energy Ohio    Duke Energy Ohio, Inc.
EPA    Environmental Protection Agency
EPS    Earnings Per Share
ERISA    Employee Retirement Income Security Act

 

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Term or Acronym    Definition
ESP    Electric Security Plan
EWG    Exempt Wholesale Generator
FASB    Financial Accounting Standards Board
FERC    Federal Energy Regulatory Commission
FPP    Fuel and Purchased Power
GAAP    Generally Accepted Accounting Principles in the United States
GWh    Gigawatt-hours
HAP    Hazardous Air Pollutant
IGCC    Integrated Gasification Combined Cycle
IMPA    Indiana Municipal Power Agency
ITC    Investment Tax Credit
IURC    Indiana Utility Regulatory Commission
KPSC    Kentucky Public Service Commission
KV    Kilovolt
kWh    Kilowatt-hour
LIBOR    London Interbank Offered Rate
MACT    Maximum achievable control technology
Mcf    Thousand cubic feet
Midwest ISO    Midwest Independent Transmission System Operator, Inc.
MMBtu    Million British Thermal Unit
Moody’s    Moody’s Investor Services
MRO    Market Rate Option
MTBE    Methyl tertiary butyl ether
MW    Megawatt
MWh    Megawatt-hour
NCUC    North Carolina Utilities Commission
NDTF    Nuclear Decommissioning Trust Funds
NEIL    Nuclear Electric Insurance Limited
NMC    National Methanol Company
NOx    Nitrogen oxide
NPNS    Normal purchase/normal sale

 

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Term or Acronym    Definition
NRC    Nuclear Regulatory Commission
NSR    New Source Review
OCC    Office of the Ohio Consumers’ Counsel
ORS    South Carolina Office of Regulatory Staff
OUCC    Indiana Office of Utility Consumer Counselor
Pioneer Transmission    Pioneer Transmission, LLC
PSCSC    Public Service Commission of South Carolina
PUCO    Public Utilities Commission of Ohio
PUHCA    Public Utility Holding Company Act of 1935, as amended
QSPE    Qualifying Special Purpose Entity
REPS    Renewable Energy and Energy Efficiency Portfolio Standard
RICO    Racketeer Influenced and Corrupt Organizations
RSP    Rate Stabilization Plan
RTO    Regional Transmission Organization
SB 221    Ohio Senate Bill 221
SCEUC    South Carolina Energy Users Committee
sEnergy    sEnergy Insurance Limited
SEC    Securities and Exchange Commission
SHGP    South Houston Green Power, L.P.
SO2    Sulfur dioxide
SPE    Special Purpose Entity
Spectra Energy    Spectra Energy Corp.
Spectra Capital    Spectra Energy Capital, LLC (formerly Duke Capital LLC)
S&P    Standard & Poor’s
Stimulus Bill    The American Recovery and Reinvestment Act of 2009
Synfuel    Synthetic Fuel
VDEQ    Virginia Department of Environmental Quality
VIE    Variable Interest Entity
WACC    Weighted Average Cost of Capital
WARN    North Carolina Waste Awareness Reduction Network

 

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

The following sections describe the business and operations of each of Duke Energy’s reportable business segments, as well as Other. (For more information on the operating outlook of Duke Energy and its reportable segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Introduction—Executive Overview and Economic Factors for Duke Energy’s Business”. For financial information on Duke Energy’s reportable business segments, see Note 2 to the Consolidated Financial Statements, “Business Segments.”)

U.S. FRANCHISED ELECTRIC AND GAS

Service Area and Customers

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity and transports and sells natural gas. It conducts operations primarily through Duke Energy Carolinas, the regulated transmission and distribution operations of Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky collectively referred to as Duke Energy Midwest). Its service area covers about 50,000 square miles with an estimated population of 11 million in central and western North Carolina, western South Carolina, southwestern Ohio, central, north central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas supplies electric service to approximately 4 million residential, commercial and industrial customers over 151,600 miles of distribution lines and a 20,900 mile transmission system. U.S. Franchised Electric and Gas provides domestic regulated transmission and distribution services for natural gas to approximately 500,000 customers in southwestern Ohio and northern Kentucky via approximately 7,200 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and approximately 6,000 miles of service lines. Electricity is also sold wholesale to incorporated municipalities and to public and private utilities. In addition, municipal and cooperative customers who purchased portions of the power generated by the Catawba Nuclear Station may also buy power from a variety of suppliers, including Duke Energy Carolinas, through contractual agreements. For more information on the Catawba Nuclear Station joint ownership, see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating and Transmission Facilities.”

Duke Energy Carolinas’ service area has a diversified commercial and industrial presence. Manufacturing continues to be one of the largest contributors to the economy in the region. Other sectors such as finance, insurance, real estate services, and local government also constitute key components of the states’ gross domestic product. Chemicals, rubber and plastics, textile and motor vehicle manufacturing industries were among the most significant contributors to the Duke Energy Carolinas’ industrial sales.

Duke Energy Ohio’s and Duke Energy Kentucky’s service area both have a diversified commercial and industrial presence. Major components of the economy include manufacturing, real estate and rental leasing, wholesale trade, financial and insurance services, retail trade, education, healthcare and professional/business services.

The primary metals industry, transportation equipment, chemicals, and paper and plastics were the most significant contributors to the area’s manufacturing output and Duke Energy Ohio’s and Duke Energy Kentucky’s industrial sales revenue for 2009. Food and beverage manufacturing, fabricated metals, and electronics also have a strong impact on the area’s economic growth and the region’s industrial sales.

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

The number of residential and general service customers within the U.S. Franchised Electric and Gas’ service territory, as well as sales to these customers, is expected to increase over time. However, growth in the near-term is being hampered by the current economic conditions. Industrial sales declined in 2009 when compared to 2008. While the decline in the sales volumes to industrial customers began to stabilize in the second half of 2009, the level of sales to industrial customers is expected to remain a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales in the foreseeable future.

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

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

 

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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 owned capacity of 5,173 MW (including Duke Energy’s approximate 19% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with an overall combined owned capacity of 13,189 MW (including Duke Energy’s 69% ownership in the East Bend Steam Station and 50.05% ownership in Unit 5 of the Gibson Steam Station), thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined owned capacity of 3,263 MW, fifteen combustion turbine (CT) stations burning natural gas, oil or other fuels with an overall combined owned capacity of 5,047 MW and one combined cycle (CC) station burning natural gas with an owned capacity of 285 MW. Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Factors that could cause U.S. Franchised Electric and Gas to purchase power for its customers include generating plant outages, extreme weather conditions, generation reliability during the summer, growth, and price. U.S. Franchised Electric and Gas has interconnections and arrangements with its neighboring utilities to facilitate planning, emergency assistance, sale and purchase of capacity and energy, and reliability of power supply.

U.S. Franchised Electric and Gas’ generation portfolio is a balanced mix of energy resources having different operating characteristics and fuel sources designed to provide energy at the lowest possible cost to meet its obligation to serve native-load customers. All options, including owned generation resources and purchased power opportunities, are continually evaluated on a real-time basis to select and dispatch the lowest-cost resources available to meet system load requirements. The vast majority of customer energy needs are met by large, low-energy-production-cost nuclear and coal-fired generating units that operate almost continuously (or at baseload levels). In 2009, approximately 98.1% of the total generated energy came from U.S. Franchised Electric and Gas’ low-cost, efficient nuclear and coal units (59.6% coal and 38.5% nuclear). The remaining energy needs were supplied by hydroelectric, CT and CC generation or economic purchases from the wholesale market.

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

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

U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territories. Long-term projections indicate a need for capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC), coal facilities or gas-fired generation units. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. Significant current or potential future capital projects are discussed below.

 

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South Carolina passed new energy legislation South Carolina Senate Bill 431 (S 431) which became effective May 3, 2007. This legislation includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear baseload generation in rates during construction through a rider. The North Carolina General Assembly also passed comprehensive energy legislation North Carolina Senate Bill 3 (SB 3) in July 2007 that was signed into law by the Governor on August 20, 2007. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance, subject to prudency review, for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to construction work in progress for baseload plants in a rate case.

William States Lee III Nuclear Station. On December 12, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC), which has been docketed for review, for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station at a site in Cherokee County, South Carolina. Each reactor is capable of producing approximately 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. The NRC review of the COL application continues and the estimated receipt of the COL is in mid 2013. Duke Energy Carolinas filed with the U.S. Department of Energy (DOE) for a federal loan guarantee, which has the potential to significantly lower financing costs associated with the proposed William States Lee III Nuclear Station; however, it was not among the four projects selected by the DOE for the final phase of due diligence for the federal loan guarantee program. The project could be selected in the future if the program funding is expanded or if any of the current finalists drop out of the program.

Cliffside Unit 6. On June 2, 2006, Duke Energy Carolinas filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. On March 21, 2007, the NCUC issued an Order allowing Duke Energy Carolinas to build one 800 MW unit. On February 20, 2008, Duke Energy Carolinas entered into an amended and restated engineering, procurement, construction and commissioning services agreement, valued at approximately $1.3 billion, with an affiliate of The Shaw Group, Inc., of which approximately $950 million relates to participation in the construction of Cliffside Unit 6, with the remainder related to a flue gas desulfurization system on an existing unit at Cliffside. On February 27, 2009, Duke Energy Carolinas filed its latest updated cost estimate of $1.8 billion (excluding up to approximately $0.6 billion of allowance for funds used during construction (AFUDC)) for the approved new Cliffside Unit 6. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $125 million in federal advanced clean coal tax credits. Construction of Cliffside Unit 6 is underway and is approximately 55% complete as of December 31, 2009.

Dan River and Buck Combined Cycle Facilities. On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 620 MW combined cycle natural gas-fired generating facility at its existing Dan River Steam Station, as well as updated preliminary CPCN information to construct a 620 MW combined cycle natural gas-fired generating facility at its existing Buck Steam Station. On December 14, 2007, Duke Energy Carolinas filed CPCN applications for the two combined cycle facilities. The NCUC consolidated its consideration of the two CPCN applications and held an evidentiary hearing on the applications on March 11, 2008. On May 5, 2008, Duke Energy Carolinas entered into an engineering, construction and commissioning services agreement for the Buck combined cycle project, valued at approximately $275 million, with Shaw North Carolina, Inc. On November 5, 2008, Duke Energy Carolinas notified the NCUC that since the issuance of the CPCN Order, recent economic factors have caused increased uncertainty with regard to forecasted load and near-term capital expenditures, resulting in a modification of the construction schedule. On September 1, 2009, Duke Energy Carolinas filed with the NCUC further information clarifying the construction schedule for the two projects. Under the revised schedule, the Buck Project is expected to begin operation in combined cycle mode by the end of 2011, but without a phased-in simple cycle commercial operation. The Dan River Project is expected to begin operation in combined cycle mode by the end of 2012, also without a phased-in simple cycle commercial operation. On December 21, 2009, Duke Energy Carolinas entered into a First Amended and Restated engineering, construction and commissioning services agreement with Shaw North Carolina, Inc. for $322 million which reflects the revised schedule. Based on the most updated cost estimates, total costs (including AFUDC) for the Buck and Dan River projects are approximately $660 million and $710 million, respectively.

On October 15, 2008, the Division of Air Quality (DAQ) issued a final air construction permit authorizing construction of the Buck combined cycle natural gas-fired generating units, and on August 24, 2009, the DAQ issued a final air permit authorizing construction of the Dan River combined cycle natural gas-fired generation units.

Edwardsport IGCC. On September 7, 2006, Duke Energy Indiana and Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana (Vectren) filed a joint petition with the IURC seeking a CPCN for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. The facility was initially estimated to cost approximately $2 billion (including approximately $120 million of AFUDC). In August 2007, Vectren formally withdrew its participation in the IGCC plant and a hearing was conducted on the CPCN petition based on Duke Energy Indiana owning 100% of the project. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana a CPCN for the proposed IGCC Project, approved the cost estimate of $1.985 billion and approved the timely recovery of costs related to the project. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management.

On May 1, 2008, Duke Energy Indiana filed its first semi-annual IGCC Rider and ongoing review proceeding with the IURC as required under the CPCN Order issued by the IURC. In its filing, Duke Energy Indiana requested approval of a new cost estimate for the IGCC Project of $2.35 billion (including approximately $125 million of AFUDC) and for approval of plans to study carbon capture as required by the IURC’s CPCN Order. On January 7, 2009, the IURC approved Duke Energy Indiana’s request, including the new cost estimate of $2.35 billion, and cost recovery associated with a study on carbon capture. Duke Energy Indiana was required to file its plans for studying carbon storage related to the project within 60 days of the order. On November 3, 2008 and May 1, 2009, Duke Energy Indiana filed its second and third semi-annual IGCC riders, respectively, both of which were approved by the IURC in full.

On November 24, 2009, Duke Energy Indiana filed a petition for its fourth semi-annual IGCC rider and ongoing review proceeding with the IURC. Duke Energy has experienced design modifications and scope growth above what was anticipated from the preliminary engineering design, adding capital costs to the IGCC project. Duke Energy Indiana forecasted that the additional capital cost items would use the remaining contingency and escalation amounts in the current $2.35 billion cost estimate and add approximately $150 million, or about 6.4% to the total IGCC Project cost estimate, excluding the impact associated with the need to add more contingency. Duke Energy Indiana did not request approval of an increased cost estimate in the fourth semi-annual update proceeding; rather, Duke Energy Indiana requested the IURC to establish a subdocket proceeding in which Duke Energy will present additional evidence regarding an updated estimated cost for the IGCC project and in which a more comprehensive review of the IGCC project could occur. On January 27, 2010, the IURC approved Duke Energy Indiana’s request for a subdocket proceeding regarding the cost estimate issues and accepted procedural schedules for the fourth semi-annual update proceeding and the subdocket proceeding. The evidentiary hearing for the fourth semi-annual update proceeding is scheduled for April 6, 2010. In the cost estimate subdocket proceeding, Duke Energy Indiana will be filing a new cost estimate for the IGCC project on April 7, 2010, with its case-in-chief testimony, and a hearing is scheduled to begin August 10, 2010. Duke Energy Indiana continues to work with its

 

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vendors to update and refine the forecasted increased cost to complete the Edwardsport IGCC project, and currently anticipates that the total cost increase it submits in the cost estimate subdocket proceeding will be significantly higher than the $150 million previously identified.

Duke Energy Indiana filed a petition with the IURC requesting approval of its plans for studying carbon storage, sequestration and/or enhanced oil recovery for the carbon dioxide (CO2) from the Edwardsport IGCC facility on March 6, 2009. On July 7, 2009, Duke Energy Indiana filed its case-in-chief testimony requesting approval for cost recovery of a $121 million site assessment and characterization plan for CO2 sequestration options including deep saline sequestration, depleted oil and gas sequestration and enhanced oil recovery for the CO2 from the Edwardsport IGCC facility. The Indiana Office of Utility Consumer Counselor (OUCC) filed testimony supportive of the continuing study of carbon storage, but recommended that Duke Energy Indiana break its plan into phases, recommending approval of only approximately $33 million in expenditures at this time and deferral of expenditures rather than cost recovery through a tracking mechanism as proposed by Duke Energy Indiana. Intervenor CAC recommended against approval of the carbon storage plan stating customers should not be required to pay for research and development costs. Duke Energy Indiana’s rebuttal testimony was filed October 30, 2009, wherein it amended its request to seek deferral of approximately $42 million to cover the carbon storage site assessment and characterization activities scheduled to occur through approximately the end of 2010, with further required study expenditures subject to future IURC proceedings. An evidentiary hearing was held on November 9, 2009, and an order is expected in the first half of 2010.

Under the Edwardsport IGCC CPCN order and statutory provisions, Duke Energy Indiana is entitled to recover the costs reasonably incurred in reliance on the CPCN Order. In December 2008, Duke Energy Indiana entered into a $200 million engineering, procurement and construction management agreement with Bechtel Power Corporation. Construction of Edwardsport is underway and is approximately 50% complete as of December 31, 2009.

See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for further discussion on the above in-process or potential construction projects.

Fuel Supply

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

 

     Generation by Source
(Percent)

 

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

 

     

 

2009

 

  

2008

 

  

2007

 

  

2009

 

  

2008    

 

  

2007  

 

Coal(a)

   59.6        66.9         66.5    2.88    2.59          2.20    

Nuclear(b)

   38.5        32.1         31.2    0.48    0.44          0.38    

Oil and gas(c)

   0.4        0.7         1.1    7.71    13.47          9.32    
                       

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

   98.5        99.7         98.8    1.96    1.97          1.71    

Hydroelectric(d)

   1.5        0.3         1.2         
                       
   100.0        100.0         100.0         
                       

 

(a) Statistics related to coal generation and all fuels reflect U.S. Franchised Electric and Gas’ 69% ownership interest in the East Bend Steam Station and 50.05% ownership interest in Unit 5 of the Gibson Steam Station.
(b) Statistics related to nuclear generation and all fuels reflect U.S. Franchised Electric and Gas’ 12.5% interest in the Catawba Nuclear Station through September 30, 2008 and an approximate 19% ownership interest in the Catawba Nuclear Station from October 1, 2008 and thereafter.
(c) Cost statistics include amounts for light-off fuel at U.S. Franchised Electric and Gas’ coal-fired stations.
(d) Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.

Coal. U.S. Franchised Electric and Gas meets its coal demand in the Carolinas and Midwest through a portfolio of purchase supply contracts and spot agreements. Large amounts of coal are purchased under supply contracts with mining operators who mine both underground and at the surface. U.S. Franchised Electric and Gas uses spot-market purchases to meet coal requirements not met by supply contracts. Expiration dates for its supply contracts, which have various price adjustment provisions and market re-openers, range from 2010 to 2014. U.S. Franchised Electric and Gas expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required as existing contracts expire, though prices will fluctuate over time as coal markets change. The coal purchased for the Carolinas is primarily produced from mines in eastern Kentucky, West Virginia and southwestern Virginia. The coal purchased for the regulated Midwest entities is primarily produced in Indiana, Illinois, and Kentucky. U.S. Franchised Electric and Gas has an adequate supply of coal under contract to fuel its projected 2010 operations and a significant portion of supply to fuel its projected 2011 operations.

The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Carolinas is approximately 1%; however, as Carolinas coal plants continue to bring on scrubbers over the next several years, the sulfur content of coal purchased could increase as higher sulfur coal options are considered. The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Midwest is approximately 2%. Coupled with the use of available sulfur dioxide (SO2) emission allowances on the open market, this satisfies the current emission limitations for SO2 for existing facilities in the Carolinas and Midwest.

Gas. U.S. Franchised Electric and Gas is responsible for the purchase and the subsequent delivery of natural gas to native load customers in its Ohio and Kentucky service territories. U.S. Franchised Electric and Gas’ natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows U.S. Franchised Electric and Gas to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides U.S. Franchised Electric and Gas the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under U.S. Franchised Electric and Gas’ customer choice/gas transportation programs. In 2009, firm supply purchase commitment agreements provided approximately 99% of the natural gas supply, with the remaining gas purchased on the spot market. These firm supply agreements feature two levels of gas supply, specifically (1) base load, which is a continuous supply to meet normal demand requirements, and (2) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.

 

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U.S. Franchised Electric and Gas also owns two underground caverns with a total storage capacity of approximately 16 million gallons of liquid propane. In addition, U.S. Franchised Electric and Gas has access to 5.5 million gallons of liquid propane storage and product loan through a commercial services agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

U.S. Franchised Electric and Gas manages natural gas procurement-price volatility mitigation programs for Duke Energy Ohio and Duke Energy Kentucky. These programs pre-arrange between 10-25% of total winter heating season gas requirements for Duke Energy Ohio, between 10-35% of total winter heating season gas requirements for Duke Energy Kentucky and between 10-50% of total summer season gas requirements for both Duke Energy Ohio and Duke Energy Kentucky for up to three years in advance of the delivery month. Duke Energy Ohio and Duke Energy Kentucky use primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2009, Duke Energy Ohio and Duke Energy Kentucky, combined, had locked in pricing for approximately 22% of their winter 2009/2010 system load requirements.

U.S. Franchised Electric and Gas is also responsible for the purchase and the subsequent delivery of natural gas to the gas turbine generators to serve native electric load customers in the Duke Energy Carolinas, Duke Energy Indiana and Duke Energy Kentucky service territories. The natural gas procurement strategy is to contract with one or several suppliers who buy spot market natural gas supplies along with firm or interruptible interstate pipeline transportation capacity for deliveries to the site. This strategy allows for competitive pricing, flexibility of delivery, and reliable natural gas supplies to each of the natural gas plants. Many of the natural gas plants can be served by several supply zones and multiple pipelines.

Duke Energy Indiana hedges a percentage of its winter and summer expected native gas burn from Indiana gas turbine units using financial swaps tied to the New York Mercantile Exchange (NYMEX)-Henry Hub natural gas futures.

Nuclear. The industrial processes for producing nuclear generating fuel generally involve the mining and milling of uranium ore to produce uranium concentrates, the services to convert uranium concentrates to uranium hexafluoride, the services to enrich the uranium hexafluoride, and the services to fabricate the enriched uranium hexafluoride into usable fuel assemblies.

Duke Energy Carolinas has contracted for uranium materials and services to fuel the Oconee, McGuire and Catawba Nuclear Stations in the Carolinas. Uranium concentrates, conversion services and enrichment services are primarily met through a diversified portfolio of long-term supply contracts. The contracts are diversified by supplier, country of origin and pricing. Duke Energy Carolinas staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements at Oconee, McGuire and Catawba in the near-term and decreasing portions of its fuel requirements over time thereafter. Due to the technical complexities of changing suppliers of fuel fabrication services, Duke Energy Carolinas generally sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

Duke Energy Carolinas has entered into fuel contracts that, based on its current need projections, cover 100% of the uranium concentrates, conversion services, and enrichment services requirements of the Oconee, McGuire and Catawba Nuclear Stations through at least 2011 and cover fabrication services requirements for these plants through at least 2018. For subsequent years, a portion of the fuel requirements at Oconee, McGuire and Catawba are covered by long-term contracts. For future requirements not already covered under long-term contracts, Duke Energy Carolinas believes it will be able to renew contracts as they expire, or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with uranium spot market purchases.

Energy Efficiency. Several factors have led to increased focus on energy efficiency, including environmental constraints, increasing costs of generating plans and legislative mandates regarding building codes and appliance efficiencies. As a result of these factors, Duke Energy has developed various programs designed to promote the efficient use of electricity by its customers. These programs, collectively called save-a-watt, have been filed with various state commissions over the past several years.

Save-a-watt was approved by the PUCO on December 17, 2008, in conjunction with the ESP, and Duke Energy Ohio began offering programs and billing a rate rider effective January 1, 2009. Save-a-watt is approved to continue through December 31, 2011.

On February 26, 2009, the NCUC approved Duke Energy Carolinas’ energy efficiency programs and authorized Duke Energy Carolinas to implement its rate rider pending approval of a final compensation mechanism by the NCUC. Duke Energy Carolinas began offering energy conservation programs to North Carolina retail customers and billing a conservation-program only rider on June 1, 2009. In October 2009, Duke Energy Carolinas also began offering demand response programs in North Carolina. On December 14, 2009, the NCUC approved the save-a-watt compensation model and, effective January 1, 2010, Duke Energy Carolinas began billing a rate rider reflecting both conservation and demand response programs. The save-a-watt programs and compensation approach in North Carolina are approved through December 31, 2013.

Duke Energy Carolinas began offering demand response and conservation programs to South Carolina retail customers effective June 1, 2009. On January 20, 2010, the PSCSC approved a save-a-watt rider for Duke Energy Carolinas’ energy efficiency programs. Duke Energy Carolinas began billing this rider to retail customers February 1, 2010. The save-a-watt programs and compensation approach in South Carolina are approved through December 31, 2013.

In October 2007, Duke Energy Indiana filed its petition with the IURC requesting approval of save-a-watt. Duke Energy Indiana reached a settlement with all intervenors except one, the CAC, and filed the settlement agreement with the IURC. An evidentiary hearing with the IURC was held on February 27, 2009 and March 2, 2009. On February 10, 2010, the IURC approved the request.

The KPSC approved Duke Energy Kentucky’s current energy efficiency programs in 2009. The KPSC is reviewing Duke Energy Kentucky’s proposed adjustment for 2010 and a decision is expected by May 2010. On December 1, 2008, Duke Energy Kentucky filed an application for the save-a-watt compensation model. On January 27, 2010, Duke Energy Kentucky withdrew the application to implement save-a-watt and plans to file a revised portfolio in the future.

SmartGrid and Distributed Renewable Generation Demonstration Project. Duke Energy Indiana filed a petition in May 2008, and case-in-chief testimony in September 2008, supporting its request to build an intelligent distribution grid in Indiana. The proposal requested approval of distribution formula rates or, in the alternative, a SmartGrid Rider to recover the return on and of the capital costs of the build-out and the recovery of incremental operating and maintenance expenses and lost revenues. The petition also included a pilot program for the installation of small solar photovoltaic and wind generation on customer sites, for approximately $10 million over a three-year period. Duke Energy Indiana filed supplemental testimony in January 2009 to reflect the impacts of new favorable tax treatment on the cost/benefit analysis for SmartGrid. After various filings by interveners, on June 4, 2009, Duke Energy Indiana filed with the IURC a settlement agreement with the OUCC, the CAC, Nucor Corporation, and the Duke Energy Indiana Industrial Group which provided for a full deployment of Duke Energy Indiana’s SmartGrid initiative at a slower pace, including cost recovery through a tracking mechanism. The settlement also included increased reporting and monitoring requirements, approval of Duke Energy Indiana’s renewable distributed generation pilot and the creation of a collaborative design to initiate several time differentiated pricing pilots, an electric vehicle pilot and a home area network pilot. Additionally, the settlement agreement provided for tracker recovery of the costs associated with the SmartGrid initiative, subject to cost recovery caps and a termination date for the tracker. The tracker would also include a reduction in costs associated with the adoption of a new depreciation study. An evidentiary hearing was held on June 29, 2009. On November 4, 2009, the IURC issued an order that rejected

 

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the settlement agreement as incomplete and not in the public interest. The IURC cited a lack of defined benefits of the programs and encouraged the parties to continue the collaborative process outlined in the settlement or to consider smaller scale pilots or phased-in options. The IURC required the parties to present a procedural schedule within 10 days to address the underlying relief requested in the cause, and to supplement the record to address issues regarding the American Recovery and Reinvestment Act (the Stimulus Bill) funding recently awarded by the DOE. Duke Energy Indiana is considering its next steps, including a review of the implications of this Order on the Stimulus Bill SmartGrid Investment Grant award from the DOE. A technical conference was held at the IURC on December 1, 2009, wherein a procedural schedule was established for the IURC’s continuing review of Duke Energy Indiana’s smart grid proposal. Duke Energy is currently scheduled to file supplemental testimony in support of a revised SmartGrid proposal by April 1, 2010, with an evidentiary hearing scheduled for May 5, 2010.

Duke Energy Ohio received approval to recover expenditures incurred to deploy the SmartGrid infrastructure in December 2008 in conjunction with the approval of Duke Energy Ohio’s ESP filing. On June, 30, 2009, Duke Energy Ohio filed an application to establish rates for return of its SmartGrid net costs incurred for gas and electric distribution service through the end of 2008. Duke Energy Ohio proposed its gas SmartGrid rider as part of its most recent gas distribution rate case. A Stipulation and Recommendation was entered into by Duke Energy Ohio, Staff of the PUCO, Kroger Company, and Ohio Partners for Affordable Energy, which provides for a revenue increase of approximately $4.2 million under the electric rider and $590,000 under the natural gas rider. Approval of the Stipulation and Recommendation is expected in the first quarter 2010.

Duke Energy Business Services, on behalf of Duke Energy Indiana and Duke Energy Ohio, was awarded a $200 million SmartGrid investment grant from the DOE in October 2009. Duke Energy is currently evaluating the terms and conditions of the grant in conjunction with regulatory activities described above that are ongoing in Indiana and Ohio.

See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.

Renewable Energy. Climate change concerns, as well as the oil price volatility, have sparked rising government support in driving increasing renewable energy legislation at both the federal and state level. For example, as discussed further below, the North Carolina legislation (SB 3) passed in 2007 established a renewable energy and energy efficiency portfolio standard (REPS) for electric utilities, and in 2008, the state of Ohio also passed legislation that included renewable energy and advanced energy targets. Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana have issued Request for Proposals (RFP) seeking bids for power generated from renewable energy sources, including sun, wind, water, organic matter and other sources.

With the passage of Senate Bill 221 (SB 221) in Ohio in 2008, Duke Energy Ohio is required to secure renewable energy and include an increasing percentage of renewables as part of its resource portfolio. The compliance percentages are based on a three-year historical average of its standard service offer load. The requirements are 0.25% of the baseline load from non-solar and 0.004% from solar beginning in 2009, increasing to 12.5% non-solar and 0.5% solar by 2024. Of these percentages, at least 50% of each resource type must come from resources located within the state of Ohio. To address this legislation, Duke Energy Ohio initiated several acquisition activities including comprehensive renewable RFPs in June 2008. Duke Energy Ohio evaluated the bids and selected both solar and non-solar bids to begin negotiations aimed toward final contract executions. Initial objectives were focused on meeting the specific near-term 2009, 2010 and 2011 requirements. Duke Energy Ohio is also working with regulators to seek clarifications on points of the SB 221 renewable guidelines. Effective December 10, 2009, the PUCO adopted a set of reporting standards known as “Green Rules” which will regulate energy efficiency, alternative energy generation requirements and emission reporting for activities mandated by SB 221. Duke Energy Ohio will continue its renewable efforts with bidders, suppliers and the community in Ohio to meet the increasing renewable obligations.

With the passage of SB 3 in North Carolina in 2007, Duke Energy Carolinas was required to include an increasing percentage of renewables as part of its generation portfolio. SB 3 requires solar compliance at 0.02% of retail sales beginning in 2010 and 3% of total portfolio to comply with solar, swine and poultry requirements beginning 2012. Total North Carolina renewable energy resource compliance increases to 12.5% by 2021. SB 3 granted the NCUC authority to approve an energy efficiency rate rider to compensate utilities for new energy efficiency programs that they implement, as well as a REPS rider to recover incremental costs incurred to comply with the renewable portfolio standard. To address this legislation, Duke Energy Carolinas initiated a comprehensive renewable RFP in April 2007 to address the 2010 through 2014 renewable portfolio standards requirements. As a result of the 2007 renewable energy RFP, Duke Energy Carolinas has executed a contract with a solar bidder and several landfill gas contracts which will be added to the hydro facilities portfolio to meet future compliance requirements. Duke Energy Carolinas is working with regulators to seek clarifications on points of the SB 3 renewable guidelines. Duke Energy Carolinas will continue to meet its growing renewable efforts with bidders, suppliers and the community in the Carolinas to meet the increasing renewable obligations.

Inventory

Generation of electricity is capital-intensive. U.S. Franchised Electric and Gas must maintain an adequate stock of fuel, materials and supplies in order to ensure continuous operation of generating facilities and reliable delivery to customers. As of December 31, 2009, the inventory balance for U.S. Franchised Electric and Gas was approximately $1,278 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

Nuclear Insurance and Decommissioning

Duke Energy Carolinas owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and the Catawba Nuclear Stations each have two nuclear reactors and the Oconee Nuclear Station has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy Carolinas for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to provide for public liability claims resulting from nuclear incidents to the maximum total financial protection liability, which was approximately $12.5 billion and increased to approximately $12.6 billion effective January 1, 2010. See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies—Nuclear Insurance,” for more information.

        In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2009, 2008 and 2007, Duke Energy Carolinas expensed approximately $48 million and contributed cash of approximately $48 million to the Nuclear Decommissioning Trust Funds (NDTF) for decommissioning costs. The entire amount of these contributions were to the funds reserved for contaminated costs as contributions to the funds reserved for non-contaminated costs have been discontinued since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external NDTF was approximately $1,765 million as of December 31, 2009 and $1,436 million as of December 31, 2008.

As the NCUC and the PSCSC require that Duke Energy Carolinas update its cost estimate for decommissioning its nuclear plants every five years, new site-specific nuclear decommissioning cost studies were completed in January 2009 that showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination, of approximately $3 billion in 2008 dollars. This estimate includes Duke Energy Carolinas’ 19.25% ownership interest in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy Carolinas to recover estimated decommissioning costs through retail rates over

 

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the expected remaining service periods of Duke Energy Carolinas’ nuclear stations. Duke Energy Carolinas believes that the decommissioning costs being recovered through rates, when coupled with the existing fund balance and expected fund earnings, will be sufficient to provide for the cost of future decommissioning.

Duke Energy Carolinas filed these site-specific nuclear decommissioning cost studies with the NCUC and the PSCSC in April 2009. In addition to the decommissioning cost studies, a new funding study was completed and indicates the current annual funding requirement of approximately $48 million is sufficient to cover the estimated decommissioning costs. Duke Energy Carolinas received an order from the NCUC on its rate case filing on December 7, 2009, and from the PSCSC on Duke Energy Carolinas’ rate case on January 27, 2010. Both the NCUC and the PSCSC approved the existing $48 million annual funding level for nuclear decommissioning costs. See Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for more information.

After used fuel is removed from a nuclear reactor, it is cooled in a spent-fuel pool at the nuclear station. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy Carolinas contracted with the DOE for the disposal of used nuclear fuel. The DOE failed to begin accepting used nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. Duke Energy Carolinas will continue to safely manage its used nuclear fuel until the DOE accepts it. In 1998, Duke Energy Carolinas filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial used nuclear fuel by the required date. Damages claimed in the lawsuit were based upon Duke Energy Carolinas’ costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional used fuel storage capacity. On March 5, 2007, Duke Energy Carolinas and the U.S. Department of Justice reached a settlement resolving Duke Energy Carolinas’ used nuclear fuel litigation against the DOE. The agreement provided for an initial payment to Duke Energy Carolinas for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs.

Asbestos Related Injuries and Damages Claims

Duke Energy has experienced numerous claims for indemnification and medical reimbursements relating to damages for bodily injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas on its electric generation plants prior to 1985.

Duke Energy has third-party insurance to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Reserves recorded on Duke Energy’s Consolidated Balance Sheets are based upon the minimum amount in Duke Energy’s best estimate of the range of loss for current and future asbestos claims through 2027. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change management’s estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside Duke Energy’s control, management believes it is reasonably possible that Duke Energy Carolinas may incur asbestos liabilities in excess of its recorded reserves.

Duke Energy Indiana and Duke Energy Ohio have also been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. The impact on Duke Energy’s consolidated results of operations, cash flows, or financial position of these cases to date has not been material. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana and Duke Energy Ohio generating plants; (ii) the possible incidence of various illnesses among exposed workers and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the foreseeable future is not material. This estimated range of exposure may change as additional settlements occur and claims are made and more case law is established.

See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies-Litigation-Asbestos Related Injuries and Damages Claims,” for more information.

Competition

U.S. Franchised Electric and Gas competes in some areas with government-owned power systems, municipally owned electric systems, rural electric cooperatives and other private utilities. By statute, the NCUC and the PSCSC assign service areas outside municipalities in North Carolina and South Carolina, respectively, to regulated electric utilities and rural electric cooperatives. Substantially all of the territory comprising Duke Energy Carolinas’ service area has been assigned in this manner. In unassigned areas, Duke Energy Carolinas’ business remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina, competition continues between municipalities and other electric suppliers outside the municipalities’ corporate limits, subject to the regulation of the PSCSC. In Kentucky, the right of municipalities to serve customers outside corporate limits is subject to court approval. In Ohio, certified suppliers may offer retail electric generation service to residential, commercial and industrial customers. In Indiana, the state is divided into certified electric service areas for municipal utilities, rural cooperatives and investor owned utilities. There are limited circumstances where the certified electric service areas can be modified, with approval of the IURC. U.S. Franchised Electric and Gas also competes with other utilities and marketers in the wholesale electric business. In addition, U.S. Franchised Electric and Gas continues to compete with natural gas providers.

Regulation

State

The NCUC, the PSCSC, the PUCO, the IURC and the KPSC (collectively, the State Utility Commissions) approve rates for retail electric service within their respective states. In addition, the PUCO and the KPSC approve rates for retail gas distribution service within their respective states. The FERC approves U.S. Franchised Electric and Gas’ cost-based rates for electric sales to certain wholesale customers. The State Utility Commissions, except for the PUCO, also have authority over the construction and operation of U.S. Franchised Electric and Gas’ generating facilities. CPCN’s issued by the State Utility Commissions, as applicable, authorize U.S. Franchised Electric and Gas to construct and operate its electric facilities, and to sell electricity to retail and wholesale customers. Prior approval from the relevant State Utility Commission is required for Duke Energy’s regulated operating companies to issue securities.

Duke Energy Carolinas 2009 North Carolina Rate Case. On June 2, 2009, Duke Energy Carolinas filed an Application for Adjustment of Rates and Charges Applicable to Electric Service in North Carolina to increase its base rates. The Application was based upon

 

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a historical test year consisting of the 12 months ended December 31, 2008. On October 20, 2009, Duke Energy Carolinas entered into a settlement agreement with the North Carolina Public Staff. Two organizations representing industrial customers joined the settlement on October 21, 2009. The terms of the agreement include a base rate increase of $315 million (or approximately 8%) phased in primarily over a two-year period beginning January 1, 2010. In order to mitigate the impact of the increase on customers, the agreement provides for (i) a one-year delay in the collection of financing costs related to the Cliffside modernization project until January 1, 2011; and (ii) the accelerated return of certain regulatory liabilities to customers which lowered the total impact to customer bills to an increase of approximately 7% in the near-term. The proposed settlement includes a 10.7% return on equity and a capital structure of 52.5% equity and 47.5% long-term debt. Additionally, Duke Energy Carolinas agreed not to file another rate case before 2011 with any changes to rates taking effect no sooner than 2012. The NCUC approved the settlement agreement in full by order dated December 7, 2009. The new rates were effective and implemented on January 1, 2010.

Duke Energy Carolinas 2009 South Carolina Rate Case. On July 27, 2009, Duke Energy Carolinas filed its Application for Authority to Increase and Adjust Rates and Charges for an increase in rates and charges in South Carolina. On September 25, 2009, Duke Energy Carolinas filed a supplemental request seeking PSCSC approval of a charge to customer bills to pay for Duke Energy Carolinas’ new energy efficiency efforts. Parties to the proceeding include the South Carolina Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC), and the South Carolina Green Party. Duke Energy Carolinas, ORS, and SCEUC filed a settlement agreement on November 24, 2009, recommending, (i) a $74 million increase in base rates, (ii) an allowed return on equity of 11% with rates set at a return on equity of 10.7% and capital structure of 53% equity, and (iii) various riders, including one that provides for the return of DSM charges previously collected from customers over three years rather than five years, and another that provides for a storm reserve provision allowing Duke Energy Carolinas to collect $5 million annually (up to a maximum funding level of $50 million accumulating in reserves) to be used against large storm costs in any particular period. On January 20, 2010, the PSCSC approved the settlement agreement in full, including the cost recovery mechanism for the energy efficiency effort. The new rates were effective February 1, 2010.

Duke Energy Ohio Electric Rate Filings. New legislation (SB 221) passed in April 2008 and signed by the Governor of Ohio on May 1, 2008 codified the PUCO’s authority to approve an electric utility’s standard generation service offer through an ESP, which allows for pricing structures similar to those under the historic RSP. Electric utilities are required to file an ESP and may also file an application for a Market Rate Option (MRO) at the same time. The MRO is a price determined through a competitive bidding process. On July 31, 2008, Duke Energy Ohio filed an ESP to be effective January 1, 2009. On December 17, 2008, the PUCO issued its finding and order adopting a modified Stipulation with respect to Duke Energy Ohio’s ESP filing. The PUCO agreed to Duke Energy Ohio’s request for a net increase in base generation revenues, before impacts of customer switching, of $36 million, $74 million and $98 million in 2009, 2010 and 2011, respectively, including the termination of the residential and non-residential Regulatory Transition Charge, the recovery of expenditures incurred to deploy the SmartGrid infrastructure and the implementation of save-a-watt. See “Commercial Power” section below for additional information related to the ESP.

For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—U.S. Franchised Electric and Gas.”

Federal

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

The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rule makings. Among the key provisions, the Energy Policy Act of 2005 repealed the Public Utility Holding Company Act (PUHCA) of 1935, directed FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extended the Price Anderson Act for 20 years (until 2025), provided loan guarantees, standby support and production tax credits for new nuclear reactors, gave FERC enhanced merger approval authority, provided FERC new backstop authority for the siting of certain electric transmission projects, streamlined the processes for approval and permitting of interstate pipelines, and reformed hydropower relicensing. In 2005 and 2006, FERC initiated several rule makings as directed by the Energy Policy Act of 2005. These rulemakings have now been completed, subject to certain appeals and further proceeding. Duke Energy does not believe that these rulemakings or the appeals will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

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

Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana are transmission owners in a regional transmission organization operated by the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a non-profit organization which maintains functional control over the combined transmission systems of its members. In 2005, the Midwest ISO began administering an energy market within its footprint and in January 2009 it began administering an ancillary services market. Additionally, in April 2009, the Midwest ISO began administering a voluntary capacity auction, and in June 2009, instituted a tariff based capacity requirement.

On December 17, 2001, the IURC approved the transfer of functional control of the operation of the Duke Energy Indiana transmission system to the Midwest ISO, a Regional Transmission Organization (RTO) established in 1998. On June 1, 2005, the IURC authorized Duke Energy Indiana to transfer control area operations tasks and responsibilities and transfer dispatch and Day 2 energy markets tasks and responsibilities to the Midwest ISO. On August 13, 2008, the IURC authorized Duke Energy Indiana to transfer additional balancing authority functions to the Midwest ISO to permit Duke Energy Indiana to participate in the Midwest ISO’s ancillary services market.

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

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

 

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proposal, which is not projected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and the potential impacts such legislation could have on Duke Energy’s operations.

Other

U.S. Franchised Electric and Gas is subject to the jurisdiction of the NRC for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy Carolinas’ three Oconee nuclear units through 2033 for Units 1 and 2 and through 2034 for Unit 3. In 2003, the NRC renewed the operating licenses for all units at Duke Energy Carolinas’ McGuire and Catawba stations. The two McGuire units are licensed through 2041 and 2043, respectively, while the two Catawba units are licensed through 2043. All but one of U.S. Franchised Electric and Gas’ hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act, with license terms expiring from 2005 to 2036. The FERC has authority to issue new hydroelectric generating licenses. Hydroelectric facilities whose licenses expired in 2005 through 2009 are operating under annual extensions of the current license until FERC issues a new license. Other hydroelectric facilities whose licenses expire between 2010 and 2016 are in various stages of relicensing. Duke Energy expects to receive new licenses for all applicable hydroelectric facilities with the exception of the Dillsboro Project, for which Duke Energy requested and the FERC approved license surrender. Duke Energy Carolinas has removed the Dillsboro Project dam and powerhouse as part of multi-project and multi-stakeholder agreements and Duke Energy Carolinas is continuing with stream restoration and post-removal monitoring as requested by FERC’s license surrender order.

U.S. Franchised Electric and Gas is subject to the jurisdiction of the U.S. Environmental Protection Agency (EPA) and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

COMMERCIAL POWER

Commercial Power owns, operates and manages power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio, acquired from Cinergy in April 2006, which are dedicated under the ESP, and the five Midwestern gas-fired non-regulated generation assets that were a portion of former DENA, which are dispatched into wholesale markets. Commercial Power’s assets, excluding wind energy generation assets, are comprised of approximately 7,550 net MW of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Effective January 1, 2009, approximately half of Commercial Power’s Ohio-based generation assets began operating under an ESP, which expires on December 31, 2011, and is described below. Prior to January 1, 2009, these generation assets were contracted through the RSP, which expired on December 31, 2008.

Commercial Power also has a retail sales subsidiary, DERS, which is certified by the PUCO as a CRES provider in Ohio. DERS serves retail electric customers in Southwest, West Central and Northern Ohio with generation and other energy services at competitive rates. During 2009, due to increased levels of customer switching as a result of the competitive markets in Ohio, which is discussed further below, DERS has focused on acquiring customers that had previously been served by Duke Energy Ohio under the ESP, as well as those previously served by other Ohio franchised utilities.

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

 

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LOGO

Through DEGS, Commercial Power is an on-site energy solutions and utility services provider. Primarily through joint ventures, DEGS engages in utility systems construction, operation and maintenance of utility facilities, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of usable energy from a single source. DEGS currently has approximately 735 net MW of wind energy in operation and over 5,000 MW of wind energy projects in the development pipeline. DEGS also is developing transmission, solar and biomass projects.

The following map shows the location of DEGS generation assets.

 

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LOGO

Rates and Regulation

Effective January 1, 2009, approximately half of Commercial Power’s generation assets operate under an ESP, which expires on December 31, 2011. Prior to the ESP, these generation assets had been contracted through the RSP, which expired on December 31, 2008. The ESP consists of the following discrete charges:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

Commercial Power’s generation operations in the Midwest include generation assets located in Ohio that are dedicated to serve Ohio native load customers. These assets, as excess capacity allows, also generate revenues through sales outside the native load customer base, and such revenue is termed non-native.

Prior to December 17, 2008, Commercial Power did not apply regulatory accounting treatment to any of its operations due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. In April 2008, new legislation (SB 221) was passed in Ohio and signed by the Governor of Ohio on May 1, 2008. The new law codified the PUCO’s authority to approve an electric utility’s standard service offer either through an ESP or a MRO, which is a price determined through a competitive bidding process. On July 31, 2008, Duke

 

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Energy Ohio filed an ESP and, with certain amendments, the ESP was approved by the PUCO on December 17, 2008. The approval of the ESP on December 17, 2008 resulted in the reapplication of regulatory accounting treatment to certain portions of Commercial Power’s operations as of that date. The ESP became effective on January 1, 2009.

Under the ESP, Commercial Power bills for its native load generation via numerous riders. SB 221 and the ESP resulted in the approval of an enhanced recovery mechanism for certain of these riders, which includes, but is not limited to, a price-to-compare fuel and purchased power rider and certain portions of a price-to-compare cost of environmental compliance rider. Accordingly, Commercial Power began applying regulatory accounting treatment to the corresponding RSP riders that enhanced the recovery mechanism for recovery under the ESP on December 17, 2008. The remaining portions of Commercial Power’s Ohio native load generation operations, revenues from which are reflected in rate riders for which the ESP does not specifically allow enhanced recovery, as well as all generation operations associated with non-native customers, including Commercial Power’s Midwest gas-fired generation assets, continue to not apply regulatory accounting as those operations do not meet the necessary accounting criteria. Moreover, generation remains a competitive market in Ohio and native load customers continue to have the ability to switch to alternative suppliers for their electric generation service. As customers switch, there is a risk that some or all of the regulatory assets will not be recovered through the established riders. In assessing the probability of recovery of its regulatory assets established for its native load generation operations, Duke Energy continues to monitor the amount of native load customers that have switched to alternative suppliers. At December 31, 2009, management has concluded that the established regulatory assets are still probable of recovery even though there have been increased levels of customer switching.

Despite certain portions of the Ohio native load operations not meeting the criteria for applying regulatory accounting treatment, all of Commercial Power’s Ohio native load operations’ rates are subject to approval by the PUCO, and thus these operations are referred to here-in as Commercial Power’s regulated operations.

Commercial Power is subject to regulation at the state level, primarily from PUCO and at the federal level, primarily from FERC. The PUCO approves prices for all retail electric generation sales by Duke Energy Ohio for its native retail service territory. See “Regulation” section within U.S. Franchised Electric and Gas for additional information regarding deregulation in Ohio.

Regulations of FERC and the PUCO govern access to regulated electric customer and other data by non-regulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of Commercial Power.

Other ongoing regulatory initiatives at both state and federal levels addressing market design, such as the development of capacity markets and real-time electricity markets, impact financial results from Commercial Power’s marketing and generation activities.

Commercial Power is subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and the potential impacts such legislation could have on Duke Energy’s operations.

Market Environment and Competition

Similar to U.S. Franchised Electric and Gas’ operations, the overall economic conditions have negatively impacted Commercial Power’s retail volumes for all customer classes. Commercial Power competes for wholesale contracts for the purchase and sale of electricity, coal, natural gas and emission allowances. The market price of commodities and services, along with the quality and reliability of services provided, drive competition in the energy marketing business. Commercial Power’s main competitors include other non-regulated generators in the Midwestern U.S. wholesale power, coal and natural gas marketers, renewable energy companies and financial institutions and hedge funds engaged in energy commodity marketing and trading.

Low commodity prices in 2009 have put downward pressure on power prices. The available capacity and lower prices have provided opportunities for customers in Ohio to switch generation suppliers. Competitive power suppliers have begun supplying power to current Commercial Power customers in Ohio and Commercial Power experienced an increase in customer switching beginning in the second quarter of 2009 and accelerating in the later part of the year. As of December 31, 2009, customer switching levels approximated 40% of Commercial Power’s Ohio native load. However, through DERS, Commercial Power was able to acquire approximately 60% of the switched load by offering customers a discount to the ESP price. Additionally, DERS has been able to acquire new customers previously served by other Ohio franchised utilities.

Fuel Supply

Commercial Power relies on coal and natural gas for its generation of electric energy.

Coal. Commercial Power meets its coal demand through a portfolio of purchase supply contracts and spot agreements. Large amounts of coal are purchased under supply contracts with mining operators who mine both underground and at the surface. Commercial Power uses spot-market purchases to meet coal requirements not met by supply contracts. Expiration dates for its supply contracts, which have various price adjustment provisions and market re-openers, range from 2010 to 2012. Commercial Power expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required as existing contracts expire, though prices will fluctuate over time as coal markets change. The coal purchased is primarily produced in Illinois, Ohio and eastern Kentucky. Commercial Power has an adequate supply of coal to fuel its projected 2010 operations and a significant portion of supply to fuel its projected 2011 operations. The majority of Commercial Power’s coal-fired generation is equipped with flue gas desulfurization equipment. As a result, Commercial Power is able to satisfy the current emission limitations for SO2 for existing facilities.

Gas. Commercial Power is responsible for the purchase and the subsequent delivery of natural gas to its gas turbine generators. The majority of Commercial Power’s natural gas requirements are purchased in the spot market on an as-needed basis.

 

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INTERNATIONAL ENERGY

International Energy principally operates and manages power generation facilities and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through DEI and its affiliates and its activities target power generation in Latin America. Additionally, International Energy has equity method investments in NMC, located in Saudi Arabia, which is a regional producer of MTBE and Attiki, located in Athens, Greece, which is a natural gas distributor and was acquired in connection with the Cinergy merger. In December 2009, International Energy decided to abandon its investment in Attiki. See Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions,” for additional information.

International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and industrial/commercial companies. International Energy’s current strategy is focused on optimizing the value of its current Latin American portfolio and expanding the portfolio through investment in generation opportunities in Latin America.

International Energy owns, operates or has substantial interests in approximately 4,000 net MW of generation facilities.

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

LOGO

Competition and Regulation

International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government-owned electric generating companies, local distribution companies with self-generation capability and other privately-owned electric generating and marketing companies. The principal elements of competition are price and availability, terms of service, flexibility and reliability of service.

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

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

 

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OTHER

The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, Bison, Duke Energy’s wholly-owned, captive insurance subsidiary, Duke Energy’s effective 50% interest in Crescent and DukeNet and related telecom businesses. Additionally, Other includes the remaining portion of Duke Energy’s business formerly known as DENA that was not exited or transferred to Commercial Power, primarily DETM, which is 60% owned by Duke Energy and 40% owned by Exxon Mobil Corporation and management is currently in the process of winding down. See Note 2 to the Consolidated Financial Statements, “Business Segments,” for more information on Crescent.

Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as property, business interruption and general liability of subsidiaries and affiliates of Duke Energy.

Competition and Regulation

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

ENVIRONMENTAL MATTERS

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and the potential impacts such legislation could have on Duke Energy’s operations. Additionally, other potential future environmental laws and regulations could have a significant impact on Duke Energy’s results of operations, cash flows or financial position. However, if such laws are enacted, Duke Energy would seek appropriate regulatory recovery of costs to comply within its regulated operations.

For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Notes 4 and 16 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively.

Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with current international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our various business segments and is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Energy.

GEOGRAPHIC REGIONS

For a discussion of Duke Energy’s foreign operations and certain of the risks associated with them, see “Risk Factors,” “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk,” and Notes 2 and 8 to the Consolidated Financial Statements, “Business Segments” and “Risk Management, Derivative Instruments and Hedging Activities,” respectively.

EMPLOYEES

On December 31, 2009, Duke Energy had approximately 18,680 employees. A total of approximately 4,620 operating and maintenance employees were represented by unions.

EXECUTIVE OFFICERS OF DUKE ENERGY

STEPHEN G. DE MAY, 47, Senior Vice President, Investor Relations and Treasurer. Mr. De May assumed the role of Treasurer in November 2007 and in October 2009 Mr. De May assumed additional responsibility for investor relations. Prior to that, he served as Assistant Treasurer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. De May served as Vice President, Energy and Environmental Policy of Duke Energy since February 2004.

LYNN J. GOOD, 50, Group Executive and Chief Financial Officer. Ms. Good assumed her current position in July 2009. In November 2007, Ms. Good began serving as President, Commercial Businesses. Prior to that, she served as Senior Vice President and Treasurer since December 2006; prior to that she served as Treasurer and Vice President, Financial Planning since October 2006; and prior to that she served as Vice President and Treasurer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Ms. Good served as Executive Vice President and Chief Financial Officer of Cinergy from August 2005 and Vice President, Finance and Controller of Cinergy from November 2003 to August 2005.

DHIAA M. JAMIL, 53, Group Executive, Chief Generation Officer and Chief Nuclear Officer. Mr. Jamil assumed his position as Chief Generation Officer in July 2009 and his position as Chief Nuclear Officer in February 2008. Prior to that he served as Senior Vice President, Nuclear Support, Duke Energy Carolinas, LLC since March 2007.

 

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MARC E. MANLY, 57, Group Executive, Chief Legal Officer and Corporate Secretary. Mr. Manly assumed the role of Corporate Secretary in December 2008 and assumed position of Chief Legal Officer in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Manly served as Executive Vice President and Chief Legal Officer of Cinergy since November 2002.

JAMES E. ROGERS, 62, Chairman, President and Chief Executive Officer. Mr. Rogers assumed the role of Chief Executive Officer and President in April 2006, upon the merger of Duke Energy and Cinergy and assumed the role of Chairman on January 2, 2007. Until the merger of Duke Energy and Cinergy, Mr. Rogers served as Chairman of the Board of Cinergy since 2000 and as Chief Executive Officer of Cinergy since 1995.

B. KEITH TRENT, 50, Group Executive, President, Commercial Businesses. Mr. Trent assumed his current position in July 2009. Prior to that he served as Group Executive and Chief Strategy, Policy and Regulatory Officer since May 2007. Prior to that he served as Group Executive and Chief Strategy and Policy Officer since October 2006 and prior to that he served as Group Executive and Chief Development Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Trent served as Executive Vice President, General Counsel and Secretary of Duke Energy since March 2005. Prior to that he served as General Counsel, Litigation of Duke Energy from May 2002 to March 2005.

JAMES L. TURNER, 50, Group Executive; President and Chief Operating Officer, U.S. Franchised Electric and Gas. Mr. Turner assumed his current position in May 2007. Prior to that he served as Group Executive and President, U.S. Franchised Electric and Gas since October 2006, and prior to that he served as Group Executive and Chief Commercial Officer, U.S. Franchised Electric and Gas since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Turner served as President of Cinergy since 2005, Executive Vice President and Chief Financial Officer of Cinergy from 2004 to 2005.

STEVEN K. YOUNG, 51, Senior Vice President and Controller. Mr. Young assumed his current position in December 2006. Prior to that he served as Vice President and Controller since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Young served as Vice President and Controller of Duke Energy since June 2005. Prior to that Mr. Young served as Senior Vice President and Chief Financial Officer of Duke Energy Carolinas from March 2003 to June 2005.

Executive officers serve until their successors are duly elected.

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

Item 1A. Risk Factors.

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

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

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

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

Duke Energy’s ownership and operation of nuclear generation facilities requires Duke Energy to meet licensing and safety-related requirements imposed by the NRC. In the event of non-compliance, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending upon its assessment of the severity of the situation. Revised security and safety requirements promulgated by the NRC, which could be prompted by, among other things, events within or outside of Duke Energy’s control, such as a serious nuclear incident at a facility owned by a third-party, could necessitate substantial capital and other expenditures at Duke Energy’s nuclear plants, as well as assessments against Duke Energy to cover third-party losses. In addition, if a serious nuclear incident were to occur, it could have a material adverse effect on Duke Energy’s results of operations and financial condition.

Duke Energy’s ownership and operation of nuclear generation facilities also requires Duke Energy to maintain funded trusts that are intended to pay for the decommissioning costs of Duke Energy’s nuclear power plants. Poor investment performance of these decommissioning trusts’ holdings and other factors impacting decommissioning costs could unfavorably impact Duke Energy’s liquidity and results of operations as Duke Energy could be required to significantly increase its cash contributions to the decommissioning trusts.

Duke Energy’s plans for future expansion and modernization of its generation fleet subject it to risk of failure to adequately execute and manage its significant construction plans, as well as the risk of recovering all such costs or of recovering costs in an untimely manner, which could materially impact Duke Energy’s results of operations, cash flows or financial position.

During the three year period from 2010 to 2012, Duke Energy anticipates cumulative capital expenditures of approximately $14 billion to $15 billion of which approximately $11 billion relates to its regulated U.S. Franchised Electric and Gas businesses. The completion of Duke Energy’s anticipated capital investment projects in existing and new generation facilities is subject to many construction and development risks, including, but not limited to, risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Moreover, Duke Energy’s ability to recover all these costs and recovering costs in a timely manner could materially impact Duke Energy’s consolidated financial position, results of operations or cash flows.

 

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

Duke Energy depends on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity Duke Energy sells to the wholesale market. FERC’s power transmission regulations, as well as those of Duke Energy’s international markets, require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. If transmission is disrupted, or if transmission capacity is inadequate, Duke Energy’s ability to sell and deliver products may be hindered.

The different regional power markets have changing regulatory structures, which could affect Duke Energy’s growth and performance in these regions. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of Duke Energy’s wholesale power marketing business.

Duke Energy may be unable to secure long-term power sales agreements or transmission agreements, which could expose Duke Energy’s sales to increased volatility.

In the future, Duke Energy may not be able to secure long-term power sales agreements to customers for Duke Energy’s unregulated power generation facilities. If Duke Energy is unable to secure these types of agreements, Duke Energy’s sales volumes would be exposed to increased volatility. Without the benefit of long-term customer power purchase agreements, Duke Energy cannot assure that it will be able to sell the power generated by Duke Energy’s facilities or that Duke Energy’s facilities will be able to operate profitably. The inability to secure these agreements could materially adversely affect Duke Energy’s financial and operational results.

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

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

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

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

Customers of Duke Energy Ohio have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation.

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and Duke Energy’s native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service. Competitive power suppliers have announced intentions of supplying power to Duke Energy’s current customers in Ohio, and Duke Energy has experienced an increase in customer switching in the second half of 2009. These evolving market conditions may continue to impact Duke Energy’s results of operations, and also may impact Duke Energy’s ability to continue to apply regulatory accounting treatment to certain portions of its Commercial Power business segment.

Duke Energy must meet credit quality standards and there is no assurance that it and its rated subsidiaries will maintain investment grade credit ratings. If Duke Energy or its rated subsidiaries are unable to maintain an investment grade credit rating, Duke Energy would be required under credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect Duke Energy’s liquidity.

Each of Duke Energy’s and its rated subsidiaries senior unsecured long-term debt is currently rated investment grade by various rating agencies. Duke Energy cannot be sure that the senior unsecured long-term debt of Duke Energy or its rated subsidiaries will be rated investment grade in the future.

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

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

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

        Duke Energy’s business is financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from Duke Energy’s assets. Accordingly, Duke Energy relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from Duke Energy’s operations and to fund investments originally financed through debt instruments with disparate maturities. If Duke Energy is not able to access capital at competitive rates or at all, Duke Energy’s ability to finance its operations and implement its strategy and business plan as scheduled could be adversely affected. An inability to access capital may limit Duke Energy’s ability to pursue improvements or acquisitions that Duke Energy may otherwise rely on for future growth.

 

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Market disruptions may increase Duke Energy’s cost of borrowing or adversely affect Duke Energy’s ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity and gas; terrorist attacks or threatened attacks on Duke Energy’s facilities or unrelated energy companies; or the overall health of the energy industry.

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

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

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

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

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

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

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

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

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

Duke Energy’s costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and Duke Energy’s required or voluntary contributions made to the plans. While Duke Energy complied with the minimum funding requirements as of December 31, 2009, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $471 million. Without sustained growth in the pension investments over time to increase the value of Duke Energy’s plan assets and depending upon the other factors impacting Duke Energy’s costs as listed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations could have a material impact on Duke Energy’s financial position, results of operations or cash flows.

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

Duke Energy is subject to numerous environmental laws and regulations affecting many aspects of Duke Energy’s present and future operations, including air emissions (such as reducing 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 cleanup costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets. The steps Duke Energy could be required to take to ensure that its facilities are in compliance could be prohibitively expensive. As a result, Duke Energy may be required to shut down or alter the operation of its facilities, which may cause Duke Energy to incur losses. Further, Duke Energy’s regulatory rate structure and Duke Energy’s contracts with customers may not necessarily allow Duke Energy to recover capital costs Duke Energy incurs to comply with new environmental regulations. Also, Duke Energy may not be able to obtain or maintain from time to time all required environmental regulatory approvals for Duke Energy’s operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if Duke Energy fails to obtain and comply with them or if environmental laws or regulations change and become more stringent, then the operation of Duke Energy’s facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on Duke Energy’s financial position, results of operations or cash flows, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

 

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

The EPA also has plans to propose new federal regulations governing the management of coal combustion by-products, including fly ash. These regulations may require Duke Energy to make additional capital expenditures and increase Duke Energy’s operating and maintenance costs.

Additionally, potential other new environmental regulations, including the use of coal from mountain removal and water discharge, could require Duke Energy to make additional capital expenditures and increase costs of fuel.

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

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

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

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

Duke Energy is subject to numerous legal proceedings, including claims for damages for bodily injuries alleged to have arisen prior to 1985 from the exposure to or use of asbestos at electric generation plants of Duke Energy Carolinas. Litigation is subject to many uncertainties and Duke Energy cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which Duke Energy is involved could require Duke Energy to make additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on Duke Energy’s cash flows and results of operations. Similarly, it is reasonably possible that the terms of resolution could require Duke Energy to change Duke Energy’s business practices and procedures, which could also have a material effect on Duke Energy’s cash flows, financial position or results of operations.

Duke Energy’s results of operations may be negatively affected by overall market, economic and other conditions that are beyond Duke Energy’s control.

Sustained downturns or sluggishness in the economy generally affect the markets in which Duke Energy operates and negatively influence Duke Energy’s energy operations. Declines in demand for energy as a result of economic downturns in Duke Energy’s franchised electric service territories will reduce overall sales and lessen Duke Energy’s cash flows, especially as Duke Energy’s industrial customers reduce production and, therefore, consumption of electricity and gas. Although Duke Energy’s franchised electric and gas business is subject to regulated allowable rates of return and recovery of certain costs, such as fuel under periodic adjustment clauses, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations. Additionally, prolonged economic downturns that negatively impact Duke Energy’s results of operations and cash flows could result in future material impairment charges being recorded to write-down the carrying value of certain assets, including goodwill, to their respective fair values.

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

Factors that could impact sales volumes, generation of electricity and market prices at which Duke Energy is able to sell electricity are as follows:

 

   

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

 

   

supply of and demand for energy commodities;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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

 

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

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

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

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

New laws or regulations could have a negative impact on Duke Energy’s financial position, cash flows or results of operations.

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

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

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

The insurance industry has also been disrupted by these potential events. As a result, the availability of insurance covering risks Duke Energy and Duke Energy’s competitors typically insure against may decrease. In addition, the insurance Duke Energy is able to obtain may have higher deductibles, higher premiums, lower coverage limits and more restrictive policy terms.

Additional risks and uncertainties not currently known to Duke Energy or that Duke Energy currently deems to be immaterial also may materially adversely affect Duke Energy’s financial condition, results of operations or cash flows.

Item 1B. Unresolved Staff Comments.

None.

 

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Item 2. Properties.

U.S. FRANCHISED ELECTRIC AND GAS

As of December 31, 2009, U.S. Franchised Electric and Gas operated three nuclear generating stations with a combined owned capacity of 5,173 MW (including an approximate 19% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with an overall combined owned capacity of 13,189 MW, (including a 69% ownership in the East Bend Steam Station and an approximate 50% ownership in Unit 5 of the Gibson Steam Station), thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined owned capacity of 3,263 MW, fifteen CT stations with an overall combined owned capacity of 5,047 MW and one CC station with an owned capacity of 285 MW. The stations are located in North Carolina, South Carolina, Indiana, Ohio and Kentucky. The MW displayed in the table below are based on summer capacity.

 

Name   

Total MW
Capacity

 

  

Owned MW
Capacity

 

 

Fuel                

 

  

Location

 

  

Ownership
Interest
(percentage)

 

Carolinas:

                   

Oconee

   2,538               2,538      Nuclear    SC    100%  

Catawba(a)

   2,258               435      Nuclear    SC    19.25     

Belews Creek

   2,220               2,220      Coal    NC    100     

McGuire

   2,200               2,200      Nuclear    NC    100     

Marshall

   2,078               2,078      Coal    NC    100     

Bad Creek

   1,360               1,360      Hydro    SC    100     

Lincoln CT

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

Allen

   1,127               1,127      Coal    NC    100     

Rockingham CT

   825               825      Natural gas/Fuel oil    NC    100     

Cliffside

   760               760      Coal    NC    100     

Jocassee

   730               730      Hydro    SC    100     

Mill Creek CT

   595               595      Natural gas/Fuel oil    SC    100     

Riverbend

   454               454      Coal    NC    100     

Lee

   370               370      Coal    SC    100     

Buck

   369               369      Coal    NC    100     

Cowans Ford

   325               325      Hydro    NC    100     

Dan River

   276               276      Coal    NC    100     

Buzzard Roost CT

   196               196      Natural gas/Fuel oil    SC    100     

Keowee

   152               152      Hydro    SC    100     

Lee CT

   82               82      Natural gas/Fuel oil    SC    100     

Riverbend CT

   64               64      Natural gas/Fuel oil    NC    100     

Buck CT

   62               62      Natural gas/Fuel oil    NC    100     

Dan River CT

   48               48      Natural gas/Fuel oil    NC    100     

Other small hydro (26 plants)

   651               651      Hydro    NC/SC    100     

Midwest:

                   

Gibson(b)

   3,132               2,822      Coal    IN    90     

Cayuga(c)

   1,005               1,005      Coal/Fuel oil    IN    100     

East Bend(d)

   600               414      Coal    KY    69     

Madison CT

   576               576      Natural gas    OH    100     

Gallagher

   560               560      Coal    IN    100     

Woodsdale CT

   462               462      Natural gas/Propane    OH    100     

Wheatland CT

   460               460      Natural gas    IN    100     

Wabash River(e)

   411               411      Coal/Fuel oil    IN    100     

Noblesville CC

   285               285      Natural gas    IN    100     

Miami Fort (Unit 6)

   163               163      Coal    OH    100     

Edwardsport

   160               160      Coal/Fuel oil    IN    100     

Henry County CT

   129               129      Natural gas    IN    100     

Cayuga CT

   99               99      Natural gas/Fuel oil    IN    100     

Miami Wabash CT

   96               96      Fuel oil    IN    100     

Connersville CT

   86               86      Fuel oil    IN    100     

Markland

   45               45      Hydro    IN    100     
                       

Total

   29,276               26,957           
                       

 

(a) This generation facility is jointly owned by Duke Energy Carolinas, along with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation and Piedmont Municipal Power Agency.
(b) Duke Energy Indiana owns and operates Gibson Station Units 1-4 and owns 50.05% of Unit 5, but is the operator. Unit 5 is jointly owned by Duke Energy Indiana, Wabash Valley Power Association, Inc. and Indiana Municipal Power Agency.
(c) Includes Cayuga Internal Combustion (IC).
(d) This generation facility is jointly owned by Duke Energy Kentucky and a subsidiary of Dayton Power and Light, Inc.
(e) Includes Wabash River IC.

 

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In addition, as of December 31, 2009, U.S. Franchised Electric and Gas owned approximately 20,900 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts (KV), 1,800 miles of 345 KV, 3,300 miles of 230 KV, 8,800 miles of 100 to 161 KV, and 6,400 miles of 13 to 69 KV. U.S. Franchised Electric and Gas also owned approximately 151,600 conductor miles of electric distribution lines, including 103,200 miles of overhead lines and 48,400 miles of underground lines, as of December 31, 2009 and approximately 7,200 miles of gas mains and approximately 6,000 miles of service lines. As of December 31, 2009, the electric transmission and distribution systems had approximately 2,300 substations. U.S. Franchised Electric and Gas also owns two underground caverns with a total storage capacity of approximately 16 million gallons of liquid propane. In addition, U.S. Franchised Electric and Gas has access to 5.5 million gallons of liquid propane storage and product loan through a commercial services agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

Substantially all of U.S. Franchised Electric and Gas’ electric plant in service is mortgaged under the indenture relating to Duke Energy Carolinas’, Duke Energy Ohio’s and Duke Energy Indiana’s various series of First Mortgage Bonds.

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

COMMERCIAL POWER

The following table provides information about Commercial Power’s generation portfolio as of December 31, 2009. The MW displayed in the table below are based on summer capacity.

 

Name   

Total MW
Capacity

 

  

Owned MW
Capacity

 

  

  Plant Type

 

  

  Primary Fuel

 

  

  Location

 

  

Approximate
Ownership
Interest
(percentage)

 

Hanging Rock

   1,240       1,240       Combined Cycle    Natural gas         OH    100%  

Lee

   640       640       Simple Cycle    Natural gas         IL    100     

Vermillion(a)

   640       480       Simple Cycle    Natural gas         IN    75     

Fayette

   620       620       Combined Cycle    Natural gas         PA    100     

Washington

   620       620       Combined Cycle    Natural gas         OH    100     

Dick’s Creek

   152       152       Simple Cycle    Natural gas         OH    100     

Beckjord CT

   212       212       Simple Cycle    Fuel oil         OH    100     

Miami Fort CT

   60       60       Simple Cycle    Fuel oil         OH    100     

Miami Fort (Units 7 and 8)(b)

   1,000       640       Steam    Coal         OH    64     

W.C. Beckjord(b)

   1,124       862       Steam    Coal         OH    76.7     

W.M. Zimmer(b)

   1,300       605       Steam    Coal         OH    46.5     

J.M. Stuart(b)(c)

   2,340       912       Steam    Coal         OH    39     

Killen(b)(c)

   600       198       Steam    Coal         OH    33     

Conesville(b)(c)

   780       312       Steam    Coal         OH    40     
                              

Total Fossil & CT

   11,328       7,553                  

Happy Jack

   29       29          Wind         WY    100     

Ocotillo

   59       59          Wind         TX    100     

Notrees

   153       153          Wind         TX    100     

North Allegheny

   70       70          Wind         PA    100     

Campbell Hill

   99       99          Wind         WY    100     

Silver Sage

   42       42          Wind         WY    100     
                              

Total Renewable Energy

   452       452                  
                              

Total

   11,780       8,005                  
                              

 

(a) This generation facility is jointly owned by Duke Energy Ohio and Wabash Valley Power Association, Inc.
(b) These generation facilities are jointly owned by Duke Energy Ohio and subsidiaries of American Electric Power, Inc. and/or Dayton Power and Light, Inc.
(c) Station is not operated by Duke Energy Ohio.

In addition to the above facilities, Commercial Power owns an equity interest in the 585 MW capacity Sweetwater wind projects located in Texas. Commercial Power’s share in these projects is 283 MW.

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

 

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INTERNATIONAL ENERGY

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

 

Name   

Total
MW
Capacity

 

  

Owned
MW
Capacity

 

  

Fuel        

 

  

Location

 

  

Approximate
Ownership
Interest
(percentage)

 

Paranapanema(a)

   2,307       2,114       Hydro    Brazil    95%  

Cerros Colorados

   576       523       Hydro/Natural Gas    Argentina    91     

Egenor

   501       501       Hydro/Diesel    Peru    100     

DEI Guatemala

   283       283       Fuel Oil/Diesel    Guatemala    100     

DEI El Salvador

   328       296       Fuel Oil/Diesel    El Salvador    90     

Electroquil

   192       159       Diesel    Ecuador    83     

Aguaytia

   177       177       Natural Gas    Peru    100     
                        

Total

   4,364       4,053            
                        

 

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

International Energy also owns a 25% equity interest in NMC. In 2009, NMC produced approximately 1 million metric tons of methanol and 1 million metric tons of MTBE. Approximately 40% of methanol is normally used in the MTBE production. Additionally, International Energy owns a 25% equity interest in Attiki, which is a natural gas distributor within the geographical area of Athens, Greece. In December 2009, International Energy decided to abandon its investment in Attiki. See Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions,” for additional information.

For additional information and a map showing International Energy’s properties, see “Business—International Energy” earlier in this section.

OTHER

Duke Energy owns approximately 5.7 million square feet of corporate, regional and district office space spread throughout its service territories in the Carolinas and the Midwest. Additionally, Duke Energy leases approximately 1.5 million square feet of office space throughout the Carolinas, Midwest and in Houston, Texas. In February 2009, Duke Energy entered into a lease for approximately 500,000 square feet of office space in Charlotte, North Carolina that will become its new corporate headquarters.

Item 3. Legal Proceedings.

For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” and “Commitments and Contingencies—Environmental.”

Brazilian Regulatory Citations. On September 5, 2007, the State Environmental Agency of Parana assessed fines against International Energy of approximately $10 million for failure to comply with reforestation measures allegedly required by state regulations in Brazil. International Energy believes that federal law is controlling and has challenged the assessment. In addition, International Energy was assessed a fine by the federal environmental agency, IBAMA, in the amount of approximately $150 thousand for improper maintenance of existing reforested areas. International Energy believes that it has properly maintained all reforested areas and is also contesting this assessment. These assessed fines were judged to be valid in the administrative court between June and September 2009. International Energy has challenged these administrative court rulings by filing three judicial actions for annulment between July and October 2009.

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

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

 

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

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

Common Stock Data by Quarter

 

     2009

 

   2008

 

          Stock Price
Range(a)

 

        Stock Price
Range(a)

 

    

Dividends
Per Share

 

  

High

 

  

Low

 

  

Dividends
Per Share

 

  

High

 

  

Low

 

    

First Quarter

     $ 0.23       $  15.96       $  11.72         $  0.22        $  20.60    $  17.00   

Second Quarter(b)

   0.47         14.83         13.31         0.45          19.20      17.02   

Third Quarter

   —         16.02         14.10         —          19.10      16.77   

Fourth Quarter(b)

   0.24         17.94         15.33         0.23          17.99      13.50   

 

(a) Stock prices represent the intra-day high and low stock price.
(b) Dividends paid in September 2009 and December 2009 increased from $0.23 per share to $0.24 per share and dividends paid in September 2008 and December 2008 increased from $0.22 per share to $0.23 per share.

Duke Energy expects to continue its policy of paying regular cash dividends; however, there is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition, and are subject to declaration by the Board of Directors.

Duke Energy’s operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to Duke Energy. See “Liquidity and Capital Resources” within “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding these restrictions and their impacts on Duke Energy’s liquidity.

Issuer Purchases of Equity Securities for Fourth Quarter of 2009

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

Stock Performance Graph

The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in Duke Energy Corporation common stock, as compared with the Standard & Poor’s (S&P) 500 Stock Index and the Philadelphia Utility Index for the five-year period 2005 through 2009.

This performance chart assumes $100 invested on December 31, 2004 in Duke Energy common stock, in the S&P 500 Stock Index and in the Philadelphia Utility Index and that all dividends are reinvested.

 

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LOGO

NYSE CEO Certification

Duke Energy has filed the certification of its Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits to this Annual Report on Form 10-K for the year ended December 31, 2009. In May 2009, Duke Energy’s Chief Executive Officer, as required by Section 303A.12(a) of the NYSE Listed Company Manual, certified to the NYSE that he was not aware of any violation by Duke Energy of the NYSE’s corporate governance listing standards.

 

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

 

    

2009

 

  

2008

 

  

2007

 

  

2006

 

  

2005

 

 
     (in millions, except per-share amounts)

Statement of Operations

              

Total operating revenues

   $  12,731        $  13,207         $  12,720         $  10,607        $  6,906   

Total operating expenses

     10,518          10,765           10,222           9,210          5,586   

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

     —          —           —           201          191   

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

     36          69           (5)          223          (55)  
 

Operating income

     2,249          2,511           2,493           1,821          1,456   

Total other income and expenses

     333          121           428           354          217   

Interest expense

     751          741           685           632          381   
 

Income from continuing operations before income taxes

     1,831          1,891           2,236           1,543          1,292   

Income tax expense from continuing operations

     758          616           712           450          375   
 

Income from continuing operations

     1,073          1,275           1,524           1,093          917   

Income (loss) from discontinued operations, net of tax

     12          16           (22)          783          935   
 

Income before cumulative effect of change in accounting principle and extraordinary items

     1,085          1,291           1,502           1,876          1,852   

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

     —          —           —           —          (4)  

Extraordinary items, net of tax

     —          67           —           —          —   
 

Net income

     1,085          1,358           1,502           1,876          1,848   

Dividends and premiums on redemption of preferred and preference stock

     —          —           —           —          12   

Net income (loss) attributable to noncontrolling interests

     10          (4)          2           13          24   
 

Net income attributable to Duke Energy Corporation

   $ 1,075        $ 1,362         $ 1,500         $ 1,863        $ 1,812   
 

Ratio of Earnings to Fixed Charges

     3.0          3.4           3.7           2.6          2.4   

Common Stock Data

              

Shares of common stock outstanding(c)

              

Year-end

     1,309          1,272           1,262           1,257          928   

Weighted average—basic

     1,293          1,265           1,260           1,170          934   

Weighted average—diluted

     1,294          1,267           1,265           1,188          970   

Income from continuing operations attributable to Duke Energy Corporation common shareholders

              

Basic

   $ 0.82        $ 1.01         $ 1.21         $ 0.92        $ 0.94   

Diluted

     0.82          1.01           1.20           0.91          0.92   

Income (loss) from discontinued operations attributable to Duke Energy Corporation common shareholders

              

Basic

   $ 0.01        $ 0.02         $ (0.02)        $ 0.67        $ 1.00   

Diluted

     0.01          0.01           (0.02)          0.66          0.96   

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

              

Basic

   $ 0.83        $ 1.03         $ 1.19         $ 1.59        $ 1.94   

Diluted

     0.83          1.02           1.18           1.57          1.88   

Earnings per share (from extraordinary items)

              

Basic

   $ —        $ 0.05         $ —         $ —        $ —   

Diluted

     —          0.05           —           —          —   

Net income attributable to Duke Energy Corporation common shareholders

              

Basic

   $ 0.83        $ 1.08         $ 1.19         $ 1.59        $ 1.94   

Diluted

     0.83          1.07           1.18           1.57          1.88   

 

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2009

 

  

2008

 

  

2007

 

  

2006

 

  

2005

 

 
     (in millions, except per-share amounts)

Dividends per share(d)

     0.94          0.90           0.86           1.26          1.17   

Balance Sheet

              

Total assets

   $  57,040        $  53,077         $  49,686         $  68,700        $  54,723   

Long-term debt including capital leases, less current maturities

   $  16,113        $  13,250         $  9,498         $  18,118        $  14,547   

 

(a) Significant transactions reflected in the results above include: 2009 impairment of goodwill and other assets (see Note 11 to the Consolidated Financial Statements, “Goodwill and Intangible Assets”), 2007 spin-off of the natural gas businesses (see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”), 2006 merger with Cinergy, 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006, 2005 DENA disposition, 2005 deconsolidation of DCP Midstream effective July 1, 2005, and 2005 Duke Energy Field Services, LLC (DEFS) sale of Texas Eastern Products Pipeline Company, LLC (TEPPCO).
(b) Periods prior to 2009 have been recast to reflect the adoption of the noncontrolling interest presentation provisions of Accounting Standards Codification 810 – Consolidation, which was adopted by Duke Energy effective January 1, 2009.
(c) 2006 increase primarily attributable to issuance of approximately 313 million shares in connection with Duke Energy’s merger with Cinergy.
(d) 2007 decrease due to the spin-off of the natural gas businesses to shareholders on January 2, 2007 as dividends subsequent to the spin-off were split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximated the former total dividend of Duke Energy prior to the spin-off.

 

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

INTRODUCTION

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

EXECUTIVE OVERVIEW

2009 Financial Results. For the year-ended December 31, 2009, Duke Energy Corporation (Duke Energy) reported net income attributable to Duke Energy of $1,075 million and basic and diluted earnings per share (EPS) of $0.83, as compared to net income attributable to Duke Energy of $1,362 million and basic and diluted EPS of $1.08 and $1.07, respectively, for the year-ended December 31, 2008. Income from continuing operations was $1,073 million for 2009 as compared to $1,275 million for 2008. Total reportable segment EBIT (defined below in “Segment Results” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations) decreased to $2,713 million in 2009 from $3,073 million in 2008.

See “Results of Operations” below for a detailed discussion of the consolidated results of operations, as well as a detailed discussion of EBIT results for each of Duke Energy’s reportable business segments, as well as Other.

2009 Areas of Focus and Accomplishments. In 2009, management was focused on managing through the economic recession, investing in modernization of Duke Energy’s regulated infrastructure and dealing with increased competition in Ohio.

Managing Through the Economic Recession and Changing Competitive Landscapes. In U.S. Franchised Electric and Gas, Duke Energy’s largest business segment, weather-normalized electric volumes were down approximately 4% when compared to 2008. This was driven primarily by a decrease in industrial sales volumes, which were down approximately 14% compared to 2008. Although industrial sales volumes were down year over year, industrial volumes began to show signs of stabilization late in 2009. On a weather-normalized basis, residential sales volumes were slightly positive, while commercial sales volumes were slightly negative. Looking forward to 2010, management expects the load forecast to be relatively flat compared to 2009.

In 2009, Commercial Power’s operations were impacted by the competitive markets in Ohio, which were triggered by low commodity prices that put downward pressure on power prices. The available capacity and lower prices provided opportunities for native load customers in Ohio to switch generation suppliers. Competitive power suppliers began supplying power to current Commercial Power native load customers in Ohio and Commercial Power experienced an increase in customer switching beginning in the second quarter of 2009. As of December 31, 2009, customer switching levels approximated 40% of Commercial Power’s native load. However, through Duke Energy Retail Sales (DERS), Commercial Power acquired approximately 60% of the switched load by offering customers a discount to the Electric Security Plan (ESP) price. When factoring in the DERS activity, Commercial Power experienced net customer switching of about 15%, although those native load customers acquired by DERS were at lower margins than customers served under the ESP. Additionally, DERS has been able to acquire new customers outside Commercial Power’s native load territory. As a result of lower forecasted energy prices, lower demand for electricity due to the economy and competitive pressures in Ohio, and other valuation factors, a non-cash goodwill impairment charge of approximately $371 million was recorded by Commercial Power in the third quarter of 2009.

In light of the above economic factors that impacted Duke Energy’s business in 2009, management was focused on offsetting those economic pressures by successfully managing costs and achieving excellent operational performance. Duke Energy achieved significant operations and maintenance cost mitigation goals across its business segments and also reduced planned capital expenditures by approximately $200 million, which highlights Duke Energy’s ability to take advantage of the flexibility within its capital spending plan. Additionally, Duke Energy’s generation fleet operated at some of the highest levels in Duke Energy’s history. These combined efforts allowed Duke Energy to largely mitigate the negative impact of the economy on its results of operations in 2009.

Key Regulatory Accomplishments. During 2009, Duke Energy completed the following regulatory initiatives:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

Overall, the regulatory and legislative accomplishments during 2009 have positioned Duke Energy well for 2010 and beyond.

Capital Expenditures and Fleet and Grid Modernization. Duke Energy’s strategy for meeting customer demand, while building a sustainable business that allows its customers and its shareholders to prosper in a carbon-constrained environment, includes significant commitments to renewable energy, customer energy efficiency, advanced nuclear power, advanced clean-coal and high-efficiency natural gas electric generating plants, and retirement of older less efficient coal-fired power plants. Due to the likelihood of upcoming environmental regulations, including carbon legislation, air pollutant regulation by the U.S. Environmental Protection Agency (EPA) and coal regulation, Duke Energy has been focused on modernizing its fleet in preparation for a low carbon future. During 2009, Duke Energy has continued the construction of Cliffside Unit 6 in North Carolina and the Edwardsport IGCC plant in Indiana and these construction projects are approximately 55% complete and 50% complete, respectively, at December 31, 2009. Both are scheduled to be placed in service during 2012. Once in service, Duke Energy will begin retiring older, less efficient coal and gas-fired units. Additionally, Duke Energy Carolinas has begun construction on a 620 megawatt (MW) combined cycle natural gas-fired generating facility at each of its existing Buck and Dan River Steam Stations. These facilities are scheduled to be placed in service in 2011 and 2012, respectively. In conjunction with these and other capital projects, management is continuing its focus on reducing regulatory lag, which refers to the period of time between making an investment and earning a return and recovering that investment. In 2007, the Indiana Utility Regulatory Commission (IURC) approved the timely recovery of initial construction cost estimates associated with the Edwardsport IGCC plant. The 2009 rate case settlements in North Carolina and South Carolina included stipulations allowing for the recovery in base rates of financing costs related to Cliffside Unit 6, although the recovery is delayed in North Carolina for a one year period.

 

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Duke Energy Carolinas is also continuing to seek all necessary regulatory approvals for the proposed William States Lee III Nuclear Station, including the December 2007 filings of a Combined Construction and Operating License (COL) application with the Nuclear Regulatory Commission (NRC) and requests to incur up to $230 million in development costs through 2009, which were approved in 2008. Although these actions are necessary steps as management continues to pursue the option of building a new nuclear plant, submitting these applications does not commit Duke Energy Carolinas to build a nuclear unit.

In 2009, Duke Energy made significant strides in adding to its existing renewable energy portfolio. One way Duke Energy is reducing its environmental footprint while meeting demand for reliable, clean energy is by investing in zero carbon wind power. During 2009, Commercial Power, through Duke Energy Generation Services (DEGS), brought approximately 364 MW of wind generation online through a combination of completed construction and acquisition. At December 31, 2009, DEGS had approximately 735 MW of wind generation in commercial operation. The wind assets in service have long-term power purchase agreements to sell the output to an end customer. Additionally, DEGS became an owner in a biomass development joint venture and, in early 2010, announced it would acquire a 16 MW solar development project in San Antonio, Texas.

Management is also making progress on increasing the role energy efficiency will have in meeting customers’ growing energy needs. Energy efficiency is considered a “fifth fuel” in the portfolio available to meet customers’ growing needs for electricity, along with coal, nuclear, natural gas and renewable energy. During 2009, Duke Energy’s save-a-watt models were approved in North Carolina, South Carolina and Ohio and Duke Energy is awaiting a decision on the proposed save-a-watt model in Indiana, which is expected in the first quarter of 2010. The save-a-watt proposal in Kentucky was withdrawn and will be addressed in Duke Energy Kentucky’s next general rate case.

Duke Energy Objectives – 2010 and beyond. Duke Energy will continue to focus on operational excellence, shaping federal and state legislative and regulatory policy, continued modernization of infrastructure and investing in renewable energy, including energy efficiency. The majority of future earnings are anticipated to be contributed from U.S. Franchised Electric and Gas, which consists of Duke Energy’s regulated businesses that currently own a capacity of approximately 27,000 MW of generation. The regulated generation portfolio consists of a mix of coal, nuclear, natural gas and hydroelectric generation, with the substantial majority of all of the sales of electricity coming from coal and nuclear generation facilities. The favorable rate case outcomes reached in the various jurisdictions in 2009, as discussed above, will increase U.S. Franchised Electric and Gas’ revenues by approximately $460 million upon full implementation.

As a result of the downturn in the economy, Duke Energy experienced reductions in sales volumes in 2009, most notably within the industrial customer class. Management anticipates that recessionary pressures will continue in 2010, resulting in essentially flat kilowatt-hour sales in both the Carolinas and the Midwest service territories. In order to address these pressures, management is focused on containing costs in 2010 and currently expects non-recoverable (i.e., not directly recovered via a rider or other mechanism) operations and maintenance expense to be flat compared to 2009, due largely to sustainable reductions achieved during 2009, as well as certain 2010 initiatives such as a voluntary severance program and office consolidation. In addition, management will continue efforts to achieve constructive regulatory outcomes to reduce regulatory lag, including continually reviewing the need for general rate case filings in certain jurisdictions in 2010 and beyond.

Additionally, due to the competitive markets in Ohio, customer switching will continue to impact the results of the Commercial Power business, as management currently estimates that an incremental 5% of current customer load will switch to alternative suppliers in 2010. Management is focused on mitigating lost volume and margin erosion in 2010 through DERS efforts to acquire native load customers, as well as acquiring customers outside of Commercial Power’s Ohio native load territory that are currently supplied by other electric generators.

During the three-year period from 2010 through 2012, Duke Energy anticipates total capital expenditures of approximately $14 billion to $15 billion. Of this amount, approximately $5.7 billion is expected to be spent on committed projects, including base load power plants to meet long-term growth in customer demand and to modernize the generation fleet, ongoing environmental projects, and nuclear fuel. Approximately $6.8 billion of capital expenditures are expected to be used primarily for overall system maintenance, customer connections, and corporate expenditures. Although these expenditures are ultimately necessary to ensure overall system maintenance and reliability, the timing of the expenditures may be influenced by broad economic conditions and customer growth. The remaining estimated capital expenditures of approximately $1.2 billion to $2.7 billion are of a discretionary nature and relate to growth opportunities in which Duke Energy may invest, provided there are opportunities to meet return expectations along with assurance of constructive regulatory treatment in the regulated businesses. Discretionary capital primarily includes Commercial Power renewable and transmission projects, projects at International Energy and renewable projects at U.S. Franchised Electric and Gas. Capital expenditures are currently estimated to be approximately $5.2 billion in 2010. These expenditures are principally related to expansion plans, maintenance costs, environmental spending related to Clean Air Act (CAA) requirements and nuclear fuel. Duke Energy is committed to adding base load capacity at a reasonable price while modernizing the current generation facilities by replacing older, less efficient plants with cleaner, more efficient plants. Significant expansion projects include the Edwardsport IGCC plant, an 825 MW coal unit at Duke Energy Carolinas’ existing Cliffside facility and new gas-fired generation units at Duke Energy Carolinas’ existing Dan River and Buck Steam Stations, as well as other additions due to system growth. Additionally, Duke Energy is evaluating the potential construction of the William States Lee III nuclear power plant in Cherokee County, South Carolina.

Duke Energy anticipates capital expenditures at Commercial Power will primarily relate to growth opportunities, such as renewable energy generation projects and environmental control equipment, as well as maintenance on existing plants. Capital expenditures at International Energy, which will be funded with cash held or raised by International Energy, will primarily be for strategic growth opportunities, as well as maintenance on existing plants.

With the exception of equity issuances to fund the dividend reinvestment plan and other internal plans, Duke Energy does not currently anticipate the issuance of any other common equity in the foreseeable future. Duke Energy expects to have access to liquidity in the capital markets at reasonable rates and terms in 2010. Additionally, Duke Energy has access to unsecured revolving credit facilities, which are not restricted upon general market conditions, with aggregate bank commitments of approximately $3.14 billion. At December 31, 2009, Duke Energy has available borrowing capacity of approximately $1.9 billion under this facility. For further information related to management’s assessment of liquidity and capital resources, including known trends and uncertainties, see “Liquidity and Capital Resources” below.

        As the majority of Duke Energy’s anticipated future capital expenditures are related to its regulated operations, a risk to Duke Energy is the ability to recover costs related to such expansion in a timely manner. Energy legislation passed in North Carolina and South Carolina in 2007 provides, among other things, mechanisms for Duke Energy to recover financing costs for new nuclear or coal base load generation during the construction phase. In Indiana, Duke Energy has received approval to recover its development costs for the new IGCC plant at the Edwardsport Generating Station. Duke Energy has received approval for nearly $260 million of future federal tax credits related to costs to be incurred for the modernization of Cliffside Unit 6, as well as the IGCC plant in Indiana. In addition, Duke Energy has received general assurances from the North Carolina Utilities Commission (NCUC) that the North Carolina allocable portion of development costs associated with the William States Lee III nuclear station will be recoverable through a future rate case proceeding as long as the costs are deemed prudent and reasonable. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state legislators or regulators.

 

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

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable regulated businesses like U.S. Franchised Electric and Gas and certain portions of Commercial Power’s operations, and the traditionally higher-growth businesses like the unregulated portion of Commercial Power’s operations and International Energy. As was the case throughout much of 2009, all of Duke Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market prices of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2010 and beyond.

As Duke Energy experienced in 2009, declines in demand for electricity as a result of economic downturns reduce overall electricity sales and have the potential to lessen Duke Energy’s cash flows, especially as industrial customers reduce production and, thus, consumption of electricity. A weakening economy could also impact Duke Energy’s customer’s ability to pay, causing increased delinquencies, slowing collections and lead to higher than normal levels of accounts receivables, bad debts and financing requirements. A portion of U.S. Franchised Electric and Gas’ business risk is mitigated by its regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses. The ESP in Ohio also helps mitigate a portion of the risk associated with certain portions of Commercial Power’s generation operations by providing mechanisms for recovery of certain costs associated with, among other things, fuel and purchased power for native-load customers.

If negative market conditions should persist over time and estimated cash flows over the lives of Duke Energy’s individual assets, including goodwill, do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. A change in management’s intent about the use of individual assets (held for use versus held for sale) could also result in impairments or losses.

Duke Energy’s 2010 goals can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in the United States (U.S.) are subject to regulation on the federal and state level. Regulations, applicable to the electric power industry, have a significant impact on the nature of the businesses and the manner in which they operate. New legislation and changes to regulations are ongoing, including anticipated carbon legislation, and Duke Energy cannot predict the future course of changes in the regulatory or political environment or the ultimate effect that any such future changes will have on its business.

Duke Energy’s earnings are impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as there are timing differences as to when such costs are recovered in rates. To mitigate these risks, Duke Energy enters into derivative instruments to effectively hedge some, but not all, known exposures.

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

Duke Energy also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by cash flow from operations. An inability to access capital at competitive rates or at all could adversely affect Duke Energy’s ability to implement its strategy. Market disruptions or a downgrade of Duke Energy’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity. Additionally, there are no assurances that commitments made by lenders under Duke Energy’s credit facilities will be available if needed as a source of funding due to ongoing uncertainties in the financial services industry.

For further information related to management’s assessment of Duke Energy’s risk factors, see Item 1A. “Risk Factors.”

RESULTS OF OPERATIONS

Consolidated Operating Revenues

Year Ended December 31, 2009 as Compared to December 31, 2008. Consolidated operating revenues for 2009 decreased approximately $476 million compared to 2008. This change was primarily driven by the following:

 

   

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

 

   

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

Partially offsetting these decreases was:

 

   

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

Year Ended December 31, 2008 as Compared to December 31, 2007. Consolidated operating revenues for 2008 increased approximately $487 million compared to 2007. This change was primarily driven by the following:

 

   

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

 

   

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

Partially offsetting these increases was:

 

   

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

Consolidated Operating Expenses

Year Ended December 31, 2009 as Compared to December 31, 2008. Consolidated operating expenses for 2009 decreased approximately $247 million compared to 2008. This change was driven primarily by the following:

 

   

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

 

   

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

 

   

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

 

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Partially offsetting these decreases was:

 

   

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

Year Ended December 31, 2008 as Compared to December 31, 2007. Consolidated operating expenses for 2008 increased approximately $543 million compared to 2007. This change was driven primarily by the following:

 

   

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

 

   

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

 

   

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

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

Consolidated gains (losses) on sales of other assets and other, net was a gain of approximately $36 million and $69 million in 2009 and 2008, respectively, and a loss of approximately $5 million for 2007. The gains and losses for all years relate primarily to sales of emission allowances by U.S. Franchised Electric and Gas and Commercial Power.

Consolidated Operating Income

Year Ended December 31, 2009 as Compared to December 31, 2008. For 2009, consolidated operating income decreased approximately $262 million compared to 2008. Drivers to operating income are discussed above.

Year Ended December 31, 2008 as Compared to December 31, 2007. For 2008, consolidated operating income increased approximately $18 million compared to 2007. Drivers to operating income are discussed above.

Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses

Year Ended December 31, 2009 as Compared to December 31, 2008. For 2009, consolidated other income and expenses increased approximately $212 million compared to 2008. This increase was primarily driven by an increase in equity earnings of approximately $172 million due mostly to impairment charges recorded by Crescent JV (Crescent) in 2008, of which Duke Energy’s proportionate share was approximately $238 million, partially offset by decreased equity earnings from International Energy of approximately $55 million primarily related to lower contributions from its investment in National Methanol Company (NMC) and losses from its investment in Attiki Gas Supply S.A. (Attiki). Also, the mark-to-market and investment income on investments that support benefit obligations and within the captive insurance portfolio increased approximately $45 million as a result of gains in 2009 compared to losses in 2008. Additionally, foreign exchange impacts, primarily related to the remeasurement of certain U.S. dollar denominated cash and debt balances at International Energy, resulted in gains in 2009 compared to losses in 2008 due to favorable foreign exchange rates, resulting in an increase of approximately $43 million in 2009 compared to 2008. Partially offsetting these increases was decreased interest income of approximately $53 million due primarily to lower average cash and short-term investment balances, an approximate $26 million charge in 2009 related to certain performance guarantees Duke Energy had issued on behalf of Crescent and an approximate $18 million impairment charge in 2009 to write down the carrying value of International Energy’s investment in Attiki to its fair value.

Year Ended December 31, 2008 as Compared to December 31, 2007. For 2008, consolidated other income and expenses decreased approximately $307 million compared to 2007. This decrease was primarily driven by a decrease in equity earnings of approximately $259 million due primarily to impairment charges recorded by Crescent, of which Duke Energy’s proportionate share was approximately $238 million, partially offset by increased equity earnings from International Energy of approximately $25 million primarily related to its investment in NMC primarily as a result of higher margins, an approximate $62 million decrease in interest income primarily due to favorable income tax settlements in 2007 and lower earnings on invested cash and short-term investment balances during 2008 as compared to 2007, an approximate $54 million decrease due to unfavorable investment returns and an approximate $34 million decrease associated with foreign currency losses due primarily to losses in 2008 associated with the remeasurement of certain U.S. dollar denominated cash and debt balances at International Energy, partially offset by an approximate $80 million increase in the equity component of allowance for funds used during construction (AFUDC) as a result of increased capital spending and the absence of convertible debt charges of approximately $21 million recognized in 2007 related to the spin-off of Spectra Energy Corp. (Spectra Energy).

Consolidated Interest Expense

Year Ended December 31, 2009 as Compared to December 31, 2008. Consolidated interest expense increased approximately $10 million in 2009 as compared to 2008. This increase is primarily attributable to higher debt balances, partially offset by lower average interest rates on floating rate debt and commercial paper balances.

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

Consolidated Income Tax Expense from Continuing Operations

Year Ended December 31, 2009 as Compared to December 31, 2008. For 2009, consolidated income tax expense from continuing operations increased approximately $142 million compared to 2008. Although pre-tax income was lower in 2009 compared to 2008, the effective tax rate for the year ended December 31, 2009 was approximately 41% compared to 33% for the year ended December 31, 2008 due primarily to an approximate $371 million non-deductible goodwill impairment charge in 2009.

Year Ended December 31, 2008 as Compared to December 31, 2007. For 2008, consolidated income tax expense from continuing operations decreased approximately $96 million compared to 2007. This decrease primarily resulted from lower pre-tax income in 2008 compared to 2007. The effective tax rate for the year ended December 31, 2008 increased to approximately 33% compared to 32% for the year ended December 31, 2007. The increase in the effective tax rate during 2008 is primarily attributable to adjustments related to prior year tax returns, an increase in foreign taxes, a decrease in the manufacturing deduction and a deferred state tax benefit recorded in 2007 partially offset by higher AFUDC equity and a tax benefit recorded for certain foreign restructurings.

 

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

Consolidated income (loss) from discontinued operations was income of approximately $12 million and $16 million for 2009 and 2008, respectively, and a loss of $22 million for 2007. The 2008 amount is primarily comprised of Commercial Power’s sale of its 480 MW natural gas-fired peaking generating station located near Brownsville, Tennessee to Tennessee Valley Authority, which resulted in an approximate $15 million after-tax gain.

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

Extraordinary Item, net of tax

The reapplication of regulatory accounting treatment to certain of Commercial Power’s operations on December 17, 2008 resulted in an approximate $67 million after-tax (approximately $103 million pre-tax) extraordinary gain related to total mark-to-market losses previously recorded in earnings associated with open forward native load economic hedge contracts for fuel, purchased power and emission allowances, which the ESP allows to be recovered through a fuel and purchased power rider.

Segment Results

Management evaluates segment performance based on earnings before interest and taxes from continuing operations (excluding certain allocated corporate governance costs), after deducting amounts attributable to noncontrolling interests related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the amounts attributable to noncontrolling interests related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so interest and dividend income on those balances, as well as gains and losses on remeasurement of foreign currency denominated balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Energy’s ownership interest in operations without regard to financing methods or capital structures.

See Note 2 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s segment structure.

Duke Energy’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.

EBIT by Business Segment

 

    

Years Ended December 31,

 

 
     2009     2008     Variance
2009 vs.
2008
    2007     Variance
2008 vs.
2007
 
   
     (in millions)  

U.S. Franchised Electric and Gas

   $   2,321      $   2,398      $ (77   $   2,305      $ 93   

Commercial Power

     27        264        (237     278        (14

International Energy

     365        411        (46     388        23   
                                        

Total reportable segment EBIT

     2,713        3,073        (360     2,971        102   

Other

     (251     (568     317        (260     (308
                                        

Total reportable segment EBIT and other

     2,462        2,505        (43     2,711        (206

Interest expense

     (751     (741     10        (685     56   

Interest income and other(a)

     102        117        (15     201        (84

Add back of noncontrolling interest component of reportable segment and Other EBIT

     18        10        8        9        1   
                                        

Consolidated earnings from continuing operations before income taxes

   $ 1,831      $ 1,891      $ (60   $ 2,236      $ (345
                                        

 

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

Noncontrolling interest amounts presented below includes only expenses and benefits related to EBIT of Duke Energy’s joint ventures. It does not include the noncontrolling interest component related to interest and taxes of the joint ventures.

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

 

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U.S. Franchised Electric and Gas

U.S. Franchised Electric and Gas includes the regulated operations of Duke Energy Carolinas, LLC (Duke Energy Carolinas), Duke Energy Indiana, Inc. (Duke Energy Indiana), and Duke Energy Kentucky, Inc. (Duke Energy Kentucky) and certain regulated operations of Duke Energy Ohio, Inc. (Duke Energy Ohio).

 

    

Years Ended December 31,

 

 
     2009    2008    Variance
2009 vs.
2008
    2007    Variance
2008 vs.
2007
 
   
     (in millions, except where noted)  

Operating revenues

   $ 9,433    $ 10,159    $ (726   $ 9,740    $ 419   

Operating expenses

     7,263      7,889      (626     7,488      401   

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

     20      6      14             6   
                                     

Operating income

     2,190      2,276      (86     2,252      24   

Other income and expenses, net

     131      122      9        53      69   
                                     

EBIT

   $ 2,321    $ 2,398    $ (77   $ 2,305    $ 93   
                                     

Duke Energy Carolinas’ GWh sales(a)

     79,830      85,476      (5,646     86,604      (1,128

Duke Energy Midwest GWh sales(a)(b)

     56,753      62,523      (5,770     64,570      (2,047

Net proportional MW capacity in operation(c)

     26,957      27,438      (481     27,586      (148

 

(a) Gigawatt-hours (GWh).
(b) Duke Energy Ohio (Ohio transmission and distribution only), Duke Energy Indiana and Duke Energy Kentucky collectively referred to as Duke Energy Midwest within this U.S. Franchised Electric and Gas segment discussion.
(c) Megawatt (MW).

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

 

     2009     2008     2007  
Increase (decrease) over prior year                   
   

Residential sales(a)

   (0.2 )%    (0.5 )%    6.5

General service sales(a)

   (1.1 )%    (0.5 )%    5.4

Industrial sales(a)

   (15.2 )%    (5.5 )%    (2.3 )% 

Wholesale sales

   (31.6 )%    11.9   40.9

Total Duke Energy Carolinas’ sales(b)

   (6.6 )%    (1.3 )%    4.8

Average number of customers

   0.5   1.5   2.0

 

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

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

 

     2009     2008    

2007

 
Increase (decrease) over prior year                   
   

Residential sales(a)

   (4.3 )%    (3.0 )%    6.7

General service sales(a)

   (3.5 )%    (1.2 )%    6.3

Industrial sales(a)

   (15.0 )%    (6.5 )%    (0.4 )% 

Wholesale sales

   (20.8 )%    1.5   7.7

Total Duke Energy Midwest’s sales(b)

   (9.2 )%    (3.2 )%    4.5

Average number of customers

   (0.3 )%    0.3   0.8

 

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

 

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

Operating Revenues. The decrease was driven primarily by:

 

   

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

 

   

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

 

   

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

 

   

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

Partially offsetting these decreases was:

 

   

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

Operating Expenses. The decrease was driven primarily by:

 

   

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

 

   

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

 

   

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

Partially offsetting these decreases was:

 

   

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

Gains (Losses) on Sales of Other Assets and Other, net. The increase is primarily due to gains on the sale of nitrogen oxide (NOx) emission allowances in 2009.

Other Income and Expenses, net. The increase is due primarily to a higher equity component of AFUDC earned from additional capital spending for ongoing construction projects, partially offset by a favorable 2008 IURC ruling.

EBIT. The decrease resulted primarily from lower weather adjusted sales volumes, milder weather, lower wholesale power revenues, higher benefits costs and higher property and other taxes. These negative impacts were partially offset by decreased operation and maintenance costs as a result of lower outage and maintenance costs, lower depreciation rates in the Carolinas and overall net higher rates and rate riders.

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

U.S. Franchised Electric and Gas continues to increase the overall number of retail customers served, maintain low costs and deliver high-quality customer service in the Carolinas and Midwest; however, sales to all retail customer classes were negatively impacted by the economic downturn in 2009, particularly sales to the industrial sector. These trends are expected to continue for some period into 2010, and perhaps beyond, until the economy begins to recover. The general decline in the textile industry in the Carolinas, exacerbated by the struggling economy, is also expected to continue in 2010, fueled by the expiration of certain import limitations related to foreign textile products.

U.S. Franchised Electric and Gas evaluates the carrying amount of its recorded goodwill for impairment on an annual basis as of August 31 and performs interim impairment assessments if a triggering event occurs that indicates it is more likely than not that the fair value of a reporting unit is less than its carrying value. For further information on key assumptions that impact U.S. Franchised Electric and Gas’ goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment Assessments. As of the date of the 2009 annual impairment analysis, the fair value of U.S. Franchised Electric and Gas’ reporting units exceeded their respective carrying value, thus no goodwill impairment charges were recorded. However, the fair value of the Ohio Transmission and Distribution reporting unit (Ohio T&D), which had a goodwill balance of approximately $700 million as of December 31, 2009, exceeded the carrying value of equity by less than 15%. Management is continuing to monitor the impact of recent market and economic events to determine if it is more likely than not that the carrying value of the Ohio T&D reporting unit has been impaired. Should any such triggering events or circumstances occur in 2010 that would more likely than not reduce the fair value of the Ohio T&D reporting unit below its carrying value, management would perform an interim impairment assessment of the Ohio T&D goodwill and it is possible that a goodwill impairment charge could be recorded as a result of this assessment. Potential circumstances that could have a negative effect on the fair value of the Ohio T&D reporting unit include additional declines in load volume forecasts, changes in the weighted average cost of capital (WACC), changes in the timing and/or recovery of and on investments in SmartGrid technology, and the success of future rate case filings.

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

Operating Revenues. The increase was driven primarily by:

 

   

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

 

   

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

 

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Partially offsetting these increases were:

 

   

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

 

   

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

 

   

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

Operating Expenses. The increase was driven primarily by:

 

   

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

 

   

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

 

   

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

Partially offsetting these increases was:

 

   

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

Other Income and Expenses, net. The increase is due primarily to the equity component of AFUDC due to additional capital spending for ongoing construction projects and a favorable $25 million IURC ruling.

EBIT. The increase resulted primarily from decreased regulatory amortization, the substantial completion of the required rate reductions due to the merger with Cinergy and increased AFUDC. These increases were partially offset by the impacts of the unfavorable economy on sales, milder weather, additional depreciation as rate base increased during 2008, higher operation and maintenance costs, overall net lower retail rates and rate riders, and the 2007 DOE settlement.

Commercial Power

 

    

Years Ended December 31,

 

 
     2009     2008    Variance
2009 vs.
2008
    2007     Variance
2008 vs.
2007
 
   
     (in millions, except where noted)  

Operating revenues

    $ 2,114       $ 1,826     $ 288       $ 1,881       $ (55

Operating expenses

     2,134        1,645      489        1,618        27   

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

     12        59      (47     (7     66   
                                       

Operating income

     (8     240      (248     256        (16

Other income and expenses, net

     35        24      11        22        2   
                                       

EBIT

    $ 27       $ 264     $ (237    $ 278       $ (14
                                       

Actual plant production, GWh

     26,962        20,199      (6,763     23,702        (3,503

Net proportional megawatt capacity in operation

     8,005        7,641      364        8,019        (378

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

Operating Revenues. The increase was primarily driven by:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

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Operating Expenses. The increase was primarily driven by:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

Partially offsetting these increases was:

 

   

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

Gains (Losses) on Sales of Other Assets and Other, net. The decrease in 2009 compared to 2008 is attributable to lower gains on sales of emission allowances.

Other Income and Expenses, net. The increase in 2009 compared to 2008 is attributable to higher equity earnings of unconsolidated affiliates in 2009 primarily as a result of a full year of equity earnings from investments held by Catamount Energy Corporation (Catamount). Catamount, which is a leading wind power company, was acquired in September 2008. Partially offsetting this increase was a 2009 impairment charge to the carrying value of an equity method investment.

EBIT. The decrease is primarily attributable to higher impairment charges in 2009 primarily due to a goodwill impairment charge, partially offset by a 2008 impairment charge related to emission allowance, increased plant maintenance expenses and fewer gains on sales of emission allowances. These factors were partially offset by higher retail revenue pricing as a result of implementation of the ESP, higher margins from the Midwest gas-fired assets due to increased generation volumes and PJM capacity revenues.

Matters Impacting Future Commercial Power Results

Commercial Power’s current strategy is focused on maintaining its competitive position in Ohio, maximizing the returns and cash flows from its current portfolio, as well as growing its non-regulated renewable energy portfolio. Results for Commercial Power are sensitive to changes in power supply, power demand, fuel and power prices and weather, as well as dependent upon completion of energy asset construction projects and tax credits on renewable energy production.

Recently, low commodity prices have put downward pressure on power prices. The available capacity and lower prices have provided opportunities for customers in Ohio to switch generation suppliers. Competitive power suppliers have begun supplying power to current Commercial Power customers in Ohio and Commercial Power has experienced an increase in customer switching in the second half of 2009. Customer switching is anticipated to continue in 2010 and could have a significant impact on Commercial Power’s results. Additionally, these evolving market conditions may potentially impact Commercial Power’s ability to continue to apply regulatory accounting treatment to certain portions of its Commercial Power business segment. As of December 31, 2009, Commercial Power had regulatory assets of approximately $163 million related to under-collections under its ESP and mark-to-market losses on certain economic hedges.

As discussed in Note 11 to the Consolidated Financial Statements, “Goodwill and Intangible Assets,” Commercial Power recorded an impairment charge in the third quarter of 2009 of approximately $371 million within its non-regulated generation reporting unit to write down the goodwill to its implied fair value. As a result of this impairment charge, the carrying value of goodwill associated with the non-regulated generation reporting unit of approximately $520 million is equivalent to its implied fair value. This impairment charge was based on a number of factors, including a decline in load forecast, depressed market power prices, customer switching and carbon emission legislation and/or EPA regulation developments. Should the assumptions used related to these factors change in the future as a result of then market conditions, as well as any acceleration in the timing of carbon emission legislation/EPA regulation developments, it is possible that further goodwill impairment charges could be recorded. For further information on key assumptions that impact Commercial Power’s goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment Assessments.

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

Operating Revenues. The decrease was primarily driven by:

 

   

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

 

   

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

 

   

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

Operating Expenses. The increase was primarily driven by:

 

   

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

 

   

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

 

   

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

Partially offsetting these increases were:

 

   

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

 

   

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

 

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

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

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

International Energy

 

    

Years Ended December 31,

 

     2009    2008    Variance
2009 vs.
2008
    2007    Variance
2008 vs.
2007
 
     (in millions, except where noted)

Operating revenues

    $ 1,158     $   1,185     $ (27    $ 1,060     $ 125

Operating expenses

     834      899      (65     776      123

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

          1      (1          1
                                   

Operating income

     324      287      37        284      3

Other income and expenses, net

     63      146      (83     114      32

Expense attributable to noncontrolling interest

     22      22             10      12
                                   

EBIT

    $ 365     $ 411     $ (46    $ 388     $ 23
                                   

Sales, GWh

     19,978      18,066      1,912        17,127      939

Net proportional megawatt capacity in operation

     4,053      4,018      35        3,968      50

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

Operating Revenues. The decrease was driven primarily by:

 

   

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

 

   

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

Partially offsetting these decreases was:

 

   

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

Operating Expenses. The decrease was driven primarily by:

 

   

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

 

   

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

Partially offsetting these decreases was:

 

   

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

 

   

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

 

   

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

Other Income and Expenses, net. The decrease was driven primarily by a $41 million decrease in equity earnings at NMC as a result of lower pricing for both methanol and methyl tertiary butyl ether (MTBE), partially offset by lower butane costs, an approximate $18 million impairment of the investment in Attiki and approximately $14 million of decreased equity earnings at Attiki due to lower margins and the absence of prior year hedge income due to hedge contract terminations.

EBIT. The decrease in EBIT was primarily due to lower equity earnings at NMC and Attiki, an impairment of the investment in Attiki and unfavorable exchange rates and transmission adjustments in Brazil, partially offset by favorable hydrology in Brazil and Central America and lower operating expenses in Peru.

Matters Impacting Future International Energy Results

International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand, transmission and fuel constraints and fuel and commodity prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.

Certain of International Energy’s long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy’s outstanding local currency debt.

 

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As noted above, International Energy is committed to selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. However, International Energy periodically evaluates all of its businesses to ensure those businesses continue to align with its overall strategies. As such, International Energy is in the early stages of exploring a possible sale of certain long-lived assets in Latin America. The estimated fair value for these assets currently being evaluated for potential sale is less than carrying value. Consistent with generally accepted accounting principles (GAAP), write-downs to fair value have not been recorded on these long-lived assets as the forecasted undiscounted cash flows for the assets exceed the carrying value. In 2010, it is possible that a write-down of the carrying value of these assets to fair value could occur if a sale at an amount below carrying value becomes likely.

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

Operating Revenues. The increase was driven primarily by:

 

   

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

 

   

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

 

   

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

Operating Expenses. The increase was driven primarily by:

 

   

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

 

   

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

 

   

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

Partially offsetting these increases was:

 

   

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

 

   

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

Other Income and Expenses, net. The increase was driven primarily by a $16 million increase in equity earnings at NMC as a result of higher pricing and volumes for both methanol and MTBE and approximately $9 million of increased equity earnings at Attiki due to a hedge termination.

EBIT. The increase in EBIT was primarily due to higher average prices, increased demand, and favorable exchange rates in Brazil, higher MTBE and methanol margins and sales volumes at NMC; partially offset by unfavorable hydrology, higher royalty fees and the lack of the 2007 transmission congestion in Peru, and unfavorable results in Guatemala, primarily due to higher fuel prices and maintenance costs.

Other

 

    

Years Ended December 31,

 

 
     2009     2008     Variance
2009 vs.
2008
    2007     Variance
2008 vs.
2007
 
   
     (in millions)  

Operating revenues

    $ 128       $ 134       $ (6    $ 167       $ (33

Operating expenses

     389          429        (40       467        (38

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

     4        3        1        2        1   
                                        

Operating income

     (257     (292     35        (298     6   

Other income and expenses, net

     2        (288     290        37        (325

Benefit attributable to noncontrolling interest

     (4     (12     (8     (1     (11
                                        

EBIT

    $ (251    $ (568    $ 317       $ (260    $ (308
                                        

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

Operating Income. The increase was primarily due to favorable results at Duke Energy Trading and Marketing (DETM) and Bison Insurance Company Limited (Bison) and lower corporate costs, partially offset by higher deferred compensation expense due to improved market performance.

Other Income and Expenses, net. The increase was due primarily to impairment charges recorded by Crescent in 2008, for which Duke Energy’s proportionate share was approximately $238 million, with no comparable losses in 2009, and favorable returns on investments that support benefit obligations. Partially offsetting these favorable variances was a 2009 charge related to certain performance guarantees Duke Energy had issued on behalf of Crescent.

EBIT. The increase was due primarily to prior year losses at Crescent, favorable results at Bison and DETM and lower corporate costs, partially offset by a 2009 charge related to certain performance guarantees Duke Energy had issued on behalf of Crescent.

Matters Impacting Future Other Results

Other’s future results could be impacted by continued volatility in the debt and equity markets and other economic conditions, which could result in the recording of other-than-temporary impairment charges for investments in debt and equity securities, including certain investments in auction rate debt securities. Duke Energy analyzes all investments in debt and equity securities to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment is other-than-temporary

 

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includes, but is not limited to, the length of time over which the market value has been lower than the cost basis of the investment, the percentage decline compared to the cost of the investment and management’s intent and ability to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. For investments in debt securities, the other-than-temporary analysis also involves the consideration of underlying collateral and guarantees of principal by government entities, as well as other factors relevant to determine the amount of credit loss, if any.

In January 2010, Duke Energy announced plans to offer a voluntary severance plan to approximately 8,750 eligible employees. As this is a voluntary plan, all severance benefits offered under this plan are considered special termination benefits under GAAP. Special termination benefits are measured upon employee acceptance and recorded immediately absent a significant retention period. If a significant retention period exists, the costs of the special termination benefits are recorded ratably over the remaining service periods of the affected employees. The window for employees to request to voluntarily end their employment under this plan opened on February 3, 2010 and closed on February 24, 2010 for approximately 8,400 eligible employees. For employees affected by the consolidation of Duke Energy’s corporate functions in Charlotte, North Carolina, as discussed further below, the window will close March 31, 2010. Duke Energy currently estimates severance payments associated with this voluntary plan, based on employees’ requests to voluntarily end their employment received through February 24, 2010, of approximately $130 million. However, until management of Duke Energy approves the requests, it reserves the right to reject any request to volunteer based on business needs and/or excessive participation.

In addition, in January 2010, Duke Energy announced that it will consolidate certain corporate office functions, resulting in transitioning over the next two years of approximately 350 positions from its offices in the Midwest to its corporate headquarters in Charlotte, North Carolina. Employees who do not relocate have the option to elect to participate in the voluntary plan discussed above, find a regional position within Duke Energy or remain with Duke Energy through a transition period, at which time a reduced severance benefit would be paid under Duke Energy’s ongoing severance plan. Management cannot currently estimate the costs, if any, of severance benefits which will be paid to its employees due to this office consolidation.

Duke Energy believes that it is possible that the voluntary severance plan may trigger settlement accounting or curtailment accounting with respect to its pension and other post-retirement benefit plans. At this time, management is unable to determine the likelihood that settlement or curtailment accounting will be triggered.

Additionally, Duke Energy has a 50% ownership interest in Crescent, a partnership for U.S. tax purposes. Crescent filed for Chapter 11 Bankruptcy in a U.S. Bankruptcy Court in June 2009. As of December 31, 2009, Duke Energy believes it is more likely than not that all tax benefits associated with its investment in Crescent will be realized. However, the form, timing and structure of Crescent’s future emergence from bankruptcy remain unresolved. Based on this uncertainty, as of December 31, 2009, it is reasonably possible that Duke Energy could incur a future tax liability related to its inability to fully utilize tax losses associated with its partnership interest in Crescent and the resolution of Crescent’s emergence from bankruptcy.

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

Operating Revenues. The reduction was driven primarily by higher premiums earned by Bison in 2007 related to the assumption of liabilities by Bison from other Duke Energy business units.

Operating Expenses. The reduction was primarily driven by the establishment of reserves related to liabilities assumed by Bison from other Duke Energy business units in 2007 with no comparable charges in 2008, a prior year donation to the Duke Foundation, reduced benefit costs, and decreased severance costs. These favorable variances were partially offset by a prior year benefit related to contract settlement negotiations and unfavorable property loss experience at Bison.

Other Income and Expenses, net. The increase in net expense was primarily driven by approximately $230 million of losses at Crescent in 2008 compared to earnings of approximately $38 million in 2007 due to Duke Energy recording its proportionate share of impairment charges recorded by Crescent and lower earnings as a result of the downturn in the real estate market, unfavorable returns on investments related to executive life insurance and lower investment income at Bison, partially offset by prior year convertible debt charges of approximately $21 million related to the spin-off of Spectra Energy with no comparable charges in 2008.

EBIT. The decrease was due to Duke Energy’s proportionate share of impairment charges recorded by Crescent and lower overall earnings at Crescent, a prior year benefit related to contract settlement negotiations, unfavorable investment returns and unfavorable property loss experience at Bison, partially offset by a prior year donation to Duke Foundation, prior year convertible debt charges, decreased severance costs and reduced benefits costs.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

Regulatory Accounting

Certain of Duke Energy’s regulated operations (primarily the majority of U.S. Franchised Electric and Gas and certain portions of Commercial Power) meet the criteria for application of regulatory accounting treatment. As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP in the U.S. for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment for similar costs in Duke Energy’s jurisdictions, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment, recognition of nuclear decommissioning costs and amortization of regulatory assets. Total regulatory assets were $3,886 million as of December 31, 2009 and $4,077 million as of

 

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December 31, 2008. Total regulatory liabilities were $3,108 million as of December 31, 2009 and $2,678 million as of December 31, 2008. For further information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

In order to apply regulatory accounting treatment and record regulatory assets and liabilities, certain criteria must be met. In determining whether the criteria are met for its operations, management makes significant judgments, including determining whether revenue rates for services provided to customers are subject to approval by an independent, third-party regulator, whether the regulated rates are designed to recover specific costs of providing the regulated service, and a determination of whether, in view of the demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the operations’ costs can be charged to and collected from customers. This final criterion requires consideration of anticipated changes in levels of demand or competition, direct and indirect, during the recovery period for any capitalized costs. If facts and circumstances change so that a portion of Duke Energy’s regulated operations meet all of the scope criteria when such criteria had not been previously met, regulatory accounting treatment would be reapplied to all or a separable portion of the operations. Such reapplication includes adjusting the balance sheet for amounts that meet the definition of a regulatory asset or regulatory liability.

Commercial Power owns, operates and manages power plants in the Midwestern United States. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s generation in Ohio, primarily coal-fired assets, that are dedicated to serve Ohio native load customers (native load), as well as wholesale customers to the extent there is excess generation, and five Midwestern gas-fired non-regulated generation assets that are not dedicated to serve Ohio native load customers (non-native). The non-native generation operations do not qualify for regulatory accounting treatment as these operations do not meet the scope criteria. Most of the generation asset native load output in Ohio was contracted through the RSP through December 31, 2008. As discussed further in the notes to the Consolidated Financial Statements, specifically Note 1, “Summary of Significant Accounting Policies” and Note 4, “Regulatory Matters”, beginning on December 17, 2008, Commercial Power began applying regulatory accounting treatment to certain portions of its native load operations due to the passing of Ohio Senate Bill 221 (SB 221) and the approval of the ESP. However, other portions of Commercial Power’s native load operations continue to not qualify for regulatory accounting treatment, as certain costs of the native load operations do not result in a rate structure designed to recover the specific costs of that portion of the operations. Despite certain portions of the Ohio native load operations not qualifying for regulatory accounting treatment, all of Commercial Power’s Ohio native load operations’ rates are subject to approval by the PUCO, and thus these operations are referred to here-in as Commercial Power’s regulated operations. Moreover, generation remains a competitive market in Ohio and native load customers continue to have the ability to switch to alternative suppliers for their electric generation service. As customers switch, there is a risk that some or all of Commercial Power’s regulatory assets will not be recovered through the established riders. Duke Energy will continue to monitor the amount of native load customers that have switched to alternative suppliers when assessing the recoverability of its regulatory assets established for its native load generation operations. At December 31, 2009, management has concluded that the established regulatory assets of approximately $163 million are still probable of recovery even though there have been increased levels of customer switching.

No other operations within Commercial Power, and no operations within the International Energy business segment, qualify for regulatory accounting treatment.

The substantial majority of U.S. Franchised Electric and Gas’s operations qualify for regulatory accounting treatment and thus its costs of business and related revenues can result in the recording of regulatory assets and liabilities, as described above.

Goodwill Impairment Assessments

At December 31, 2009 and 2008, Duke Energy had goodwill balances of $4,350 million and $4,720 million, respectively. At December 31, 2009, the goodwill balances at the segment level were $3,483 million at U.S. Franchised Electric and Gas, $569 million at Commercial Power, and $298 million at International Energy. The majority of Duke Energy’s goodwill relates to the acquisition of Cinergy in April 2006, whose assets are primarily included in the U.S. Franchised Electric and Gas and Commercial Power segments. Commercial Power also has approximately $70 million of goodwill that resulted from the September 2008 acquisition of Catamount, a leading wind power company located in Rutland, Vermont. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment.

Duke Energy is required to perform an annual goodwill impairment test at the reporting unit level as of the same date each year and, accordingly, performs its annual impairment testing of goodwill for all reporting units as of August 31 each year. Duke Energy updates the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The annual analysis of the potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the fair values of reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment loss. If the carrying amount is less than fair value, further testing of goodwill impairment is not performed. Duke Energy did not record any impairment on its goodwill as a result of the 2008 or 2007 impairment tests.

Step two of the goodwill impairment test involves comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Under step two, determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The difference between the fair value of the entire reporting unit as determined in step one and the net fair value of all identifiable assets and liabilities represents the implied fair value of goodwill. The goodwill impairment charge, if any, would be the difference between the carrying amount of goodwill and the implied fair value of goodwill upon the completion of step two.

For purposes of the step one analyses, determination of reporting units’ fair value was based on a combination of the income approach, which estimates the fair value of Duke Energy’s reporting units based on estimated discounted future cash flows, and the market approach, which estimates the fair value of Duke Energy’s reporting units based on market comparables within the utility and energy industries. Based on completion of step one of the 2009 annual impairment tests, management determined that the fair values of all reporting units except for Commercial Power’s non-regulated Midwest generation reporting unit, for which the carrying value of goodwill was approximately $890 million as of the annual impairment testing date, were greater than their respective carrying values. Accordingly, for only Commercial Power’s non-regulated Midwest generation reporting unit, management was required to perform step two of the goodwill impairment test to determine the amount of the goodwill impairment.

Commercial Power’s non-regulated Midwest generation reporting unit includes nearly 4,000 MW of coal-fired generation capacity in Ohio dedicated to serve Ohio native load customers under the ESP through December 31, 2011. These assets, as excess capacity allows, also generate revenues through sales outside the native load customer base, and such revenue is termed non-native. Additionally, this reporting unit has approximately 3,600 MW of gas-fired generation capacity in Ohio, Pennsylvania, Illinois and Indiana. The businesses within Commercial Power’s non-regulated Midwest generation reporting unit operate in an unregulated environment in Ohio. As a result, the operations within this reporting unit are subjected to competitive pressures that do not exist in any of Duke Energy’s regulated jurisdictions.

Commercial Power’s other businesses, including the wind generation assets, are in a separate reporting unit for goodwill impairment testing purposes. No impairment exists with respect to Commercial Power’s wind generation assets.

 

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The fair value of the non-regulated Midwest generation reporting unit is impacted by a multitude of factors, including current and forecasted customer demand, current and forecasted power and commodity prices, impact of the economy on discount rates, valuation of peer companies, competition, and regulatory and legislative developments. Management’s assumptions and views of these factors continually evolves, and such views and assumptions used in determining the step one fair value of the reporting unit in 2009 changed significantly from those used in the 2008 annual impairment test. These factors had a significant impact on the risk-adjusted discount rate and other inputs used to value the non-regulated Midwest generation reporting unit. These factors significantly impacted management’s valuation of the reporting unit, and consequently resulted in an approximate $371 million goodwill impairment charge in 2009.

As noted above, for purposes of the step one analyses, determination of the reporting units’ fair values was based on a combination of the income approach, which estimates the fair value of Duke Energy’s reporting units based on discounted future cash flows, and the market approach, which estimates the fair value of Duke Energy’s reporting units based on market comparables within the utility and energy industries. Key assumptions used in the income approach analyses for the U.S. Franchised Electric and Gas reporting units include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts, as well as other factors, into its revenue and expense forecasts.

Estimated future cash flows under the income approach are based to a large extent on Duke Energy’s internal business plan, and adjusted as appropriate for Duke Energy’s views of market participant assumptions. In addition to the factors noted above for the Commercial Power non-regulated Midwest generation reporting unit, Duke Energy’s internal business plan reflects management’s assumptions related to customer usage and attrition based on internal data and economic data obtained from third party sources, as well as projected commodity pricing data. The business plan assumes the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, anticipated earnings/returns related to significant future capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also makes assumptions regarding the run rate of operation, maintenance and general and administrative costs based on the expected outcome of the aforementioned events. Should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, revisions to current cash flow assumptions could cause the fair value of Duke Energy’s reporting units to be significantly different in future periods.

One of the most significant assumptions that Duke Energy utilizes in determining the fair value of its reporting units under the income approach is the discount rate applied to the estimated future cash flows. Management determines the appropriate discount rate for each of its reporting units based on the weighted average cost of capital (WACC) for each individual reporting unit. The WACC takes into account both the cost of equity and pre-tax cost of debt. In calculating the WACCs, Duke Energy considered implied WACC’s for certain peer companies in determining the appropriate WACC rates to use. As each reporting unit has a different risk profile based on the nature of its operations, including factors such as regulation, the WACC for each reporting unit may differ. Accordingly, the WACCs were adjusted, as appropriate, to account for company specific risk premiums. For example, transmission and distribution reporting units generally would have a lower company specific risk premium as they do not have the higher level of risk associated with owning and operating generation assets nor do they have significant construction risk or risk associated with potential future carbon legislation or carbon regulation. The discount rates used for calculating the fair values as of August 31, 2009 for each of Duke Energy’s domestic reporting units were commensurate with the risks associated with each reporting unit and ranged from 6.0% to 9.0%. For Duke Energy’s international operations, a base discount rate of 8.5% was used, with specific adders used for each separate jurisdiction in which International Energy operates to reflect the differing risk profiles of the jurisdictions and countries. This resulted in discount rates for the August 31, 2009 goodwill impairment test for the international operations ranging from approximately 9.5% to 13.5%.

Another significant assumption that Duke Energy utilizes in determining the fair value of its reporting units under the income approach is the long-term growth rate of the businesses for purposes of determining a terminal value at the end of the discrete forecast period. A long-term growth rate of three percent was used in the valuations of all of the U.S. Franchised Electric and Gas reporting units, reflecting the median long-term inflation rate and the significant capital investments forecasted for all of the U.S. Franchised Electric and Gas reporting units. A long-term growth rate of two percent was used in the valuation of the Commercial Power non-regulated Midwest generation reporting unit given the finite lives of the unregulated generation power plants and current absence of plans to reinvest in the unregulated generation assets.

These underlying assumptions and estimates are made as of a point in time; subsequent changes, particularly changes in the discount rates or growth rates inherent in management’s estimates of future cash flows, could result in a future impairment charge to goodwill. Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.

As discussed above, with the exception of the Commercial Power non-regulated Midwest generation reporting unit, the impairment tests as of August 31, 2009 did not indicate that the fair value of any of Duke Energy’s reporting units were less than its book value. For these reporting units, the estimated fair value of equity exceeded the carrying value of equity by over 15%, with the exception of U.S. Franchised Electric and Gas’s Ohio T&D reporting unit. As of December 31, 2009, the Ohio T&D reporting unit had a goodwill balance of approximately $700 million. Potential circumstances that could have a negative effect on the fair value of the Ohio T&D reporting unit include additional declines in load volume forecasts, changes in the WACC, changes in the timing and/or recovery of and on investments in SmartGrid technology, and the success of future rate case filings.

As an overall test of the reasonableness of the estimated fair values of the reporting units, Duke Energy reconciled the combined fair value estimates of its reporting units to its market capitalization as of August 31, 2009. The reconciliation confirmed that the fair values were reasonably representative of market views when applying a reasonable control premium to the market capitalization. Additionally, Duke Energy would perform an interim impairment assessment should any events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Subsequent to August 31, 2009, management did not identify any indicators of potential impairment that required an update to the annual impairment test. The majority of Duke Energy’s business is in environments that are either fully or partially rate-regulated. In such environments, revenue requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, Duke Energy’s regulated utilities operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions. Additionally, with respect to the Commercial Power non-regulated Midwest generation reporting unit, the Ohio generation assets have begun to be negatively impacted by increased competition. However, the effects of increased competition in Ohio were appropriately considered in the August 31, 2009 valuation of the reporting unit, and subsequent to August 31, 2009 management did not identify any indicators of potential impairment that required an update to the annual impairment test. However, management will continue to monitor changes in the business, as well as overall market conditions and economic factors that could require additional impairment tests.

Revenue Recognition

Revenues on sales of electricity and gas are recognized when either the service is provided or the product is delivered. Operating revenues include unbilled electric and gas revenues earned when service has been delivered but not billed by the end of the accounting period. Unbilled retail revenues are estimated by applying an average revenue per kilowatt-hour (kWh) or per Mcf for all customer classes to

 

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the number of estimated kWh or Mcfs delivered but not billed. Unbilled wholesale energy revenues are calculated by applying the contractual rate per megawatt-hour (MWh) to the number of estimated MWh delivered but not yet billed. Unbilled wholesale demand revenues are calculated by applying the contractual rate per MW to the MW volume delivered but not yet billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are primarily recorded as Receivables on the Consolidated Balance Sheets and exclude receivables sold to Cinergy Receivables Company, LLC (Cinergy Receivables), were approximately $460 million and $390 million at December 31, 2009 and 2008, respectively. Additionally, Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana sell, on a revolving basis, nearly all of their retail accounts receivable and a portion of their wholesale accounts receivable and related collections to Cinergy Receivables, a bankruptcy remote, special purpose entity that is a wholly-owned limited liability company of Cinergy, a wholly-owned subsidiary of Duke Energy. The securitization transaction was structured to meet the criteria for sale accounting treatment under the accounting guidance for transfers and servicing of financial assets and, accordingly, the transfers of receivables are accounted for as sales. Receivables for unbilled retail and wholesale revenues of approximately $238 million and $266 million at December 31, 2009 and 2008, respectively, were included in the sales of accounts receivables to Cinergy Receivables. Effective January 1, 2010, Duke Energy began consolidating Cinergy Receivables as a result of the adoption of new accounting rules, under which the criteria for sale accounting treatment is not met.

Accounting for Loss Contingencies

Duke Energy is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its consolidated financial statements, management makes judgments regarding the future outcome of contingent events and records a loss contingency when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. Management regularly reviews current information available to determine whether such accruals should be adjusted and whether new accruals are required. Estimating probable losses requires analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, state and local courts and other regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the consolidated financial statements may differ from the actual outcome once the contingency is resolved, which could have a material impact on future results of operations, financial position and cash flows of Duke Energy.

Duke Energy has experienced numerous claims for indemnification and medical cost reimbursement relating to damages for bodily injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas on its electric generation plants prior to 1985.

Amounts recognized as asbestos-related reserves related to Duke Energy Carolinas in the Consolidated Balance Sheets totaled approximately $980 million and $1,031 million as of December 31, 2009 and 2008, respectively, and are classified in Other within Deferred Credits and Other Liabilities and Other within Current Liabilities. These reserves are based upon the minimum amount in Duke Energy’s best estimate of the range of loss for current and future asbestos claims through 2027. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe that they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change our estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside our control, management believes that it is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.

Duke Energy has a third-party insurance policy to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Duke Energy Carolinas’ cumulative payments began to exceed the self insurance retention on its insurance policy during the second quarter of 2008. Future payments up to the policy limit will be reimbursed by Duke Energy’s third party insurance carrier. The insurance policy limit for potential future insurance recoveries for indemnification and medical cost claim payments is $1,051 million in excess of the self insured retention. Insurance recoveries of approximately $984 million and $1,032 million related to this policy are classified in the Consolidated Balance Sheets in Other within Investments and Other Assets and Receivables as of December 31, 2009 and 2008, respectively. Duke Energy is not aware of any uncertainties regarding the legal sufficiency of insurance claims. Management believes the insurance recovery asset is probable of recovery as the insurance carrier continues to have a strong financial strength rating.

For further information, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Accounting for Income Taxes

Significant management judgment is required in determining Duke Energy’s provision for income taxes, deferred tax assets and liabilities and the valuation recorded against Duke Energy’s net deferred tax assets, if any.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the book basis and tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the use of tax planning that could impact the ability to realize deferred tax assets. If future utilization of deferred tax assets is uncertain, a valuation allowance may be recorded against certain deferred tax assets.

In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the impacts of various items, including changes to income tax laws, Duke Energy’s forecasted financial condition and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. Although management believes current estimates are reasonable, actual results could differ from these estimates.

        Significant judgment is also required in computing Duke Energy’s quarterly effective tax rate (ETR). ETR calculations are revised each quarter based on the best full year tax assumptions available at that time, including, but not limited to, income levels, deductions and credits. In accordance with interim tax reporting rules, a tax expense or benefit is recorded every quarter to adjust for the difference in tax expense computed based on the actual year-to-date ETR versus the forecasted annual ETR.

With the adoption of new income tax accounting guidance on January 1, 2007, Duke Energy began recording unrecognized tax benefits for positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, when a more-likely-than-not threshold is met for a tax position and management believes that the position will be sustained upon examination by the taxing authorities. Duke Energy records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant

 

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management judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in the Consolidated Financial Statements. Management reevaluates tax positions each period in which new information about recognition or measurement becomes available.

Undistributed foreign earnings associated with International Energy’s operations are considered indefinitely reinvested, thus no U.S. tax is recorded on such earnings. This assertion is based on management’s determination that the cash held in International Energy’s foreign jurisdictions is not needed to fund the operations of its U.S. operations and that International Energy either has invested or has plans to reinvest such earnings. While management currently plans to indefinitely reinvest all of International Energy’s unremitted earnings, should circumstances change, Duke Energy may need to record additional income tax expense in the period in which such determination changes.

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

Pension and Other Post-Retirement Benefits

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

Funding requirements for defined benefit (DB) plans are determined by government regulations. Duke Energy made voluntary contributions to its DB retirement plans of approximately $800 million in 2009, zero in 2008 and $350 million in 2007. Additionally, during 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans.

Duke Energy Plans

Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain non-contributory defined benefit retirement plans (Plans). The Plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain executives.

Duke Energy and most of its subsidiaries also provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Certain employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

Duke Energy recognized pre-tax qualified pension cost of $6 million in 2009. In 2010, Duke Energy’s pre-tax qualified pension cost is expected to be approximately $30 million higher than in 2009 as a result of an increase in net actuarial loss amortization in 2010, primarily attributable to the effect of negative actual returns on assets from 2008. Duke Energy recognized pre-tax nonqualified pension cost of $13 million and pre-tax other post-retirement benefits cost of $34 million, in 2009. In 2010, pre-tax non-qualified pension cost and pre-tax other post-retirement benefits costs are expected to remain approximately the same as 2009.

For both pension and other post-retirement plans, Duke Energy assumed that its plan’s assets would generate a long-term rate of return of 8.5% as of December 31, 2009. The assets for Duke Energy’s pension and other post-retirement plans are maintained in a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate. Duke Energy also invests other post-retirement assets in the Duke Energy Corporation Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBAs is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBAs are passively managed.

The expected long-term rate of return of 8.5% for the plan’s assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 3.2% for U.S. equities, 2.0% for Non-U.S. equities, 1.0% for Global equities, 2.0% for fixed income securities, and 0.3% for real estate.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 5.50% as of December 31, 2009. Duke Energy determines the appropriate discount based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third-party bond yield curve corresponding to each duration. The yield curve is based on a bond universe of AA and AAA-rated long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact Duke Energy’s future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future. The following table presents the approximate effect on Duke Energy’s 2009 pre-tax pension expense, pension obligation and other post-benefit obligation if a 0.25% change in rates were to occur:

 

     Qualified Pension Plans   Other Post-Retirement Plans
     +0.25%   -0.25%   +0.25%   -0.25%
     (in millions)

Effect on 2009 pension expense (pre-tax)

        

Expected long-term rate of return

   $ (11)       $          11    $        (1)    $        1  

 

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    Qualified Pension Plans         Other Post-Retirement Plans
    +0.25     -0.25 %        +0.25%             -0.25%    
    (in millions)

Discount rate

  $ (2 )     $ 2        $ (1)          $ 1        

Effect on benefit obligation, at December 31, 2009 Discount rate

    (99 )       99          (17)            17        

Duke Energy’s U.S. post-retirement plan uses a medical care trend rate which reflects the near and long-term expectation of increases in medical health care costs. Duke Energy’s U.S. post-retirement plan uses a prescription drug trend rate which reflects the near and long-term expectation of increases in prescription drug health care costs. As of December 31, 2009, the medical care trend rates were 8.50%, which grades to 5.00% by 2019. As of December 31, 2009, the prescription drug trend rate was 11.00%, which grades to 5.00% by 2024. The following table presents the approximate effect on Duke Energy’s 2009 pre-tax other post-retirement expense and other post-benefit obligation if a 1% point change in the health care trend rate were to occur:

 

    Other Post-Retirement Plans
    +1.0%          

 

-1.0%      

 

           
    (in millions)

Effect on other post-retirement expense

        $ 3                  $ (2)      

Effect on post-retirement benefit obligation

     38               (34)      

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

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

At December 31, 2009, Duke Energy had cash and cash equivalents of approximately $1.5 billion, of which approximately $600 million is held in foreign jurisdictions and is forecasted to be used to fund the operations of and investments in International Energy. To fund its liquidity and capital requirements during 2010, Duke Energy will rely primarily upon cash flows from operations, borrowings, equity issuances to fund the dividend reinvestment plan (DRIP) and other internal plans and its existing cash and cash equivalents. The relatively stable operating cash flows of the U.S. Franchised Electric and Gas business segment compose a substantial portion of Duke Energy’s cash flows from operations and it is anticipated that it will continue to do so for the next several years. A material adverse change in operations, or in available financing, could impact Duke Energy’s ability to fund its current liquidity and capital resource requirements.

Ultimate cash flows from operations are subject to a number of factors, including, but not limited to, regulatory constraints, economic trends and market volatility (see Item 1A. “Risk Factors” for details).

Duke Energy projects 2010 capital and investment expenditures of approximately $5.2 billion, primarily consisting of:

 

   

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

 

   

$0.6 billion at Commercial Power

 

   

$0.2 billion at International Energy and

 

   

$0.2 billion at Other

Duke Energy continues to focus on reducing risk and positioning its business for future success and will invest principally in its strongest business sectors. Based on this goal, approximately 80% of total projected 2010 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2010 capital and investment expenditures include approximately $2.3 billion for system growth, $1.6 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.2 billion of nuclear fuel and approximately $0.1 billion of environmental expenditures.

With respect to the 2010 capital expenditure plan, Duke Energy has flexibility within its $5.2 billion budget to defer or eliminate certain spending should the broad economy continue to deteriorate. Of the $5.2 billion budget, approximately $2.9 billion relates to projects for which management has committed capital, including, but not limited to, the continued construction of Cliffside Unit 6 and the Edwardsport IGCC plant, and management intends to spend those capital dollars in 2010 irrespective of broader economic factors. Approximately $2.1 billion of projected 2010 capital expenditures are expected to be used primarily for overall system maintenance, customer connections and corporate expenditures. Although these expenditures are ultimately necessary to ensure overall system maintenance and reliability, the timing of the expenditures may be influenced by broad economic conditions and customer growth, thus management has more flexibility in terms of when these dollars are actually spent. The remaining planned 2010 capital expenditures of approximately $0.2 billion are of a discretionary nature and relate to growth opportunities in which Duke Energy may invest, provided there are opportunities to meet return expectations.

As a result of Duke Energy’s significant commitment to modernize its generating fleet through the construction of new units, as well as its focus on increasing its renewable energy portfolio, the ability to cost effectively manage the construction phase of current and future projects is critical to ensuring full and timely recovery of costs of construction within its regulated operations. Should Duke Energy encounter

 

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

Duke Energy anticipates its debt to total capitalization ratio to remain at approximately 44% in 2010. In 2010, Duke Energy currently anticipates issuing additional net debt of approximately $1.7 billion at the operating subsidiary level, primarily for the purpose of funding capital expenditures. Due to the flexibility in the timing of projected 2010 capital expenditures, the timing and amount of debt issuances throughout 2010 could be influenced by changes in the timing of capital spending. Additionally, Duke Energy plans to generate approximately $400 million of cash from the issuance of common stock under its DRIP and other internal plans.

Duke Energy has access to unsecured revolving credit facilities, which are not restricted upon general market conditions, with aggregate bank commitments of approximately $3.14 billion. At December 31, 2009, Duke Energy has available borrowing capacity of approximately $1.9 billion under this facility. Management currently believes that amounts available under its revolving credit facility are accessible should there be a need to generate additional short-term financing in 2010, such as the issuance of commercial paper; however, due to the sustained downturn in overall economic conditions, specifically in the financial services sector, there is no guarantee that commitments provided by financial institutions under the revolving credit facility will be available if needed. Management expects that cash flows from operations, issuances of debt and cash generated from the issuance of common stock under the DRIP and other internal plans will be sufficient to cover the 2010 funding requirements related to capital and investments expenditures and dividend payments.

Duke Energy monitors compliance with all debt covenants and restrictions and does not currently believe it will be in violation or breach of its significant debt covenants during 2010. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Energy also maintains an active dialogue with the credit rating agencies.

Operating Cash Flows

Net cash provided by operating activities was $3,463 million in 2009, compared to $3,328 million in 2008, an increase in cash provided of $135 million. The increase in cash provided by operating activities was driven primarily by:

 

   

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

 

   

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

 

   

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

Net cash provided by operating activities was $3,328 million in 2008, compared to $3,208 million in 2007, an increase in cash provided of $120 million. The increase in cash provided by operating activities was driven primarily by:

 

   

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

 

   

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

Investing Cash Flows

Net cash used in investing activities was $4,492 million in 2009, $4,611 million in 2008, and $2,151 million in 2007.

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

Capital, Investment and Acquisition Expenditures by Business Segment

 

    Years Ended December 31,

 

    

 

2009

 

  

 

2008

 

  

 

2007

 

    (in millions)

U.S. Franchised Electric and Gas

   $ 3,560     $ 3,650     $ 2,613

Commercial Power

    688      870      442

International Energy

    128      161      74

Other

    181      241      153
                   

Total consolidated

   $  4,557     $  4,922     $  3,282
                   

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

 

   

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

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

 

   

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