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 1943

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal period ended December 31, 2012 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	Exact name of registrants as specified in theircharters, addresses of principal executiveoffices,  telephone numbers and states of incorporation	IRS Employer Identification No.
1-32853	DUKE ENERGY CORPORATION 550 South Tryon Street Charlotte, NC 28202-1803 704-382-3853 State of Incorporation: Delaware	20-2777218
1-4928	DUKE ENERGY CAROLINAS, LLC 526 South Church Street Charlotte, NC 28202-1803 704-382-3853 State of Incorporation: North Carolina	56-0205520
1-15929	PROGRESS ENERGY, INC. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 704-382-3853 State of Incorporation: North Carolina	56-2155481
1-3382	CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. 410 South Wilmington Street Raleigh, North Carolina  27601-1748 704-382-3853 State of Incorporation: North Carolina	56-0165465
1-3274	FLORIDA POWER CORPORATION  d/b/a PROGRESS ENERGY FLORIDA, INC. 299 First Avenue North St. Petersburg, Florida 33701 704-382-3853 State of Incorporation: Florida	59-0247770
1-1232	DUKE ENERGY OHIO, INC. 139 East Fourth Street Cincinnati, OH 45202 704-382-3853 State of Incorporation: Ohio	31-0240030
1-3543	DUKE ENERGY INDIANA, INC. 1000 East Main Street Plainfield, IN 46168 704-382-3853 State of Incorporation: Indiana	35-0594457

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

Registrant	Title of each class	Name of each exchange on which registered
Duke Energy Corporation (Duke Energy)	Common Stock, $0.001 par value	New York Stock Exchange, Inc.
Duke Energy	5.125% Junior Subordinated Debentures due January 15, 2073	New York Stock Exchange, Inc.
Duke Energy Carolinas, LLC (Duke Energy Carolinas)	All of the registrant’s limited liability company member interests are directly owned by Duke Energy.
Progress Energy, Inc. (Progress Energy)	All of the registrant’s common stock is directly owned by Duke Energy.
Progress Energy Carolinas, Inc. (Progress Energy Carolinas)	All of the registrant’s common stock is indirectly owned by Duke Energy.
Progress Energy Florida, Inc. (Progress Energy Florida)	All of the registrant’s common stock is indirectly owned by Duke Energy.
Duke Energy Ohio, Inc. (Duke Energy Ohio)	All of the registrant’s common stock is indirectly owned by Duke Energy.
Duke Energy Indiana, Inc. (Duke Energy Indiana)	All of the registrant’s common stock is indirectly owned by Duke Energy.

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

Registrant	Name of each exchange on which registered
Duke Energy	None
Duke Energy Carolinas	None
Progress Energy	None
Progress Energy Carolinas	$5 Preferred Stock, No Par Value; Serial Preferred stock, No Par Value
Progress Energy Florida	None
Duke Energy Ohio	None
Duke Energy Indiana	None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Duke Energy	Yes x	No ¨	Progress Energy Florida	Yes x	No ¨
Duke Energy Carolinas	Yes x	No ¨	Duke Energy Ohio	Yes ¨	No x
Progress Energy	Yes ¨	No x	Duke Energy Indiana	Yes ¨	No x
Progress Energy Carolinas	Yes x	No ¨

Indicate by check mark if the registrant is not required to file reports to pursuant to Section 13 or Section 15(d) of the Exchange Act.

Duke Energy	Yes ¨	No x	Progress Energy Florida	Yes ¨	No x
Duke Energy Carolinas	Yes ¨	No x	Duke Energy Ohio	Yes ¨	No x
Progress Energy	Yes ¨	No x	Duke Energy Indiana	Yes ¨	No x
Progress Energy Carolinas	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.

Duke Energy	Yes x	No ¨	Progress Energy Florida	Yes x	No ¨
Duke Energy Carolinas	Yes x	No ¨	Duke Energy Ohio	Yes x	No ¨
Progress Energy	Yes x	No ¨	Duke Energy Indiana	Yes x	No ¨
Progress Energy Carolinas	Yes x	No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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).

Duke Energy	Yes x	No ¨	Progress Energy Florida	Yes x	No ¨
Duke Energy Carolinas	Yes x	No ¨	Duke Energy Ohio	Yes x	No ¨
Progress Energy	Yes x	No ¨	Duke Energy Indiana	Yes x	No ¨
Progress Energy Carolinas	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.

Duke Energy	Yes ¨	No x	Progress Energy Florida	Yes x	No ¨
Duke Energy Carolinas	Yes x	No ¨	Duke Energy Ohio	Yes x	No ¨
Progress Energy	Yes x	No ¨	Duke Energy Indiana	Yes x	No ¨
Progress Energy Carolinas	Yes x	No ¨

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):

Duke Energy	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
Duke Energy Carolinas	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
Progress Energy	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
Progress Energy Carolinas	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
Progress Energy Florida	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
Duke Energy Ohio	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
Duke Energy Indiana	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Duke Energy	Yes ¨	No x	Progress Energy Florida	Yes ¨	No x
Duke Energy Carolinas	Yes ¨	No x	Duke Energy Ohio	Yes ¨	No x
Progress Energy	Yes ¨	No x	Duke Energy Indiana	Yes ¨	No x
Progress Energy Carolinas	Yes ¨	No x

Estimated aggregate market value of the common equity held by nonaffiliates of Duke Energy Corporation at June 30, 2012.	30,788,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at February 25, 2013.	704,653,826

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Duke Energy definitive proxy statement for the 2013 Annual Meeting of the Shareholders or an amendment to this Annual Report are incorporated by reference into PART III, Items 10, 11, 12, 13, and 14 hereof.

This combined Form 10-K is filed separately by seven registrants: Duke Energy, Duke Energy Carolinas, Progress Energy, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio and Duke Energy Indiana (collectively the Duke Energy Registrants). Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants.

Duke Energy Carolinas, Progress Energy, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio and Duke Energy Indiana meet the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and are therefore filing this form with the reduced disclosure format specified in General Instructions I(2) of Form 10-K.  

TABLE OF CONTENTS
FORM 10-K FOR THE YEAR ENDED December 31, 2012
Item			Page
PART I.
DUKE ENERGY CORPORATION (DUKE ENERGY)
1.	BUSINESS......................................................................................		9
		GENERAL...........................................................................
		U.S. FRANCHISED ELECTRIC AND GAS............................
		COMMERCIAL POWER.......................................................
		INTERNATIONAL ENERGY.................................................
		OTHER...............................................................................
		GEOGRAPHIC REGIONS....................................................
		EMPLOYEES......................................................................
		EXECUTIVE OFFICERS OF DUKE ENERGY........................
		ENVIRONMENTAL MATTERS………………………………
DUKE ENERGY CAROLINAS, LLC (DUKE ENERGY CAROLINAS)
PROGRESS ENERGY, INC. (PROGRESS ENERGY)
CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. (PROGRESS ENERGY CAROLINAS)
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC (PROGRESS ENERGY FLORIDA)
DUKE ENERGY OHIO, INC. (DUKE ENERGY OHIO)
DUKE ENERGY INDIANA, INC. (DUKE ENERGY INDIANA)
1A.	RISK FACTORS........................................................................		24
1B.	UNRESOLVED STAFF COMMENTS..........................................		29
2.	PROPERTIES.............................................................................		30
3.	LEGAL PROCEEDINGS.............................................................		34
4.	MINE SAFETY DISCLOSURE.....................................................		34
PART II.
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES..............................................................................		35
6.	SELECTED FINANCIAL DATA...................................................		37
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS..........................		38
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........................................................................................		74
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......		81
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..........................		271
9A.	CONTROLS AND PROCEDURES...............................................		271
PART III.
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.................................................................................................		272
11.	EXECUTIVE COMPENSATION...................................................		272
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.....		272
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.......................................................		272
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES......................		272
PART IV.
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES ....................		274
		SIGNATURES.................................................................	276
		EXHIBIT INDEX................................................................	Exhibit-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, which are intended to cover Duke Energy and the applicable Duke Energy Registrants, are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” “target,” “guidance,” “outlook,” 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;

·The ability to recover eligible costs and earn an adequate return on investment through the regulatory process;

·The costs of retiring Progress Energy Florida’s Crystal River Unit 3 could prove to be more extensive than is currently identified.  All costs associated with the retirement Crystal River Unit 3 asset, including replacement power may not be fully recoverable through the regulatory process;

·The ability to maintain relationships with customers, employees or suppliers post-merger;

·The ability to successfully integrate the Progress Energy businesses and realize cost savings and any other synergies expected from the merger;

·The risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect;

·The impact of compliance with material restrictions or conditions related to the Progress Energy merger imposed by regulators could exceed our expectations;

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

·Industrial, commercial and residential growth or decline in the respective Duke Energy Registrants’ 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 each of the Duke Energy Registrants’ operations, including the economic, operational and other effects of storms, hurricanes, droughts and tornadoes;

·The ability to successfully operate electric generating facilities and deliver electricity to customers;

·The ability to recover, in a timely manner, if at all, costs associated with future significant weather events through the regulatory process;

·The impact on the Duke Energy Registrants’ facilities and business from a terrorist attack, cyber security threats and other catastrophic events;

·The inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, safety, regulatory and financial risks;

·The timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates and the ability to recover such costs through the regulatory process, where appropriate;

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

·The performance of electric generation facilities and of projects undertaken by Duke Energy’s nonregulated businesses;

·The results of financing efforts, including the Duke Energy Registrants’ ability to obtain financing on favorable terms, which can be affected by various factors, including the respective Duke Energy Registrants’ 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 and nuclear decommissioning trust funds;

·The level of creditworthiness of counterparties to Duke Energy Registrants’ transactions;

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

·Growth in opportunities for the respective Duke Energy Registrants’ 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 Registrants’ capital investment projects in existing and new generation facilities, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards, as well as the ability to recover costs from ratepayers in a timely manner or at all;

·The Subsidiary Registrants ability to pay dividends or distributions to Duke Energy Corporation holding company (the Parent);

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

·The impact of potential goodwill impairments;

·The ability to reinvest retained earnings of foreign subsidiaries or repatriate such earnings on a tax free basis; and

·The ability to successfully complete future 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. The Duke Energy Registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Glossary of Terms

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

Term or Acronym	Definition
the 2006 Plan.....................	Duke Energy’s 2006 Long-Term Incentive Plan
2010 Tax Relief Act............	Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010
the 2010 Plan.....................	Duke Energy’s 2010 Long-Term Incentive Plan
ADEA..................................	Age Discrimination in Employment Act
AFUDC................................	Allowance for Funds Used During Construction
Aguaytia.............................	Aguaytia Integrated Energy Project
ANEEL................................	Brazilian Electricity Regulatory Agency
AOCI...................................	Accumulated Other Comprehensive Income
ASC....................................	Accounting Standards Codification
ASU....................................	Accounting Standards Update
ATRA..................................	American Taxpayer Relief Act of 2012
Attiki....................................	Attiki Gas Supply S.A.
BCA....................................	Budget Control Act of 2011
Bison...................................	Bison Insurance Company Limited
BPM....................................	Bulk Power Marketing
Brunswick............................	Brunswick Nuclear Station
CAA....................................	Clean Air Act
CAC....................................	Citizens Action Coalition of Indiana, Inc.
CAIR...................................	Clean Air Interstate Rule
Catamount..........................	Catamount Energy Corporation
Catawba	Catawba Nuclear Station
CC.......................................	Combined Cycle
CCR....................................	Coal Combustion Residuals
CCS....................................	Carbon Capture and Storage
CG&E..................................	The Cincinnati Gas & Electric Company
CRC....................................	Cinergy Receivables Company, LLC
Cliffside Unit 6....................	Unit 6 of the Cliffside Facility in North Carolina
CT.......................................	Combustion Turbine
Cinergy...............................	Cinergy Corp. (collectively with its subsidiaries)
CO2.....................................	Carbon Dioxide
COL....................................	Combined Construction and Operating License
CPCN..................................	Certificate of Public Convenience and Necessity
CRES..................................	Competitive Retail Electric Supplier
Crescent..............................	Crescent Joint Venture (JV)
Crystal River Unit 3..............	Crystal River Nuclear Station – Unit 3
CSAPR	Cross-State Air Pollution Rule
CVO....................................	Progress Energy’s contingent value obligation
CWIP...................................	Construction Work in Progress
DAQ....................................	Division of Air Quality
DB.......................................	Defined Benefit (Pension Plan)
DECAM...............................	Duke Energy Commercial Asset Management
DEGS..................................	Duke Energy Generation Services, Inc.
DEI......................................	Duke Energy International, LLC
DEIGP.................................	Duke Energy International Geracao Paranapenema S.A.
DENR..................................	Department of Environment and Natural Resources
DERF..................................	Duke Energy Receivables Finance Company, LLC
Duke Energy Retail.............	Duke Energy Retail Sales, LLC
DETM.................................	Duke Energy Trading and Marketing, LLC
DOE....................................	U.S. Department of Energy
DOJ.....................................	U.S. Department of Justice
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.
Duke Energy Registrants......	Duke Energy, Duke Energy Carolinas, Progress Energy, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio, and Duke Energy Indiana
DukeNet..............................	DukeNet Communications, LLC
DukeSolutions.....................	DukeSolutions, Inc.
EIP......................................	Progress Energy’s Equity Incentive Plan
EPA....................................	U.S. Environmental Protection Agency
EPC....................................	Engineering, Procurement and Construction
EPS....................................	Earnings Per Share
ERISA.................................	Employee Retirement Income Security Act
ESP....................................	Electric Security Plan
ETR....................................	Effective tax rate
FASB..................................	Financial Accounting Standards Board
FCC.....................................	Federal Communications Commission
FERC..................................	Federal Energy Regulatory Commission
FDEP..................................	Florida Department of Environmental Protection
Florida Progress..................	Florida Progress Corporation
FPSC..................................	Florida Public Service Commission
Funding Corp......................	Florida Progress Funding Corporation
GAAP..................................	Generally Accepted Accounting Principles in the United States
GHG....................................	Greenhouse Gas
Global.................................	U.S. Global, LLC
GWh....................................	Gigawatt-hours
HAP....................................	Hazardous Air Pollutant
Harris...................................	Shearon Harris Nuclear Station
IAP......................................	State Environmental Agency of Parana
IBAMA................................	Brazil Institute of Environment and Renewable Natural Resources
IBNR...................................	Incurred but not yet reported
IFRS....................................	International Financial Reporting Standards
IGCC...................................	Integrated Gasification Combined Cycle
IMPA...................................	Indiana Municipal Power Agency
IRS......................................	Internal Revenue Service
ITC......................................	Investment Tax Credit
IURC...................................	Indiana Utility Regulatory Commission
KPSC..................................	Kentucky Public Service Commission
kV........................................	Kilovolt
kWh.....................................	Kilowatt-hour
Levy....................................	Progress Energy Florida’s proposed nuclear plant in Levy County, Fla.
Legacy Duke Directors.........	Members of the pre-merger Duke Energy board of directors
LIBOR.................................	London Interbank Offered Rate
MATS.................................	Mercury and Air Toxics Standards (previously referred to as the Utility MACT Rule)
Mcf......................................	Thousand cubic feet
McGuire..............................	McGuire Nuclear Station
Merger Agreement..............	Agreement and Plan of Merger with Progress Energy, Inc.
Merger Sub.........................	Diamond Acquisition Corporation
MGP...................................	Manufactured gas plant
Midwest ISO........................	Midwest Independent Transmission System Operator, Inc.
MMBtu................................	Million British Thermal Unit
Moody’s...............................	Moody’s Investor Services
MRO...................................	Market Rate Offer
MTBE.................................	Methyl tertiary butyl ether
MW.....................................	Megawatt
MVP....................................	Multi Value Projects
MWh...................................	Megawatt-hour
NCUC..................................	North Carolina Utilities Commission
NDTF..................................	Nuclear decommissioning trust funds
NEIL....................................	Nuclear Electric Insurance Limited
NMC....................................	National Methanol Company
NOL....................................	Net operating loss
NOx.....................................	Nitrogen oxide
Non-GHG............................	Non Greenhouse Gas
NPNS..................................	Normal purchase/normal sale
NRC....................................	U.S. Nuclear Regulatory Commission
NSPS..................................	New Source Performance Standard
NSR....................................	New Source Review
OCI.....................................	Other comprehensive income
Oconee...............................	Oconee Nuclear Station
Ohio T&D............................	Ohio Transmission and Distribution
ORS....................................	South Carolina Office of Regulatory Staff
OUCC..................................	Indiana Office of Utility Consumer Counselor
OVEC..................................	Ohio Valley Electric Corporation
PJM....................................	PJM Interconnection, LLC
Preferred Securities.............	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by FPC Capital I
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Energy..................	Progress Energy, Inc.
Progress Energy Carolinas...	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
Progress Energy Florida......	Florida Power Corporation d/b/a Progress Energy Florida
Progress Energy Registrants	Progress Energy, Progress Energy Carolinas and Progress Energy Florida
Prosperity............................	Prosperity Mine, LLC
PSCSC................................	Public Service Commission of South Carolina
PSD....................................	Prevention of Significant Deterioration
PUCO..................................	Public Utilities Commission of Ohio
Q-Comm.............................	Q-Comm Corporation
QF.......................................	Qualified Facilities
QSPE..................................	Qualifying Special Purpose Entity
Relative TSR......................	TSR of Duke Energy stock relative to a pre-defined peer group
REPS..................................	Renewable Energy and Energy Efficiency Portfolio Standard
Robinson.............................	Robinson Nuclear Station
RSP....................................	Rate Stabilization Plan
RTO....................................	Regional Transmission Organization
Saluda................................	Saluda River Electric Cooperative, Inc.’s
SB 3....................................	North Carolina General Assembly Senate Bill 3
SB 221................................	Ohio Senate Bill 221
SCEUC................................	South Carolina Energy Users Committee
SEC....................................	Securities and Exchange Commission
Segment Income................	Income from continuing operations net of income attributable to noncontrolling interests
SHGP..................................	South Houston Green Power, L.P.
SO2.....................................	Sulfur dioxide
Spectra Energy...................	Spectra Energy Corp.
Spectra Capital...................	Spectra Energy Capital, LLC (formerly Duke Capital LLC)
S&P....................................	Standard & Poor’s
SSO....................................	Standard Service Offer
Stimulus Bill.......................	The American Recovery and Reinvestment Act of 2009
Subordinated Notes............	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Subsidiary Registrants.........	Duke Energy Carolinas, Progress Energy, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio and Duke Energy Indiana
TSR....................................	Total shareholder return
U.S......................................	United States
USFE&G.............................	U.S. Franchised Electric and Gas
Vectren...............................	Vectren Energy Delivery of Indiana
Vermillion...........................	Vermillion Generating Station
VIE......................................	Variable Interest Entity
VSP....................................	Voluntary Severance Program
WACC.................................	Weighted Average Cost of Capital
Windstream.........................	Windstream Corp.
WVPA.................................	Wabash Valley Power Association, Inc.

ITEM 1. BUSINESS

DUKE ENERGY

General. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is an energy company headquartered in Charlotte, North Carolina. Duke Energy operates in the U.S. primarily through its direct and indirect wholly owned subsidiaries, Duke Energy Carolinas, LLC (Duke Energy Carolinas), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (Progress Energy Carolinas), Florida Power Corporation d/b/a Progress Energy Florida, Inc. (Progress Energy Florida), Duke Energy Ohio, Inc. (Duke Energy Ohio), and Duke Energy Indiana, Inc. (Duke Energy Indiana), as well as in Latin America through Duke Energy International, LLC (DEI). When discussing Duke Energy’s consolidated financial information, it necessarily includes the results of its six separate subsidiary registrants, Duke Energy Carolinas, Progress Energy, Inc. (Progress Energy), Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio, and Duke Energy Indiana (collectively referred to as the Subsidiary Registrants), which, along with Duke Energy, are collectively referred to as the Duke Energy Registrants. The financial information for Progress Energy, Progress Energy Carolinas and Progress Energy Florida includes results after July 2, 2012.

Duke Energy is a Delaware corporation. Its principal executive offices are located at 550 South Tryon Street, Charlotte, North Carolina 28202-1803. Duke Energy Carolinas is a North Carolina limited liability company. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. Progress Energy and Progress Energy Carolinas are North Carolina corporations. Their principal executive offices are located at 410 South Wilmington Street, Raleigh, North Carolina 27601-1748. Progress Energy Florida is a Florida corporation. Its principal executive offices are located at 299 First Avenue North, St. Petersburg, Florida 33701. Duke Energy Ohio is an Ohio corporation. Its principal executive offices are located at 139 East Fourth Street, Cincinnati, Ohio 45202. Duke Energy Indiana is an Indiana corporation. Its principal executive offices are located at 1000 East Main Street, Plainfield, Indiana 46168.

The telephone number for the Duke Energy Registrants is 704-382-3853. The Duke Energy Registrants electronically file 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 the Duke Energy Registrants file 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 the Duke Energy Registrants, including its reports filed with the SEC, is available through Duke Energy’s website at http://www.duke-energy.com. Such reports are accessible at no charge through Duke Energy’s website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.

Merger with Progress Energy. On July 2, 2012, Duke Energy completed the merger contemplated by the Agreement and Plan of Merger (Merger Agreement), among Duke Energy, Diamond Acquisition Corporation, a North Carolina corporation and Duke Energy’s wholly owned subsidiary (Merger Sub) and Progress Energy, Inc. (Progress Energy), a North Carolina corporation engaged in the regulated utility business of generation, transmission and distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. As a result of the merger, Merger Sub was merged into Progress Energy and Progress Energy became a wholly owned subsidiary of Duke Energy.

The merger between Duke Energy and Progress Energy provides increased scale and diversity with potentially enhanced access to capital over the long term and a greater ability to undertake the significant construction programs necessary to respond to increasing environmental regulation, plant retirements and customer demand growth. Duke Energy’s business risk profile is expected to improve over time due to the increased proportion of the business that is regulated. Additionally, cost savings, efficiencies and other benefits are expected from the combined operations.

Immediately preceding the merger, Duke Energy completed a one-for-three reverse stock split with respect to the issued and outstanding shares of Duke Energy common stock. The shareholders of Duke Energy approved the reverse stock split at Duke Energy’s special meeting of shareholders held on August 23, 2011. All share and per share amounts presented within the Form 10-K reflect the impact of the one-for-three reverse stock split.

Progress Energy’s shareholders received 0.87083 shares of Duke Energy common stock in exchange for each share of Progress Energy common stock outstanding as of July 2, 2012. Generally, all outstanding Progress Energy equity-based compensation awards were converted into Duke Energy equity-based compensation awards using the same ratio. The merger was structured as a tax-free exchange of shares.

For additional information on the details of this transaction including regulatory conditions and accounting implications, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets.”

Duke Energy Business Segments. Duke Energy conducts its operations in the following business segments, all of which are considered reportable segments under the applicable accounting rules: U.S. Franchised Electric and Gas (USFE&G), Commercial Power and International Energy. The remainder of Duke Energy’s operations are presented as Other. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business segments in deciding how to allocate resources and evaluate performance. For additional information on each of these business segments, including financial and geographic information about each reportable business segment, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

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.”

U.S. FRANCHISED ELECTRIC AND GAS

U.S. Franchised Electric and Gas (USFE&G) generates, transmits, distributes and sells electricity in most portions of North Carolina, northern South Carolina, central, north central and southern Indiana, west central Florida, and northern Kentucky. USFE&G also transmits, distributes and sells electricity in southwestern Ohio. Additionally, USFE&G transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Indiana, and the regulated transmission and distribution operations of Duke Energy Ohio (Duke Energy Indiana and Duke Energy Ohio are collectively referred to as Duke Energy Midwest). 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 Florida Public Service Commission (FPSC), the Public Utilities Commission of Ohio (PUCO), the Indiana Utility Regulatory Commission (IURC), and the Kentucky Public Service Commission (KPSC). The substantial majority of USFE&G’s operations are regulated and, accordingly, these operations qualify for regulatory accounting treatment.

PART I

USFE&G supplies electric service to 7.2 million residential, general service and industrial customers. Its service area covers approximately 104,000 square miles with an estimated population of 22 million. USFE&G provides regulated transmission and distribution services for natural gas to 500,000 customers in southwestern Ohio and northern Kentucky. Electricity is also sold wholesale to incorporated municipalities, electric cooperative utilities and other load serving entities.

Duke Energy Carolinas’ and Progress Energy Carolinas’ service areas share a diversified economy that is driven by service, manufacturing and government related output and jobs. Sales to general service customers, which include both service and government sectors, represent approximately one third of total retail sales and the main segments include health care, education, financial services, information technology and military buildings. Sales to industrial customers represent a little less than one third of total retail sales and key sectors are textiles, chemicals, rubber and plastics, paper, food & beverage and auto manufacturing.

Progress Energy Florida’s service area has a strong base of residential customers and lower percentages of general service and industrial customers relative to the other Duke Energy utilities’ states. Sales to general service customers, which include both service and government sectors, represent approximately 40% of total retail sales; the largest service segments include tourism, heath care and agriculture. Sales to industrial customers represent only around 10% of total retail sales and main sectors include phosphate rock mining and processing, electronics design and manufacturing, and citrus and other food processing.

Duke Energy Indiana’s service area is characterized by a strong presence of manufacturing activity. Sales to industrial customers represent around 40% of total retail volumes; the larger segments within the industrial class include primary metals, transportation equipment, building materials, food & beverage and chemicals. Sales to general service customers represent approximately 30% of total retail and the largest contributors to general service sales include retail, financial, health care and education services.

Duke Energy Ohio’s service area has a diversified economy that is driven by primarily by the services sector. The contribution of manufacturing to the regional economy is lower relative to Indiana and the Carolinas’ service territories. Sales to general service customers, which include both service and government sectors, represent approximately 40% of total retail sales and the main segments include healthcare, education, real estate and rental leasing, financial & insurance services and wholesale trade services. Sales to industrial customers represent approximately one fourth of total retail sales and key industries are aerospace, primary metals, chemicals and food.

The number of residential, general service and industrial customers within the USFE&G 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. While total industrial sales increased in 2012 when compared to 2011, the growth rate was modest when compared to historical periods.

Seasonality and the Impact of Weather

USFE&G’s 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. Residential and general service customers are most impacted by weather. Industrial customers are less weather sensitive. Estimated weather impacts are based on actual current period weather compared to normal weather conditions, with normal weather conditions defined as the long-term average of actual historical weather conditions.

The estimated impact of weather on earnings is based on the number of customers, temperature variances from a normal condition and customers’ historic usage levels and patterns. The methodology used to estimate the impact of weather does not and cannot consider all variables that may impact customer response to weather conditions such as humidity and relative temperature changes. The precision of this estimate may also be impacted by applying long-term weather trends to shorter term periods.

Degree-day data are used to estimate the energy required to maintain comfortable indoor temperatures based on each day’s average temperature. Heating-degree days measure the variation in the weather based on the extent to which the average daily temperature falls below a base temperature, and cooling-degree days measure the variation in weather based on the extent to which the average daily temperature rises above the base temperature. Each degree of temperature below the base temperature counts as one heating-degree day and each degree of temperature above the base temperature counts as one cooling-degree day.

Competition

Retail. USFE&G’s regulated utility businesses operate as the sole supplier of electricity within their service territories. USFE&G owns and operates all of the businesses and facilities necessary to generate, transmit and distribute electricity. Services are priced by state commission approved rates designed to include the costs of providing these services and a reasonable return on invested capital. This regulatory policy is intended to provide safe and reliable electricity at fair prices. USFE&G’s competition in the regulated electric distribution business is primarily from the on-site generation of industrial customers.

USFE&G is not aware of any enacted or proposed legislation in North Carolina, South Carolina, Florida, Kentucky or Indiana that would give its retail customers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. However, USFE&G competes with suppliers of other forms of energy in connection with their retail customers.

Although there is no pending legislation at this time, if the retail jurisdictions served by USFE&G become subject to deregulation, the recovery of “stranded costs” could become a significant consideration. Stranded costs primarily include the generation assets of USFE&G’s regulated utilities whose value in a competitive marketplace would be less than their current book value, as well as above-market purchased power commitments to qualified facilities (QFs). QFs are typically small power production facilities that generate power within a utility company’s service territory for which the utility companies are legally obligated to purchase the energy of these facilities at an avoided cost rate. Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs.

USFE&G’s largest stranded cost exposure is primarily related to Progress Energy Florida’s purchased power commitments with QFs, under which it has future minimum expected capacity payments through 2025 of $3.8 billion. Progress Energy Florida was obligated to enter into these contracts under provisions of the Public Utilities Regulatory Policies Act of 1978. Progress Energy Florida continues to seek ways to address the impact of escalating payments under these contracts. However, the FPSC allows full recovery of the retail portion of the cost of power purchased from QFs. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies” for additional information related these purchased power commitments.

Wholesale. USFE&G competes with other utilities and merchant generators for bulk power sales and for sales to municipalities and cooperatives. USFE&G also competes with other utilities and marketers in the wholesale electric business. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service. Wholesale electric prices are influenced primarily by market conditions and fuel costs.

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Increased competition in the wholesale electric utility industry and the availability of transmission access could affect USFE&G’s load forecasts, plans for power supply and wholesale energy sales and related revenues. Wholesale energy sales will be impacted by the extent to which additional generation is available to sell to the wholesale market and the ability of USFE&G to attract new wholesale customers and to retain current wholesale customers.

Energy Capacity and Resources

USFE&G owns over 50,000 megawatts of generation capacity. For additional information on USFE&G’s generation facilities, see “U.S. Franchised Electric and Gas” in Item 2.“Properties.”

Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Factors that could cause USFE&G to purchase power for its customers include generating plant outages, extreme weather conditions, generation reliability during the summer, growth, and price. USFE&G 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.

USFE&G’s 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 Duke Energy Carolinas, Progress Energy Carolinas, and Duke Energy Indiana’s customer energy needs have historically been met by large, low-energy-production-cost coal-fired and nuclear generating units that operated almost continuously (or at baseload levels). However, recent commodity pricing trends have resulted in more combined cycle gas-fired generation. The vast majority of Progress Energy Florida’s customer energy needs have historically been met by large, low-energy-production-cost nuclear, fossil steam and combined cycle gas-fired generation. However, due to the extended outage of the Crystal River Nuclear Station Unit 3 (Crystal River Unit 3) nuclear plant a portion of customer needs have been served with purchased power for the past 3 years.

CT’s and CC’s are less expensive to build and maintain than either nuclear or coal, and can be rapidly started or stopped as needed to meet changing customer loads or operated as base load units depending on commodity prices. Hydroelectric units produce low-cost energy, but their operations are limited by the availability of water flow.

USFE&G’s pumped-storage hydroelectric facilities in the Carolinas 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 periods. These facilities allow USFE&G to maximize the value spreads between different high- and low-cost generation periods.

Recently Completed Generation Projects. During 2012 and 2011, USFE&G completed construction of and placed into service a total of 3,585 megawatts (MW) of new generation capacity including Cliffside Unit 6 and the Buck, Dan River, Lee and Smith combined cycle natural gas facilities. The total capital cost of this new generation capacity was $4.8 billion.

Generation Projects Currently Under Construction. The following information relates to generation projects currently under construction by USFE&G.

Edwardsport Integrated Gasification Combined Cycle (IGCC)Plant. Duke Energy Indiana has completed the construction and is conducting testing of a 618 MW Integrated Gasification Combined Cycle (IGCC) power plant at its existing Edwardsport Generating Station in Knox County, Indiana.

On December 27, 2012, the IURC approved the settlement agreement finalized in April 2012  between Duke Energy Indiana, the Office of Utility Consumer Counselor (OUCC), the Duke Energy Indiana Industrial Group and Nucor Steel Indiana, on the cost increase for the construction of the Edwardsport IGCC plant. The settlement agreement, as approved, caps costs to be reflected in customer rates at $2.595 billion, including estimated allowance for funds used during construction (AFUDC) through June 30, 2012. Duke Energy Indiana was allowed to recover AFUDC after June 30, 2012 until customer rates are revised, with such recovery decreasing to 85% on AFUDC accrued after November 30, 2012.

Duke Energy Indiana’s current cost estimate for the Edwardsport IGCC plant is approximately $3.154 billion, excluding financing costs. Through December 31, 2012, Duke Energy Indiana has recorded total pre-tax impairment and other charges of $897 million related to the Edwardsport IGCC plant. If cost estimates for the plant increase, additional charges to expense, which could be material, could occur. The Edwardsport IGCC plant is expected to be in service by mid-2013. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters” for further information.

L.V. Sutton Combined Cycle Facility.Progress Energy Carolinas is in the process of constructing an approximately 625 MW natural gas-fired generating facility at its existing L.V. Sutton Steam Station (Sutton) in New Hanover County, North Carolina. The Sutton project has an expected in-service date of December 2013. Based on updated cost estimates, total costs (including AFUDC) for the Sutton project is estimated to be approximately $600 million.

Potential New Construction. The following information relates to major generation projects currently being evaluated for construction by USFE&G.

Shearon Harris Nuclear Station Expansion. In 2006, Progress Energy Carolinas selected a site at its existing Shearon Harris Nuclear Station (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, Progress Energy Carolinas filed its combined Construction and Operating License (COL) application with the Nuclear Regulatory Commission (NRC) for two Westinghouse Electric Advanced Passive (AP) 1000 reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application.

Levy Nuclear Station. On July 30, 2008, Progress Energy Florida filed its COL application with the NRC for two Westinghouse AP1000 reactors at its proposed Levy Nuclear Station (Levy), which the NRC docketed on October 6, 2008. Various parties filed a joint petition to intervene in the Levy COL application. On October 31, 2012 and November 1, 2012, the Atomic Safety and Licensing Board held an evidentiary hearing on portions of the intervention petitions.  A decision is expected in March 2013. In 2008, the FPSC granted Progress Energy Florida’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule for Levy, together with the associated facilities, including transmission lines and substation facilities.

On April 30, 2012, as part of its annual nuclear cost recovery filing, Progress Energy Florida updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current low natural gas prices, Progress Energy Florida has shifted the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 FPSC Settlement Agreement. Although the scope and overnight cost for Levy, including land acquisition, related transmission work and other required investments, remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

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Along with the FPSC’s annual prudence reviews, Progress Energy Florida will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; demand side management (DSM) and energy efficiency (EE) programs; and availability and terms of capital financing. Taking into account these criteria, Levy is considered to be Progress Energy Florida’s preferred baseload generation option.

Under the terms of the 2012 FSPC Settlement Agreement, Progress Energy Florida began residential cost-recovery of its proposed Levy Nuclear Station effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement and continuing for a five-year period, with true-up of any actual costs not recovered during the five year period occurring in the final year. Progress Energy Florida will not file for recovery of any new Levy costs that were not addressed in the 2012 FSPC Settlement Agreement before March 1, 2017 and will not begin recovering those costs from customers before the first billing cycle of January, 2018, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the COL and any engineering, procurement and construction cancellation costs, if Progress Energy Florida ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose Progress Energy Florida continuing to pursue a COL for Levy. The 2012 FSPC Settlement Agreement also provides that Progress Energy Florida will treat the allocated wholesale cost of Levy (approximately $68 million) as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. Progress Energy Florida will have the discretion to accelerate and/or suspend such amortization in full or in part provided that it amortizes all of the regulatory asset by December 31, 2016.

William States Lee III Nuclear Station.In December 2007, Duke Energy Carolinas filed an application with the NRC, which has been docketed for review, for a combined COL for two Westinghouse AP1000 reactors for the proposed William States Lee III Nuclear Station (Lee Nuclear Station) at a site in Cherokee County, South Carolina. Each reactor is capable of producing 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the NCUC and PSCSC have concurred with the prudency of Duke Energy incurring project development and pre-construction costs.

Potential Plant Retirements. The Subsidiary Registrants periodically file Integrated Resource Plans (IRP) with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (15-20 years), and options being considered to meet those needs. The IRP’s filed by the Subsidiary Registrants in 2012 and 2011 included planning assumptions to potentially retire by 2015, certain coal-fired generating facilities in North Carolina, South Carolina, Indiana and Ohio that do not have the requisite emission control equipment, primarily to meet Environmental Protection Agency (EPA) regulations that are not yet effective. Additionally, management is considering the impact pending environmental regulations might have on certain coal-fired generating facilities in Florida. These facilities total approximately 3,954 MW at eight sites. Duke Energy continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives, and plans to seek regulatory recovery for amounts that would not be otherwise recovered when any assets are retired. For additional information related to potential plant retirements see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

Fuel Supply

USFE&G relies principally on coal, natural gas and nuclear fuel for its generation of electric energy. The following table lists USFE&G’s sources of power and fuel costs for the three years ended December 31, 2012.

		Generation by Source(a)						Cost of Delivered Fuel per Net Kilowatt-hour Generated (Cents)(a)
		2012		2011		2010		2012	2011	2010
Coal(b)		46.2	%	60.0	%	61.5	%	3.55	3.17	3.04
Nuclear(c)		36.4		37.6		36.3		0.62	0.55	0.52
Oil and gas(d)		16.6		1.4		0.9		4.03	5.89	6.77
All fuels (cost-based on weighted average)(b)		99.2		99.0		98.7		2.55	2.21	2.15
Hydroelectric(e)		0.8		1.0		1.3
Total generation(f)		100.0	%	100.0	%	100.0	%
(a)	Statistics begin July 2, 2012 for Progress Energy Carolinas and Progress Energy Florida.
(b)	Statistics related to coal generation and all fuels reflect USFE&G’s ownership interest in jointly owned generation facilities.
(c)	Statistics related to nuclear generation and all fuels reflect USFE&G’s ownership interest in jointly owned generation facilities. (Crystal River Unit 3 has been in an outage since September 2009)
(d)	Statistics related to oil and gas generation and all fuels reflect USFE&G’s ownership interest in jointly owned generation facilities. Cost statistics include amounts for light-off fuel at USFE&G’s coal-fired stations and combined cycle (gas only).
(e)	Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.
(f)	In addition, USFE&G produced approximately 10,500 megawatt-hours (MWh) in solar generation for 2012, and 5,800 MWh in 2011 and 2010; no fuel costs are attributed to this generation.

Coal. USFE&G meets its coal demand through a portfolio of long-term purchase contracts and short-term spot market purchase agreements. Large amounts of coal are purchased under long-term contracts with mining operators who mine both underground and at the surface. USFE&G uses spot-market purchases to meet coal requirements not met by long-term contracts. Expiration dates for its long-term contracts, which have various price adjustment provisions and market re-openers, range from 2013 to 2018 for the Carolinas, 2013 to 2016 for Florida, and 2013 to 2018 for Indiana. USFE&G 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 Central Appalachia, Northern Appalachia and the Illinois Basin. The coal purchased for Florida is primarily produced from mines in Central Appalachia and the Illinois Basin. The coal purchased for Indiana is primarily produced in Indiana and Illinois. USFE&G has an adequate supply of coal under contract to fuel its projected 2013 operations and a significant portion of supply to fuel its projected 2014 operations. Coal inventory levels have increased during the past year due to the impact of mild winter weather and the economy on retail load and low natural gas prices which are resulting in higher combined cycle gas-fired generation. If these factors continue for an extended period of time, USFE&G could have excess levels of coal inventory.

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The current average sulfur content of coal purchased by USFE&G is between 1% and 2% for the Carolinas; between 1% and 2% for Florida, and between 2% and 3% for Indiana. USFE&G’s scrubbers, in combination with the use of sulfur dioxide (SO₂) emission allowances, enable USFE&G to satisfy current SO₂ emission limitations for its existing facilities.

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.

USFE&G has contracted for uranium materials and services to fuel its nuclear reactors in the Carolinas and Florida. 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. USFE&G staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements in the near-term and decreasing portions of its fuel requirements over time thereafter. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with spot market purchases. Due to the technical complexities of changing suppliers of fuel fabrication services, USFE&G generally sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

USFE&G has entered into fuel contracts that, based on its current need projections, cover 100% of its uranium concentrates, conversion services, and enrichment services requirements through at least 2013 and cover fabrication services requirements for these plants through at least 2018. The cost of termination of nuclear fuel procurement contracts that Progress Energy Florida has related to Crystal River Unit 3 are not expected to be material. For subsequent years, a portion of its fuel requirements are covered by long-term contracts. For future requirements not already covered under long-term contracts, USFE&G 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.

Gas. Oil and natural gas supply for USFE&G’s generation fleet is purchased under term and spot contracts from various suppliers. Duke Energy Carolinas and Progress Energy Carolina’s use derivative instruments to limit their exposure to price fluctuations for natural gas. Progress Energy Florida uses derivative instruments to limit its exposure to price fluctuations for natural gas, fuel oil and surcharges embedded in coal transportation agreements. USFE&G has dual-fuel generating facilities that can operate with both fuel oil and natural gas. The cost of USFE&G’s oil and natural gas is either at a fixed price or determined by market prices as reported in certain industry publications. USFE&G believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. USFE&G’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate and intrastate pipelines. USFE&G may also purchase additional shorter-term transportation for its load requirements during peak periods. Many of the natural gas plants can be served by several supply zones and multiple pipelines.

Purchased Power. USFE&G purchased approximately 19.8 million MWh, 19.0 million MWh and 18.3 million MWh of its system energy requirements during 2012, 2011, and 2010, respectively, under purchase obligations and leases and had 4,500 MW of firm purchased capacity under contract during 2012. These amounts include MWh for Progress Energy Carolinas and Progress Energy Florida for all periods presented. These agreements include approximately 682 MW of firm capacity under contract by Progress Energy Florida with certain QFs. USFE&G may need to acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. USFE&G believes that it can obtain adequate purchased power to meet these needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected.

Gas for Retail Distribution. USFE&G is responsible for the purchase and the subsequent delivery of natural gas to native load customers in its Ohio and Kentucky service territories. USFE&G’s 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 USFE&G to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides USFE&G the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under USFE&G customer choice/gas transportation programs. In 2012, firm supply purchase commitment agreements provided approximately 100% of the natural gas supply. These firm supply agreements feature two levels of gas supply, specifically (i) base load, which is a continuous supply to meet normal demand requirements, and (ii) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.

USFE&G also owns two underground caverns with a total storage capacity of 16 million gallons of liquid propane. In addition, USFE&G 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 it with natural gas to supplement the natural gas supply during peak demand periods.

Duke Energy Ohio maintains natural gas procurement-price volatility mitigation programs. These programs pre-arrange percentages of Duke Energy Ohio’s seasonal gas requirements. Duke Energy Ohio uses primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2012, Duke Energy Ohio had locked in pricing for 22% of its remaining estimated winter 2012/2013 system load requirements.

Inventory

Generation of electricity is capital-intensive. USFE&G 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, 2012, the inventory balance for USFE&G was $2,987 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

Nuclear Insurance and Decommissioning

USFE&G owns (wholly or partially) 12 nuclear reactors located at seven stations. Nuclear insurance includes: nuclear liability coverage; property, decontamination and premature decommissioning coverage; and replacement power expense coverage. The other joint owners of the jointly owned nuclear reactors reimburse USFE&G for certain expenses associated with nuclear insurance per the joint owner agreements. The Price-Anderson Act requires nuclear plant owners to provide for public nuclear liability claims resulting from nuclear incidents to the maximum total financial protection liability, which currently is $12.6 billion. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies — Nuclear Insurance,” for more information.

USFE&G has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate each plant safely. The NCUC, FPSC and the PSCSC require USFE&G regulated utilities to update their cost estimates for decommissioning their nuclear plants every five years.

Duke Energy Carolinas’ most recent site-specific nuclear decommissioning cost studies were completed in 2009 and showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination, of $3 billion in 2008

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dollars. This estimate includes Duke Energy Carolinas’ ownership interest in the jointly owned nuclear reactors. The other joint owners of the jointly owned nuclear reactors are responsible for decommissioning costs related to their ownership interests in the station. The balance of Duke Energy Carolinas’ external Nuclear Decommissioning Trust Funds (NDTF) was $2,354 million as of December 31, 2012 and $2,060 million as of December 31, 2011.

Progress Energy Carolinas’ most recent site-specific nuclear decommissioning cost studies were completed in 2009 and showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination of $3.0 billion in 2009 dollars. This estimate includes Progress Energy Carolinas’ ownership interest in the jointly owned nuclear reactors. The other joint owners of the jointly owned nuclear reactors are responsible for decommissioning costs related to their ownership interests in the station. The balance of Progress Energy Carolinas’ external NDTF was $1,259 million as of December 31, 2012 and $1,088 million as of December 31, 2011.

Progress Energy Florida’s most recent site-specific nuclear decommissioning cost studies were completed in 2008. In the Progress Energy Florida 2009 rate case, the FPSC deferred review of the 2008 nuclear decommissioning study until 2010. While Progress Energy Florida was not required to prepare a new site-specific nuclear decommissioning cost study, it was required to update its 2008 study by incorporating the most currently-available escalation rates.  This update was filed with the FPSC in December 2010. The FPSC approved this study on April 30, 2012 and showed total estimated nuclear decommissioning costs based on prompt dismantlement at the end of Crystal River Unit 3’s useful life , including the cost to decommission plant components not subject to radioactive contamination of $751 million in 2008 dollars. This estimate includes Progress Energy Florida’s ownership interest in the jointly owned nuclear reactor. The other joint owners of the jointly owned nuclear reactor are responsible for decommissioning costs related to their ownership interests in the station. With the decision in early 2013 to retire Crystal River Unit 3, as discussed below, it is anticipated that a delayed dismantlement approach to decommissioning, referred to as SAFSTOR, will be submitted to the NRC for approval. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning required by the NRC. Once an updated  site specific decommissioning study is completed it will be filed with the FPSC. As part of the evaluation of repairing Crystal River Unit 3, initial estimates of the cost to decommission the plant under the SAFSTOR option were developed, including components not subject to radioactive contamination, of $989 million in 2011 dollars. The balance of the external NDTF was $629 million as of December 31, 2012 and $559 million as of December 31, 2011.

The NCUC, FPSC and the PSCSC have allowed USFE&G’s regulated utilities to recover estimated decommissioning costs through retail rates over the expected remaining service periods of their nuclear stations. USFE&G 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. See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for more information.

The Nuclear Waste Policy Act of 1982 (as amended) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Policy Act of 1982 promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. USFE&G will continue to maximize the use of spent fuel storage capability within its own facilities for as long as feasible.

Under federal law, the U.S. Department of Energy (DOE) is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. Progress Energy Carolinas and Progress Energy Florida have contracts with the DOE for the future storage and disposal of our spent nuclear fuel. Delays have occurred in the DOE’s proposed permanent repository to be located at Yucca Mountain, Nevada. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for information about complaints filed by Progress Energy Carolinas and Progress Energy Florida in the United States Court of Federal Claims against the DOE for its failure to fulfill its contractual obligation to receive spent fuel from nuclear plants. Failure to open Yucca Mountain or another facility would leave the DOE open to further claims by utilities.

Until the DOE begins to accept the spent nuclear fuel, Progress Energy Carolinas and Progress Energy Florida will continue to safely manage their spent nuclear fuel. With certain modifications and additional approvals by the NRC, including the installation and/or expansion of on-site dry cask storage facilities at Robinson Nuclear Station (Robinson), Brunswick Nuclear Station (Brunswick) and Crystal River Unit 3, the Progress Energy Carolinas and Progress Energy Florida’s spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated by their respective systems through the expiration of the operating licenses, including any license renewals, for their nuclear generating units. Harris has sufficient storage capacity in its spent fuel pools through the expiration of its renewed operating license.

Regulation

State

The NCUC, the PSCSC, the FPSC, 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 state utility commissions, except for the PUCO, also have authority over the construction and operation of USFE&G’s generating facilities. Certificates of Public Convenience and Necessity (CPCN) issued by the state utility commissions, as applicable, authorize USFE&G 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 USFE&G’s regulated operating companies to issue securities. The underlying concept of utility ratemaking is to set rates at a level that allows the utility to collect revenues equal to its cost of providing service plus earn a reasonable rate of return on its invested capital, including equity.

Each of the state utility commissions allows recovery of certain costs through various cost-recovery clauses, to the extent the respective commission determines in periodic hearings that such costs, including any past over or under-recovered costs, are prudent. The clauses are in addition to approved base rates. USFE&G’s regulated utilities generally do not earn a return on the recovery of eligible operating expenses under such clauses; however, in certain jurisdictions, they may earn a return on under-recovered costs. Additionally, the commissions may authorize a return for specified investments for energy efficiency and conservation, capacity costs, environmental compliance and utility plant.

Fuel, fuel-related costs and certain purchased power costs are eligible for recovery by USFE&G’s regulated utilities. USFE&G uses coal, oil, hydroelectric, natural gas and nuclear power to generate electricity, thereby maintaining a diverse fuel mix that helps mitigate the impact of cost increases in any one fuel. Due to the associated regulatory treatment and the method allowed for recovery, changes in fuel costs from year to year have no material impact on operating results of USFE&G, unless a commission finds a portion of such costs to have been imprudent. However, delays between the expenditure for fuel costs and recovery from ratepayers can adversely impact the timing of cash flow of USFE&G. Progress Energy Florida is obligated to notify the FPSC and permitted to file for a midcourse change to the fuel factor between annual fuel hearings in the event its estimated over- or under-recovery of fuel costs meets or exceeds a threshold of ten percent of estimated total retail fuel revenues and, accordingly, has the ability to mitigate the cash flow impacts due to the timing of recovery of fuel and purchased power costs.

The following is a summary of pending retail base rate case proceedings for each of USFE&G’s regulated utilities.

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Duke Energy Carolinas 2013 North Carolina Rate Case. On February 4, 2013, Duke Energy Carolinas filed an application with the NCUC for an increase in base rates of approximately $446 million, or an average 9.7% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 53% equity and 47% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization, environmental compliance and the capital additions.

Duke Energy Carolinas expects revised rates, if approved, to go into effect late third quarter of 2013.

Progress Energy Carolinas 2012 North Carolina Rate Case. On October 12, 2012, Progress Energy Carolinas filed an application with the NCUC for an increase in base rates of approximately $387 million, or an average 12% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 55% equity and 45% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. The rate case includes a corresponding decrease in Progress Energy Carolinas’ energy efficiency and demand side management rider, resulting in a net requested increase of $359 million, or 11% increase in retail revenues.

On February 25, 2013, the North Carolina Public Staff filed with the NCUC a Notice of Settlement in Principle (Settlement Notice). Pursuant to the Settlement Notice between Progress Energy Carolinas and the Public Staff, the parties have agreed to a two year step-in to a total agreed upon net rate increase, with the first year providing for a $151 million, or 4.7% average increase in rates, and the second year providing for rates to be increased by an additional $31 million, or 1.0% average increase in rates.  This second year increase is a result of Progress Energy Carolinas agreeing to delay collection of financing costs on the construction work in progress for the Sutton combined cycle natural gas plant for one year.  The Settlement Notice is based upon a return on equity of 10.2% and a 53% equity component of the capital structure. 

Once filed, the actual settlement agreement will be subject to approval by the NCUC. Progress Energy Carolinas expects revised rates, if approved, to go into effect June 1, 2013.

Duke Energy Ohio 2012 Electric Rate Case. On July 9, 2012, Duke Energy Ohio filed an application with the PUCO for an increase in electric distribution rates of approximately $87 million. On average, total electric rates would increase approximately 5.1% under the filing. The rate increase is designed to recover the cost of investments in projects to improve reliability for customers and upgrades to the distribution system. Pursuant to a stipulation in another case, Duke Energy Ohio will continue recovering its costs associated with grid modernization in a separate rider.

Duke Energy Ohio expects revised rates, if approved, to go into effect in the first half of 2013.

Duke Energy Ohio 2012 Natural Gas Rate Case. On July 9, 2012, Duke Energy Ohio filed an application with the PUCO for an increase in natural gas distribution rates of approximately $45 million. On average, total natural gas rates would increase approximately 6.6% under the filing. The rate increase is designed to recover the cost of upgrades to the distribution system, as well as environmental cleanup of manufactured gas plant sites. In addition to the recovery of costs associated with the manufactured gas plants, the rate request includes a proposal for an accelerated service line replacement program and a new rider to recover the associated incremental cost. The filing also requests that the PUCO renew the rider recovery of Duke Energy Ohio’s accelerated main replacement program and grid modernization program.

On January 4, 2013, the PUCO Staff filed a staff report recommending that Duke Energy Ohio only be allowed to recover costs related to manufactured gas plant (MGP) sites which are currently used and useful in the provision of natural gas distribution service. Duke Energy Ohio filed its objection to the staff report on February 4, 2013.

Duke Energy Ohio expects revised rates, if approved, to go into effect in the first half of 2013.

The following is a summary of recently resolved or settled retail base rate case proceedings for each of USFE&G’s regulated utilities.

Progress Energy Florida 2012 FPSC Settlement. On February 22, 2012, the FPSC approved a comprehensive settlement agreement among Progress Energy Florida, the Florida Office of Public Counsel and other consumer advocates. The 2012 FPSC Settlement Agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: (i) Progress Energy Florida’s proposed Levy Nuclear Project cost recovery, (ii) the Crystal River Unit 3 delamination prudence review then pending before the FPSC, and (iii) certain customer rate matters. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters – Rate Related Information,” for additional provisions of the 2012 settlement agreement.

Duke Energy Carolinas 2011 North Carolina Rate Case. On January 27, 2012, the NCUC approved a settlement agreement between Duke Energy Carolinas and the North Carolina Utilities Public Staff (Public Staff). The terms of the agreement include an average 7.2% increase in retail revenues, or approximately $309 million annually beginning in February 2012. The agreement includes a 10.5% return on equity and a capital structure of 53% equity and 47% long-term debt.

On March 28, 2012, the North Carolina Attorney General filed a notice of appeal with the NCUC challenging the rate of return approved in the agreement. On April 17, 2012, the NCUC denied Duke Energy Carolinas’ request to dismiss the notice of appeal. Briefs were filed on August 22, 2012 by the North Carolina Attorney General and the American Association of Retired Persons (AARP) with the North Carolina Supreme Court, which is hearing the appeal. Duke Energy Carolinas filed a motion to dismiss the appeal on August 31, 2012 and the North Carolina Attorney General filed a response to that motion on September 13, 2012. Briefs by the appellees, Duke Energy Carolinas and the Public Staff, were filed on September 21, 2012. The North Carolina Supreme Court denied Duke Energy Carolinas’ motion to dismiss on procedural grounds and set the matter for oral arguments on November 13, 2012. Duke Energy Carolinas is awaiting an order.

Duke Energy Carolinas 2011 South Carolina Rate Case. On January 25, 2012, the PSCSC approved a settlement agreement between Duke Energy Carolinas and the ORS, Wal-Mart Stores East, LP, and Sam’s East, Inc. The Commission of Public Works for the city of Spartanburg, South Carolina and the Spartanburg Sanitary Sewer District were not parties to the agreement; however, they did not object to the agreement. The terms of the agreement include an average 5.98% increase in retail and commercial revenues, or approximately $93 million annually beginning February 6, 2012. The agreement includes a 10.5% return on equity, a capital structure of 53% equity and 47% long-term debt.

Duke Energy Ohio Standard Service Offer (SSO). The PUCO approved Duke Energy Ohio’s current Electric Security Plan (ESP) on November 22, 2011. The ESP effectively separates the generation of electricity from Duke Energy Ohio’s retail load obligation and requires Duke Energy Ohio to transfer its generation assets to a nonregulated affiliate on or before December 31, 2014. The ESP includes competitive auctions for electricity supply whereby the energy price is recovered from retail customers. As a result, Duke Energy Ohio now earns retail margin on the transmission and distribution of electricity only and not on the cost of the underlying energy. New rates for Duke Energy Ohio went into effect for SSO customers on January 1, 2012. The ESP also includes a provision for a non-bypassable stability charge of $110 million per year to be collected from January 1, 2012 through December 31, 2014.

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On January 18, 2012, the PUCO denied a request for rehearing of its decision on Duke Energy Ohio’s ESP filed by Columbus Southern Power and Ohio Power Company.

For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters — Rate Related Information.”

Federal

The FERC approves USFE&G’s cost-based rates for electric sales to certain wholesale customers, as well as sales of transmission service. Regulations of FERC and the state utility commissions govern access to regulated electric and gas customers and other data by nonregulated entities and services provided between regulated and nonregulated energy affiliates. These regulations affect the activities of nonregulated affiliates with USFE&G.

Regional Transmission Organizations (RTO). PJM Interconnection, LLC (PJM) and Midwest Independent Transmission System Operator, Inc. (MISO) are the Independent System Operators (ISO) and the FERC-approved RTOs for the regions in which Duke Energy Ohio and Duke Energy Indiana operate. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the PJM region. MISO is the transmission provider under, and the administrator of, the MISO Open Access Transmission Tariff (MISO Tariff), operates the MISO energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the MISO region. Duke Energy Ohio is a member of PJM and provides regional transmission service pursuant to the PJM Tariff. Duke Energy Ohio and the other transmission owners in PJM have turned over control of their transmission facilities to PJM, and their transmission systems are currently under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service. Duke Energy Indiana is a member of MISO and provides regional transmission service pursuant to the MISO Tariff. Duke Energy Indiana and the other transmission owners in MISO have turned over control of their transmission facilities to MISO, and their transmission systems are currently under the dispatch control of MISO. Under the MISO Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the MISO members at rates based on the costs of transmission service.

Prior to January 1, 2012, Duke Energy Ohio was a member of MISO. See Note 4 to the Consolidated Financial Statements, Regulatory Matters, for additional information related to Duke Energy Ohio’s RTO realignment from MISO to PJM.

Other

Nuclear Matters. The nuclear power industry faces uncertainties with respect to the cost and long-term availability of disposal sites for spent nuclear fuel and other radioactive waste, compliance with changing regulatory requirements, capital outlays for modifications and new plant construction, the technological and financial aspects of decommissioning plants at the end of their licensed lives, and requirements relating to nuclear insurance. Nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.

USFE&G 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 Nuclear Station (McGuire) and Catawba Nuclear Station (Catawba). The two McGuire units are licensed through 2041 and 2043, respectively, while the two Catawba units are licensed through 2043. The NRC has renewed the operating licenses for all of Progress Energy Carolinas’ nuclear plants. The renewed operating licenses for Brunswick Unit 1 and Unit 2, Harris and Robinson expire in 2036, 2034, 2046 and 2030, respectively.

The NRC issues orders with regard to security at nuclear plants in response to new or emerging threats. The most recent orders include additional restrictions on nuclear plant access, increased security measures at nuclear facilities and closer coordination with our partners in intelligence, military, law enforcement and emergency response at the federal, state and local levels. USFE&G is in compliance with the requirements outlined in the orders through the use of additional security measures until permanent construction projects are completed in 2013. As the NRC, other governmental entities and the industry continue to consider security issues, it is possible that more extensive security plans could be required.

Crystal River Unit 3. In September 2009, Crystal River Unit 3 began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, it was determined that the concrete delamination at Crystal River Unit 3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created to accommodate the replacement of the unit’s steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. Crystal River Unit 3 has remained out of service while Progress Energy Florida conducted an engineering analysis and review of the new delamination and evaluated possible repair options.

Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur.

Progress Energy Florida developed a repair plan, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls, which had a preliminary cost estimate of $900 million to $1.3 billion. 

In March 2012, Duke Energy commissioned an independent review team led by Zapata Incorporated (Zapata) to review and assess the Progress Energy Florida Crystal River Unit 3 repair plan, including the repair scope, risks, costs and schedule. In its final report in late September, Zapata found that the proposed repair scope appears to be technically feasible, but there were significant risks that need to be addressed regarding the approach, construction methodology, scheduling and licensing. Zapata performed four separate analyses of the estimated project cost and schedule to repair Crystal River Unit 3, including; (i) an independent review of the proposed repair scope (without existing assumptions or data), of which Zapata estimated costs of $1.49 billion with a project duration of 35 months; (ii) a review of Progress Energy Florida’s previous bid information, which included cost estimate data from Progress Energy Florida, of which Zapata estimated costs of $1.55 billion with a project duration of 31 months; (iii) an expanded scope of work scenario, that included the Progress Energy Florida scope plus the replacement of the containment building dome and the removal and replacement of concrete in the lower building elevations, of which Zapata estimated costs of approximately $2.44 billion with a project duration of 60 months, and; (iv) a “worst case” scenario, assuming Progress Energy Florida performed the more limited scope of work, and at the conclusion of that work, additional damage occurred in the dome and in the lower elevations, which forced replacement of each, of which Zapata estimated costs of $3.43 billion with a project duration of 96 months. The principal difference between Zapata’s estimate and Progress Energy Florida’s previous estimate appears to be due to the respective levels of contingencies included by each party, including higher project risk and longer project duration. Progress Energy Florida has filed a copy of the Zapata report with the FPSC and with the NRC. The FPSC held a status conference on October 30, 2012 to discuss Duke Energy’s analysis of the Zapata report.

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On February 5, 2013, following the completion of a comprehensive analysis, Duke Energy announced its intention to retire Crystal River Unit 3. Duke Energy concluded that it did not have a high degree of confidence that repair could be successfully completed and licensed within estimated costs and schedule, and that it was in the best interests of Progress Energy Florida’s customers and joint owners and Duke Energy’s investors to retire the unit. Progress Energy Florida developed initial estimates of the cost to decommission the plant during its analysis of whether to repair or retire Crystal River Unit 3. With the final decision to retire, Progress Energy Florida is working to develop a comprehensive decommissioning plan, which will evaluate various decommissioning options and costs associated with each option. The plan will determine resource needs as well as the scope, schedule and other elements of decommissioning. Progress Energy Florida intends to use a safe storage (SAFSTOR) option for decommissioning. Generally, SAFSTOR involves placing the facility into a safe storage configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities occur, usually in 40 to 60 years. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning required by the NRC. Once an updated site specific decommissioning study is completed it will be filed with the FPSC. As part of the evaluation of repairing Crystal River Unit 3, initial estimates of the cost to decommission the plant under the SAFSTOR option were developed which resulted in an estimate in 2011 dollars of $989 million. See Note 9 for additional information. Additional specifics about the decommissioning plan are being developed.

Progress Energy Florida maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at Crystal River Unit 3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power of up to $490 million per event when the unit is out of service as a result of these events. Actual replacement power costs have exceeded the insurance coverage. Progress Energy Florida also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

Throughout the duration of the Crystal River Unit 3 outage, Progress Energy Florida worked with NEIL for recovery of applicable repair costs and associated replacement power costs. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL had not provided a written coverage decision for either delamination and no payments were made on the second delamination and no replacement power reimbursements were made by NEIL since May 2011. These considerations led Progress Energy Florida to conclude, in the second quarter of 2012, that it was not probable that NEIL would voluntarily pay the full coverage amounts that Progress Energy Florida believes them to owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, Progress Energy Florida agreed to non-binding mediation prior to commencing any formal dispute resolution. On February 5, 2013, Progress Energy Florida announced it and NEIL had accepted the mediator’s proposal whereby NEIL will pay Progress Energy Florida an additional $530 million. Along with the $305 million which NEIL previously paid, Progress Energy Florida will receive a total of $835 million in insurance proceeds.

As a result of the 2012 FPSC Settlement Agreement, Progress Energy Florida will be permitted to recover prudently incurred fuel and purchased power costs through its fuel clause without regard for the absence of Crystal River Unit 3 for the period from the beginning of the Crystal River Unit 3 outage through December 31, 2016.

In accordance with the terms of the 2012 FPSC Settlement Agreement, with consumer representatives and approved by the FPSC, Progress Energy Florida retained the sole discretion to retire Crystal River Unit 3. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket.Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013.

 Progress Energy Florida did not begin the repair of Crystal River Unit 3 prior to December 31, 2012. Consistent with the 2012 FPSC Settlement Agreement regarding the timing of commencement of repairs, Progress Energy Florida recorded a Regulatory liability of $100 million in the third quarter of 2012 related to replacement power obligations. This amount is included within fuel used in electric generation and purchased power in Progress Energy Florida’s and Progress Energy’s Statements of Operations and Comprehensive Income for the year ended December 31, 2012. Progress Energy Florida will refund this replacement power liability on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. This amount is reflected as part of the purchase price allocation of the merger with Progress Energy in Duke Energy’s Consolidated Financial Statements.

Progress Energy Florida also retained sole discretion to retire the unit without challenge from the parties to the agreement. As a result, Progress Energy Florida will be allowed to recover all remaining Crystal River Unit 3 investments and to earn a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017.

In conjunction with the decision to retire Crystal River Unit 3, Progress Energy Florida reclassified all Crystal River Unit 3 investments, including property, plant and equipment; nuclear fuel; inventory; and deferred assets to a regulatory asset account. At December 31, 2012, Progress Energy Florida had $1,637 million of net investment in Crystal River Unit 3 recorded in Regulatory assets on its Consolidated Balance Sheets. Progress Energy Florida recorded $192 million of impairment and other charges related to the wholesale portion of Crystal River Unit 3 investments, which are not covered by the 2012 FSPC Settlement Agreement, and other provisions. The significant majority of this amount is recorded in Impairment charges on Progress Energy Florida’s and Progress Energy’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012. This amount is reflected as part of the purchase price allocation of the merger with Progress Energy in Duke Energy’s Consolidated Financial Statements.

In accordance with the 2012 FPSC Settlement Agreement, NEIL proceeds received allocable to retail customers will be applied first to replacement power costs incurred after December 31, 2012 through December 31, 2016, with the remainder used to write down the remaining Crystal River Unit 3 investments.

Progress Energy Florida believes the decision to retire Crystal River Unit 3, the actions taken and costs incurred in response to the Crystal River Unit 3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and exit cost to wind down the operations at the plant and decommission Crystal River Unit 3 could be material. Retirement of the plant could impact funding obligations associated with Progress Energy Florida’s nuclear decommissioning trust fund.

Progress Energy Florida is a party to a master participation agreement and other related agreements with the joint owners of Crystal River Unit 3 which convey certain rights and obligations on Progress Energy Florida and the joint owners. In December 2012, Progress Energy Florida reached an agreement with one group of joint owners related to all Crystal River Unit 3 matters.

Progress Energy Florida cannot predict the outcome of matters described above.

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Hydroelectric Generating Facilities. All but one of USFE&G’s hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act. The FERC has jurisdiction to issue new hydroelectric operating licenses when the existing license expires. The 13 hydroelectric stations of the Catawba-Wateree Project are in the late stages of the FERC relicensing process. These stations continue to operate under annual extensions of the current FERC license, which expired in 2008, until the FERC issues a new license, which is currently projected to be issued by mid-2013. Relicensing is now under way for two hydroelectric stations comprising the Keowee-Toxaway Project. The current Keowee-Toxaway Project license does not expire until 2016 and the project will continue to operate under the current license until the new license is issued. The Bad Creek Project license will expire in 2028, the Gaston Shoals Project and Ninety Nine Islands Project licenses will expire in 2036 and the Queens Creek Project which will expire in 2023. All other hydroelectric stations are operating under current operating licenses, including ten hydroelectric stations in the East Fork, West Fork, Nantahala, Bryson, Mission, Franklin projects, and the Markland Project (in Indiana) for which new licenses were issued in 2010 through 2012. Duke Energy requested and the FERC approved a license surrender for the Dillsboro project. 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.

Progress Energy Carolinas has three hydroelectric generating plants licensed by the FERC: Walters, Tillery and Blewett. Progress Energy Carolinas also owns the Marshall Plant, which has a license exemption. The total summer generating capacity for all four units is 225 MW. Progress Energy Carolinas submitted an application to relicense its Tillery and Blewett plants for 50 years and anticipates a decision by the FERC in 2013. The Walters Plant license will expire in 2034.

Other Matters. USFE&G 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.

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 other EPA regulations under development and the potential impacts such legislation and regulation could have on Duke Energy’s operations.

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, excluding renewable energy generation assets, consist primarily of coal-fired and gas-fired nonregulated generation assets which are dispatched into wholesale markets. These assets are comprised of 6,825 net 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. The coal-fired generation assets were dedicated under the Duke Energy Ohio Electric Security Plan (ESP) through December 31, 2011. As discussed in the USFE&G section above, the new ESP effectively separates the generation of electricity from Duke Energy Ohio’s retail load obligation as of January 1, 2012. As a result, As a result, the energy from Duke Energy Ohio’s coal-fired generation assets no longer serve retail load customers or receive negotiated pricing under the ESP. Effective January 1, 2012, Duke Energy Ohio completed its Regional Transmission Organization (RTO) realignment to PJM and operates as a Fixed Resource Requirement (FRR) entity through May 31, 2015. As an FRR entity, Duke Energy Ohio is obligated to self supply capacity for the Duke Energy Ohio load zone. The generation assets began selling all of their electricity into wholesale markets in January 2012 and currently receive wholesale energy margins and capacity revenues from PJM at market rates. Commercial Power has economically hedged its forecasted coal-fired generation and a significant portion of its forecasted gas-fired generation for 2013. Capacity revenues are 100% contracted in PJM through May 2016.

For information on Commercial Power’s generation facilities, see “Commercial Power” in Item 2, “Properties”

Commercial Power also has a retail sales subsidiary, Duke Energy Retail Sales, LLC (Duke Energy Retail), which is certified by the PUCO as a Competitive Retail Electric Supplier (CRES) provider in Ohio. Duke Energy Retail serves retail electric and gas customers in southwest, west central and northern Ohio with energy and other energy services at competitive rates.

Through Duke Energy Generation Services, Inc. (DEGS), Commercial Power engages in the development, construction and operation of renewable energy projects. In addition, DEGS develops commercial transmission projects. Currently, DEGS has approximately 1,269 net MW of renewable generating capacity in operation as of December 31, 2012.

Rates and Regulation

Duke Energy Ohio Capacity Rider Filing. On August 29, 2012, Duke Energy Ohio filed an application with the PUCO for the establishment of a charge, pursuant to Ohio’s state compensation mechanism, for capacity provided consistent with its obligations as an FRR entity. The application included a request for deferral authority and for a new tariff to implement the charge. The deferral being sought is the difference between its costs and market-based prices for capacity. The requested tariff would implement a charge to be collected via a rider through which such deferred balances will subsequently be recovered. 24 parties moved to intervene. Hearings have been set for April 2, 2013. Duke Energy Ohio expects an order in 2013.

Other Matters. As discussed in the USFE&G section above, the PUCO approved Duke Energy Ohio’s new ESP in November 2011. In November 2011, as a result of changes resulting from the PUCO’s approval of the new ESP, Commercial Power ceased applying regulatory accounting treatment to its Ohio operations. Currently, no portion of Commercial Power applies regulatory accounting.

Commercial Power’s Ohio retail load operations’ rates were subject to approval by the PUCO through December 2011, and thus these operations, through December 31, 2011, are referred to herein as Commercial Power’s regulated operations.

For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters — Rate Related Information.”

Commercial Power is subject to regulation at the federal level, primarily from the FERC. Regulations of the FERC govern access to regulated electric customer and other data by nonregulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of Commercial Power.

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

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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 nonregulated generators in the Midwestern U.S., wholesale power providers, coal and natural gas suppliers, and renewable energy.

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 through 2018. 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 majority of Commercial Power’s coal is sourced from mines in the Northern Appalachian and Illinois basins. Commercial Power has an adequate supply of coal to fuel its projected 2013 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. In general Commercial Power hedges its natural gas requirements using financial contracts. Physical gas is purchased in the spot market to meet generation needs.

INTERNATIONAL ENERGY

International Energy principally operates and manages power generation facilities and engages in sales and marketing of electric power, natural gas, and natural gas liquids outside the U.S. It conducts operations through DEI and its affiliates and its activities principally target power generation in Latin America. Additionally, International Energy owns a 25% interest in National Methanol Company (NMC), a large regional producer of methanol and methyl tertiary butyl ether (MTBE) located in Saudi Arabia. The investment in NMC is accounted for under the equity method of accounting. In the first quarter of 2012, Duke Energy completed the sale of International Energy’s indirect 25% ownership interest in Attiki Gas Supply, S.A (Attiki), a Greek corporation, to an existing equity owner in a series of transactions that resulted in the full discharge of the related debt obligation. See Note 13 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates” for additional information. In 2012, International Energy acquired a 240 MW thermal plant in southern Chile.  In addition, International acquired Iberoamericana de Energía Ibener S.A., which owns and operates a 140 MW hydro complex. See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets,” 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 4,900 gross MW of generation facilities. For information on International Energy’s generation facilities, see “International Energy” in Item 2, “Properties.”

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

Recent legislation in Brazil allowed the renewal of certain concessions that were granted prior to 1995 and due to expire in 2015 to 2017, if, among other things, the concession holders dedicated their generation capacity to the regulated market. International Energy’s concessions, which were granted after 1995, were not affected by this legislation. The change in market prices, if any, from this legislation is not expected to have a significant impact on International Energy’s earnings and cash flows because its generation capacity is highly contracted through 2016.

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

OTHER

The remainder of Duke Energy’s operations is presented as Other. While it is not an operating segment, Other primarily includes unallocated corporate interest expense, certain unallocated corporate costs, Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, contributions to the Duke Energy Foundation, Duke Energy’s effective 50% interest in DukeNet Communications, LLC (DukeNet) and related telecom businesses, and Duke Energy’s effective 60% interest in Duke Energy Trading and Marketing, LLC (DETM), which management is currently in the process of winding down.

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

Regulation

Certain entities within Other are subject to the jurisdiction of state and local agencies.

GEOGRAPHIC REGIONS

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For a discussion of Duke Energy’s foreign operations see “Management’s Discussion and Analysis of Results of Operations” and Note 3 to the Consolidated Financial Statements, “Business Segments.”

EMPLOYEES

On December 31, 2012, Duke Energy had 27,885 employees. A total of 5,784 operating and maintenance employees were represented by unions.

EXECUTIVE OFFICERS OF DUKE ENERGY

Lynn J. Good	53	Executive Vice President 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	56	Executive Vice President and Chief Nuclear Officer. Mr. Jamil assumed his position as Chief Nuclear Officer in February 2008. He also served as Chief Generation Officer for Duke Energy from July 2009 to June 2012. Prior to that he served as Senior Vice President, Nuclear Support, Duke Energy Carolinas, LLC since January 2007; and prior to that he served as Vice President, Catawba Nuclear Station, since July 2003.
Julia S. Janson	48	Executive Vice President, Chief Legal Officer and Corporate Secretary. Ms. Janson assumed her position as Executive Vice President, Chief Legal Officer and Corporate Secretary in December 2012.  Prior to that she had held the position of President of Duke Energy Ohio and Duke Energy Kentucky since 2008. She also held the position of Senior Vice President of Ethics and Compliance and Corporate Secretary for Duke Energy after its merger with Cinergy. Ms. Janson served as Chief Compliance Officer and Corporate Secretary for Cinergy since 2000.
Marc E. Manly	60	Executive Vice President and President, Commercial Businesses. Mr. Manly assumed the position of Executive Vice President and President, Commercial Businesses in December 2012.  Prior to that he had held the positions of Chief Legal Officer since April 2006, upon the merger of Duke Energy and Cinergy. He also held the position of Corporate Secretary from December 2008 until June 2012. 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	65	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	53	Executive Vice President and Chief Operating Officer, Regulated Utilities. Mr. Trent assumed his current position in December 2012. He previously held the position of Executive Vice President, Regulated Utilities upon the merger with Progress Energy in July 2012 and prior to that, President, Commercial Businesses from July 2009 until July 2012. 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.
Jennifer L. Weber	46	Executive Vice President and Chief Human Resources Officer. Ms. Weber assumed her current position in January 2011. Prior to that she served as Senior Vice President and Chief Human Resources Officer since November 2008. Prior to that she served as Senior Vice President of Human Resources at Scripps Networks Interactive from 2005 to 2008.
Lloyd M. Yates	52	Executive Vice President, Regulated Utilities. Mr. Yates assumed his position as Executive Vice President, Regulated Utilities in November 2012. Prior to that, he was named Executive Vice President, Customer Operations in July 2012, upon the merger of Duke Energy and Progress Energy. Mr. Yates served as Chief Executive Officer, Progress Energy Carolinas, Inc. from July 2007 until June 2012.
Steven K. Young	54	Vice President, Chief Accounting Officer and Controller. Mr. Young assumed the role of Chief Accounting Officer in July 2012. He assumed the role of Controller 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 or appointed.

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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.

ENVIRONMENTAL MATTERS

The Duke Energy Registrants are subject to federal, state and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Duke Energy is also subject to international laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental laws and regulations affecting the Duke Energy Registrants 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.

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 the Duke Energy Registrants’ operations. Additionally, other recently passed and potential future environmental laws and regulations could have a significant impact on the Duke Energy Registrants’ results of operations, cash flows or financial position. However, if and when such laws and regulations become effective, the Duke Energy Registrants will seek appropriate regulatory recovery of costs to comply within its regulated operations.

For more information on environmental matters involving the Duke Energy Registrants, including possible liability and capital costs, see Notes 4 and 5 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 5 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 the Duke Energy Registrants.

Duke Energy Subsidiary Registrants

Duke Energy Carolinas

Duke Energy Carolinas generates, transmits, distributes and sells electricity in central and western North Carolina and western South Carolina. Duke Energy Carolinas is subject to the regulatory provisions of the NCUC, the PSCSC, the NRC and FERC. Duke Energy Carolinas operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Duke Energy Carolinas’ service area covers approximately 24,000 square miles and supplies electric service to 2.4 million residential, commercial and industrial customers. See Item 2. “Properties” for further discussion of Duke Energy Carolinas’ generating facilities, transmission and distribution.

The remainder of Duke Energy Carolinas’ operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its parent, Duke Energy.

Progress Energy

Progress Energy, Inc. is a public utility holding company primarily engaged in the regulated electric utility business. Headquartered in Raleigh, North Carolina, it owns, directly or indirectly, all of the outstanding common stock of its utility subsidiaries, Progress Energy Carolinas and Progress Energy Florida. When discussing Progress Energy’s financial information, it necessarily includes the results of Progress Energy Carolinas and Progress Energy Florida.

Progress Energy is subject to the regulatory provisions of the NCUC, the PSCSC, the FPSC, the NRC and the FERC. Progress Energy operates in one reportable segment, Franchised Electric, which generates, transmits, distributes and sells electricity in portions of North Carolina, South Carolina and Florida. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

The remainder of Progress Energy’s operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its parent, Duke Energy.

Progress Energy Carolinas

Progress Energy Carolinas is a regulated public utility founded in North Carolina in 1908 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina. For information about Progress Energy Carolinas’ generating plants, see Item 2, “Properties.” Progress Energy Carolinas is subject to the regulatory provisions of the NCUC, the PSCSC, the NRC and FERC. Progress Energy Carolinas operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

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Progress Energy Carolinas’ service area covers approximately 34,000 square miles, including a substantial portion of the coastal plain of North Carolina extending from the Piedmont to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in western North Carolina in and around the city of Asheville and an area in the northeastern portion of South Carolina. At December 31, 2012, Progress Energy Carolinas was providing electric services to approximately 1.5 million residential, commercial and industrial customers.

The remainder of Progress Energy Carolinas’ operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its ultimate parent, Duke Energy.

Progress Energy Florida

Progress Energy Florida is a regulated public utility founded in Florida in 1899 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. For information about Progress Energy Florida’s generating plants, see Item 2, “Properties.” Progress Energy Florida is subject to the regulatory provisions of the FPSC, the NRC and FERC. Progress Energy Florida operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Progress Energy Florida’s service area covers approximately 20,000 square miles in west-central Florida, and includes the densely populated areas around Orlando, as well as the cities of St. Petersburg and Clearwater. Progress Energy Florida is interconnected with 22 municipal and 9 rural electric cooperative systems. At December 31, 2012, Progress Energy Florida was providing electric services to approximately 1.7 million residential, commercial and industrial customers.

The remainder of Progress Energy Florida’s operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its ultimate parent, Duke Energy.

Duke Energy Ohio

Duke Energy Ohio is a wholly owned subsidiary of Cinergy, which is a wholly owned subsidiary of Duke Energy. Duke Energy Ohio is a combination electric and gas public utility that provides service in southwestern Ohio and northern Kentucky through its wholly owned subsidiary Duke Energy Kentucky, as well as electric generation in parts of Ohio, Illinois, and Pennsylvania. Duke Energy Ohio’s principal lines of business include generation, transmission and distribution of electricity, the sale of and/or transportation of natural gas, and energy marketing. Duke Energy Kentucky’s principal lines of business include generation, transmission and distribution of electricity, as well as the sale of and/or transportation of natural gas. References herein to Duke Energy Ohio include Duke Energy Ohio and its subsidiaries. Duke Energy Ohio is subject to the regulatory provisions of the PUCO, the KPSC and FERC.

Duke Energy Ohio Business Segments. At December 31, 2012, Duke Energy Ohio operated two business segments, both of which are considered reportable segments under the applicable accounting rules: Franchised Electric and Gas and Commercial Power. For additional information on each of these business segments, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

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

Franchised Electric and Gas

Franchised Electric and Gas consists of Duke Energy Ohio’s regulated electric and gas transmission and distribution systems located in Ohio and Kentucky, including its regulated electric generation in Kentucky. Franchised Electric and Gas plans, constructs, operates and maintains Duke Energy Ohio’s transmission and distribution systems, which transmit and distribute electric energy to consumers in southwestern Ohio. In addition, Franchised Electric and Gas plans, constructs, operates and maintains Duke Energy Kentucky’s generation assets and transmission and distribution systems, which generate, transmit and distribute electric energy to consumers in and northern Kentucky. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. Substantially all of Franchised Electric and Gas’ operations are regulated and, accordingly, these operations qualify for regulatory accounting treatment.

Duke Energy Ohio’s Franchised Electric and Gas service area covers 3,000 square miles and supplies electric service to 830,000 residential, commercial and industrial customers and provides regulated transmission and distribution services for natural gas to 500,000 customers. See Item 2. “Properties” for further discussion of Duke Energy Ohio’s Franchised Electric and Gas generating facilities.

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 consists primarily of coal-fired generation assets located in Ohio and gas-fired nonregulated generation assets which are dispatched into wholesale markets and receive capacity revenues at market rates. These assets are comprised of 6,825 net 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. The coal-fired generation assets were dedicated under the Duke Energy Ohio ESP through December 31, 2011. Duke Energy Ohio’s Commercial Power reportable operating segment does not include the operations of DEGS or Duke Energy Retail, which is included in the Commercial Power reportable operating segment at Duke Energy. See Item 2. “Properties”, for further discussion of Duke Energy Ohio’s Commercial Power generating facilities.

The PUCO approved Duke Energy Ohio’s new ESP in November 2011. The ESP includes competitive auctions for electricity supply for a term of January 1, 2012 through May 31, 2015. The ESP also includes a provision for a non-bypassable stability charge of $110 million per year to be collected from 2012-2014 and requires Duke Energy Ohio to transfer its generation assets to a nonregulated affiliate on or before December 31, 2014. As a result of the new ESP, the energy from Duke Energy Ohio’s coal-fired generation assets no longer serve retail load customers or receive negotiated pricing under the ESP.

Effective January 1, 2012, Duke Energy Ohio completed its RTO realignment to PJM, and operates as an FRR entity through May 31, 2015. As an FRR entity, Duke Energy Ohio is required to self supply capacity for the Duke Energy Ohio load zone.

See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for further discussion related to regulatory filings.

In 2012, 2011, and 2010 Duke Energy Ohio earned approximately 36%, 24%, and 13%, respectively, of its consolidated operating revenues from PJM. These revenues relate to the sale of capacity and electricity from all of Duke Energy Ohio’s nonregulated generation assets in 2012 and its gas-fired nonregulated generation assets in 2011 and 2010.

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Other

The remainder of Duke Energy Ohio’s operations is presented as Other. Although it is not considered a business segment, Other primarily consists of certain governance costs allocated by its ultimate parent, Duke Energy.

Duke Energy Indiana

Duke Energy Indiana, an Indiana corporation organized in 1942, is an indirect wholly owned subsidiary of Duke Energy. Duke Energy Indiana generates, transmits and distributes electricity in central, north central, and southern Indiana. Duke Energy Indiana is subject to the regulatory provisions of the IURC and FERC. Duke Energy Indiana operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. The substantial majority of Duke Energy Indiana’s operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Duke Energy Indiana’s service area covers 23,000 square miles. Duke Energy Indiana supplies electric service to 790,000 residential, commercial and industrial customers. See Item 2. “Properties” for further discussion of Duke Energy Indiana’s generating facilities, transmission and distribution.

The remainder of Duke Energy Indiana’s operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its ultimate parent, Duke Energy.

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ITEM 1A. RISK FACTORS

Unless otherwise indicated, the risk factors discussed below generally relate to risks associated with all of the Duke Energy Registrants. Risks identified at the Subsidiary Registrant level are generally applicable to Duke Energy.

The Duke Energy Registrants’ 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 their ability to recover costs.

The Duke Energy Registrants’ 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, Florida, Ohio, Indiana and Kentucky. If the Duke Energy Registrants’ franchised electric earnings exceed the returns established by the state regulatory commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease the Duke Energy Registrants’ future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, the Duke Energy Registrants’ future earnings could be negatively impacted.

If legislative and regulatory structures were to evolve in such a way that the Duke Energy Registrants’ exclusive rights to serve their franchised customers were eroded, their future earnings could be negatively impacted.

The Duke Energy Registrants’ plans for future expansion and modernization of their generation fleet subject them to risk of failure to adequately execute and manage their significant construction plans, as well as the risk of not recovering all costs or of recovering costs in an untimely manner, which could materially impact their results of operations, cash flows or financial position.

The completion of the Duke Energy Registrants’ 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, the Duke Energy Registrants’ ability to recover all these costs and recovering costs in a timely manner could materially impact the Duke Energy Registrants’ consolidated financial position, results of operations or cash flows.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect the Duke Energy Registrants’ financial position, results of operations or cash flows and their utility 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 the Duke Energy Registrants and consequently on their 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 the Duke Energy Registrants due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. The Duke Energy Registrants cannot predict the extent and timing of entry by additional competitors into the electric markets. The Duke Energy Registrants cannot predict when they will be subject to changes in legislation or regulation, nor can they predict the impact of these changes on their financial position, results of operations or cash flows.

The ability of the Duke Energy Registrants to recover significant costs resulting from severe weather events is subject to regulatory oversight, and the timing and amount of any such recovery is uncertain and may impact their financial condition, results of operations and cash flows.

The Duke Energy Registrants are subject to incurring significant costs resulting from damage sustained during severe weather events. If the Duke Energy Registrants cannot recover costs associated with future severe weather events in a timely manner, or in an amount sufficient to cover our actual costs, their financial condition, results of operations and cash flows could be materially and adversely impacted.

Energy conservation could negatively impact the Duke Energy Registrants’ financial results.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in or applications of technology could lead to declines in per capita energy consumption. To the extent conservation results in reduced energy demand or significantly slows the growth in demand, the Duke Energy Registrants’ unregulated business activities could be adversely impacted. In the Duke Energy Registrants’ regulated operations, conservation could have a negative impact depending on the regulatory treatment of the associated impacts. The Duke Energy Registrants currently have energy-efficiency riders in place to recover the cost of energy-efficiency programs in North Carolina, South Carolina, Florida, Ohio and Kentucky. Should the Duke Energy Registrants be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact.

The Duke Energy Registrants’ businesses are subject to extensive federal regulation that will affect their operations and costs.

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

The Duke Energy Registrants are subject to numerous environmental laws and regulations that require significant capital expenditures that can increase cost of operations, and which may impact or limit business plans, or cause exposure to environmental liabilities.

The Duke Energy Registrants are subject to numerous environmental laws and regulations affecting many aspects of their present and future operations, including air 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 the Duke Energy Registrants 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 from 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 the Duke Energy Registrants could be required to take to ensure that their facilities are in compliance could be prohibitively expensive. As a result, the Duke Energy Registrants may be required to shut down or alter the operation of their facilities, which may cause the Duke Energy Registrants to incur losses. Further, the Duke Energy Registrants’ regulatory rate structure and their contracts with customers may not necessarily allow for the recovery of capital costs incurred to comply with new environmental regulations. Also, the Duke Energy Registrants may not be able to obtain or maintain from time to time all

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required environmental regulatory approvals for their operating assets or development projects. Delays in obtaining any required environmental regulatory approvals, failure to obtain and comply with them or changes in environmental laws or regulations to more stringent compliance levels could result in additional costs of operation for existing facilities or development of new facilities being prevented, delayed or 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 the Duke Energy Registrants’ 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.

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

Other potential new environmental regulations, limiting the use of coal acquired from mountaintop removal and imposing additional requirements on water discharges associated with mountaintop removal, could increase costs of fuel and require the Duke Energy Registrants to make additional related capital expenditures. In addition, the Duke Energy Registrants are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of their power generation facilities and natural gas assets 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, the Duke Energy Registrants may obtain, or be required to provide, indemnification against some environmental liabilities. If the Duke Energy Registrants incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, the Duke Energy Registrants could suffer material losses.

The Duke Energy Registrants’ sales may decrease if they are unable to gain adequate, reliable and affordable access to transmission assets.

The Duke Energy Registrants depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver electricity sold 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, the Duke Energy Registrants’ ability to sell and deliver products may be hindered.

The different regional power markets have changing regulatory structures, which could affect the Duke Energy Registrants’ 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 the Duke Energy Registrants’ wholesale power marketing business.

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

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

If the rating agencies were to rate the Duke Energy Registrants or their rated subsidiaries below investment grade, the entities’ borrowing costs would increase, perhaps significantly. In addition, their potential pool of investors and funding sources would likely decrease. Further, if the Duke Energy Registrants’ short-term debt rating were to fall, access to the commercial paper market could be significantly limited. Any downgrade or other event negatively affecting the credit ratings of the Duke Energy Registrants’ subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase their 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 reduction in liquidity and borrowing availability could ultimately impact the ability to indefinitely reinvest the earnings of its international operations, which could result in significant income taxes that would have a material adverse effect on Duke Energy’s results of operations.

A downgrade below investment grade could also require the Duke Energy Registrants 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 the Duke Energy Registrants’ liquidity and profitability and could have a material adverse effect on their financial position, results of operations or cash flows.

The Duke Energy Registrants are exposed to credit risk of the customers and counterparties with whom they do business.

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

The Duke Energy Registrants’ operating results may fluctuate on a seasonal and quarterly basis and can be negatively affected by changes in weather conditions and severe weather.

Electric power generation is generally a seasonal business. In most parts of the U.S., 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 the Duke Energy Registrants’ businesses may fluctuate substantially on a seasonal and quarterly basis and thus make period-to-period comparison less relevant.

Sustained severe drought conditions could impact generation by the Duke Energy Registrants’ hydroelectric plants, as well as their fossil and nuclear plant operations, as these facilities use water for cooling purposes and for the operation of environmental compliance equipment. Furthermore, destruction caused by severe weather events, such as hurricanes, tornadoes, severe thunderstorms, snow and ice storms, can result in lost operating revenues due to outages; property damage, including downed transmission and distribution lines; and additional and unexpected expenses to mitigate storm damage.

The Duke Energy Registrants are involved in numerous legal proceedings, the outcomes of which are uncertain. Adverse resolution of these matters could negatively affect the Duke Energy Registrants’ financial position, results of operations or cash flows.

The Duke Energy Registrants are 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 the Duke Energy Registrants cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of

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PART I

some of the matters could require 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 the Duke Energy Registrants’ cash flows and results of operations. Similarly, it is reasonably possible that the terms of resolution could require the Duke Energy Registrants to change business practices and procedures, which could also have a material effect on their financial position, results of operations or cash flows.

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

Sustained downturns or sluggishness in the economy generally affect the markets in which the Duke Energy Registrants operate and negatively influence energy operations. Declines in demand for energy as a result of economic downturns in the Duke Energy Registrants’ franchised electric service territories will reduce overall sales and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity and gas. Although the Duke Energy Registrants’ 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 the Duke Energy Registrants’ 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.

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

Factors that could impact sales volumes, generation of electricity and market prices at which the Duke Energy Registrants’ 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 the Duke Energy Registrants’ ability to operate its facilities in an economical manner;

·supply of and demand for energy commodities;

·transmission or transportation constraints or inefficiencies which impact the Duke Energy Registrants’ 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, gas and uranium;

·electric generation capacity surpluses which cause the Duke Energy Registrants’ 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, the Duke Energy Registrants’ markets.

Coal inventory levels have increased due to mild weather, low natural gas and power prices resulting in higher combined cycle gas-fired generation, and the economy’s overall effect on load. Continuation of these factors for an extended period of time could result in additional costs of managing the coal inventory or other costs. If these costs are not recoverable the Duke Energy Registrants’ results of operations could be negatively impacted.

Fluctuations in commodity prices or availability may adversely affect various aspects of the Duke Energy Registrants’ operations as well as their financial condition, results of operations and cash flows.

The Duke Energy Registrants are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, nuclear fuel, electricity and other energy-related commodities, including emission allowances, as a result of their ownership of energy-related assets. Fuel costs are recovered primarily through cost-recovery clauses, subject to the approval of state utility commissions. Additionally, the Duke Energy Registrants have hedging strategies in place to mitigate fluctuations in commodity supply prices, but to the extent that these do not cover the entire exposure to commodity price fluctuations, or their hedging procedures do not work as planned, there can be no assurances that the Duke Energy Registrants’ financial performance will not be negatively impacted by price fluctuations. Additionally, the Duke Energy Registrants are exposed to risk that counterparties will not be able to perform their obligations. Should counterparties fail to perform, the Duke Energy Registrants might be forced to replace the underlying commitment at prevailing market prices possibly resulting in losses in addition to the amounts, if any, already paid to the counterparties.

Certain of the Duke Energy Registrants hedge agreements may result in the receipt of, or posting of, derivative collateral with counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to the return of collateral received and/or the posting of collateral with counterparties negatively impact our liquidity. Downgrades in the Duke Energy Registrants’ credit ratings could lead to additional collateral posting requirements. The Duke Energy Registrants continually monitor derivative positions in relation to market price activity.

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

The 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 required or voluntary contributions made to the plans. The Subsidiary Registrants participate in employee benefit plans sponsored by Duke Energy or Progress Energy. The Subsidiary Registrants are allocated their proportionate share of the cost and obligations related to these plans. Without sustained growth in the pension investments over time to increase the value of plan assets and depending upon the other factors impacting costs as listed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations, and the Subsidiary Registrants’ proportionate share of such cash funding obligations, could have a material impact on the Duke Energy Registrants’ financial position, results of operations or cash flows.

Potential terrorist activities or military or other actions, including cyber system attacks, could adversely affect the Duke Energy Registrants’ businesses.

The continued threat of terrorism and the impact of retaliatory military and other action by the U.S. and its allies may lead to increased political, economic and financial market instability and volatility in prices for natural gas and oil which may have material adverse affects in ways the Duke Energy

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PART I

Registrants cannot predict at this time. In addition, future acts of terrorism and any possible reprisals as a consequence of action by the U.S. and its allies could be directed against companies operating in the U.S. or their international affiliates. Cyber systems, infrastructure and generation facilities such as the Duke Energy Registrants’ nuclear plants could be potential targets of terrorist activities or harmful activities by individuals or groups. The potential for terrorism has subjected the Duke Energy Registrants’ operations to increased risks and could have a material adverse effect on their businesses. In particular, the Duke Energy Registrants may experience increased capital and operating costs to implement increased security for their cyber systems and plants, including 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 the Duke Energy Registrants and their competitors typically insure against may decrease. In addition, the insurance the Duke Energy Registrants are able to obtain may have higher deductibles, higher premiums, lower coverage limits and more restrictive policy terms.

Information security risks have generally increased in recent years as a result of the proliferation of new technologies and the increased sophistication and activities of cyber attacks. Through our smart grid and other initiatives, the Duke Energy Registrants have increasingly connected equipment and systems related to the generation, transmission and distribution of electricity to the Internet. Because of the critical nature of the infrastructure and the increased accessibility enabled through connection to the Internet, the Duke Energy Registrants may face a heightened risk of cyber attack. In the event of such an attack, the Duke Energy Registrants could have business operations disrupted, property damaged and customer information stolen; experience substantial loss of revenues, response costs and other financial loss; and be subject to increased regulation, litigation and damage to our reputation.

Additional risks and uncertainties not currently known to the Duke Energy Registrants or which they currently deem to be immaterial also may materially adversely affect the Duke Energy Registrants’ financial condition, results of operations or cash flows.

Failure to attract and retain an appropriately qualified workforce could unfavorably impact the Duke Energy Registrants’ results of operations.

Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the lengthy time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If the Duke Energy Registrants are unable to successfully attract and retain an appropriately qualified workforce, their financial position or results of operations could be negatively affected.

The Duke Energy Registrants rely on access to short-term borrowings and longer-term capital markets to finance their capital requirements and support their liquidity needs. Access to those markets can be adversely affected by a number of conditions, many of which are beyond the Duke Energy Registrants’ control.

The Duke Energy Registrants’ businesses are 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 their assets. Accordingly, as a source of liquidity for capital requirements not satisfied by the cash flow from their operations and to fund investments originally financed through debt instruments with disparate maturities, Duke Energy and the Subsidiary Registrants rely on access to short-term money markets as well as longer-term capital markets and the Subsidiary Registrants also rely on access to short-term intercompany borrowings. If the Duke Energy Registrants are not able to access capital at competitive rates or at all, the ability to finance their operations and implement their strategy and business plan as scheduled could be adversely affected. An inability to access capital may limit the Duke Energy Registrants’ ability to pursue improvements or acquisitions that they may otherwise rely on for future growth.

Market disruptions may increase the Duke Energy Registrants’ cost of borrowing or adversely affect their 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 their facilities or unrelated energy companies; or the overall health of the energy industry. The availability of credit under Duke Energy’s revolving credit facilities depends upon the ability of the banks providing commitments under such facilities to provide funds when their obligations to do so arise. Systematic risk of the banking system and the financial markets could prevent a bank from meeting its obligations under the facility agreement.

Duke Energy maintains revolving credit facilities to provide back-up for a commercial paper program for variable rate demand tax-exempt bonds that may be put to the Duke Energy Registrant issuer at the option of the holder and certain letters of credit at various entities. These facilities typically include borrowing sublimits for the Subsidiary Registrants and financial covenants that 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 the Duke Energy Registrants 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 it 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 its international projects.

Duke Energy currently owns and may acquire and/or dispose of material energy-related investments and projects outside the U.S. The economic, regulatory, market and political conditions in some of the countries where Duke Energy has interests or in which it may explore development, acquisition or investment opportunities could present risks related to, among others, Duke Energy’s ability to obtain financing on suitable terms, its customers’ ability to honor their obligations with respect to projects and investments, delays in construction, limitations on its 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 it to risks related to fluctuations in currency rates. These risks, and Duke Energy’s activities to mitigate such risks, may adversely affect its cash flows and results of operations.

Duke Energy’s operations and investments outside the U.S. expose it 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 its cash flows and results of operations.

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PART I

Duke Energy’s merger with Progress Energy may not achieve its intended results.

The merger is expected to result in various benefits, including, among other things, cost savings and operating efficiencies relating to the joint dispatch of generation and combining of fuel purchasing power. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including market conditions, risks related to Duke Energy’s businesses, and whether the business of Progress Energy is integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs; decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s financial position, results of operations or cash flows.

Duke Energy’s and Progress Energy’s ability to fully utilize tax credits may be limited.

In accordance with the provisions of Internal Revenue Code Section 29/45K, Duke Energy and Progress Energy have generated tax credits based on the content and quantity of coal-based solid synthetic fuels produced and sold to unrelated parties. This tax credit program expired at the end of 2007. The timing of the utilization of the tax credits is dependent upon Duke Energy’s and Progress Energy’s taxable income. The timing of the utilization can also be impacted by certain substantial changes in ownership, including the merger of Duke Energy and Progress Energy. Additionally, in the normal course of business, Duke Energy’s and Progress Energy’s tax returns are audited by the IRS. If Duke Energy’s and Progress Energy’s tax credits were disallowed in whole or in part as a result of an IRS audit, there could be significant additional tax liabilities and associated interest for previously recognized tax credits, which could have a material adverse impact on Duke Energy’s and Progress Energy’s earnings and cash flows. Although Duke Energy and Progress Energy are unaware of any currently proposed legislation or new IRS regulations or interpretations impacting previously recorded synthetic fuels tax credits, the value of credits generated could be unfavorably impacted by such legislation or IRS regulations and interpretations.

Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida may incur substantial costs and liabilities due to their ownership and operation of nuclear generating facilities.

Ownership interest in and operation of nuclear stations by Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida subject them to various risks. These risks include, 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.

Ownership and operation of nuclear generation facilities requires compliance with 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 Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s control, such as a serious nuclear incident at a facility owned by a third-party, could necessitate substantial capital and other expenditures, as well as assessments 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 Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s results of operations and financial condition.

Ownership and operation of nuclear generation facilities also requires the maintenance of funded trusts that are intended to pay for the decommissioning costs of the respective nuclear power plants. As discussed below, poor investment performance of these decommissioning trusts’ holdings and other factors impacting decommissioning costs could unfavorably impact Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s liquidity and results of operations as they could be required to significantly increase their cash contributions to the decommissioning trusts.

Market performance and other changes may decrease the value of Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s Nuclear Decommissioning Trust Fund (NDTF) investments, which then could require significant additional funding.

The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations to decommission nuclear plants. Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida have significant obligations in this area and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below projected rates of return. Although a number of factors impact funding requirements, a decline in the market value of the assets may increase the funding requirements of the obligations for decommissioning nuclear plants. If Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida are unable to successfully manage the NDTF assets, their financial condition, results of operations and cash flows could be negatively affected.

The costs of retiring Progress Energy Florida’s Crystal River Unit 3 could prove to be more extensive than is currently identified. All costs associated with retirement of the Crystal River Unit 3 asset, including replacement power, may not be fully recoverable through the regulatory process.

Early retirement could result in continued purchases of replacement power and/or additional capital and operating costs associated with construction of replacement capacity resources to continue to service Progress Energy Florida’s customer needs. However, there is no definitive plan for new generating capacity at this time. In addition, exit costs to wind down operations and ultimately to retire and decommission the plant could exceed estimates and, if not recoverable through the regulatory process, could adversely affect Duke Energy’s, Progress Energy’s and Progress Energy Florida’s financial condition, results of operations and cash flows.

While the foregoing reflects Progress Energy Florida’s current intentions and estimates with respect to the retirement of Crystal River Unit 3, the cost of replacement power, and the degree of recoverability of these costs, are all subject to significant uncertainties. Additional developments with respect to Crystal River Unit 3, costs that are greater than anticipated and recoverability that is less than anticipated could adversely affect Duke Energy’s, Progress Energy’s and Progress Energy Florida’s financial condition, results of operations and cash flows.

Duke Energy Ohio’s and Duke Energy Indiana’s membership in a RTO presents risks that could have a material adverse effect on their results of operations, financial condition and cash flows.

The price at which Duke Energy Ohio can sell its generation capacity and energy is dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and its business rules. As a result, the prices in day–ahead and real–time energy markets and RTO capacity markets are subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, are also subject to volatility. PJM Interconnection, LLC (PJM) conducts Reliability Pricing Model (RPM) base residual auctions for capacity on an annual planning year basis. The results of the PJM RPM base residual auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources. Auction prices could fluctuate substantially over relatively short periods of time. Duke Energy Ohio cannot predict the outcome of future auctions, but if the auction prices are sustained at low levels, its results of operations, financial condition and cash flows could be adversely impacted.

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PART I

The rules governing the various regional power markets may also change, which could affect Duke Energy Ohio’s and Duke Energy Indiana’s costs and/or revenues. To the degree Duke Energy Ohio and Duke Energy Indiana incur significant additional fees and increased costs to participate in an RTO, their results of operations may be impacted. Duke Energy Ohio and Duke Energy Indiana may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Duke Energy Ohio and Duke Energy Indiana may be required to expand their transmission system according to decisions made by an RTO rather than their own internal planning process. While RTO transmission rates were initially designed to be revenue neutral, various proposals and proceedings currently taking place by the FERC may cause transmission rates to change from time to time. In addition, RTOs has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on Duke Energy Ohio and Duke Energy Indiana. Duke Energy Ohio and Duke Energy Indiana may also incur fees and costs to participate in RTOs.

As a members of an RTO, Duke Energy Ohio and Duke Energy Indiana are subject to certain additional risks, including those associated with the allocation among RTO members, of losses caused by unreimbursed defaults of other participants in the RTO markets and those associated with complaint cases filed against an RTO that may seek refunds of revenues previously earned by RTO members, including Duke Energy Ohio and Duke Energy Indiana.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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PART I

ITEM 2. PROPERTIES
U.S. FRANCHISED ELECTRIC AND GAS
	The following table provides information related to USFE&G’s electric generation stations as of December 31, 2012.  The MW
displayed in the table below are based on summer capacity.
Facility		Plant Type	Primary Fuel	Location	Total MW Capacity	Owned MW Capacity	Ownership Interest
Duke Energy Carolinas:
Oconee		Nuclear	Uranium	SC	2,538	2,538	100	%
Catawba(a)		Nuclear	Uranium	SC	2,258	435	19.26
Belews Creek		Fossil Steam	Coal	NC	2,220	2,220	100
McGuire		Nuclear	Uranium	NC	2,200	2,200	100
Marshall		Fossil Steam	Coal	NC	2,078	2,078	100
Cliffside		Fossil Steam	Coal	NC	1,377	1,377	100
Bad Creek		Hydro	Water	SC	1,360	1,360	100
Lincoln		Combustion Turbine	Gas / Oil	NC	1,267	1,267	100
Allen		Fossil Steam	Coal	NC	1,127	1,127	100
Rockingham		Combustion Turbine	Gas / Oil	NC	825	825	100
Jocassee		Hydro	Water	SC	780	780	100
Buck		Combined Cycle	Gas	NC	620	620	100
Dan River		Combined Cycle	Gas	NC	620	620	100
Mill Creek		Combustion Turbine	Gas / Oil	SC	596	596	100
Riverbend(j)		Fossil Steam	Coal	NC	454	454	100
Lee		Fossil Steam	Coal	SC	370	370	100
Cowans Ford		Hydro	Water	NC	325	325	100
Buck(j)		Fossil Steam	Coal	NC	256	256	100
Keowee		Hydro	Water	SC	152	152	100
Lee		Combustion Turbine	Gas / Oil	SC	82	82	100
Distributed generation		Renewable	Solar	NC	8	8	100
Other small hydro (26 plants)		Hydro	Water	NC / SC	660	660	100
Total Duke Energy Carolinas					22,173	20,350
Progress Energy Carolinas:
Roxboro(b)		Fossil Steam	Coal	NC	2,417	2,327	96.28	%
Brunswick(b)		Nuclear	Uranium	NC	1,870	1,527	81.66
Smith		Combined Cycle	Gas / Oil	NC	1,084	1,084	100
H.F. Lee		Combined Cycle	Gas	NC	920	920	100
Harris(b)		Nuclear	Uranium	NC	900	754	83.83
Wayne County		Combustion Turbine	Gas / Oil	NC	863	863	100
Smith		Combustion Turbine	Gas / Oil	NC	820	820	100
Darlington		Combustion Turbine	Gas / Oil	SC	790	790	100
Mayo(b)		Fossil Steam	Coal	NC	727	609	83.83
Robinson		Nuclear	Uranium	SC	724	724	100
Sutton(j)		Fossil Steam	Coal	NC	575	575	100
Asheville		Fossil Steam	Coal	NC	376	376	100
Asheville		Combustion Turbine	Gas / Oil	NC	324	324	100
Weatherspoon		Combustion Turbine	Gas / Oil	NC	131	131	100
Walters		Hydro	Water	NC	112	112	100
Tillery		Hydro	Water	NC	87	87	100
Sutton		Combustion Turbine	Gas / Oil	NC	61	61	100
Blewett		Combustion Turbine	Oil	NC	52	52	100
Cape Fear		Combustion Turbine	Oil	NC	35	35	100
Blewett		Hydro	Water	NC	22	22	100
Robinson		Combustion Turbine	Gas / Oil	SC	11	11	100
Marshall		Hydro	Water	NC	4	4	100
Total Progress Energy Carolinas					12,905	12,208
Progress Energy Florida:
Crystal River		Fossil Steam	Coal	FL	2,295	2,295	100	%
Hines		Combined Cycle	Gas / Oil	FL	1,912	1,912	100
Bartow		Combined Cycle	Gas / Oil	FL	1,133	1,133	100
Anclote		Fossil Steam	Gas / Oil	FL	1,011	1,011	100
Intercession City(c)		Combustion Turbine	Gas / Oil	FL	982	982	(c)
Crystal River Unit 3(d)		Nuclear	Uranium	FL	860	789	91.78
DeBary		Combustion Turbine	Gas / Oil	FL	638	638	100
Tiger Bay		Combined Cycle	Gas	FL	205	205	100
Bartow		Combustion Turbine	Gas / Oil	FL	177	177	100
Bayboro		Combustion Turbine	Oil	FL	174	174	100
Suwannee River		Combustion Turbine	Gas / Oil	FL	155	155	100
Turner		Combustion Turbine	Oil	FL	137	137	100
Suwannee River		Fossil Steam	Gas / Oil	FL	129	129	100
Higgins		Combustion Turbine	Gas / Oil	FL	105	105	100
Avon Park		Combustion Turbine	Gas / Oil	FL	48	48	100
University of Florida Cogeneration		Combustion Turbine	Gas	FL	46	46	100
Rio Pinar		Combustion Turbine	Oil	FL	12	12	100
Total Progress Energy Florida					10,019	9,948
Duke Energy Ohio:
East Bend(e)		Fossil Steam	Coal	KY	600	414	69	%
Woodsdale		Combustion Turbine	Gas / Propane	OH	462	462	100
Miami Fort (Unit 6)		Fossil Steam	Coal	OH	163	163	100
Total Duke Energy Ohio					1,225	1,039
Duke Energy Indiana:
Gibson(f)		Fossil Steam	Coal	IN	3,132	2,822	90.1	%
Cayuga(g)		Fossil Steam	Coal / Oil	IN	1,005	1,005	100
Wabash River(h)		Fossil Steam	Coal / Oil	IN	676	676	100
Madison		Combustion Turbine	Gas	OH	576	576	100
Vermillion(i)		Combustion Turbine	Gas	IN	568	355	62.5
Wheatland		Combustion Turbine	Gas	IN	460	460	100
Noblesville		Combined Cycle	Gas	IN	285	285	100
Gallagher		Fossil Steam	Coal	IN	280	280	100
Henry County		Combustion Turbine	Gas	IN	129	129	100
Cayuga		Combustion Turbine	Gas / Oil	IN	99	99	100
Connersville		Combustion Turbine	Oil	IN	86	86	100
Miami Wabash		Combustion Turbine	Oil	IN	80	80	100
Markland		Hydro	Water	IN	45	45	100
Total Duke Energy Indiana					7,421	6,898
Total USFE&G					53,743	50,443
Totals by plant type:
Nuclear					11,350	8,967
Fossil Steam					21,268	20,564
Combined Cycle					6,779	6,779
Combustion Turbine					10,791	10,578
Hydro					3,547	3,547
Renewable					8	8
Total USFE&G					53,743	50,443
(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)	This generation facility is jointly owned by Progress Energy Carolinas and the North Carolina Eastern Municipal Power Agency.
(c)	Progress Energy Florida owns and operates Intercession City Station Units 1-10 and 12-14. Unit 11 is jointly owned by Progress Energy Florida and Georgia Power Company. Georgia Power Company has the exclusive right to the output of this unit during the months of June through September. Progress Energy Florida has the exclusive right to the output of this unit for the remainder of the year.
(d)	Due to the extended outage at the Crystal River Unit 3 nuclear generating unit that began in September 2009 and the related delaminations, no nuclear power was generated in 2012, 2011 or 2010.  This generation facility is owned by Progress Energy Florida and various municipal electric companies.  In February 2013, Duke Energy announced the retirement of Crystal River Unit 3.
(e)	This generation facility is jointly owned by Duke Energy Ohio and a subsidiary of The AES Corporation.
(f)	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.
(g)	Includes Cayuga Internal Combustion (IC).
(h)	Includes Wabash River IC.
(i)	This generation facility is jointly owned by Duke Energy Indiana and the Wabash Valley Power Association.
(j)	Duke Energy has announced plans to retire these plants in 2013.

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PART I

	The following table provides information related to USFE&G's electric transmission and distribution properties as of December 31, 2012.
		Duke Energy Carolinas	Progress Energy Carolinas	Progress Energy Florida	Duke Energy Ohio	Duke Energy Indiana	Total USFE&G
Electric transmission  lines:
Miles of 525 KV		600	300	200	-	-	1,100
Miles of 345 KV		-	-	-	1,000	700	1,700
Miles of 230 KV		2,600	3,300	1,700	-	700	8,300
Miles of 100 to 161 KV		6,800	2,600	1,000	700	1,400	12,500
Miles of 13 to 69 KV		3,100	-	2,200	800	2,500	8,600
Total conductor miles of electric transmission lines		13,100	6,200	5,100	2,500	5,300	32,200
Electric distribution lines:
Miles of overhead lines		66,700	44,600	52,000	14,000	22,600	199,900
Miles of underground line		35,000	22,400	18,700	5,600	8,300	90,000
Total conductor miles of electric distribution lines		101,700	67,000	70,700	19,600	30,900	289,900
Number of electric transmission and distribution substations		1,500	500	500	300	500	3,300
Miles of gas mains		-	-	-	7,200	-	7,200
Miles of gas service lines		-	-	-	6,000	-	6,000
	Substantially all of USFE&G’s electric plant in service is mortgaged under indentures relating to Duke Energy Carolinas’, Progress
Energy Carolinas', Progress Energy Florida's, Duke Energy Ohio’s and Duke Energy Indiana’s various series of First Mortgage Bonds.

COMMERCIAL POWER
	The following table provides information related to Commercial Power’s electric generation stations as of December 31, 2012.  The
MW displayed in the table below are based on summer capacity."
Facility		Plant Type	Primary Fuel	Location	Total MW Capacity	Owned MW Capacity	Ownership Interest
Duke Energy Ohio:
Stuart(a)(b)(c)		Fossil Steam	Coal	OH	2,308	900	39	%
Zimmer(a)(c)		Fossil Steam	Coal	OH	1,300	605	46.5
Hanging Rock		Combined Cycle	Gas	OH	1,226	1,226	100
Beckjord(a)(c)		Fossil Steam	Coal	OH	1,024	765	74.7
Miami Fort (Units 7 and 8)(a)(c)		Fossil Steam	Coal	OH	1,000	640	64
Conesville(a)(b)(c)		Fossil Steam	Coal	OH	780	312	40
Washington		Combined Cycle	Gas	OH	617	617	100
Fayette		Combined Cycle	Gas	PA	614	614	100
Killen(a)(b)(c)		Fossil Steam	Coal	OH	600	198	33
Lee		Combustion Turbine	Gas	IL	568	568	100
Beckjord(c)		Combustion Turbine	Oil	OH	188	188	100
Dick's Creek(c)		Combustion Turbine	Gas	OH	136	136	100
Miami Fort(c)		Combustion Turbine	Oil	OH	56	56	100
Total Duke Energy Ohio					10,417	6,825
Duke Energy Renewables:
Los Vientos Windpower II		Renewable	Wind	TX	202	202	100	%
Los Vientos Windpower I		Renewable	Wind	TX	200	200	100
Top of the World		Renewable	Wind	WY	200	200	100
Notrees		Renewable	Wind	TX	153	153	100
Campbell Hill		Renewable	Wind	WY	99	99	100
North Allegheny		Renewable	Wind	PA	70	70	100
Laurel Hill Wind Energy		Renewable	Wind	PA	69	69	100
Ocotillo		Renewable	Wind	TX	59	59	100
Kit Carson		Renewable	Wind	CO	51	51	100
Silver Sage		Renewable	Wind	WY	42	42	100
Happy Jack		Renewable	Wind	WY	29	29	100
Shirley		Renewable	Wind	WI	20	20	100
Bagdad		Renewable	Solar	AZ	15	15	100
Washington White Post		Renewable	Solar	NC	12	12	100
TX Solar		Renewable	Solar	TX	14	14	100
Black Mountain		Renewable	Solar	AZ	9	9	100
Other small solar		Renewable	Solar	Various	25	25	100
Total Duke Energy Renewables					1,269	1,269
Total Commercial Power					11,686	8,094
Totals by plant type:
Fossil Steam					7,012	3,420
Combined Cycle					2,457	2,457
Combustion Turbine					948	948
Renewable					1,269	1,269
Total Commercial Power					11,686	8,094
(a)	These generation facilities are jointly owned by Duke Energy Ohio and subsidiaries of American Electric Power Company, Inc. and/or The AES Corporation.
(b)	Station is not operated by Duke Energy Ohio.
(c)	These generation facilities were dedicated under the ESP through December 31, 2011.
	In addition to the above facilities, Commercial Power owns an equity interest in the 585 MW capacity Sweetwater wind projects
located in Texas, the 299 MW capacity DS Cornerstone wind projects located in Kansas and the 13 MW capacity INDU Solar Holding JV. Commercial Power's share in these projects in 440 MW.

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PART I

INTERNATIONAL ENERGY
	The following table provides additional information related to International Energy’s electric generation stations as of December 31,
2012. The MW displayed in the table below are based on summer capacity.
Facility		Primary Fuel	Location	Total MW Capacity	Owned MW Capacity	Ownership Interest
Paranapanema(a)		Water	Brazil	2,258	2,073	92	%
Egenor		Water / Diesel	Peru	622	622	100
Cerros Colorados		Water / Gas	Argentina	576	524	91
DEI Chile		Water / Diesel / Gas	Chile	380	380	100
DEI El Salvador		Oil / Diesel	El Salvador	328	296	90
DEI Guatemala		Oil / Diesel / Coal	Guatemala	356	356	100
Electroquil		Diesel	Ecuador	192	163	85
Aguaytia		Gas	Peru	170	170	100
Total International Energy				4,882	4,584
(a)	Includes Canoas I and II, which is jointly owned by Duke Energy and Companhia Brasileira de Aluminio, as well as Duke Energy's wholly owned Palmeiras small hydro plant.
	International Energy also owns a 25% equity interest in NMC. In 2012, NMC produced approximately 900,000 metric tons of methanol
and in excess of 1 million metric tons of MTBE. Approximately 40% of methanol is normally used in the MTBE production.
OTHER
	Duke Energy owns approximately 5.2 million square feet and leases 2.9 million square feet of corporate, regional and district office
space spread throughout its service territories and in Houston, Texas.

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PART I

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 5 to the Consolidated Financial Statements, “Commitments and Contingencies — Litigation” and “Commitments and Contingencies — Environmental.”

Brazilian Regulatory Citations.In September 2007, the State Environmental Agency of Parana (IAP) assessed seven fines against Duke Energy International Geracao Paranapenema S.A. (DEIGP), totaling $15 million for failure to comply with reforestation measures allegedly required by state regulations in Brazil. On January 14, 2010, DEIGP received a notice that one of the fines was subsequently increased, on grounds that DEIGP is an alleged repeat offender; however, in 2012 the decision to increase the amount of that fine was reversed. DEIGP filed administrative appeals with respect to all the fines. Between 2009 and 2012, four of the fines, in the total amount of $9 million, were judged to be valid in the administrative courts. DEIGP challenged those administrative rulings in the Brazilian state courts, by filing judicial actions for annulment and also requested that its payment obligations be enjoined pending resolution on the merits. In one of the four cases, the court granted DEIGP’s request for injunction, and subsequently ruled on the merits in favor of DEIGP. The plaintiff filed an appeal. In two of the four cases, the court granted DEIGP’s request for injunction, and a decision on the merit is pending. In the fourth case, DEIGP’s request for injunction was denied; however, DEIGP was granted permission to deposit the total amount of the fine in the court registry and to suspend entry of the debt in the state tax liability roster.

Additionally, DEIGP was assessed three environmental fines by the Brazilian federal environmental enforcement agency, Brazil Institute of Environment and Renewable Natural Resources (IBAMA), totaling approximately $1 million for improper maintenance of existing reforested areas. DEIGP believes that it has properly maintained all reforested areas and has challenged these assessments.

ITEM 4. MINE SAFETY DISCLOSURES

This is not applicable for any of the Duke Energy Registrants.

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PART I

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 25,
2013, there were approximately 189,580 common stockholders of record.
Common Stock Data by Quarter
		2012						2011
				Stock Price Range(a)						Stock Price Range(a)
		Dividends Declared Per Share(b)		High		Low		Dividends Declared Per Share(b)		High		Low
First Quarter		$	0.750	$	66.33	$	62.01	$	0.735	$	55.44	$	52.08
Second Quarter(c)			1.515		70.20		60.57		1.485		58.50		53.85
Third Quarter			-		69.87		63.03		-		60.63		50.61
Fourth Quarter			0.765		65.90		59.63		0.75		66.36		57.51
(a)	Stock prices represent the intra-day high and low stock price.
(b)	On July 2, 2012, immediately prior to the close of the merger with Progress Energy, Duke Energy executed a one-for-three reverse stock split. All per share amounts included in the above table are presented as if the one-for-three reverse stock split had been effective at the beginning of the earliest period presented.
(c)	Dividends in June 2012 increased from $0.75 per share to $0.765 per share and dividends in June 2011 increased from $0.735 per share to $0.75 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.

Securities Authorized for Issuance Under Equity Compensation Plans

Duke Energy will provide information that is responsive to this Item 5 in its definitive proxy statement or in an amendment to this Annual Report not later than 120 days after the end of the fiscal year covered by this Annual Report, in either case under the caption “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” and possibly elsewhere therein. That information is incorporated in this Item 5 by reference.

Issuer Purchases of Equity Securities for Fourth Quarter of 2012

There were no repurchases of equity securities during the fourth quarter of 2012.

Stock Performance Graph

The performance graph below illustrates a five year comparison of cumulative total returns of Duke Energy Corporation common stock, as compared with the Standard & Poor’s (S&P) 500 Stock Index and the Philadelphia Utility Index for the 5-year period 2007 through 2012.

This performance graph assumes an initial investment of $100 invested on December 31, 2007, 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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PART I

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, 2012.

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ITEM 6. SELECTED FINANCIAL DATA
(in millions, except per-share amounts)		2012		2011		2010		2009		2008
Statement of Operations(a)
Total operating revenues		$	19,624	$	14,529	$	14,272	$	12,731	$	13,207
Operating income			3,126		2,777		2,461		2,249		2,511
Income from continuing operations			1,746		1,713		1,320		1,073		1,275
Net income			1,782		1,714		1,323		1,085		1,358
Net income attributable to Duke Energy Corporation		$	1,768	$	1,706	$	1,320	$	1,075	$	1,362
Common Stock Data
Income from continuing operations attributable to Duke Energy Corporation common shareholders(b)
	Basic	$	3.01	$	3.83	$	2.99	$	2.46	$	3.03
	Diluted		3.01		3.83		2.99		2.46		3.03
Net income attributable to Duke Energy Corporation common shareholders(b)
	Basic	$	3.07	$	3.83	$	3.00	$	2.49	$	3.23
	Diluted		3.07		3.83		3.00		2.49		3.22
Dividends declared per share(b)			3.03		2.97		2.91		2.82		2.70
Balance Sheet
Total assets		$	113,856	$	62,526	$	59,090	$	57,040	$	53,077
Long-term debt including capital leases, VIEs and redeemable preferred stock of subsidiaries, less current maturities			36,444		18,679		17,935		16,113		13,250
(a)	Significant transactions reflected in the results above include: (i) the 2012 merger with Progress Energy and (ii) 2012 and 2011 pre-tax impairment and other charges related to the Edwardsport IGCC project (see Note 4 to the Consolidated Financial Statements, "Regulatory Matters"); and (iii) 2010 impairment of goodwill and other assets (see Note 12 to the Consolidated Financial Statements, "Goodwill, Intangible Assets and Impairments").
(b)	On July 2, 2012, immediately prior to the merger with Progress Energy, Duke Energy executed a one-for-three reverse stock split. All share and earnings per share amounts are presented as if the one-for-three reverse stock split had been effective at the beginning of the earliest period presented.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis includes financial information prepared in accordance with generally accepted accounting principles (GAAP) in the United States (U.S.), as well as certain non-GAAP financial measures such as adjusted earnings and adjusted earnings per share, discussed below. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.

The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Duke Energy, Duke Energy Carolinas, Progress Energy, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio and Duke Energy Indiana. However, none of the registrants makes any representation as to information related solely to Duke Energy or the Subsidiary Registrants of Duke Energy other than itself.

DUKE ENERGY

Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is an energy company headquartered in Charlotte, North Carolina. Duke Energy operates in the United States (U.S.) primarily through its wholly owned subsidiaries, Duke Energy Carolinas, LLC (Duke Energy Carolinas), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (Progress Energy Carolinas), Florida Power Corporation d/b/a Progress Energy Florida, Inc. (Progress Energy Florida), Duke Energy Ohio, Inc. (Duke Energy Ohio), and Duke Energy Indiana, Inc. (Duke Energy Indiana), as well as in Latin America through International Energy.

When discussing Duke Energy’s consolidated financial information, it necessarily includes the results of its six separate subsidiary registrants, Duke Energy Carolinas, Progress Energy, Inc. (Progress Energy), Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio and Duke Energy Indiana (collectively referred to as the Subsidiary Registrants), which, along with Duke Energy, are collectively referred to as the Duke Energy Registrants.

On July 2, 2012, Duke Energy merged with Progress Energy, with Duke Energy continuing as the surviving corporation, and Progress Energy becoming a wholly owned subsidiary of Duke Energy. Progress Energy Carolinas and Progress Energy Florida, Progress Energy’s regulated utility subsidiaries, are now indirect wholly owned subsidiaries of Duke Energy. Duke Energy’s consolidated financial statements include Progress Energy, Progress Energy Carolinas and Progress Energy Florida activity from July 2, 2012, forward.

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

EXECUTIVE OVERVIEW

Merger with Progress Energy

On July 2, 2012, Duke Energy completed the merger contemplated by the Agreement and Plan of Merger (Merger Agreement), among Diamond Acquisition Corporation, a North Carolina corporation and Duke Energy’s wholly owned subsidiary (Merger Sub) and Progress Energy, Inc. (Progress Energy), a North Carolina corporation engaged in the regulated utility business of generation, transmission and distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. As a result of the merger, Merger Sub was merged into Progress Energy and Progress Energy became a wholly owned subsidiary of Duke Energy.

The merger between Duke Energy and Progress Energy provides increased scale and diversity with potentially enhanced access to capital over the long term and a greater ability to undertake the significant construction programs necessary to respond to increasing environmental regulation, plant retirements and customer demand growth. Duke Energy’s business risk profile is expected to improve over time due to the increased proportion of the business that is regulated. Additionally, cost savings, efficiencies and other benefits are expected from the combined operations.

Immediately preceding the merger, Duke Energy completed a one-for-three reverse stock split with respect to the issued and outstanding shares of Duke Energy common stock. The shareholders of Duke Energy approved the reverse stock split at Duke Energy’s special meeting of shareholders held on August 23, 2011. All share and per share amounts presented herein reflect the impact of the one-for-three reverse stock split.

Progress Energy’s shareholders received 0.87083 shares of Duke Energy common stock in exchange for each share of Progress Energy common stock outstanding as of July 2, 2012. Generally, all outstanding Progress Energy equity-based compensation awards were converted into Duke Energy equity-based compensation awards using the same ratio. The merger was structured as a tax-free exchange of shares.

For additional information on the details of this transaction including regulatory conditions and accounting implications, see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets.”

2012 Financial Results

The following table summarizes adjusted earnings and net income attributable to Duke Energy for the years ended December 31, 2012, 2011 and 2010.

		Years Ended December 31,
		2012				2011				2010
(in millions, except per share amounts)		Amount		Per diluted share		Amount		Per diluted share		Amount		Per diluted share
Adjusted earnings(a)		$	2,483	$	4.32	$	1,943	$	4.38	$	1,882	$	4.29
Net income attributable to Duke Energy		$	1,768	$	3.07	$	1,706	$	3.83	$	1,320	$	3.00
(a)	See Results of Operations below for Duke Energy’s definition of adjusted earnings as well as a reconciliation of this non-GAAP financial measure to net income attributable to Duke Energy.

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Adjusted earnings increased from 2011 to 2012 primarily due to the inclusion of Progress Energy results beginning in July 2012, and the impact of the 2011 Duke Energy Carolinas rate cases. Adjusted earnings increased from 2010 to 2011 primarily due to earnings attributable to Duke Energy’s ongoing modernization program and increased results at International Energy net of less favorable weather and higher operating expenses.

Net income for the year ended December 31, 2012 includes pretax impairment and other charges of $628 million related to the Edwardsport integrated gasification combined cycle (IGCC) project and costs to achieve the Progress Energy merger of $636 million. Net income for the year ended December 31, 2011 includes pretax impairment charges of $222 million related to the Edwardsport IGCC project and $79 million to write down the carrying value of excess emission allowances held by Commercial Power to fair value. Net income for the year ended December 31, 2010 was impacted by goodwill and other impairment charges of $660 million, primarily related to the nonregulated generation operations in the Midwest and gains on the sale of assets of $248M related to the sale of Q-Comm and the sale of a 50 percent interest in DukeNet.

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

2012 Areas of Focus and Accomplishments

In 2012, Duke Energy was focused on managing regulatory approvals related to the merger with Progress Energy, completing its remaining major capital projects and obtaining constructive regulatory outcomes.

Regulatory Approvals Related to the Merger with Progress Energy. In June 2012, the FERC and NCUC conditionally approved Duke Energy’s merger with Progress Energy. On July 2, 2012, Duke Energy successfully closed the merger with Progress Energy. See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets” for further discussion related to the merger with Progress Energy.

Completion and Placing in Service of Major Capital Projects. In 2012, U.S. Franchised Electric and Gas (USFE&G) made significant progress toward advancing its fleet modernization program. Duke Energy Carolinas has invested approximately $3.5 billion through 2012 in three key generation fleet modernization projects with approximately 2,065 megawatts (MW) of capacity. In 2012, Duke Energy Carolinas placed its 620 MW Dan River combined cycle natural gas-fired generation facility and its 825 MW coal-fired Cliffside Unit 6 in service, completing its portion of the fleet modernization program.

 Progress Energy Carolinas has invested approximately $1.7 billion through 2012 in three key generation fleet modernization projects with approximately 2,140 megawatts (MW) of capacity. In 2012, Progress Energy Carolinas placed in service the second of these projects, the 920 MW Lee combined cycle natural gas-fired generation facility, and continued to construct the 625 MW combined cycle natural gas-fired generation Sutton facility, which is 64% complete at December 31, 2012. The Sutton project is scheduled to be placed in service in 2013.

Duke Energy Indiana has invested approximately $3.4 billion through 2012 in its generation fleet modernization project, the 618 MW Edwardsport IGCC plant, which is 99% complete at December 31, 2012. In 2012, Duke Energy Indiana experienced cost pressures and regulatory scrutiny related to the Edwardsport IGCC project. As a result, Duke Energy Indiana recorded additional pre-tax impairment and other charges of approximately $628 million. This project is scheduled to be placed in service during 2013. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters” for further discussion of the Edwardsport IGCC project.

In 2012, Commercial Power completed five new wind farms and three solar farms, totaling approximately 800 MW, of which 150 MW were contributed to a joint venture with Sumitomo Corporation of America.

Obtaining Constructive Regulatory Outcomes. In 2012, Duke Energy successfully filed three rate cases in North Carolina and Ohio, including Progress Energy Carolinas’ first request for a base rate increase in 25 years.

In the fourth quarter of 2012, Duke Energy reached a settlement agreement with the NCUC, the North Carolina Public Staff and the North Carolina Department of Justice (NCDOJ) regarding the NCUC’s and NCDOJ’s investigations into the post-merger CEO change. The settlement agreements resolve all matters related to the NCUC and NCDOJ investigations.

On December 27, 2012, the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement finalized in April 2012, between Duke Energy Indiana, the OUCC, the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana, on the cost increase for the construction of the project. The settlement agreement, as approved, caps costs to be reflected in customer rates at $2.595 billion, including estimated financing costs through June 30, 2012.

2013 Objectives

Duke Energy will focus on obtaining constructive regulatory outcomes related to its pending and planned rate cases, achieving intended savings and efficiencies from its merger with Progress Energy, successfully managing the Crystal River Unit 3 retirement and related regulatory proceedings, completing the remaining major capital projects in its fleet modernization program and optimizing nuclear fleet performance.

Obtaining Constructive Regulatory Outcomes. The significant majority of Duke Energy’s future earnings are anticipated to be contributed from USFE&G, which consists of Duke Energy’s regulated businesses. Duke Energy has several ongoing rate cases and other regulatory proceedings in North Carolina, Ohio and Indiana. Later in 2013, Duke Energy Carolinas and Progress Energy Carolinas will file additional rate cases in South Carolina. Duke Energy expects resolution of these cases in 2013 or early 2014. These planned rates cases are needed to recover investments in Duke Energy’s ongoing infrastructure modernization projects and operating costs. Planning for and obtaining favorable outcomes from these regulatory proceedings are key factors in achieving Duke Energy’s long-term growth assumptions.

Achieving Intended Merger Cost Savings and Efficiencies. Duke Energy is taking a disciplined and systematic approach to merger integration work. Duke Energy is on track to achieve intended savings and efficiencies. In addition, through the efficient joint dispatch of the Duke Energy Carolinas and Progress Energy Carolinas generation fleets, Duke Energy is ahead of schedule in achieving fuels savings for customers in the Carolinas, achieving $52 million in fuel costs during the first six months following the merger. These savings are passed to customers.

Management of Crystal River Unit 3 Retirement. On February 5, 2013, following the completion of a comprehensive analysis, Duke Energy announced its intention to retire Crystal River Unit 3. Duke Energy concluded that it did not have a high degree of confidence that repair could be successfully completed and licensed within estimated costs and schedule, and that was in the best interests of Progress Energy Florida’s customers and joint owners and Duke Energy’s investors to retire the unit. Progress Energy Florida developed initial estimates of the cost to decommission the plant during its analysis of whether to repair or retire Crystal River Unit 3. With the final decision to retire, Progress Energy Florida is working to develop a comprehensive decommissioning plan, which will evaluate various decommissioning options and costs associated with each option. The plan will determine resource needs as well as the scope, schedule and other elements of decommissioning. Progress Energy Florida intends to use a safe

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storage (SAFSTOR) option for decommissioning. Generally, SAFSTOR involves placing the facility into a safe storage configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities occur, usually in 40 to 60 years. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning required by the NRC. Additional specifics about the decommissioning plan are being developed. Also on February 5, 2013, Progress Energy Florida announced it and NEIL had accepted the mediator’s proposal whereby NEIL will pay Progress Energy Florida an additional $530 million. Along with the $305 million which NEIL previously paid, Progress Energy Florida will receive a total of $835 million in insurance proceeds. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket. Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013.

Completing Remaining Major Capital Projects. Duke Energy anticipates total capital expenditures of $5.9 billion to $6.3 billion in 2013. Approximately $1.7 billion of these expenditures are related to expansion and growth projects, including but not limited to, the Edwardsport IGCC plant and the Sutton combined cycle facility. Following the completion of the Sutton and Edwardsport facilities in 2013, the major components of Duke Energy’s fleet modernization program will be complete. The fleet modernization program will permit Duke Energy to retire up to 6,800 MW of older, less-efficient coal-fired units by 2015, with approximately 3,800 MW retired by the end of 2013.

Optimizing Nuclear Fleet Performance. In 2012, Duke Energy’s nuclear fleet achieved a capacity factor over 90 percent, excluding Crystal River Unit 3. Duke Energy will continue to leverage best practices across the nuclear fleet to maintain and improve the performance of the fleet. To meet this goal, targeted investments to increase overall fleet performance and to meet the NRC’s Fukushima-related requirements totaling $825 million are planned over the next three years.

Economic Factors for Duke Energy’s Business

The historical and future trends of Duke Energy’s operating results have been and will be affected in varying degrees by a number of factors, including those discussed below. Duke Energy’s revenues depend on customer usage, which varies with weather conditions and behavior patterns, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric service within their respective jurisdictions and affect Duke Energy’s ability to recover its costs from customers.

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 if retail customers reduce consumption of electricity. A weakening economy could also impact Duke Energy’s customers’ ability to pay, causing increased delinquencies, slowing collections and leading to higher than normal levels of accounts receivables, bad debts and financing requirements. A portion of USFE&G’s business risk is mitigated by its regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses.

If negative market conditions should persist over time and estimated cash flows over the lives of Duke Energy’s individual assets, 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 evaluates the carrying amount of its recorded goodwill for impairment on an annual basis as of August 31 and performs interim impairment tests if a triggering event occurs that indicates it is not 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 Duke Energy’s goodwill impairment assessments, see “Critical Accounting Policy for Goodwill Impairment Assessments” and Note 12 to the Consolidated Financial Statements, “Goodwill, Intangible Assets and Impairments.”

Duke Energy’s goals for 2013 and beyond could also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in the 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. USFE&G has four outstanding rate cases and plans to initiate two additional rate cases in 2013. 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. 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 U.S. 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. For further information related to management’s assessment of Duke Energy’s risk factors, see Item 1A, “Risk Factors.”

RESULTS OF OPERATIONS

In this section, Duke Energy provides analysis and discussion of earnings and factors affecting earnings on both a GAAP and non-GAAP basis.

Management evaluates financial performance in part based on the non-GAAP financial measure, Adjusted earnings and Adjusted diluted earnings per share (EPS), which is measured as income from continuing operations after deducting income attributable to noncontrolling interests, adjusted for the dollar and per share impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Special items represent certain charges and credits, which management believes will not be recurring on a regular basis, although it is reasonably possible such charges and credits could recur. Mark-to-market adjustments reflect the mark-to-market impact of derivative contracts, which is recognized in GAAP earnings immediately as such derivative contracts do not qualify for hedge accounting or regulatory accounting treatment, used in Duke Energy’s hedging of a portion of economic value of its generation assets in the Commercial Power segment. The economic value of the generation assets is subject to fluctuations in fair value due to market price volatility of the input and output commodities (e.g., coal, power) and, as such, the economic hedging involves both purchases and sales of those input and output commodities related to the generation assets. Because the operations of the generation assets are accounted for under the accrual method, management believes that excluding the impact of mark-to-market changes of the economic hedge contracts from operating earnings until settlement better matches the financial impacts of the hedge contract with the portion of economic value of the underlying hedged asset. Management believes that the presentation of adjusted earnings and adjusted diluted EPS provides useful information to investors, as it provides them an additional relevant comparison of Duke Energy’s performance across periods. Management uses this non-GAAP financial measure for planning and forecasting and for reporting results to the Board of Directors, employees, shareholders, analysts and

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investors concerning Duke Energy’s financial performance. The most directly comparable GAAP measure for Adjusted earnings and Adjusted diluted EPS is Net Income and Diluted EPS attributable to Duke Energy common shareholders, which includes the dollar and per share impact of special items, the mark-to-market impacts of economic hedges in the Commercial Power segment and discontinued operations.

Overview

The following table reconciles Adjusted earnings to Net income attributable to Duke Energy and Adjusted diluted EPS to Diluted EPS attributable to Duke Energy (amounts are net of tax):

	Years Ended December 31,
	2012				2011				2010
(in millions, except per share amounts)	Amount		Per diluted share		Amount		Per diluted share		Amount		Per diluted share
Adjusted earnings	$	2,483	$	4.32	$	1,943	$	4.38	$	1,882	$	4.29
Edwardsport charges		(402)		(0.70)		(135)		(0.30)		-		-
Costs to achieve mergers and acquisitions		(397)		(0.70)		(51)		(0.12)		(17)		(0.04)
Economic hedges (mark-to-market)		(6)		(0.01)		(1)		(0.01)		21		0.04
Democratic National Convention host committee support		(6)		(0.01)		-		-		-		-
Employee severance and office consolidation		60		0.11		-		-		(105)		(0.24)
Emission allowance impairment		-		-		(51)		(0.12)		-		-
Goodwill and other asset impairments		-		-		-		-		(602)		(1.37)
Litigation reserves		-		-		-		-		(16)		(0.04)
Asset sales		-		-		-		-		154		0.35
Income from discontinued operations		36		0.06		1		-		3		0.01
Net income attributable to Duke Energy	$	1,768	$	3.07	$	1,706	$	3.83	$	1,320	$	3.00

The variance in adjusted earnings for the year ended December 31, 2012, compared to the year ended December 31, 2011, was primarily due to:

·The inclusion of Progress Energy results beginning in July 2012; and

·Increased retail pricing and riders primarily resulting from the implementation of revised rates in North Carolina and South Carolina.

Partially offset by

·Unfavorable weather in 2012 compared to 2011;

·Higher depreciation and amortization expense;

·Lower nonregulated Midwest coal generation results; and 

·Incremental shares issued to complete the Progress Energy merger (impacts per share diluted amounts only).

The variance in adjusted earnings for the year ended December 31, 2011, compared to the year ended December 31, 2010, was primarily due to:

·Increased earnings associated with major construction projects at USFE&G;

·Effect of 2010 Duke Energy Foundation funding;

·Increased results in Brazil due to higher average contract prices;

·Increased earnings from National Methanol Company (NMC);

·Lower corporate governance costs;

·Increased results in Peru due to additional capacity revenues and an arbitration award; and

·Increased results in Central America due to higher average prices and volumes.

Partially offset by

·Less favorable weather in 2011 compared to 2010 at USFE&G;

·Increased operation and maintenance costs at USFE&G; and

·Lower volumes as a result of customer switching in Ohio, net of retention by Duke Energy Retail Sales, LLC (Duke Energy Retail) at Commercial Power.

Segment Results

In 2012, management began evaluating segment performance based on segment income. Segment income is defined as income from continuing operations net of income attributable to noncontrolling interests. Segment income, as discussed below, includes intercompany revenues and expenses that are eliminated in the Consolidated Financial Statements. In conjunction with management’s use of the new reporting measure, certain governance costs that were previously unallocated have now been allocated to each of the segments. In addition, direct interest expense and income taxes are included in segment income. Prior year financial information has been recast to conform to the current year presentation. None of these changes impacts the reportable operating segments or the Duke Energy Registrants’ previously reported consolidated revenues, net income or EPS.

Management also uses adjusted segment income as a measure of historical and anticipated future segment and Other performance. Adjusted segment income is a Non-GAAP financial measure, as it is based upon segment income adjusted for special items and the mark-to-market impact of economic hedges in the Commercial Power segment. Management believes that the presentation of adjusted segment income provides useful information to investors, as it provides them with an additional relevant comparison of a segment’s performance across periods.

The most directly comparable GAAP measure for adjusted segment income is reported segment income, which represents segment income from continuing operations, including any special items and the mark-to-market impact of economic hedges in the Commercial Power segment.

See Note 3 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s segment structure.

Duke Energy’s segment income and adjusted segment income may not be comparable to similarly titled measures of another company because other entities may not calculate segment income or adjusted segment income in the same manner. The following tables reconcile adjusted segment income to segment income, and detailed discussions follow.

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		Year Ended December 31, 2012
(in millions, except per share amounts)	USFE&G		Commercial Power		International Energy		Total Reportable Segments		Other		Duke Energy
Adjusted segment income	$	2,086	$	93	$	439	$	2,618	$	(135)	$	2,483
Edwardsport impairment and other charges		(402)		-		-		(402)		-		(402)
Costs to achieve mergers and acquisitions		-		-		-		-		(397)		(397)
Mark-to-market impact of economic hedges		-		(6)		-		(6)		-		(6)
Democratic National Convention Host Committee support		-		-		-		-		(6)		(6)
Employee severance and office consolidation		60		-		-		60		-		60
Segment income	$	1,744	$	87	$	439	$	2,270	$	(538)	$	1,732
Income from discontinued operations											$	36
Net income attributable to Duke Energy											$	1,768
		Year Ended December 31, 2011
(in millions, except per share amounts)	USFE&G		Commercial Power		International Energy		Total Reportable Segments		Other		Duke Energy
Adjusted segment income	$	1,316	$	186	$	466	$	1,968	$	(25)	$	1,943
Edwardsport impairment and other charges		(135)		-		-		(135)		-		(135)
Emission allowance impairment		-		(51)		-		(51)		-		(51)
Costs to achieve mergers and acquisitions		-		-		-		-		(51)		(51)
Mark-to-market impact of economic hedges		-		(1)		-		(1)		-		(1)
Segment income	$	1,181	$	134	$	466	$	1,781	$	(76)	$	1,705
Income from discontinued operations											$	1
Net income attributable to Duke Energy											$	1,706
		Year Ended December 31, 2010
(in millions, except per share amounts)	USFE&G		Commercial Power		International Energy		Total Reportable Segments		Other		Duke Energy
Adjusted segment income	$	1,380	$	254	$	305	$	1,939	$	(57)	$	1,882
Goodwill and other asset impairments		-		(602)		-		(602)		-		(602)
Employee severance and office consolidation		-		-		-		-		(105)		(105)
Costs to achieve mergers and acquisitions		-		-		-		-		(17)		(17)
Litigation reserves		-		-		-		-		(16)		(16)
Mark-to-market impact of economic hedges		-		21		-		21		-		21
Assets sales		-		-		-		-		154		154
Segment income	$	1,380	$	(327)	$	305	$	1,358	$	(41)	$	1,317
Income from discontinued operations											$	3
Net income attributable to Duke Energy											$	1,320

The remaining information presented through this discussion of results of operations is presented on a GAAP basis.

U.S. Franchised Electric and Gas

U.S. Franchised Electric and Gas includes the regulated operations of Duke Energy Carolinas, Progress Energy Carolinas, Progress Energy Florida, Duke Energy Ohio and Duke Energy Indiana.

		Years Ended December 31,
(in millions)		2012		2011		Variance 2012 vs. 2011		2010		Variance 2011 vs. 2010
Operating revenues		$	16,080	$	10,619	$	5,461	$	10,597	$	22
Operating expenses			12,943		8,473		4,470		8,144		329
Gains on sales of other assets and other, net			15		2		13		5		(3)
Operating income			3,152		2,148		1,004		2,458		(310)
Other income and expense, net			341		274		67		278		(4)
Interest expense			806		568		238		569		(1)
Income before income taxes			2,687		1,854		833		2,167		(313)
Income tax expense			941		673		268		787		(114)
Less: Income attributable to noncontrolling interest			2		-		2		-		-
Segment income		$	1,744	$	1,181	$	563	$	1,380	$	(199)
Duke Energy Carolinas' GWh sales(a)(b)			81,362		82,127		(765)		85,441		(3,314)
Progress Energy Carolinas' GWh sales(a)(c)(d)			58,390		56,223		2,167		59,702		(3,479)
Progress Energy Florida GWh sales(a)(e)			38,443		39,578		(1,135)		43,240		(3,662)
Duke Energy Ohio GWh sales(a)			24,344		24,923		(579)		25,519		(596)
Duke Energy Indiana GWh sales(a)			33,577		33,181		396		34,899		(1,718)
Total USFE&G GWh sales			236,116		236,032		84		248,801		(12,769)
Net proportional MW capacity in operation(f)			49,654		27,397				26,869
(a)	Gigawatt-hours (GWh).
(b)	Includes 421 GWh sales associated with interim firm power sale agreements (Interim FERC Mitigation) entered into as part of FERC's approval of the merger with Progress Energy, which are not included in the operating results in the table above, for the year ended December 31, 2012. See Note 2 to the Consolidated Financial Statements, "Acquisitions, Dispositions and Sales of Other Assets," for a discussion of the Interim FERC Mitigation.
(c)	Includes 577 GWh sales associated with the Interim FERC Mitigation, which are not included in the operating results in the table above, for year ended December 31, 2012. See Note 2 to the Consolidated Financial Statements, "Acquisitions, Dispositions and Sales of Other Assets," for a discussion of the Interim FERC Mitigation.
(d)	All of Progress Energy Carolinas' GWh sales for the years ended December 31, 2011 and December 31, 2010, and 26,634 GWh sales for the year ended December 31, 2012, occurred prior to the merger between Duke Energy and Progress Energy.
(e)	All of Progress Energy Florida's GWh sales for the years ended December 31, 2011 and December 31, 2010, and 18,348 GWh sales for the year ended December 31, 2012, occurred prior to the merger between Duke Energy and Progress Energy.
(f)	Megawatt (MW).

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Year  Ended December 31, 2012 as Compared to December 31, 2011

Operating revenues.The variance was driven primarily by:

·A $4,918 million increase in operating revenues due to the inclusion of Progress Energy operating revenues beginning in July 2012,

·A $352 million net increase in retail pricing and rate riders primarily due to revised retail rates resulting from the 2011 North Carolina and South Carolina rate cases implemented in the first quarter of 2012, and revenues recognized for energy efficiency programs, and

·A $293 million increase in fuel revenues (including emission allowances) driven primarily by higher revenues in Ohio for purchases of power as a result of the new Ohio ESP, higher fuel rates for electric retail customers in all jurisdictions, and higher revenues for purchases of power in Indiana and the Carolinas, partially offset by decreased demand from electric retail customers in 2012 mainly due to unfavorable weather conditions, and lower demand and fuel rates in Ohio and Kentucky from natural gas retail customers . Fuel revenues represent sales to retail and wholesale customers.

Partially offsetting these increases was:

·A $155 million decrease in electric and gas sales (net of fuel) to retail customers due to unfavorable weather conditions in 2012 compared to 2011. For the Carolinas, weather statistics for cooling degree days in 2012 were less favorable compared to 2011, while cooling degree days in the Ohio and Indiana were favorable in 2012 compared to the same period in 2011. For the Carolinas, Ohio and Indiana, weather statistics for heating degree days in 2012 were unfavorable compared to 2011.

Operating expenses.The increase was driven primarily by:

·A $3,845 million increase in operating expenses due to the inclusion of Progress Energy operating expenses beginning in July 2012,

·A $378 million increase due to an additional impairment and other charges related to the Edwardsport IGCC plant that is currently under construction. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for additional information,

·A $277 million increase in fuel expense (including purchased power and natural gas purchases for resale) primarily related to higher purchases of power in Ohio as a result of the new Ohio ESP, higher volumes of natural gas used in electric generation, higher coal prices, higher purchased power costs in Indiana and the Carolinas, partially offset by lower volume of coal used in electric generation resulting from unfavorable weather conditions and lower coal-fired generation due to low natural gas prices, lower prices for natural gas used in electric generation, and lower gas volumes and prices to full-service retail gas customers, and

·A $105 million increase in depreciation and amortization primarily due to increases in depreciation as a result of additional plant in service and amortization of regulatory assets.

Partially offsetting these increases was:

·A $99 million decrease in operating and maintenance expense primarily due to the establishment of regulatory assets in the first quarter of 2012, pursuant to regulatory orders, for future recovery of certain employee severance costs related to the 2010 voluntary severance plan and other costs, and lower storm costs, partially offset by increased costs associated with the energy efficiency programs. 

Other income and expense, net. The variance was driven primarily by the inclusion of Progress Energy other income and expenses beginning in July 2012.

Interest expense. The variance was primarily driven bythe inclusion of Progress Energy interest expense beginning in July 2012.

Income tax expense. The variance is primarily due to an increase in pretax income. The effective tax rate for the years ended December 31, 2012 and 2011 was 35.0% and 36.3%, respectively.

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Segment income.  The variance resulted primarily from the inclusion of Progress Energy results beginning in July 2012, higher net retail pricing and rate riders and decreased operating and maintenance expenses. These positive impacts were partially offset by the additional impairment and other charges related to the Edwardsport IGCC plant, unfavorable weather, and increased depreciation and amortization.

Year Ended December 31, 2011 as Compared to December 31, 2010

Operating revenues.The variance was driven primarily by:

·A $230 million increase in rate riders and retail rates primarily due to the 2011 implementation of the North Carolina construction work in progress (CWIP) rider, the save-a-watt (SAW) and demand side management programs, and the rider for the Edwardsport IGCC plant,

·A $22 million increase in fuel revenues (including emission allowances) driven primarily by higher fuel rates for electric retail customers in all jurisdictions, and higher purchased power costs in Indiana, partially offset by decreased demand from electric retail customers in 2011 compared to the same period in 2010 mainly due to less favorable weather conditions, lower demand and fuel rates in Ohio and Kentucky from natural gas retail customers. Fuel revenues represent sales to retail and wholesale customers, and

·An $18 million net increase in wholesale power revenues, net of sharing, primarily due to additional volumes and charges for capacity for customers served under long-term contracts.

Partially offsetting these increases was:

·A $244 million decrease in GWh and thousand cubic feet (Mcf) sales to retail customers due to less favorable weather conditions in 2011 compared to the same period in 2010. For the Carolinas, Ohio and Indiana, weather statistics for both heating degree days and cooling degree days in 2011 were unfavorable compared to 2010. The year 2010 had the most cooling degree days on record and December 2010 tied with December 1963 for the coldest December on record in the Duke Energy Carolinas’ service area (dating back to 1961).

Operating expenses. The variance was driven primarily by:

·A $204 million increase due to impairment charges, which primarily relate to an additional impairment charge related to the Edwardsport IGCC plant that is currently under construction. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information, and

·A $110 million increase in operating and maintenance expenses primarily due to higher non-outage costs at nuclear and fossil generation stations, higher storm costs, increased scheduled outage costs at nuclear generation stations, and increased costs related to the implementation of the SAW program, partially offset by a 2010 litigation settlement.

Income tax expense.  The income tax variance increase is primarily due to an increase in pretax income. The effective tax rate for each of the years ended December 31, 2011 and 2010 was 36.3%.

Segment income. As discussed above, the variance resulted primarily from less favorable weather, impairment charges, higher operating and maintenance expenses, and higher income tax expense. These negative impacts were partially offset by overall net higher retail rates and rate riders and higher wholesale power revenues.

Matters Impacting Future USFE&G Results

On December 27, 2012, the IURC approved a settlement agreement between Duke Energy Indiana and certain intervenors to cap the construction costs recoverable in retail rates. The Edwardsport Generating Station (Edwardsport IGCC) plant is scheduled to begin commercial operation in mid-2013. USFE&G’s earnings could be adversely impacted by additional delays in the commencement of operations which may result in increased costs.

USFE&G currently has pending rate cases in North Carolina and Ohio. USFE&G also plans to file rate cases in South Carolina before the end of 2013. These rate cases are needed to recover the costs of plant modernization and other capital investments in generation, transmission, and distribution systems, as well as increased expenditures for nuclear plants and personnel, recovery of costs associated with MGP sites, vegetation management and other operating costs. USFE&G’s earnings could be adversely impacted if these rate cases are denied or delayed by the NCUC, PSCSC or PUCO.

In accordance with the terms of the 2012 FPSC Settlement Agreement, with consumer representatives and approved by the FPSC, Progress Energy Florida retains the sole discretion and flexibility to retire Crystal River Unit 3. As a result of the decision to retire Crystal River Unit 3, under the terms of the 2012 FPSC Settlement Agreement, Progress Energy Florida is allowed to recover all remaining Crystal River Unit 3 investments and to earn a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket. Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013. USFE&G’s financial condition and results of operations could be adversely impacted if the FPSC issues an unfavorable ruling.

The ability to integrate Progress Energy businesses and realize cost savings and any other synergies expected from the merger with Progress Energy could be different from what USFE&G expects and may have a significant impact on USFE&G’s results of operations.

Commercial Power

	Years Ended December 31,
(in millions)	2012		2011		Variance 2012 vs. 2011		2010		Variance 2011 vs. 2010
Operating revenues	$	2,078	$	2,491	$	(413)	$	2,448	$	43
Operating expenses		1,981		2,300		(319)		2,734		(434)
Gains on sales of other assets and other, net		8		15		(7)		6		9
Operating income		105		206		(101)		(280)		486
Other income and expense, net		39		21		18		44		(23)
Interest expense		63		87		(24)		68		19
Income before income taxes		81		140		(59)		(304)		444
Income tax expense		(7)		(2)		(5)		22		(24)
Less: Income attributable to noncontrolling interests		1		8		(7)		1		7
Segment income	$	87	$	134	$	(47)	$	(327)	$	461
Coal-fired plant production, GWh		16,164		17,378		(1,214)		19,442		(2,064)
Gas-fired plant production, GWh		17,122		12,021		5,101		7,026		4,995
Renewable plant production, GWh		3,452		3,132		320		2,286		846
Total Commercial Power production, GWh		36,738		32,531		4,207		28,754		3,777
Net proportional MW capacity in operation		8,094		8,325		(231)		8,272		53

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Year Ended December 31, 2012 as Compared to December 31, 2011

Operating revenues.The variance was driven primarily by:

·A $285 million decrease in electric revenues from the coal-fired generation assets driven primarily by the expiration of the 2009-2011 ESP which dedicated Commercial Power’s coal-fired generation to Duke Energy Ohio’s retail customers, net of stability charge revenues, partially offset by the coal-fired generation assets participating in the PJM Interconnection, LLC (PJM) wholesale energy market in 2012,

·A $116 million decrease in electric revenues from Duke Energy Retail Sales, LLC (Duke Energy Retail) resulting from lower volumes and unfavorable pricing,

·A $39 million decrease in electric revenues from the gas-fired generation assets driven primarily by lower power prices, partially offset by increased volumes,

·A $27 million decrease in electric revenues from Duke Energy Generation Services, Inc. (DEGS), excluding renewables, due primarily to the termination of certain operations at the end of the first quarter of 2011 and a reduction of coal sales volumes as a result of lower natural gas prices,

·An $18 million decrease in PJM capacity revenues related to lower average cleared capacity auction pricing in 2012 compared to 2011 for the gas-fired generation assets, net of an increase associated with the move of the coal-fired generation assets from Midwest Independent Transmission System Operator, Inc. (MISO) to PJM in 2012, and

·An $8 million decrease in net mark-to-market revenues on non-qualifying power and capacity hedge contracts, consisting of mark-to-market losses of $6 million in 2012 compared to gains of $2 million in 2011.

Partially offsetting these decreases were:

·A $64 million increase from participation in competitive retail load auctions, and

·A $17 million increase in electric revenues from higher production in the renewables portfolio.

Operating expenses.The variance was driven primarily by:

·A $140 million decrease in operating and maintenance expenses resulting primarily from the prior year recognition of MISO exit fees; lower transmission costs, prior year station outages, and 2011 regulatory asset amortization expenses,

·An $88 million decrease primarily from the 2011 impairment of excess emission allowances as a result of the EPA’s issuance of the CSAPR,

·An $85 million decrease in fuel expenses from the gas-fired generation assets driven by lower natural gas costs, partially offset by higher volumes,

·A $19 million decrease in DEGS, excluding renewables, fuel used due primarily to the termination of certain operations at the end of the first quarter of 2011 and from lower natural gas prices,

·A $15 million decrease due to the receipt of funds in 2012 related to a previously written off receivable associated with the Lehman Brothers bankruptcy,

·A $15 million decrease in purchased power to serve Duke Energy Retail customers, and

·A $13 million decrease in fuel used for the coal-fired generation assets driven primarily by lower generation volumes.

Partially offsetting these decreases was:

·A $54 million increase in purchase power to serve competitive retail load auctions.

Other income and expense, net.The variance is primarily due to the sale of certain DEGS operations and higher equity earnings from the renewables portfolio.

Interest expense.The variance is primarily due to higher capitalized interest on wind construction projects.

Income tax (benefit) expense. The variance in tax benefit is primarily due to a decrease in pretax income. The effective tax rate for the years ended December 31, 2012 and 2011 was (9.5) % and (1.4) %, respectively. 

Segment income.  The variance is primarily attributable to lower revenues driven by the net impact of the expiration of the 2009-2011 ESP and the impact of competitive market dispatch for the Duke Energy Ohio coal-fired assets, lower Duke Energy Retail earnings, and lower PJM capacity

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revenues. These negative impacts were partially offset by lower operating expenses, lower impairment charges, and increased margins from the gas-fired generation assets.

Year Ended December 31, 2011 as Compared to December 31, 2010

Operating revenues.The variance was driven primarily by:

·A $240 million increase in wholesale electric revenues due to higher generation volumes, net of lower pricing and lower margin earned from participation in wholesale auctions in 2011, and

·A $53 million increase in renewable generation revenues due to additional renewable generation facilities placed in service after 2010 and a full year of operations for renewable generation facilities placed in service throughout 2010.

·Partially offsetting these increases were:

·A $178 million decrease in retail electric revenues resulting from lower sales volumes driven by increased customer switching levels and unfavorable weather net of higher retail pricing under the ESP in 2011, and

·A $66 million decrease in DEGS revenues, excluding renewables, due primarily to a contract termination and plant maintenance.

Operating expenses. The variance was primarily driven by:

·A $584 million decrease in impairment charges primarily related to a $660 million charge related to goodwill and nonregulated coal-fired generation asset impairments in the Midwest in 2010, as compared to a $79 million impairment in 2011 to write down the carrying value of excess emission allowances held to fair value as a result of the EPA’s issuance of the Cross-State Air Pollution Rule (CSAPR) and a $9 million impairment of the Vermillion generation station in 2011. See Note 12 to the Consolidated Financial Statements, “Goodwill, Intangible Assets and Impairments,” for additional information, and

·A $65 million decrease in retail fuel and purchased power expenses due to lower generation volumes net of higher purchased power volumes in 2011 as compared to 2010.

Partially offsetting these decreases were:

·A $156 million increase in wholesale fuel expenses due to higher generation volumes, partially offset by favorable hedge realizations in 2011 as compared to 2010,

·A $46 million increase in operating expenses resulting primarily from the recognition of MISO exit fees, higher maintenance expenses and higher transmission costs, partially offset by lower governance costs in 2011 compared to 2010, and

·A $30 million increase in mark-to-market fuel expense on non-qualifying fuel hedge contracts, consisting of mark-to-market losses of $3 million in 2011 compared to gains of $27 million in 2010.

Other income and expense, net. The variance is primarily due to distributions from South Houston Green Power received in 2010 which did not recur in 2011.

Interest expense. The variance is primarily due to lower capitalized interest on wind construction projects.

Income tax (benefit) expense. The variance in pretax income was primarily due to a non-deductible goodwill impairment in 2010. The effective tax rates for the year ended December 31, 2011 and 2010, were (1.4%) and (7.2%), respectively.

Segment income. The variance is primarily attributable to lower goodwill, generation and other asset impairment charges, higher wholesale margins due to increased generation volumes, and an increase in renewables generation revenues. These factors were partially offset by lower retail margins driven by customer switching and unfavorable weather, higher operating expenses resulting from the recognition of MISO exit fees and increased maintenance expenses, and net mark-to-market losses on non-qualifying commodity hedge contracts in 2011 compared to gains in 2010.

Matters Impacting Future Commercial Power Results

Changes or variability in assumptions used in calculating the fair value of the renewables reporting unit for goodwill testing purposes including but not limited to, legislative actions related to tax credit extensions, long-term growth rates and discount rates, could significantly impact the estimated fair value of the renewables reporting unit. In the event of a significant decline in the estimated fair value of the renewables reporting unit, goodwill and other asset impairment charges could be recorded. The carrying value of goodwill, and intangible assets associated with proposed renewable projects within Commercial Power’s renewables reporting unit was approximately $108 million at December 31, 2012.

The current low energy price projections, as well as recently issued and proposed environmental regulations pertaining to coal and coal-fired generating  facilities, could impact future cash flows and market valuations of Commercial Power’s coal-fired generation assets which could lead to impairment charges.

International Energy

	Years Ended December 31,
(in millions)	2012		2011		Variance 2012 vs. 2011		2010		Variance 2011 vs. 2010
Operating revenues	$	1,549	$	1,467	$	82	$	1,204	$	263
Operating expenses		1,043		946		97		816		130
Losses on sales of other assets and other, net		-		(1)		1		(3)		2
Operating income		506		520		(14)		385		135
Other income and expense, net		171		203		(32)		146		57
Interest expense		76		47		29		71		(24)
Income before income taxes		601		676		(75)		460		216
Income tax expense		149		195		(46)		143		52
Less: Income attributable to noncontrolling interests		13		15		(2)		12		3
Segment income	$	439	$	466	$	(27)	$	305	$	161
Sales, GWh		20,132		18,889		1,243		19,504		(615)
Net proportional MW capacity in operation		4,584		4,277		307		4,203		74

45

PART II

Year Ended December 31, 2012 as Compared to December 31, 2011

Operating revenues.The variance was driven primarily by:

•     A $53 million increase in Central America as a result of higher volumes due to a full year of commercial operations of the Las Palmas II plant and favorable hydrology,

•     A $24 million increase in Peru due to higher average prices, and

•     A $10 million increase in Argentina due to higher volumes as a result of favorable hydrology, partially offset by unfavorable exchange rates.

Partially offsetting this increase was:

·A $7 million decrease in Brazil as a result of unfavorable exchange rates partially offset by higher average prices and volumes.

Operating expenses.The variance was driven primarily by:

•     A $76 million increase in Central America due to higher fuel costs and consumption as a result of increased dispatch,

•     An $8 million increase in general and administrative due to higher development costs, labor, and executive benefits, and

•     A $7 million increase in Argentina as a result of higher transmission, water royalty and purchased power costs.

Other income and expense, net. The variance was primarily driven by the absence of a $20 million arbitration award in Peru.

Interest expense.The variance was primarily due to lower capitalized interest in Central America and Brazil, as well as higher inflation partially offset by favorable exchange rates in Brazil.

Income tax expense. The variance in tax expense is primarily due to a decrease in pretax income.  The effective tax rate for the year ended December 31, 2012 and 2011 was 24.8% and 28.9%, respectively. 

Segment income. The variance was primarily due to unfavorable exchange rates in Brazil, the prior year Peru arbitration award, and lower margins in Central America, partially offset by higher average prices and volumes in Brazil and higher average prices in Peru.

Year Ended December 31, 2011 as Compared to December 31, 2010

Operating revenues.The variance was driven primarily by:

•     A $111 million increase in Central America as a result of higher average prices and favorable hydrology,

•     A $95 million increase in Brazil due to favorable exchange rates, and higher average contract prices and volumes, and

•     An $80 million increase in Peru due to higher average prices and volumes, and hydrocarbon prices.

Partially offsetting this increase was:

•     A $25 million decrease in Ecuador as a result of lower dispatch due to new hydro competitor commencing operations and energy imports from Colombia.

Operating expenses.The variance was driven primarily by:

•     A $77 million increase in Central America due to higher fuel costs and consumption as a result of increased dispatch,

•     A $56 million increase in Peru as a result of higher fuel costs and consumption as a result of increased dispatch, and higher purchased power and hydrocarbon royalty costs, and

•     A $25 million increase in Brazil as a result of unfavorable exchange rates, higher purchased power and a provision for a revenue tax audit.

Partially offsetting these increases was:

•     A $27 million decrease in Ecuador due to lower fuel consumption as a result of lower dispatch, and lower maintenance costs.

Other income and expense, net. The variance was primarily driven by a $44 million increase in equity earnings from NMC due to higher average prices partially offset by higher butane costs, and a $20 million arbitration award in Peru.

Interest expense.The variance was primarily a result of inflation impact in Brazil and lower interest expense in Central America due to prepayment of debt.

Income tax expense. The variance is primarily due to an increase in pretax income. The effective tax rate for the year ended December 31, 2011 and 2010 was 28.9% and 31.1%, respectively. 

Segment income.As discussed above, the variance was primarily due to favorable contract prices and exchange rates in Brazil, arbitration award and higher margins in Peru, favorable hydrology in Central America, and higher equity earnings at NMC.

Other

	Years Ended December 31,
(in millions)	2012		2011		Variance 2012 vs. 2011		2010		Variance 2011 vs. 2010
Operating revenues	$	74	$	44	$	30	$	142	$	(98)
Operating expenses		704		133		571		389		(256)
(Losses) gains on sales of other assets and other, net		(7)		(8)		1		145		(153)
Operating loss		(637)		(97)		(540)		(102)		5
Other income and expense, net		16		49		(33)		126		(77)
Interest expense		297		157		140		136		21
Loss before income taxes		(918)		(205)		(713)		(112)		(93)
Income tax benefit		(378)		(114)		(264)		(62)		(52)
Less: Loss attributable to noncontrolling interests		(2)		(15)		13		(9)		(6)
Net expense	$	(538)	$	(76)	$	(462)	$	(41)	$	(35)

46

PART II

Year Ended December 31, 2012 as Compared to December 31, 2011

Operating revenues.The variance was driven primarily by higher premiums earned at Bison Insurance Company Limited (Bison) as a result of the addition of Progress Energy and mark-to-market activity at Duke Energy Trading and Marketing, LLC (DETM).

Operating expenses.The variance was driven primarily by charges related to the Progress Energy merger, increased severance costs and higher current year donations. These negative impacts were partially offset by higher JV costs related to DETM in the prior year.

Other income and expense, net. The variance was driven primarily by current year impairments and prior year gains on sales of investments, higher interest income recorded in 2011 following the resolution of certain income tax matters related to prior years and reversal of reserves related to certain guarantees Duke Energy had issued on behalf of Crescent in 2011. These negative impacts were partially offset by higher returns on investments that support benefit obligations in 2012 compared to 2011.

Interest expense. The variance was due primarily to higher debt balances as a result of debt issuances and the inclusion of Progress Energy interest expense beginning in July 2012.

Income tax benefit. The variance is primarily due to an increase in pretax loss. The effective tax rate for the years ended December 31, 2012 and 2011 was 41.1% and 56.0%, respectively.

Net expense. The variance was due primarily to charges related to the Progress Energy merger, increased severance costs, and higher interest expense. These negative impacts were partially offset by higher income tax benefit due to increased net expense and higher returns on investments that support benefit obligations in 2012 compared to 2011.

Year Ended December 31, 2011 as Compared to December 31, 2010

Operating revenues. The variance was driven primarily by the deconsolidation of DukeNet in December 2010 and the subsequent accounting for Duke Energy’s investment in DukeNet as an equity method investment.

Operating expenses. The variance was driven primarily by $172 million of 2010 employee severance costs related to the voluntary severance plan and the consolidation of certain corporate office functions from the Midwest to Charlotte, North Carolina, prior year donations of $56 million to the Duke Energy Foundation, which is a nonprofit organization funded by Duke Energy shareholders that makes charitable contributions to selected nonprofits and government subdivisions, a decrease as a result of the DukeNet deconsolidation in December 2010 and the subsequent accounting for Duke Energy’s investment in DukeNet as an equity method investment; partially offset by higher costs related to the proposed merger with Progress Energy.

 (Losses) gains on sales of other assets and other, net. The variance was primarily due to the $139 million gain from the sale of a 50% ownership interest in DukeNet in the prior year.

Other income and expense, net. The variance was due primarily to the sale of Duke Energy’s ownership interest in Q-Comm in the prior year of $109 million; partially offset by prior year impairments and 2011 gains on sales of investments.

Interest expense. The variance was due primarily to higher debt balances as a result of debt issuances.

Income tax benefit. The variance is primarily due to a decrease in pre-tax income. The effective tax rate for the year ended December 31, 2011 and 2010 was 56.0% and 55.4%, respectively.

Net expense. The variance was driven primarily by $172 million of 2010 employee severance costs related to the voluntary severance plan and the consolidation of certain corporate office functions from the Midwest to Charlotte, North Carolina, prior year donations of $56 million to the Duke Energy Foundation, a decrease as a result of the DukeNet deconsolidation in December 2010 and the subsequent accounting for Duke Energy’s investment in DukeNet as an equity method investment, and higher interest expense due to increased debt issuances in the current year. These negative impacts were partially offset by prior year impairments and 2011 gains on sales of investments and higher income tax benefit due to increased net expense.

Matters Impacting Future Other Results

Duke Energy previously held an effective 50% interest in Crescent, which was a real estate joint venture formed by Duke Energy in 2006 that filed for Chapter 11 bankruptcy protection in June 2009. On June 9, 2010, Crescent restructured and emerged from bankruptcy and Duke Energy forfeited its entire 50% ownership interest to Crescent debt holders. This forfeiture caused Duke Energy to recognize a loss, for tax purposes, on its interest in the second quarter of 2010. Although Crescent has reorganized and emerged from bankruptcy with creditors owning all Crescent interest, there remains uncertainty as to the tax treatment associated with the restructuring. Based on this uncertainty, it is possible that Duke Energy could incur a future tax liability related to the tax losses associated with its partnership interest in Crescent and the resolution of issues associated with Crescent’s emergence from bankruptcy.

47

PART II

DUKE ENERGY CAROLINAS

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

BASIS OF PRESENTATION

The results of operations and variance discussion for Duke Energy Carolinas is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

RESULTS OF OPERATIONS

	Years Ended December 31,
(in millions)	2012		2011		Variance
Operating revenues	$	6,665	$	6,493	$	172
Operating expenses		5,160		5,014		146
Gains on sales of other assets and other, net		12		1		11
Operating income		1,517		1,480		37
Other income and expense, net		185		186		(1)
Interest expense		384		360		24
Income before income taxes		1,318		1,306		12
Income tax expense		453		472		(19)
Net income	$	865	$	834	$	31

	The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Carolinas. Except
as otherwise noted, the below percentages represent billed sales only for the periods presented and are not weather normalized.
Increase (decrease) over prior year		2012		2011
Residential sales(a)		(7.2)	%	(5.7)	%
General service sales(a)		(0.4)	%	(1.3)	%
Industrial sales(a)		0.9	%	0.8	%
Wholesale power sales		4.0	%	1.2	%
Total sales(b)		(0.9)	%	(3.9)	%
Average number of customers		0.6	%	0.3	%
(a)	Major components of retail sales.
(b)	Consists of all components of sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

The increase in Duke Energy Carolinas’ net income for the year ended December 31, 2012, compared to December 31, 2011, was primarily due to the following factors:

Operating revenues. The variance was primarily due to:

·A $323 million increase in net retail pricing and rate riders primarily due to revised retail base rates implemented in North Carolina and South Carolina in the first quarter of 2012, and revenues recognized for the energy efficiency programs, and

·A $40 million increase in weather adjusted sales volumes to customers primarily due to higher weather-normal sales to retail customers and an extra day of revenues due to 2012 being a leap year.

           Partially offsetting these increases were:

·A $141 million (net of fuel) decrease in GWh sales to retail customers due to overall unfavorable weather conditions. The weather statistics for heating degree days in 2012 were unfavorable compared to the same period in 2011, while weather statistics for cooling degree days were less favorable in 2012 compared to the same period in 2011, and

·An $88 million decrease in fuel revenues driven primarily by decreased demand from retail customers mainly due to overall unfavorable weather conditions, partially offset by higher fuel rates in both North Carolina and South Carolina.  Fuel revenues represent sales to retail and wholesale customers.

Operating expenses. The variance was primarily due to:  

·A $107 million increase in depreciation and amortization primarily due to increases in depreciation as a result of additional plant in service and amortization of certain regulatory assets,

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PART II

·A $75 million increase in operating and maintenance expenses primarily due to Duke Energy Carolinas’ portion of the costs associated with the Progress Energy merger including donations, severance, and certain other costs, higher non-outage and outage costs at generation plants, increased corporate costs, and required donations resulting from the most recent North Carolina and South Carolina rate cases, partially offset by the establishment of regulatory assets in the first quarter of 2012, pursuant to regulatory orders for future recovery of certain employee severance costs related to the 2010 voluntary severance plan and other costs, decreased storm costs, and lower governance costs, and

·A $25 million increase in general taxes primarily due to higher revenue related taxes in 2012, higher North Carolina property tax expense, capitalization of North Carolina property taxes in the prior year related to future generation plants, a favorable prior year resolution of a property tax issue related to pollution control equipment exemptions and a sales and use tax refund in 2011 with no comparable refund in 2012, and

·A $19 million increase in impairment charges primarily related to the merger with Progress Energy. These charges relate to planned transmission project costs for which no recovery is expected, and certain costs associated with mitigation sales pursuant to merger settlement agreements with the Federal Energy Regulatory Commission (FERC).

Partially offsetting these increases was:

·An $80 million decrease in fuel expense (including purchased power) primarily related to lower volume of coal used in electric generation due to lower demand from retail customers based on overall unfavorable weather conditions and lower coal-fired generation due to low natural gas prices.

Interest expense. The variance is primarily due to lower debt return on deferred projects and a lower debt component of allowance for funds used during construction (AFUDC).

Income tax expense. The variance in income tax expense is primarily due to prior year state audit settlements. The effective tax rate for the years ended December 31, 2012 and 2011 was 34.3% and 36.1%, respectively.

Matters Impacting Future Duke Energy Carolinas Results

Duke Energy Carolinas filed a rate case on February 4, 2013 in North Carolina and plans to file a rate case in South Carolina in early 2013. These planned rates cases are needed to recover investments in Duke Energy Carolinas’ ongoing infrastructure modernization projects and operating costs. Duke Energy Carolinas’ earnings could be adversely impacted if these rate cases are denied or delayed by either of the state regulatory commissions.

The ability to integrate Progress Energy businesses and realize cost savings and any other synergies expected from the merger with Progress Energy could be different from what Duke Energy Carolinas expects and may have a significant impact on Duke Energy Carolinas’ results of operations.

49

PART II

PROGRESS ENERGY

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

BASIS OF PRESENTATION

The results of operations and variance discussion for Progress Energy is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

RESULTS OF OPERATIONS

	Years Ended December 31,
(in millions)	2012		2011		Variance
Operating revenues	$	9,405	$	8,948	$	457
Operating expenses		8,266		7,369		897
(Losses) gains on sales of other assets and other, net		(2)		4		(6)
Operating income		1,137		1,583		(446)
Other income and expense, net		130		52		78
Interest expense		740		725		15
Income before income taxes		527		910		(383)
Income tax expense		172		323		(151)
Income from continuing operations		355		587		(232)
Discontinued operations, net of tax		52		(5)		57
Net income		407		582		(175)
Less: Net income attributable to noncontrolling interests		7		7		-
Net income attributable to parent	$	400	$	575	$	(175)

The decrease in Progress Energy’s net income for the year ended December 31, 2012 compared to December 31, 2011 was primarily due to the following factors:

Operating revenues. The variance was primarily due to:

·A $319 million increase in fuel and capacity revenues driven primarily by the 2011 charge of $288 million for the amount to be refunded through the fuel clause in accordance with the 2012 settlement agreement at Progress Energy Florida, and

·A $154 million increase in sales to wholesale customers primarily due to Progress Energy Carolinas’ joint dispatch agreement (JDA) revenues from Duke Energy Carolinas, the impact of an amended capacity contract with a major wholesale customer at Progress Energy Carolinas that began in May 2012 and a new wholesale contract at Progress Energy Carolinas that began in July 2012. 

Partially offsetting these increases was:

·An $86 million decrease in sales to retail customers primarily due to unfavorable weather conditions. The weather statistics for heating degree days in 2012 were unfavorable compared to the same period in 2011, while weather statistics for cooling degree days were less favorable in 2012 compared to the same period in 2011.

Operating expenses. The variance was primarily due to:

·A $385 million increase in Operation, maintenance and other expense primarily due to higher costs to achieve the merger with Duke Energy and Progress Energy Carolinas’ higher nuclear plant outage costs, and

·A $261 million increase in Fuel used in electric generation and purchased power primarily due to the impact of establishing a $100 million regulatory liability for replacement power in accordance with Progress Energy Florida’s 2012 FPSC settlement agreement (See Note 4), the impact of higher rates at Progress Energy Carolinas and a change in generation mix at Progress Energy Carolinas, which was driven by nuclear refueling outages in 2012.

·A $197 million increase in Impairment charges primarily due to the impact of the decision to retire Crystal River Unit 3 (See Note 4) and the probable disallowance of transmission project costs at Progress Energy Carolinas, which are a portion of the FERC Mitigation charges (See Note 2) included in the costs to achieve the merger with Duke Energy. 

Other income and expenses, net. The variance was primarily due to the $59 million prior-year pretax unrealized loss to record the change in fair value of the contingent value obligations (CVOs). The change in fair value was determined by an October 3, 2011 settlement agreement with a CVO holder to purchase all of their CVOs at a negotiated purchase price. The settlement agreement also led to a subsequent tender offer to remaining CVO holders at the same purchase price.

Income tax expense. The variance was primarily due to a decrease in pre-tax income. The effective tax rates for 2012 and 2011 were 32.7% and 35.6%, respectively. The decrease in the effective tax rate is primarily due to the decrease in pre-tax income as well as the decrease for the change of fair value of outstanding CVOs.

Discontinued operations, net of tax. The variance was primarily due to the impact of the US Global settlement in 2012 (See Note 5).

Matters Impacting Future Progress Energy Results

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PART II

In accordance with the terms of a 2012 FPSC Settlement Agreement, with consumer representatives and approved by the FPSC, Progress Energy Florida retains the sole discretion and flexibility to retire Crystal River Unit 3. As a result of the decision to retire Crystal River Unit 3, under the terms of the 2012 FPSC Settlement Agreement, Progress Energy Florida is allowed to recover all remaining Crystal River Unit 3 investments and to earn a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket. Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013. Progress Energy’s financial condition and results of operations could be adversely impacted if the FPSC issues an unfavorable ruling.

Progress Energy Carolinas filed a rate case in North Carolina in October 2012, and plans to file a rate case in South Carolina before the end of 2013. These rate cases are needed to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. Progress Energy’s earnings could be adversely impacted if these rate cases are denied or delayed by the NCUC or PSCSC.

The ability to integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger with Duke Energy could be different from what Progress Energy expects and may have a significant impact on Progress Energy’s results of operations.

51

PART II

PROGRESS ENERGY CAROLINAS

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

BASIS OF PRESENTATION

The results of operations and variance discussion for Progress Energy Carolinas is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

RESULTS OF OPERATIONS

	Years Ended December 31,
(in millions)	2012		2011		Variance
Operating revenues	$	4,706	$	4,547	$	159
Operating expenses		4,197		3,674		523
Gains on sales of other asset and other, net		1		3		(2)
Operating income		510		876		(366)
Other income and expense, net		79		80		(1)
Interest expense		207		184		23
Income before income taxes		382		772		(390)
Income tax expense		110		256		(146)
Net income		272		516		(244)
Preferred stock dividend requirement		3		3		-
Net income attributable to parent	$	269	$	513	$	(244)

	The following table shows the percent changes in GWh sales and average number of customers for Progress Energy Carolinas. Except
as otherwise noted, the below percentages represent billed sales only for the periods presented and are not weather normalized.
Increase (decrease) over prior year		2012		2011
Residential sales(a)		(8.2)	%	(5.0)	%
General service sales(a)		(1.8)	%	(1.9)	%
Industrial sales(a)		(1.0)	%	0.5	%
Wholesale power sales		25.9	%	(10.0)	%
Total sales(b)		3.9	%	(5.8)	%
Average number of customers		0.8	%	0.4	%
(a)	Major components of retail sales.
(b)	Consists of all components of sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

The decrease in Progress Energy Carolinas’ net income for the year ended December 31, 2012 compared to December 31, 2011 was primarily due to the following factors:

Operating Revenues. The variance was primarily due to:

·A $139 million increase in sales to wholesale customers primarily due to JDA revenues from Duke Energy Carolinas, the impact of an amended capacity contract with a major wholesale customer that began in May 2012 and a new wholesale contract that began in July 2012,

·A $53 million increase in fuel revenues driven primarily by Interim FERC Mitigation wholesale fuel revenue and higher fuel rates, and

·A $19 million increase in clause-recoverable regulatory revenues primarily due to increased spending on new and existing DSM programs.

Partially offsetting these increases was:

· A $67 million decrease in sales to retail customers primarily due to unfavorable weather conditions. The number of heating degree days for the 12 months ended December 31, 2012 was 19% below normal compared to 9% below normal for the same period in 2011. In addition, cooling degree days for the 12 months ended December 31, 2012 were 3% above normal compared to 19% above normal in the same period in 2011.

Operating Expenses. The variance was primarily due to:  

·A $303 million increase in Operation and maintenance expenses primarily due to higher nuclear plant outage costs, higher costs to achieve the merger with Duke Energy and the prior year non-capital portion of a favorable judgment from spent fuel litigation, partially offset by lower storm costs. The higher nuclear plant outage costs are primarily due to three nuclear refueling outages in 2012 compared to one outage in 2011,

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PART II

·A $140 million increase in Fuel used in electric generation and purchased power primarily due to the impact of higher rates; higher weather-adjusted volumes and increased purchased power, which was driven by favorable gas prices and nuclear plant outages; and generation mix, which was driven by nuclear plant outages, and

·A $51 million increase in Impairment charges primarily due to the disallowance of transmission project costs, which are a portion of the FERC Mitigation charges included in the costs to achieve the merger with Duke Energy.

Interest Expense. The variance was primarily due to higher interest expense on long-term debt due to higher average debt outstanding and the prior-year settlement of 2004 and 2005 income tax audits.

Income Tax Expense. The variance was primarily due to a decrease in pretax net income. The effective tax rate for the years ended December 31, 2012 and 2011 was 28.7% and 33.2%, respectively. The decrease in the effective tax rate is primarily due to the decrease in pretax income.

Matters Impacting Future Progress Energy Carolinas Results

Progress Energy Carolinas filed a rate case in North Carolina in October 2012, and plans to file a rate case in South Carolina before the end of 2013. These rate cases are needed to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. Progress Energy Carolinas’ earnings could be adversely impacted if these rate cases are denied or delayed by the NCUC or PSCSC.

The ability to integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger with Duke Energy could be different from what Progress Energy Carolinas expects and may have a significant impact on Progress Energy Carolinas’ results of operations.

53

PART II

PROGRESS ENERGY FLORIDA

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

BASIS OF PRESENTATION

The results of operations and variance discussion for Progress Energy Florida is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

RESULTS OF OPERATIONS

	Years Ended December 31,
(in millions)	2012		2011		Variance
Operating revenues	$	4,689	$	4,392	$	297
Operating expenses		4,062		3,691		371
Gains on sales of other asset and other, net		2		2		-
Operating income		629		703		(74)
Other income and expense, net		39		30		9
Interest expense		255		239		16
Income before income taxes		413		494		(81)
Income tax expense		147		180		(33)
Net income		266		314		(48)
Preferred stock dividend requirement		2		2		-
Net income attributable to parent	$	264	$	312	$	(48)

	The following table shows the percent changes in GWh sales and average number of customers for Progress Energy Florida. Except
as otherwise noted, the below percentages represent billed sales only for the periods presented and are not weather normalized.
Increase (decrease) over prior year		2012		2011
Residential sales(a)		(5.1)	%	(6.3)	%
General service sales(a)		(1.0)	%	(0.4)	%
Industrial sales(a)		(2.5)	%	0.7	%
Wholesale power sales		(34.2)	%	(25.1)	%
Total sales(b)		(2.9)	%	(8.5)	%
Average number of customers		0.8	%	0.5	%
(a)	Major components of retail sales.
(b)	Consists of all components of sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

The decrease in Progress Energy Florida’s net income for the year ended December 31, 2012 compared to December 31, 2011 was primarily due to the following factors:

Operating Revenues. The variance was primarily due to:

·A $266 million increase in fuel and capacity revenues driven primarily by the 2011 charge of $288 million for the amount to be refunded through the fuel clause in accordance with the 2012 FPSC settlement agreement and the impact of higher residential fuel rates, partially offset by unfavorable weather conditions that impacted wholesale and retail fuel revenues. Also, Progress Energy Florida had lower capacity revenues resulting from a lower capacity rate and the lower sales volume,

·A $28 million increase in other operating revenues primarily due to higher OATT rates, and

·A $15 million increase in sales to wholesale customers primarily due to a new contract with a major customer.

Partially offsetting these increases was:

· A $19 million decrease in sales to retail customers due to unfavorable weather conditions. The number of heating degree days for the 12 months ended December 31, 2012 was 22% below normal compared to 12% below normal in the same period in 2011. In addition, cooling degree days for the 12 months ended December 31, 2012 were 4% above normal compared to 5% above normal in the same period in 2011.

Operating Expenses. The variance was primarily due to:  

·A $146 million increase in Impairment charges due to the impact of the decision to retire Crystal River Unit 3 (See Note 4),

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PART II

·A $121 million increase in Fuel used in electric generation and purchased power primarily due to the impact of establishing a regulatory liability for replacement power in accordance with the 2012 FPSC settlement agreement (See Note 4), and an increase in deferred fuel expense related to higher under-recovered fuel costs in 2011 as a result of higher system requirements driven by favorable weather in the prior year. These increases were partially offset by lower natural gas prices and lower system requirements as a result of unfavorable weather conditions in the current year and a lower Crystal River Unit 3 indemnification charge for the estimated joint owner replacement power costs,

·An $86 million increase in Operation and maintenance expenses primarily due to higher costs to achieve the merger with Duke Energy, and

·A $23 million increase in Depreciation and amortization primarily due to a decrease in the reduction of the cost of removal component of amortization expense as allowed under the 2012 and 2010 settlement agreements (See Note 4) and higher Environmental Cost Recovery Clause (ECRC) amortization due to less over-recovery, partially offset by lower nuclear cost-recovery amortization primarily related to the Levy nuclear station project.

Interest Expense. The variance was primarily due to the prior-year favorable settlement of 2004 and 2005 income tax audits.

Income Tax Expense. The variance was primarily due to a decrease in pretax net income. The effective tax rate for the years ended December 31, 2012 and 2011 were 35.7% and 36.3%, respectively.  

Matters Impacting Future Progress Energy Florida’s Results

In accordance with the terms of the 2012 FPSC Settlement Agreement, with consumer representatives and approved by the FPSC, Progress Energy Florida retains the sole discretion and flexibility to retire Crystal River Unit 3. As a result of the decision to retire Crystal River Unit 3, under the terms of the 2012 FPSC Settlement Agreement, Progress Energy Florida is allowed to recover all remaining Crystal River Unit 3 investments and to earn a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket. Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013. Progress Energy Florida’s financial condition and results of operations could be adversely impacted if the FPSC issues an unfavorable ruling.

The ability to integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger with Duke Energy could be different from what Progress Energy Florida expects and may have a significant impact on Progress Energy Florida’s results of operations.

55

PART II

DUKE ENERGY OHIO

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

BASIS OF PRESENTATION

The results of operations and variance discussion for Duke Energy Ohio is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

RESULTS OF OPERATIONS

	Years Ended December 31,
(in millions)	2012		2011		Variance
Operating revenues	$	3,152	$	3,181	$	(29)
Operating expenses		2,810		2,811		(1)
Gains on sales of other assets and other, net		7		5		2
Operating income		349		375		(26)
Other income and expense, net		13		19		(6)
Interest expense		89		104		(15)
Income before income taxes		273		290		(17)
Income tax expense		98		96		2
Net income	$	175	$	194	$	(19)

	The following table shows the percent changes in Franchised Electric and Gas's GWh sales and average number of customers for Duke Energy Ohio. Except
as otherwise noted, the below percentages represent billed sales only for the periods presented and are not weather normalized.
Increase (decrease) over prior year		2012		2011
Residential sales(a)		(3.3)	%	(3.2)	%
General service sales(a)		(2.6)	%	(1.2)	%
Industrial sales(a)		0.6	%	(2.9)	%
Wholesale power sales		(35.9)	%	15.9	%
Total sales(b)		(2.3)	%	(2.3)	%
Average number of customers		0.5	%	0.2	%
(a)	Major components of retail sales.
(b)	Consists of all components of sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

The decrease in Duke Energy Ohio’s net income for the year ended December 31, 2012 compared to December 31, 2011 was primarily due to the following factors:

Operating revenues. The variance was primarily driven by:

·A $285 million decrease in electric revenues from the coal-fired generation assets driven primarily by the expiration of the 2009-2011 ESP, net of stability charge revenues, partially offset by the coal-fired generation assets participating in the PJM wholesale energy market in 2012,

·A $39 million decrease in electric revenues from the gas-fired generation assets driven primarily by lower power prices, partially offset by increased volumes, and

·An $18 million decrease in PJM capacity revenues related to lower average cleared capacity auction pricing in 2012 compared to 2011 for the gas-fired generation assets, net of an increase associated with the move of the coal-fired assets from MISO to PJM in 2012.

Partially offsetting these decreases were:

·A $279 million increase in regulated fuel and purchased power revenues driven primarily by higher purchased power revenues collected under the new Ohio ESP which became effective January 1, 2012, partially offset by reduced gas sales volumes and lower natural gas costs, and

·A $32 million increase in retail Ohio electric energy efficiency rider revenue resulting primarily from the approval of the final save-a-watt order for the years 2009-2012.

Operating expenses. The variance was primarily driven by:

·A $101 million decrease in operating and maintenance expenses resulting primarily from prior year recognition of MISO exit fees, higher prior year station outages, and regulatory asset amortization expenses,

·An $88 million decrease primarily from the 2011 impairment of excess emission allowances as a result of the EPA’s issuance of the Cross-State Air Pollution Rule (CSAPR), and

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·An $85 million decrease in fuel expense from the gas-fired generation assets driven by lower natural gas costs, partially offset by higher volumes.

Partially offsetting these decreases was:

·A $274 million increase in regulated fuel expense driven primarily by higher purchased power expense as a result of the new ESP, partially offset by reduced gas sales volumes and lower natural gas costs.

Interest expense. The variance was primarily due to lower average debt balances in 2012 compared to 2011 and post in-service carrying charges related to new projects.

Income tax expense. The variance in tax expense is primarily due to an increase in the effective tax rate. The effective tax rate for the years ended December 31, 2012 and 2011 was 36.0% and 33.1%, respectively. The increase in the effective tax rate is primarily due to a $10 million reduction of deferred tax liabilities as a result of an election related to the transfer of certain gas-fired generation assets to its wholly owned subsidiary Duke Energy Commercial Asset Management, LLC (DECAM) in the second quarter of 2011.  

Matters Impacting Future Duke Energy Ohio Results

Duke Energy Ohio filed electric and gas distribution rate cases in July 2012. These planned rate cases are needed to recover capital investments, costs associated with MGP sites and operating costs. Duke Energy Ohio’s earnings could be adversely impacted if these rate cases are denied or delayed by the state regulatory commission.

The current low energy price projections, as well as recently issued and proposed environmental regulations pertaining to coal and coal-fired generating  facilities, could impact future cash flows and market valuations of Duke Energy Ohio’s coal-fired generation assets which could lead to impairment charges.

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DUKE ENERGY INDIANA

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2012, 2011, and 2010.

BASIS OF PRESENTATION

The results of operations and variance discussion for Duke Energy Indiana is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

RESULTS OF OPERATIONS

	Years Ended December 31,
(in millions)	2012		2011		Variance
Operating revenues	$	2,717	$	2,622	$	95
Operating expenses		2,792		2,340		452
Operating (loss) income		(75)		282		(357)
Other income and expense, net		90		97		(7)
Interest expense		138		137		1
(Loss) Income before income taxes		(123)		242		(365)
Income tax (benefit) expense		(73)		74		(147)
Net (loss) income	$	(50)	$	168	$	(218)

	The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Indiana. Except
as otherwise noted, the below percentages represent billed sales only for the periods presented and are not weather normalized.
Increase (decrease) over prior year		2012		2011
Residential sales(a)		(4.8)	%	(3.0)	%
General service sales(a)		(0.5)	%	(1.5)	%
Industrial sales(a)		1.7	%	1.5	%
Wholesale power sales		7.9	%	(19.1)	%
Total sales(b)		1.2	%	(4.9)	%
Average number of customers		0.6	%	0.1	%
(a)	Major components of retail sales.
(b)	Consists of all components of sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

Duke Energy Indiana’s net loss for the year ended December 31, 2012 compared to net income for the year ended December 31, 2011 was primarily due to the following factors:

Operating Revenues. The variance was primarily due to:

·A $102 million net increase in fuel revenues (including emission allowances) primarily due to an increase in fuel rates as a result of higher fuel and purchased power costs,

·A $17 million net increase in rate riders primarily related to higher recoveries under the clean coal technology and energy efficiency riders, and

·A $12 million increase in rate pricing due to the positive impact on overall average prices of lower sales volumes.

Partially offsetting these increases were:

·A $31 million decrease in retail revenue due to a regulatory order to refund revenues to customers related to the Edwardsport IGCC plant that is currently under construction.  See Note 4 to the Consolidated Financial Statements “Regulatory Matters,” for additional information, and

·A $7 million decrease in retail revenues related to less favorable weather conditions and weather-normal sales volumes in 2012 compared to 2011.

Operating Expenses. The variance was primarily due to:

·A $378 million increase due to impairment and other charges recorded in 2012 related to the Edwardsport IGCC plant that is currently under construction of $600 million, partially offset by a 2011 Edwardsport IGCC impairment charge of $222 million.  See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information, and

·A $102 million increase in fuel costs primarily due to an increase in fuel rates as a result of higher fuel and purchased power costs.

Partially offsetting these increases were:

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·A $29 million decrease in operation and maintenance primarily due to higher storm costs in the prior year, and lower generation and outage maintenance costs in 2012, partially offset by higher energy efficiency program costs.

Income Tax (Benefit) Expense. The variance in income tax expense is primarily due to a decrease in pretax income. The effective tax rates for the years ended December 31, 2012 and 2011 were 59.5% and 30.6%, respectively. The increase in the effective tax rate is primarily due to the decrease in pretax income in 2012 related to the Edwardsport IGCC project.

Matters Impacting Future Duke Energy Indiana Results

On December 27, 2012, the IURC approved a settlement agreement between Duke Energy Indiana and certain intervenors to cap the construction costs recoverable in retail rates. The Edwardsport IGCC plant is scheduled to begin commercial operation in mid-2013. Duke Energy Indiana’s earnings could be adversely impacted by additional delays in the commencement of operations which may result in increased costs.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The application of accounting policies and estimates is an important process that continues to develop 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 it believes are reasonable at the time of application. The estimates and judgments may change as time passes and more information about Duke Energy’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Energy discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Energy’s critical accounting policies and estimates are discussed below.

Regulatory Accounting

Duke Energy’s regulated operations (the substantial majority of U.S. Franchised Electric and Gas’s operations) 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 nonregulated 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 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, litigation of rate orders, 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 or may disallow recovery of all or a portion of certain assets. Total regulatory assets for Duke Energy were $11,741 million and $4,046 million as of December 31, 2012 and 2011, respectively. Total regulatory liabilities were $5,740 million and $3,006 million as of December 31, 2012 and 2011, respectively. The increases in regulatory assets and liabilities are driven primarily by the Progress Energy merger. 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.

The regulatory accounting rules require recognition of a loss if it becomes probable that part of the cost of a plant under construction or a recently completed plant will be disallowed for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made. Such assessments can require significant judgment by management regarding matters such as the ultimate cost of a plant under construction, regulatory recovery implications, etc. As discussed in Note 4, “Regulatory Matters,” during 2012, 2011 and 2010 Duke Energy Indiana recorded charges of $631 million, $222 million and $44 million, respectively, related to the IGCC plant currently under construction in Edwardsport, Indiana. Management will continue to assess matters as the construction of the plant and the related regulatory proceedings continue, and further charges could be required in 2013 or beyond. Also as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Sales of Other Assets”, Duke Energy Carolinas and Progress Energy Carolinas recorded disallowance charges in 2012 in order to gain FERC approval of the merger between Duke Energy and Progress Energy.

As discussed further in Note 1, “Summary of Significant Accounting Policies”, and Note 4, “Regulatory Matters,” Duke Energy Ohio discontinued the application of regulatory accounting treatment to portions of its generation operations in November 2011 in conjunction with the approval of its new Electric Security Plan by the Public Utilities Commission of Ohio. The effect of this change was immaterial to the financial statements.

Goodwill Impairment Assessments

Duke Energy’s goodwill balances are included in the following table.

	December 31,
(in millions)	2012		2011
U.S. Franchised Electric and Gas	$	15,950	$	3,483
Commercial Power		62		69
International Energy		353		297
Total Duke Energy goodwill	$	16,365		3,849

The Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment. During 2012, Duke Energy recorded $12,467 million of goodwill associated with the merger with Progress Energy. This goodwill represents the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed on the acquisition date, and was preliminarily allocated entirely to the USFE&G segment. The goodwill recognized is subject to change as additional information is obtained about the facts and circumstances that existed as of the acquisition date. See Note 2, “Acquisitions and Sales of Other Assets,” for additional information on the merger with Progress Energy.

The remainder of USFE&G’s goodwill relates to the acquisition of Cinergy in April 2006. Commercial Power’s goodwill resulted from the 2008 acquisition of Catamount Energy Corporation, a leading wind power company located in Rutland, Vermont, and has been allocated to the Renewables reporting unit. International Energy’s goodwill resulted from various acquisitions, including $59 million from the 2012 acquisition of Iberoamericana de Energia Ibener S.A. in Chile. See Note 2, “Acquisitions and Sales of Other Assets,” for additional information.

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Duke Energy recorded impairments of $500 million related to Commercial Power’s nonregulated Midwest generation reporting unit in 2010. Subsequent to the 2010 impairment charge there is no recorded amount of goodwill at Commercial Power’s nonregulated Midwest generation reporting unit. These impairment charges are recorded in Goodwill and Other Impairment Charges on Duke Energy’s Consolidated Statement of Operations. See Note 12 to the Consolidated Financial Statements, “Goodwill, Intangible Assets and Impairments” for further information regarding the factors impacting the valuation of Commercial Power’s nonregulated generation reporting unit. Duke Energy determined that no other goodwill impairments existed in 2012, 2011, and 2010.

As discussed in Note 12 to the Consolidated Financial Statements, “Goodwill, Intangible Assets and Impairments,” Duke Energy is required to test goodwill for impairment at the reporting unit level at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Duke Energy evaluates the carrying amount of its recorded goodwill for impairment on an annual basis as of August 31 and performs interim impairment tests 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.

The analysis of the potential impairment of goodwill may first consider qualitative factors to determine whether it is more likely than not (i.e., greater than 50 percent chance) that the fair value of a reporting unit is less than its book value. This is sometimes referred to as “step zero” and is an optional step in the annual goodwill impairment analysis. If the results of qualitative assessments indicate that the fair value of a reporting unit is more likely than not less than the carrying value of the reporting unit, the two-step impairment test is required. Step one of the impairment test involves comparing the fair values of reporting units with their carrying values, including goodwill. If the carrying amount is less than fair value in step one, further testing of goodwill is not performed. 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. 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.

As a result of the acquisition of Progress Energy, Duke Energy performed step one of the goodwill impairment test as of August 31, 2012, and concluded the fair value of each of its reporting units exceeded their respective carrying values, and thus, did not record any impairment charges. In 2011, Duke Energy performed the qualitative assessments under step zero and concluded that it was more likely than not the fair value of each reporting unit exceeded its carrying value. Thus, the two step goodwill impairment test was not necessary in 2011. 

When performing step zero of the goodwill impairment test, Duke Energy’s qualitative assessments include reviews of current forecasts compared to prior forecasts, consideration of recent fair value calculations, if any, review of the stock price performance of Duke Energy and its peers, credit ratings of Duke Energy’s significant subsidiaries, updates to weighted average cost of capital (WACC) calculations or review of the key inputs to the WACC and consideration of overall economic factors, recent regulatory commission actions and related regulatory climates, and recent financial performance.

For purposes of the step one analyses, determination of the reporting units’ fair values is 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. Generally, more emphasis is applied to the income approach as it represents management’s best estimate of future value. Key assumptions used in the income approach analyses include, but are not limited to, estimated future cash flows and the use of an appropriate discount rate. The market approach uses implied market multiples derived from comparable peer utilities and market transactions to estimate the fair value.

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. 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, projected commodity pricing data and potential changes in environmental regulations. 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. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory and economic stability, the ability to renew contracts and other factors, into its revenue and expense forecasts. 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 WACC for each individual reporting unit. The WACC takes into account both the pre-tax cost of debt and cost of equity (a major component of the cost of equity is the current risk-free rate on twenty year U.S. Treasury bonds). In the 2012 step one impairment tests, Duke Energy considered implied WACC’s for certain peer companies in determining the appropriate WACC rates to use in its analysis. 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 pending EPA regulations. The discount rates used for calculating the fair values as of August 31, 2012, for each of Duke Energy’s domestic reporting units were commensurate with the risks associated with each reporting unit and ranged from 5.2% to 7.1%. For Duke Energy’s international operations, a country specific risk adder based on the average of risk premium for each separate jurisdiction in which International Energy operates was added to the base discount rate to reflect the differing risk profiles of the jurisdictions and countries. This resulted in a discount rate for the August 31, 2012 goodwill impairment test for the international operations of 8.5%.

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

The 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. However, changes in discount rates may have a significant impact on the fair value of equity. As of August 31, 2012, all of the USFE&G

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reporting units’ estimated fair value of equity exceeded the carrying value of equity by more than 10%, except Progress Energy Florida which has preliminarily been allocated goodwill of $2,457 million. Management will continue to monitor changes in the business, as well as overall market conditions and economic factors that could require additional impairment tests.

As discussed in Note 12 to the Consolidated Financial Statements, “Goodwill, Intangible Assets and Impairments”, the fair value of USFE&G’s Progress Energy Florida reporting unit and Commercial Power’s Renewables reporting unit are impacted by a multitude of factors, including legislative actions related to tax credit extensions, long-term growth rate assumptions, the market price of power and discount rates. As of December 31, 2012, the Progress Energy Florida reporting unit and the Renewables reporting unit’s estimated fair value of equity exceeded the carrying value of equity by less than 10%. Management continues to monitor these assumptions for any indicators that the fair value of the reporting unit could be below the carrying value, and will assess goodwill for impairment as appropriate

Long-Lived Asset Impairment Assessments

Property, plant and equipment is stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Duke Energy evaluates property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted future cash flows associated with the asset. Additionally, determining the fair value of the asset requires probability weighting the future cash flows to reflect expectations about possible variations in their amounts or timing and the selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the asset and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

When it becomes probable that regulated generation, transmission or distribution assets have been abandoned, the cost of the asset is removed from plant in service. The value that may be retained as an asset on the balance sheet for the abandoned property is dependent upon amounts that may be recovered through regulated rates, including any return. As such, an impairment charge could be offset by the establishment of a regulatory asset if rate recovery is probable.

As discussed further in Note 12 to the Consolidated Financial Statements, “Goodwill, Intangible Assets and Impairments,” in the third quarter of 2012, Duke Energy Carolinas and Progress Energy Carolinas recorded certain impairment charges in conjunction with the merger between Duke Energy and Progress Energy. In the third quarter of 2011, Commercial Power recorded $79 million of pre-tax impairment charges related to Clean Air Act emission allowances which were no longer expected to be used as a result of the issuance of the final Cross State Air Pollution Rule. In the second quarter of 2010, Commercial Power recorded $160 million of pre-tax impairment charges related to certain generating assets and emission allowances in the Midwest to write-down the value of these assets to their estimated fair value, which was impacted by the EPA’s rules on emissions of NO_x and SO₂. These impairment charges are recorded in Goodwill and Other Impairment Charges on Duke Energy’s Consolidated Statement of Operations.

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 the number of estimated kWh or Mcf 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, customer mix and the average price in effect for customer classes.

At December 31, 2012 and 2011, Duke Energy had $920 million and $674 million, respectively, of unbilled revenues within Restricted Receivables of Variable Interest Entities and Receivables on the Consolidated Balance Sheets.

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 Carolinas 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 in the respective Consolidated Balance Sheets totaled $751 million and $801 million as of December 31, 2012 and 2011, 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 2030. Management believes that it is possible there will be additional claims filed against Duke Energy after 2030. 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 2030 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 may incur asbestos liabilities in excess of the recorded reserves.

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Duke Energy Carolinas has a third-party insurance policy to cover certain losses related to asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Duke Energy’s cumulative payments began to exceed the self insurance retention on its insurance policy in 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 $935 million in excess of the self insured retention. Insurance recoveries of $781 million and $813 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, 2012 and 2011, 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 5 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 allowance 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). The ETR calculations are revised each quarter based on the best annual 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, excluding discrete items impacting income tax expense that have occurred year-to-date.

Duke Energy recognizes 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 tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized in the Consolidated Financial Statements. Management reevaluates tax positions when new information about recognition or measurement becomes available. The portion of the tax benefit which is uncertain is disclosed in the notes to the Consolidated Financial Statements.

Undistributed foreign earnings associated with International Energy’s operations are considered indefinitely reinvested. As a result, 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 intentions to reinvest such earnings. While management currently intends 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. The cumulative undistributed earnings as of December 31, 2012, on which Duke Energy has not provided deferred U.S. income taxes and foreign withholding taxes is approximately $2.0 billion. The amount of unrecognized deferred tax liability related to these undistributed earnings is estimated at between $275 million and $350 million.

For further information, see Note 24 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 plans are determined by government regulations. Duke Energy made voluntary contributions to its defined benefit retirement plans of $200 million in 2012, $200 million in 2011, and $400 million in 2010 and mandatory contributions of $104 million in 2012. In 2013, Duke Energy anticipates making $350 million of contributions to its defined benefit plans.

Duke Energy and its subsidiaries, including Progress Energy and Cinergy, maintain, and the Subsidiary Registrants participate in, non-contributory defined benefit retirement plans. The plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Certain Progress Energy and Cinergy U.S. employees are covered under plans that use a final average earnings formula. Under the Cinergy 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. Under the Progress Energy final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 4-year average earnings, plus a percentage of their highest 4-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 4-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains, and the Subsidiary Registrants participate in, non-qualified, non-contributory defined benefit retirement plans which cover certain executives.

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Duke Energy and most of its subsidiaries provide, and the Subsidiary Registrants participate in, 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 $117 million in 2012. In 2013, Duke Energy’s pre-tax qualified pension cost is expected to be $61 million higher than in 2012 resulting primarily from a 2013 decrease in the discount rate on obligations and  expected long-term rate of return on assets, and 12 months of expense recognition in 2013 for the Progress Energy plans. Duke Energy recognized pre-tax nonqualified pension cost of $19 million and pre-tax other post-retirement benefits cost of $80 million, in 2012. In 2013, pre-tax non-qualified pension cost is expected to be approximately the same amount as in 2012. In 2013, pre-tax other post-retirement benefits costs are expected to be approximately $46 million higher than in 2012 resulting primarily from  12 months of expense recognition in 2013 for the Progress Energy plans.

For both pension and other post-retirement plans, Duke Energy assumes that its plan’s assets will generate a long-term rate of return of 7.75% as of December 31, 2012. The assets for Duke Energy’s pension and other post-retirement plans are maintained in two master trusts, the Duke Energy Master Retirement Trust and the Progress Energy Master Trust. The investment objective of the master trusts is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, hedge funds, real estate and other global securities are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers on 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). The investment objective of VEBA I 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. VEBA I is passively managed.

The expected long-term rate of return of 7.75% for the plan’s assets was developed using a weighted average calculation of expected returns for the master trusts based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes for the Duke Energy Retirement Master Trust were 2.53% for U.S. equities, 1.46% for Non-U.S. equities, 0.97% for global equities, 1.65% for debt securities, 0.36% for global private equity, 0.22% for hedge funds, 0.28% for real estate and 0.28% for other global securities. The weighted average returns expected by asset classes for the Progress Energy Master Trust were 1.83% for U.S. equities, 1.41% for Non-U.S. equities, 0.78% for global equities, 1.67% for debt securities, 1.20% for global private equity, 0.57% for hedge funds, 0.08% for real estate and 0.21% for other global securities

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 4.1% as of December 31, 2012. The discount rates used to measure benefit plan benefit obligations for financial reporting purposes should reflect rates at which pension benefits could be effectively settled. As of December 31, 2012, Duke Energy determined its discount rate for U.S. pension and other post-retirement obligations using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.

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 2012 pre-tax pension expense, pension obligation and other post-retirement benefit obligation if a 0.25% change in rates were to occur.

		Qualified and Non-Qualified Pension Plans				Other Post-retirement Plans
(in millions)		+0.25%		-0.25%		+0.25%		-0.25%
Effect on 2012 pre-tax pension expense
	Expected long-term rate of return	$	(12)	$	12	$	-	$	-
	Discount rate		(8)		8		(1)		1
Effect on benefit obligation at December 31, 2012
	Discount rate	$	(123)	$	127	$	(15)	$	16

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, 2012, the medical care trend rates were 8.5%, which grades to 5.00% by 2020. The following table presents the approximate effect on Duke Energy’s 2012 pre-tax other post-retirement expense and other post-retirement benefit obligation if a 1% point change in the health care trend rate were to occur.

	Other Post-retirement Plans
(in millions)	+1.0%		-1.0%
Effect on 2012 other post-retirement expense	$	9	$	(7)
Effect on other post-retirement benefit obligation at December 31, 2012		164		(133)

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LIQUIDITY AND CAPITAL RESOURCES

Overview

At December 31, 2012, Duke Energy had cash and cash equivalents and short-term investments of $1.8 billion, of which $1.1 billion is held in foreign jurisdictions and is forecasted to be used to fund the operations of and investments in International Energy. To fund its domestic liquidity and capital requirements, Duke Energy relies primarily upon cash flows from operations, borrowings, and its existing cash and cash equivalents. The relatively stable operating cash flows of USFE&G 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 foreseeable future. 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. Weather conditions, commodity price fluctuations and unanticipated expenses, including unplanned plant outages and storms, could affect the timing and level of internally generated funds.

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’s projected capital and investment expenditures for the next three fiscal years are included in the table below.

(in millions)	2013		2014		2015
U.S. Franchised Electric and Gas	$	5,300	$	5,025	$	5,400
Commercial Power, International Energy and Other		575		375		350
Total committed expenditures		5,875		5,400		5,750
Discretionary expenditures		425		625		600
Total projected capital and investment expenditures	$	6,300	$	6,025	$	6,350

	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, the majority of Duke Energy’s total projected capital expenditures are allocated to the
USFE&G segment. The table below includes the components of projected capital expenditures for USFE&G for the next three fiscal years.
		2013		2014		2015
Infrastructure growth and nuclear projects		28	%	29	%	35	%
Maintenance		57	%	51	%	44	%
Nuclear fuel		9	%	11	%	10	%
Environmental		6	%	9	%	11	%
Total projected U.S. Franchised Electric and Gas capital and investment expenditures		100	%	100	%	100	%

With respect to the 2013 capital expenditure plan, Duke Energy has flexibility within its $6.3 billion budget to defer or eliminate certain spending should economic or financing conditions deteriorate. Of the $6.3 billion budget, $1.3 billion relates to projects for which management has committed capital, including, but not limited to, the final construction of the Edwardsport IGCC plant and the Sutton combined cycle gas-fired facility, and management intends to spend those capital dollars in 2013 irrespective of broader economic factors. $4.6 billion of projected 2013 capital expenditures are expected to be used primarily for overall system maintenance and upgrades, customer connections, compliance with new environmental requirements and corporate capital 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 2013 capital expenditures of $0.4 billion are of a discretionary nature and relate to growth opportunities in which Duke Energy may invest, provided there are opportunities that meet return expectations.

As a result of Duke Energy’s significant commitment to modernize its generating fleet through the construction of new units, the ability to cost effectively manage the construction phase of current and future projects is critical to ensuring full and timely recovery of costs of construction. Should Duke Energy encounter significant cost overruns above amounts approved by the various state commissions, and those amounts are disallowed for recovery in rates, or if construction costs of renewable generation exceed amounts provided through power sales agreements and tax credits, future cash flows and results of operations could be adversely impacted.

Duke Energy’s capitalization is balanced between debt and equity as shown in the table below.

	Projected		Actual		Actual
	2013		2012		2011
Equity	50	%	50	%	52	%
Debt	50	%	50	%	48	%

Duke Energy’s fixed charges coverage ratio, calculated using SEC guidelines, was 2.5 times for 2012, 3.2 times for 2011, and 3.0 times for 2010.

In 2013, Duke Energy currently anticipates issuing additional debt of $4.3 billion, primarily for the purpose of funding capital expenditures and debt maturities. Due to the flexibility in the timing of projected 2013 capital expenditures, the timing and amount of debt issuances throughout 2013 could be influenced by changes in capital spending.

Duke Energy has access to a $6 billion master credit facility, which is not restricted upon general market conditions. At December 31, 2012, Duke Energy has available borrowing capacity of $4.9 billion under this facility. Management currently believes that amounts available under its revolving master credit facility are accessible should there be a need to generate additional short-term financing in 2013. Management expects that cash flows from operations and issuances of debt will be sufficient to cover the 2013 funding requirements related to capital and investments expenditures, dividend payments and debt maturities. See “Credit Facilities” section below for additional information regarding Duke Energy’s credit facility.

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 2013. However, circumstances could arise that may alter that view. If and when management had a belief that such

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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.

Duke Energy periodically evaluates the impact of repatriation of cash generated and held in foreign countries. Duke Energy’s current intent is to indefinitely reinvest foreign earnings. However, circumstances could arise that may alter that view, including a future change in tax law governing U.S. taxation of foreign earnings. If Duke Energy were to decide to repatriate foreign generated and held cash, recognition of material U.S. federal income tax liabilities could be required.

Cash Flow Information

The following table summarizes Duke Energy’s cash flows for the three most recently completed fiscal years.

		Years Ended December 31,
(in millions)		2012		2011		2010
Cash flows provided by (used in):
	Operating activities	$	5,244	$	3,672		4,511
	Investing activities		(6,197)		(4,434)		(4,423)
	Financing activities		267		1,202		40
Net (decrease) increase in cash and cash equivalents			(686)		440		128
Cash and cash equivalents at beginning of period			2,110		1,670		1,542
Cash and cash equivalents at end of period		$	1,424	$	2,110	$	1,670

Operating Cash Flows
	The following table summarizes key components of Duke Energy’s operating cash flows for the three most recently completed
fiscal years.
		Years Ended December 31,
(in millions)		2012		2011		2010
Net income		$	1,782	$	1,714	$	1,323
Non-cash adjustments to net income			3,769		2,628		2,972
Contributions to qualified pension plans			(304)		(200)		(400)
Working capital			(3)		(470)		616
Net cash provided by operating activities		$	5,244	$	3,672	$	4,511
	The increase in cash provided by operating activities in 2012 as compared to 2011 was driven primarily by:
•	An approximately $1,210 million increase in net income after non-cash adjustments (depreciation and amortizations, higher Edwardsport charges, severance expense and other Progress Energy merger related costs), resulting from the inclusion of Progress Energy's results beginning July 2, 2012 and the impact of the 2011 North Carolina and South Carolina rate cases, net of unfavorable weather; and
•	A $560 million increase in traditional working capital, mainly due to an increase in current year vacation and incentive accruals and prior year refund of North Carolina overcollected fuels costs and current year overcollection of North Carolina and South Carolina fuel costs, partially offset by;
•	A $100 million increase in contributions to company sponsored pension plans due to contributions for Progress Energy pension plans.
	The decrease in cash provided by operating activities in 2011 as compared to 2010 was driven primarily by:
•	Changes in traditional working capital amounts principally due to a increase in coal inventory, resulting mainly from milder weather and changes in the timing of payment of accounts payable and accrued liabilities, partially offset by;
•	A $200 million decrease in contributions to company sponsored pension plans due to 2010 pre-funding of contributions resulting from favorable borrowing conditions.

Investing Cash Flows
	The following table summarizes key components of Duke Energy’s investing cash flows for the three most recently completed
fiscal years.
		Years Ended December 31,
(in millions)		2012		2011		2010
Capital, investment and acquisition expenditures		$	(5,958)	$	(4,464)	$	(4,855)
Available for sale securities, net			(182)		(131)		95
Proceeds from sales of equity investments and other assets, and sales of and collections on notes receivable			212		118		406
Other investing items			(269)		43		(69)
Net cash used in investing activities		$	(6,197)	$	(4,434)	$	(4,423)
	The primary use of cash related to investing activities is capital, investment and acquisition expenditures, detailed by reportable
business segment in the following table.
		Years Ended December 31,
(in millions)		2012		2011		2010
U.S. Franchised Electric and Gas		$	4,220	$	3,717	$	3,891
Commercial Power			1,038		492		525
International Energy			551		114		181
Other			149		141		258
Total capital, investment and acquisition expenditures		$	5,958	$	4,464	$	4,855
	The increase in cash used in investing activities in 2012 as compared to 2011 is primarily due to the following:
•	A $1,490 million increase in capital, investment and acquisition expenditures primarily due to the inclusion of Progress Energy's capital expenditures beginning July 2, 2012, higher expenditures on renewable energy projects and the Chilean hydro acquisition, net of lower spending on Duke Energy's ongoing infrastructure modernization program as these projects near completion and
•	A $440 million increase in restricted cash primarily due to a secured debt issuance related to Chilean hydro acquisition.
	The increase in cash used in investing activities in 2011 as compared to 2010 is primarily due to the following:
•	A $290 million decrease in proceeds from sales of equity investments and other assets, and sales of and collections on notes receivable as result of cash received in 2010 from the sale of a 50% interest in DukeNet and the sale of Duke Energy’s 30% interest in Q-Comm, partially offset by the 2011 sale of Windstream stock received in conjunction with the Q-Comm sale in December 2010 and
•	A $230 million increase in purchases of available-for-sale securities, net of proceeds, due to the investment of excess cash held in foreign jurisdictions.
	These increases in cash used were partially offset by the following:
•	A $390 million decrease in capital, investment and acquisition expenditures primarily due to construction of the Edwardsport IGCC plant and Cliffside Unit 6 nearing completion.

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Financing Cash Flows
	The following table summarizes key components of Duke Energy’s financing cash flows for the three most recently completed
fiscal years.
		Years Ended December 31,
(in millions)		2012		2011		2010
Issuance of common stock related to employee benefit plans		$	23	$	67	$	302
Issuance of long-term debt, net			1,672		2,292		1,091
Notes payable and commercial paper			278		208		(55)
Dividends paid			(1,752)		(1,329)		(1,284)
Other financing items			46		(36)		(14)
Net cash provided by financing activities		$	267	$	1,202	$	40
	The decrease in net cash provided by financing activities in 2012 as compared to 2011 was due primarily to the following:
•	A $620 million decrease in net issuances of long-term debt, primarily due to the timing of issuances and redemptions between years and
•	A $420 million increase in quarterly dividends primarily due to an increase in common shares outstanding, resulting from the merger with Progress Energy and an increase in dividends per share from $0.75 to $0.765 in the third quarter of 2012. The total annual dividend per share was $3.03 in 2012 compared to $2.97 in 2011;
	These decreases in cash provided were partially offset by:
•	A $70 million increase in proceeds from net issuances of notes payable and commercial paper, primarily due to the PremierNotes program, net of paydown of commercial paper.
	The increase in net cash provided by financing activities in 2011 as compared to 2010 was due primarily to the following:
•	A $1,200 million net increase in long-term debt primarily due to financings associated with the ongoing fleet modernization program and
•	A $260 million increase in proceeds from net issuances of notes payable and commercial paper, primarily due to PremierNotes and commercial paper issuances.
•	These increases in cash provided were partially offset by:
	A $240 million decrease in proceeds from the issuances of common stock primarily related to the Dividend Reinvestment Plan (DRIP) and other internal plans, due to the discontinuance of new share issuances in the first quarter of 2011 and
•	A $50 million increase in dividends paid in 2011 due to an increase in dividends per share from $0.735 to $0.75 in the third quarter of 2011. The total annual dividend per share was $2.97 in 2011 compared to $2.91 in 2010.

Significant Notes Payable and Long-Term Debt Activities – 2012 - 2013.

Duke Energy’s outstanding long-term debt, including current maturities as of December 31, 2012, includes approximately $17.8 billion assumed in the merger with Progress Energy. This amount includes $2.3 billion of fair value adjustments recorded in connection with purchase accounting for the Progress Energy merger, which are not part of future principal payments and will amortize over the remaining life of the debt. See Note 2 to the Consolidated Financial Statements “Acquisitions, Dispositions and Sales of Other Assets” for additional information related to the merger with Progress Energy.

On February 6, 2013, Duke Energy announced that it will redeem all shares of the three and five series of preferred stock issued by Progress Energy Carolinas and Progress Energy Florida, respectively, of $93 million on March 8, 2013.

 In January 2013, Duke Energy issued $500 million of unsecured junior subordinated debentures, which carry a fixed interest rate of 5.125%, are callable at par after five years and mature January 15, 2073. Proceeds from the issuance were used to redeem at par $300 million of 7.10% junior subordinated debt in February 2013, with the remainder to repay a portion of commercial paper as it matures, to fund capital expenditures of our unregulated businesses and for general corporate purposes.

In December 2012, Duke Energy entered credit agreements with a commercial bank for a $190 million bridge loan and a $200 million revolving loan. The bridge loan carries a variable interest rate equal to the 180-day Libor rate plus 0.80% and matures on June 20, 2013. The revolving loan carries a variable interest rate equal to the 360-day Libor rate plus 1.35% and is payable in full on December 20, 2013; Duke Energy has the right to extend the term of the revolving loan for an additional 1-year terms, not to exceed a final maturity of 13 years from the date of the initial funding. Both loans are collateralized with cash deposits equal to 101% of the loan amounts, and therefore no net proceeds from the financings exist as of December 31, 2012.  

In December 2012, Los Vientos Windpower IA, LLC (Los Vientos 1A) and Los Vientos Windpower 1B, LLC (Los Vientos 1B), subsidiaries of Duke Energy Generation Services, Inc. (DEGS) an indirect wholly owned subsidiary of Duke Energy, each entered into long-term loan agreements of $246 million and $177 million, respectively.  Of the total loan amounts for Los Vientos 1A and Los Vientos 1B, $110 million for each is at a fixed interest rate of

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4.740% that mature in June, 2037 and June, 2036, respectively. The remainder of the Los Vientos 1A and Los Vientos 1B loan amounts of $136 million and $67 million, respectively, is at the six month adjusted London Interbank Offered Rate (LIBOR) plus an applicable margin that was initially set at 2.774% for each loan. In connection with the variable rate portion of the loans, Los Vientos 1A and Los Vientos 1B entered into interest rate swaps to convert the substantial majority of the variable rate loan interest payments from a variable rate to a fixed rate of 2.055% and 2.0175%, respectively, plus the applicable margin, which was 2.25% as of December 31, 2012 for each loan and each of these loans is due to mature June 30, 2030. The collateral for the loans are substantially all of the assets of Los Vientos Windpower IA, LLC and Los Vientos Windpower 1B, LLC. Proceeds from the issuances will be used to help fund the existing wind portfolio.

In November 2012, Progress Energy Florida issued $650 million principal amount of first mortgage bonds, of which $250 million carry a fixed interest rate of 0.65% and mature November 15, 2015 and $400 million carry a fixed interest rate of 3.85% and mature November 15, 2042. Proceeds from the issuances will be used to repay $425 million 4.80% first mortgage bonds due March 1, 2013, as well as for general corporate purposes.

In September 2012, Duke Energy Carolinas issued $650 million principal amount of first mortgage bonds, which carry a fixed interest rate of 4.00% and mature September 30, 2042.  Proceeds from the issuance were used to repay at maturity the $420 million debentures due through November 2012, as well as for general corporate purposes, including the funding of capital expenditures. 

In August 2012, Duke Energy Corporation issued $1.2 billion of senior unsecured notes, of which $700 million carry a fixed interest rate of 1.625% and mature August 15, 2017 and $500 million carry a fixed interest rate of 3.05% and mature August 15, 2022. Proceeds from the issuances were used to repay at maturity Duke Energy Ohio’s $500 million debentures due September 15, 2012 as well as for general corporate purposes, including the repayment of commercial paper. 

In April 2012, Duke Energy executed a joint venture agreement with Sumitomo Corporation of America (SCOA). Under the terms of the agreement, Duke Energy and SCOA each own a 50% interest in the joint venture (DS Cornerstone, LLC), which owns two wind generation projects. The facilities began commercial operations in June 2012 and August 2012. Duke Energy and SCOA also negotiated a $330 million, Construction and 12-year amortizing Term Loan Facility, on behalf of the borrower, a wholly owned subsidiary of the joint venture. The loan agreement is non-recourse to Duke Energy. Duke Energy received proceeds of $319 million upon execution of the loan agreement. This amount represents reimbursement of a significant portion of Duke Energy’s construction costs incurred as of the date of the agreement. See Note 18 to the Consolidated Financial Statements, “Variable Interest Entities” for further information.

In March 2012, Duke Energy Indiana issued $250 million principal amount of first mortgage bonds, which carry a fixed interest rate of 4.20% and mature March 15, 2042. Proceeds from the issuance were used to repay a portion of Duke Energy Indiana’s outstanding short-term debt.

In January 2012, Duke Energy Carolinas used proceeds from its December 2011 $1 billion issuance of principal amount of first mortgage bonds to repay $750 million 6.25% senior unsecured notes that matured January 15, 2012.

Significant Notes Payable and Long-Term Debt Activities — 2011.

In December 2011, Duke Energy Carolinas issued $1 billion principal amount of first mortgage bonds, of which $350 million carry a fixed interest rate of 1.75% and mature December 15, 2016 and $650 million carry a fixed interest rate of 4.25% and mature December 15, 2041. Proceeds from the issuances were used to repay $750 million 6.25% senior unsecured notes which matured January 15, 2012, with the remainder to fund capital expenditures and for general corporate purposes.

In November 2011, Duke Energy issued $500 million of senior unsecured notes, which carry a fixed interest rate of 2.15% and mature November 15, 2016. Proceeds from the issuance will be used to fund capital expenditures in Duke Energy’s unregulated businesses in the U.S. and for general corporate purposes.

In the third quarter of 2011, Duke Energy issued an additional $450 million in Commercial Paper. Proceeds from this issuance were used for general corporate purposes. In the fourth quarter of 2011, Duke Energy repaid $375 million of Commercial Paper with the proceeds from the August 2011 Duke Energy debt issuances discussed below.

In August 2011, Duke Energy issued $500 million principal amount of senior unsecured notes, which carry a fixed interest rate of 3.55% and mature September 15, 2021. Proceeds from the issuance were used to repay a portion of Duke Energy’s commercial paper, as discussed above, as it matures, to fund capital expenditures in Duke Energy’s unregulated businesses in the U.S. and for general corporate purposes.

In May 2011, Duke Energy Carolinas issued $500 million principal amount of first mortgage bonds, which carry a fixed interest rate of 3.90% and mature June 15, 2021. Proceeds from this issuance were used to fund capital expenditures and for general corporate purposes.

Significant Notes Payable and Long-Term Debt Activities — 2010.

In December 2010, Top of the World Wind Energy, LLC, a subsidiary of DEGS, an indirect wholly owned subsidiary of Duke Energy, entered into a long-term loan agreement for $193 million principal amount maturing in December 2028. The collateral for this loan is substantially all of the assets of Top of the World Windpower LLC. The initial interest rate on the notes is the six month adjusted LIBOR plus an applicable margin. In connection with this debt issuance, DEGS entered into an interest rate swap to convert the substantial majority of the loan interest payments from a variable rate to a fixed rate of 3.465% plus the applicable margin, which was 2.375% as of December 31, 2012. Proceeds from the issuance will be used to help fund the existing wind portfolio.

In September 2010, Duke Energy Carolinas converted $143 million of tax-exempt variable-rate demand bonds to tax-exempt term bonds, which carry a fixed interest rate of 4.375% and mature October 2031. Prior to the conversion, the bonds were held by Duke Energy Carolinas as treasury bonds. In connection with the conversion, the tax-exempt bonds were secured by a series of Duke Energy Carolinas’ first mortgage bonds.

In September 2010, Duke Energy Carolinas converted $100 million of tax-exempt variable-rate demand bonds, to tax-exempt term bonds, which carry a fixed interest rate of 4.625% and mature November 1, 2040. In connection with the conversion, the tax-exempt bonds were secured by a series of Duke Energy Carolinas’ first mortgage bonds.

In September 2010, Duke Energy Indiana refunded $70 million of tax-exempt auction rate bonds through the issuance of $70 million principal amount of tax-exempt term bonds, of which $60 million carry a fixed interest rate of 3.375% and mature March 1, 2019, and $10 million carry a fixed interest rate of 3.75% and mature April 1, 2022. In connection with the conversion, the tax-exempt bonds were secured by a series of Duke Energy Indiana’s first mortgage bonds.

In July 2010, Duke Energy Indiana issued $500 million principal amount of 3.75% first mortgage bonds due July 15, 2020. Proceeds from the issuance were used to repay $123 million of borrowings under the Master Credit Facility, to fund Duke Energy Indiana’s ongoing capital expenditures and for general corporate purposes.

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In July 2010, International Energy issued $281 million principal amount in Brazil, which carries an interest rate of 8.59% plus IGP-M (Brazil’s monthly inflation index) non-convertible debentures due July 2015. Proceeds of the issuance were used to refinance Brazil debt related to DEIGP and for future debt maturities in Brazil.

In June 2010, Duke Energy Carolinas issued $450 million principal amount of 4.30% first mortgage bonds due June 15, 2020. Proceeds from the issuance were used to fund Duke Energy Carolinas’ ongoing capital expenditures and for general corporate purposes.

In May 2010, Green Frontier Wind Power, LLC, a subsidiary of DEGS, an indirect wholly owned subsidiary of Duke Energy, entered into a long-term loan agreement for $325 million principal amount maturing in 2025. The collateral for this loan is a group of five wind farms located in Wyoming, Colorado and Pennsylvania. The initial interest rate on the notes is the six month adjusted LIBOR plus an applicable margin. In connection with this debt issuance, DEGS entered into an interest rate swap to convert the substantial majority of the loan interest payments from a variable rate to a fixed rate of approximately 3.4% plus the applicable margin, which was 2.5% as of December 30, 2012. Proceeds from the issuance were used to help fund the existing wind portfolio.

In March 2010, Duke Energy issued $450 million principal amount of 3.35% senior unsecured notes due April 1, 2015. Proceeds from the issuance were used to repay $274 million of borrowings under the master credit facility and for general corporate purposes.

Credit Facilities

Master Credit Facility Summary. In November 2011, Duke Energy entered into a $6 billion, 5-year master credit facility, expiring in November 2016, with $4 billion available at closing and the remaining $2 billion available following successful completion of the merger with Progress Energy. In October 2012, the Duke Energy Registrants reached an agreement with banks representing $5.63 billion of commitments under the master credit facility to extend the expiration date by one year to November 2017. Through November 2016, the available credit under this facility remains $6 billion. The Duke Energy Registrants each have borrowing capacity under the master credit facility up to specified sublimits for each borrower. However, Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimits of each borrower, subject to a maximum sublimit for each borrower. See the table below for the borrowing sublimits for each of the borrowers as of December 31, 2012. The amount available under the master credit facility is reduced by the use of the master credit facility to backstop the issuances of commercial paper, certain letters of credit and variable rate demand tax-exempt bonds that may be put to the Company at the option of the holder. Borrowing sublimits for the Subsidiary Registrants are also reduced for amounts outstanding under the money pool arrangement. The credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower.

(in millions)		Duke Energy (Parent)		Duke Energy Carolinas		Progress Energy Carolinas		Progress Energy Florida		Duke Energy Ohio		Duke Energy Indiana		Total
Facility Size(a)		$	1,750	$	1,250	$	750	$	750	$	750	$	750	$	6,000
	Notes Payable and Commercial Paper(b)		(195)		(300)		―		―		(104)		(201)		(800)
	Outstanding Letters of Credit		(50)		(7)		(2)		(1)		―		―		(60)
	Tax Exempt Bonds		―		(75)		―				(84)		(81)		(240)
Available Capacity		$	1,505	$	868	$	748	$	749	$	562	$	468	$	4,900
(a)	Represents the sublimit of each borrower at December 31, 2012. The Duke Energy Ohio sublimit includes $100 million for Duke Energy Kentucky.
(b)	Duke Energy issued $450 million of Commercial Paper and loaned the proceeds through the money pool to Duke Energy Carolinas and Duke Energy Indiana. The balances are classified as long-term borrowings within Long-term Debt in Duke Energy Carolina’s and Duke Energy Indiana’s Consolidated Balance Sheets.

In January 2012, Duke Energy Indiana and Duke Energy Kentucky collectively entered into a $156 million 2-year bilateral letter of credit agreement, under which Duke Energy Indiana and Duke Energy Kentucky may request the issuance of letters of credit up to $129 million and $27 million, respectively, on their behalf to support various series of variable-rate demand bonds. In addition, Duke Energy Indiana entered into a $78 million 2-year bilateral letter of credit facility. These credit facilities may not be used for any purpose other than to support the variable rate demand bonds issued by Duke Energy Indiana and Duke Energy Kentucky. In February 2012, letters of credit were issued corresponding to the amount of the facilities to support various series of tax-exempt bonds at Duke Energy Indiana and Duke Energy Kentucky. In February 2013, the letters of credit were amended to extend the expiration date to January 2015.

Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2012, Duke Energy was in compliance with all covenants related to its significant debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Ratings. Duke Energy and certain subsidiaries each hold credit ratings by Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s) and Standard & Poor’s (S&P). Duke Energy’s corporate credit rating and issuer credit rating from Fitch, Moody’s and S&P, respectively, as of February 13, 2013 is BBB+, Baa2 and BBB, respectively. As of February 13, 2013, the Duke Energy Registrants’ have a stable outlook rating from Fitch and Moody’s, with the exception of Progress Energy Florida, which has a negative outlook at Fitch. In addition, the Duke Energy Registrants have a negative outlook rating from S&P.

 The following table includes the Duke Energy Registrants’ Senior Unsecured Credit Ratings as of February 13, 2013.

	Standard and Poor's	Moody's Investor Service	Fitch
Duke Energy Corporation	BBB	Baa2	BBB+
Duke Energy Carolinas	BBB+	A3	A
Progress Energy	BBB	Baa2	BBB
Progress Energy Carolinas	BBB+	A3	A
Progress Energy Florida	BBB+	Baa1	A-
Duke Energy Ohio	BBB+	Baa1	A-
Duke Energy Indiana	BBB+	Baa1	A-
Duke Energy Kentucky	BBB+	Baa1	A-

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Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and pay dividends on its common stock, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted.

Credit-Related Clauses. Duke Energy may be required to repay certain debt should the credit ratings at Duke Energy Carolinas fall to a certain level at S&P or Moody’s. As of December 31, 2012, Duke Energy had $9 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s.

First Mortgage Bond Restrictions. The Subsidiary Registrants’ first mortgage bonds are secured under their respective mortgage indentures. Each mortgage constitutes a first lien on substantially all of the fixed properties of the respective company, subject to certain permitted encumbrances and exceptions. The lien of each mortgage also covers subsequently acquired property. Each mortgage allows the issuance of additional first mortgage bonds based on property additions, retirements of first mortgage bonds and the deposit of cash if certain conditions are satisfied. Most of the Subsidiary Registrants are required to pass a “net earnings” test in order to issue new first mortgage bonds, other than on the basis of retired bonds under certain circumstances. The test requires that the issuer’s adjusted net earnings, which is calculated based on results for 12 consecutive months within the prior 15 to 18 months, be at least twice the annual interest requirement for bonds currently outstanding and to be outstanding. Duke Energy Indiana’s and Progress Energy Florida’s ratios of net earnings to the annual interest requirement for bonds have at times in 2012 been below 2.0 times, due to various charges to operating expenses. As discussed in Note 4, Regulatory Matters, these charges and any future charges may impact future net earnings tests and affect the ability of Duke Energy Indiana and Progress Energy Florida to issue first mortgage bonds. In the event Duke Energy Indiana’s or Progress Energy Florida’s long-term debt requirements exceed its first mortgage bond capacity, Duke Energy Indiana or Progress Energy Florida can access alternative sources of capital, including, but not limited to issuing unsecured debt, borrowing under the money pool, entering into bilateral direct loan arrangements, and, if necessary, utilizing available capacity under the master credit facility. All other DEC registrants have earnings substantially in excess of the net earnings test requirement for issuing first mortgage bonds.

Other Financing Matters. The following table shows significant amounts presented as Current maturities of long-term debt on the Duke Energy Registrants respective Consolidated Balance Sheets as of December 31, 2012. The amounts were presented as Long-term debt as of December 31, 2011, except for the secured debt. The Duke Energy Registrants’ currently anticipates satisfying these obligations with proceeds from additional borrowings, unless otherwise noted.

(in millions)		Maturity Date	Interest Rate		December 31, 2012
Unsecured Debt:
Duke Energy (Parent)		June 2013	5.650	%	$	250
Duke Energy Indiana		September 2013	5.000	%		400
Secured Debt:
Duke Energy(a)		December 2013	3.796	%		423
Duke Energy (b)		June 2013	1.009	%		190
First Mortgage Bonds:
Duke Energy Carolinas		November 2013	5.750	%		400
Progress Energy Carolinas		September 2013	5.125	%		400
Progress Energy Florida		March 2013	4.800	%		425
Duke Energy Ohio		June 2013	2.100	%		250
Other						372
Current maturities of long-term debt					$	3,110
(a)	Represents a construction loan related to a renewable energy project that will be converted to a term loan once construction is complete.
(b)	Notes are fully offset with cash collateral, which is recorded in Other current assets in the Consolidated Balance Sheets as of December 31, 2012.

On November 13, 2012, Duke Energy filed a prospectus supplement to the September 2010 Form S-3 with the Securities and Exchange Commission (SEC), to sell up to $1 billion of fixed or variable rate unsecured senior notes, called InterNotes, due one year to 30 years from the date of issuance. The InterNotes will be issued in the retail markets as direct, unsecured and unsubordinated obligations of Duke Energy Corporation. The net proceeds from the sale of InterNotes will be used to fund capital expenditures in Duke Energy’s unregulated businesses and for general corporate purposes. The balance as of December 31, 2012 is $35 million, with maturities ranging from 10 to14 years. The notes reflect long-term debt obligations of Duke Energy and are reflected as Long-term debt on Duke Energy’s Consolidated Balance Sheets.

On March 1, 2012, Progress Energy, as a well-known seasoned issuer, Progress Energy Carolinas and Progress Energy Florida filed a combined shelf registration statement with the SEC, which became effective upon filing with the SEC. The registration statement is effective for three years and does not limit the amount or number of various securities that can be issued. On July 3, 2012, Progress Energy deregistered its equity securities from the registration statement in connection with the merger with Progress Energy, but retained its ability to issue senior debt securities and junior subordinated debentures under the registration statement. However, we do not expect Progress Energy to issue any new securities of these types in the

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future. Under Progress Energy Carolinas’ and Progress Energy Florida’s registration statements, they may issue various long-term debt securities and preferred stock.

On April 4, 2011, Duke Energy filed a registration statement (Form S-3) with the SEC to sell up to $1 billion (maximum of $500 million of notes outstanding at any particular time) of variable denomination floating rate demand notes, called PremierNotes. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Duke Energy PremierNotes Committee, or its designee, on a weekly basis. The interest rate payable on notes held by an investor may vary based on the principal amount of the investment. The notes have no stated maturity date, but may be redeemed in whole or in part by Duke Energy at any time. The notes are non-transferable and may be redeemed in whole or in part at the investor’s option. Proceeds from the sale of the notes will be used for general corporate purposes. The balance as of December 31, 2012 and December 31, 2011, is $395 million and $79 million, respectively. The notes reflect a short-term debt obligation of Duke Energy and are reflected as Notes Payable and Commercial Paper on Duke Energy’s Consolidated Balance Sheets.

In September 2010, Duke Energy filed a Form S-3 with the SEC. Under this Form S-3, which is uncapped, Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana may issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings. The registration statement also allows for the issuance of common stock by Duke Energy.

Duke Energy has paid quarterly cash dividends for 87 consecutive years and expects to continue its policy of paying regular cash dividends in the future. There is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, financial condition and are subject to the discretion of the Board of Directors.

Dividend and Other Funding Restrictions of Duke Energy Subsidiaries.As discussed in Note 4 to the Consolidated Financial Statements “Regulatory Matters”, Duke Energy’s wholly owned public utility operating companies have restrictions on the amount of funds that can be transferred to Duke Energy via dividend, advance or loan as a result of conditions imposed by various regulators in conjunction with Duke Energy’s mergers with Cinergy and Progress Energy. Progress Energy Carolinas and Progress Energy Florida also have restrictions imposed by their first mortgage bond indentures and Articles of Incorporation which, in certain circumstances, limited their ability to make cash dividends or distributions on common stock. Additionally, certain other Duke Energy subsidiaries have other restrictions, such as minimum working capital and tangible net worth requirements pursuant to debt and other agreements that limit the amount of funds that can be transferred to Duke Energy. At December 31, 2012, the amount of restricted net assets of wholly owned subsidiaries of Duke Energy that may not be distributed to Duke Energy in the form of a loan or dividend is $10.3 billion. However, Duke Energy does not have any legal or other restrictions on paying common stock dividends to shareholders out of its consolidated equity accounts. Although these restrictions cap the amount of funding the various operating subsidiaries can provide to Duke Energy, management does not believe these restrictions will have any significant impact on Duke Energy’s ability to access cash to meet its payment of dividends on common stock and other future funding obligations.

Off-Balance Sheet Arrangements

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.

Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy, either on its own or on behalf of Spectra Energy Capital, LLC (Spectra Capital) through indemnification agreements entered into as part of the spin-off of Spectra Energy Corp (Spectra Energy), having to honor its contingencies is largely dependent upon the future operations of the subsidiaries, investees and other third parties, or the occurrence of certain future events.

Duke Energy performs ongoing assessments of their respective guarantee obligations to determine whether any liabilities have been incurred as a result of potential increased non-performance risk by third parties for which Duke Energy has issued guarantees.

See Note 7 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.

Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantees, there would not be a material impact to the consolidated results of operations, cash flows or financial position.

Other than the guarantee arrangements discussed above and normal operating lease arrangements, Duke Energy does not have any material off-balance sheet financing entities or structures. For additional information on these commitments, see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Contractual Obligations

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations as of December 31, 2012.

		Payments Due By Period
(in millions)		Total		Less than 1 year (2013)		2-3 years (2014 & 2015)		4-5 years (2016 & 2017)			More than 5 years (2018 & beyond)
Long-term debt(a)		$	35,461	$	2,974	$	4,472	$	3,285	$	24,730
Interest payments on long-term debt(b)			23,031		1,671		2,922		2,585		15,853
Capital leases(c)			2,713		210		361		363		1,779
Operating leases(c)			1,682		171		295		235		981
Purchase obligations:(d)
	Fuel and purchased power(e)		24,860		5,011		6,871		3,319		9,659
	Other purchase obligations(f)		3,271		1,338		817		251		865
Uncertain tax positions(g)			-		-		-		-		-
Nuclear decommissioning trust annual funding(h)			1,712		92		183		183		1,254
Total contractual cash obligations(i)		$	92,730	$	11,467	$	15,921	$	10,221	$	55,121
(a)	See Note 6 to the Consolidated Financial Statements, “Debt and Credit Facilities.”
(b)	Interest payments on variable rate debt instruments were calculated using current interest rates and holding them constant for the life of the instruments.
(c)	See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies.” Amounts in the table above include the interest component of capital leases based on the interest rates stated in the lease agreements and exclude certain related executory costs.
(d)	Current liabilities, except for current maturities of long-term debt, and purchase obligations reflected in the Consolidated Balance Sheets, have been excluded from the above table.
(e)	Includes contractual obligations to purchase physical quantities of electricity, coal, nuclear fuel and limestone, including a total of $195 million for nuclear fuel contractual obligations related to Crystal River Unit 3. Also includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity and natural gas transportation contracts, as well as undesignated contracts and contracts that qualify as normal purchase/normal sale (NPNS). For contracts where the price paid is based on an index, the amount is based on market prices at December 31, 2012. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting arrangements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties.
(f)	Includes contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for new generation plants and nuclear plant refurbishments, environmental projects on fossil facilities, major maintenance of certain nonregulated plants, maintenance and day to day contract work at certain wind facilities and commitments to buy wind and combustion turbines (CT). Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase cannot be determined and Progress Energy Florida's engineering, procurement and construction agreement for Levy. See Note 5 to the Consolidated Financial Statements, "Commitments and Contingencies" for further discussion of the Levy engineering, procurement and construction agreement.
(g)	Uncertain tax positions of $540 million are not reflected in this table as Duke Energy cannot predict when open income tax years will close with completed examinations. See Note 24 to the Consolidated Financial Statements, "Income Taxes."
(h)	Related to future annual funding obligations to nuclear decommissioning trust fund (NDTF) through nuclear power stations' re-licensing dates. Amounts through 2017 include $13 million per year for North Carolina jurisdictional amounts that Progress Energy Carolinas retained internally and is transitioning to its external decommissioning funds per a 2008 NCUC order. The transition of the original $131 million must be complete by December 31, 2017, and at least 10 percent must be transitioned each year. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations."
(i)	The table above excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing of when cash payments will be required. Additionally, the table above excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of pension and other post-retirement benefit plans (see Note 23 to the Consolidated Financial Statements, "Employee Benefit Plans"), asset retirement obligations (see Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations") and regulatory liabilities (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also excluded are Deferred Income Taxes and Investment Tax Credits recorded on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management Policies.The Duke Energy Registrants are exposed to market risks associated with commodity prices, credit quality, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Finance and Risk Management Committee of the Board of Directors receives periodic updates from the Chief Risk Officer and other members of management on market risk positions, corporate exposures, credit exposures and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.

The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review Item 1A, “Risk Factors,” and “Safe Harbor for Forward-Looking Statements” for a discussion of the factors that may impact any such forward-looking statements made herein.

The risks discussed below do not include the price risks associated with nonfinancial instrument transactions and positions associated with the Duke Energy Registrants’ operations, such as purchase and sales commitments and inventory.

Commodity Price Risk

The Duke Energy Registrants are exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy related assets. The Duke Energy Registrants’ exposure to these fluctuations is limited by the cost-based regulation of its U.S. Franchised Electric and Gas operations as these regulated operations are typically allowed to recover substantially all of these costs through various cost-recovery clauses, including fuel clauses. While there may be a delay in timing between when these costs are incurred and when these costs are recovered through rates, changes from year to year generally do not have a material impact on operating results of these regulated operations. At December 31, 2012, substantially all derivative commodity instrument positions were subject to regulatory accounting treatment.

Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. The Duke Energy Registrants’ exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The Duke Energy Registrants employ established policies and procedures to manage the risks associated with these market fluctuations, which may include using various commodity derivatives, such as swaps, futures, forwards and options. For additional information, see Note15  to the Consolidated Financial Statements, “Risk Management, Derivative Instruments and Hedging Activities.”

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Validation of a contract’s fair value is performed by an internal group separate from the Duke Energy Registrants’ deal origination areas. While the Duke Energy Registrants use common industry practices to develop their valuation techniques, changes in their pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

Hedging Strategies.  The Duke Energy Registrants closely monitor the risks associated with commodity price changes on their future operations and, where appropriate, use various commodity instruments such as electricity, coal and natural gas forward contracts to mitigate the effect of such fluctuations on operations, in addition to optimizing the value of the non-regulated generation portfolio. Duke Energy’s primary use of energy commodity derivatives is to hedge the generation portfolio against exposure to the prices of power and fuel.

The majority of instruments used to manage the Duke Energy Registrants’ commodity price exposure are either not designated as a hedge or do not qualify for hedge accounting. These instruments are referred to as undesignated contracts. Mark-to-market changes for undesignated contracts entered into by regulated businesses are reflected as regulatory assets or liabilities on the Consolidated Balance Sheets. Undesignated contracts entered into by unregulated businesses are marked-to-market each period, with changes in the fair value of the derivative instruments reflected in earnings.

Certain derivatives used to manage the Duke Energy Registrants’ commodity price exposure are accounted for as either cash flow hedges or fair value hedges. To the extent that instruments accounted for as hedges are effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations until after delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement to the extent they are effective. Several factors influence the effectiveness of a hedge contract, including the use of contracts with different commodities or unmatched terms and counterparty credit risk. Hedge effectiveness is monitored regularly and measured at least quarterly.

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, the Duke Energy Registrants enter into other contracts that qualify for the NPNS exception. When a contract meets the criteria to qualify as an NPNS, the Duke Energy registrants apply such exception. Income recognition and realization related to NPNS contracts generally coincide with the physical delivery of power. For contracts qualifying for the NPNS exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract as long as the transaction remains probable of occurring.

Generation Portfolio Risks.  The Duke Energy Registrants are primarily exposed to market price fluctuations of wholesale power, natural gas, and coal prices in the U.S. Franchised Electric and Gas and Commercial Power segments. The Duke Energy Registrants optimize the value of theirwholesale and non-regulated generation portfolios. The portfolios include generation assets (power and capacity), fuel, and emission allowances. Modeled forecasts of future generation output, fuel requirements, and emission allowance requirements are based on forward power, fuel and emission allowance markets. The component pieces of the portfolio are bought and sold based on models and forecasts of generation in order to manage the economic value of the portfolio in accordance with the strategies of the business units. For Duke Energy Carolinas and Duke Energy Indiana, as well as the Kentucky regulated generation owned by Duke Energy Ohio, the generation portfolio not utilized to serve retail operations or committed load is subject to commodity price fluctuations, although the impact on the Consolidated Statements of Operations is partially offset by mechanisms in these regulated jurisdictions that result in the sharing of net profits from these activities with retail customers. Duke Energy Ohio is subject to wholesale commodity price risks for its non-regulated generation portfolio. The non-regulated generation portfolio dispatches all of their electricity into unregulated markets and receives wholesale energy margins and capacity revenues from PJM. Duke Energy Ohio has fully hedged its forecasted coal-fired generation for 2013. Capacity revenues are 100% contracted in PJM through May2015. International Energy generally hedges its expected generation using long-term bilateral power sales contracts when favorable market conditions exist and it is subject to wholesale commodity price risks for electricity not sold under such contracts. International Energy dispatches electricity not sold under long-term bilateral contracts into unregulated markets and receives wholesale energy margins and capacity revenues fromnational system operators. Derivative contracts executed to manage generation portfolio risks for delivery periods beyond 2013 are alsoexposed to changes in fair value due to market price fluctuations ofwholesale power, fuel oil  and coal. See “Sensitivity Analysis for Generation Portfolio and Derivative Price Risks” below, for more information regarding the effect of changes in commodity prices on the Duke Energy Registrants’ net income.

Other Commodity Risks.  At December 31, 2012, pre-tax income in 2013  was not expected to be materially impacted for exposures to other commodities’ price changes.

Sensitivity Analysis for Generation Portfolio and Derivative Price Risks.  The table below summarizes the estimated effect of commodity price changes on the Duke Energy Registrants’ pre-tax net income, based on a sensitivity analysis performed as of December 31, 2012 and December 31, 2011 for Duke Energy and Duke Energy Ohio. Forecasted exposure to commodity price risk for Duke Energy Carolinas, Progress Energy Carolinas, Progress Energy Florida and Duke Energy Indiana is not anticipated to have a material adverse effect on their consolidated results of operations in 2013, based on a sensitivity analysis performed as of December 31, 2012. The sensitivity analysis performed as of December 31, 2011 related to forecasted exposure to commodity price risk during 2012 also indicated that commodity price risk would not have a material adverse effect on the consolidated results of operations of Duke Energy Carolinas, Progress Energy Carolinas, Progress Energy Florida and Duke Energy Indiana during 2012 and the impacts of changing commodity prices in their consolidated results of operations for 2012 was insignificant. The following commodity price sensitivity calculations consider existing hedge positions and estimated production levels, as indicated in the table below, but do not consider other potential effects that might result from such changes in commodity prices.

Summary of Sensitivity Analysis for Generation Portfolio and Derivative Price Risks
		Generation Portfolio Risks for 2013(a)				Sensitivities for Derivatives Beyond 2013(b)
		As of December 31,				As of December 31,
(in millions)			2012		2011		2012		2011
Potential effect on pre-tax net income assuming a 10% price change in:
Duke Energy
Forward wholesale power prices (per MWh)		$	34	$	71	$	103	$	24
Forward coal prices (per ton)			11		2		-		-
Gas prices (per MMBtu)			21		42		-		-
Duke Energy Ohio
Forward wholesale power prices (per MWh)		$	32	$	69	$	103	$	24
Forward coal prices (per ton)			11		2		-		-
Gas prices (per MMBtu)			21		42		-		-
(a)	Amounts related to forward wholesale prices represent the potential impact of commodity price changes on forecasted economic generation which has not been contracted or hedged. Amounts related to forward coal prices and forward gas prices represent the potential impact of commodity price changes on fuel needed to achieve such economic generation. Amounts exclude the impact of mark-to-market changes on undesignated contracts relating to periods in excess of one year from the respective date.
(b)	Amounts represent sensitivities related to derivative contracts executed to manage generation portfolio risks for periods beyond 2013. Amounts exclude the potential impact of commodity price changes on forecasted economic generation and fuel needed to achieve such forecasted generation.

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Credit Risk

Credit risk represents the loss that the Duke Energy Registrants would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, the Duke Energy Registrants seek to enter into netting agreements with counterparties that permit them to offset receivables and payables with such counterparties. The Duke Energy Registrants attempt to further reduce credit risk with certain counterparties by entering into agreements that enable obtaining collateral or terminating or resetting the terms of transactions after specified time periods or upon the occurrence of credit-related events. The Duke Energy Registrants may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of their counterparties’ obligations. The Duke Energy Registrants also obtain cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on a financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction. See Note 15 to the Consolidated Financial Statements, “Risk Management, Derivative Instruments and Hedging Activities,” for additional information regarding credit risk related to derivative instruments.

The Duke Energy Registrants’ industry has historically operated under negotiated credit lines for physical delivery contracts. The Duke Energy Registrants frequently use master collateral agreements to mitigate certain credit exposures. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents a negotiated unsecured credit limit for each party to the agreement, determined in accordance with the Duke Energy Registrants’ internal corporate credit practices and standards. Collateral agreements generally also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

The Duke Energy Registrants’ principal customers for its electric and gas businesses are commodity clearinghouses, regional transmission organizations, industrial, commercial and residential end-users, marketers, distribution companies, municipalities, electric cooperatives and utilities located throughout the U.S. and Latin America. The Duke Energy Registrants have concentrations of receivables from such entities throughout these regions. These concentrations of customers may affect the Duke Energy Registrants’ overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Duke Energy Registrants analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis.

Duke Energy Carolinas has a third-party insurance policy to cover certain losses related to its 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 the third party insurance carrier. The insurance policy limit for potential future insurance recoveries for indemnification and medical cost claim payments is $935 million in excess of the self insured retention. Insurance recoveries of $781 million and $813 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, 2012 and 2011, respectively. Duke Energy Carolinas 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.

The Duke Energy Registrants also have credit risk exposure through issuance of performance guarantees, letters of credit and surety bonds on behalf of less than wholly owned entities and third parties. Where the Duke Energy Registrants have issued these guarantees, it is possible that they could be required to perform under these guarantee obligations in the event the obligor under the guarantee fails to perform. Where the Duke Energy Registrants have issued guarantees related to assets or operations that have been disposed of via sale, they attempt to secure indemnification from the buyer against all future performance obligations under the guarantees. See Note 7 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further information on guarantees issued by the Duke Energy Registrants.

The Duke Energy Registrants are also subject to credit risk of their vendors and suppliers in the form of performance risk on contracts including, but not limited to, outsourcing arrangements, major construction projects and commodity purchases. The Duke Energy Registrants’ credit exposure to such vendors and suppliers may take the form of increased costs or project delays in the event of non-performance.

Credit risk associated with the Duke Energy Registrants’ service to residential, commercial and industrial customers is generally limited to outstanding accounts receivable. The Duke Energy Registrants mitigate this credit risk by requiring customers to provide a cash deposit or letter of credit until a satisfactory payment history is established, subject to the rules and regulations in effect in each retail jurisdiction, at which time the deposit is typically refunded. Charge-offs for retail customers have historically been insignificant to the operations of the Duke Energy Registrants and are typically recovered through the retail rates. Management continually monitors customer charge-offs and payment patterns to ensure the adequacy of bad debt reserves. Duke Energy Ohio and Duke Energy Indiana sell certain of their accounts receivable and related collections through CRC, a Duke Energy consolidated variable interest entity. Losses on collection are first absorbed by the equity of CRC and next by the subordinated retained interests held by Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana. See Note 18 to the Consolidated Financial Statements, “Variable Interest Entities.”

Based on the Duke Energy Registrants’ policies for managing credit risk, their exposures and their credit and other reserves, the Duke Energy Registrants do not currently anticipate a materially adverse effect on their consolidated financial position or results of operations as a result of non-performance by any counterparty.

European Exposures.  At December 31, 2012, Duke Energy held $62 million of money market funds and short term investments in investment-grade debt securities issued by financial and nonfinancial institutions that are domiciled in Europe or have exposures to European sovereign debt. This amount is recorded at fair value and included in Cash and cash equivalents and Short-term investment in the Consolidated Balance Sheets. A disorderly default by or withdrawal of a member nation from the euro zone and financial stress in other European countries could require Duke Energy to recognize an impairment of some or all of these securities.

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Interest Rate Risk

The Duke Energy Registrants are exposed to risk resulting from changes in interest rates as a result of their issuance of variable and fixed rate debt and commercial paper. The Duke Energy Registrants manage interest rate exposure by limiting variable-rate exposures to a percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Duke Energy Registrants also enter into financial derivative instruments, which may include instruments such as, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. See Notes 1, 6, 15, and 16 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Debt and Credit Facilities,” “Risk Management, Derivative Instruments and Hedging Activities,” and “Fair Value of Financial Assets and Liabilities.”

The table below summarizes the potential effect of interest rate changes on the Duke Energy Registrants’ pre-tax net income, based on a sensitivity analysis performed as of December 31, 2012 and December 31, 2011.

Summary of Sensitivity Analysis for Interest Rate Risks
		Assuming Market Interest Rates Average 1% Higher (+) or Lower (-) in 2013 than 2012.			Assuming Market Interest Rates Average 1% Higher (+) or Lower (-) in 2012 than 2011.
(in millions)		As of December 31, 2012			As of December 31, 2011
Potential increase (+) or decrease (-) in interest expense:(a)
Duke Energy		+/-	$	32	+/-	$	7
Duke Energy Carolinas		+/-	$	3	+/-	$	5
Progress Energy		+/-	$	19	+/-	$	20
Progress Energy Carolinas		+/-	$	15	+/-	$	13
Progress Energy Florida		+/-	$	2	+/-	$	7
Duke Energy Ohio		+/-	$	13	+/-	$	8
Duke Energy Indiana		+/-	$	7	+/-	$	8
(a)	Amounts presented net of offsetting impacts in interest income.

These amounts were estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, short-term and long-term investments, cash and cash equivalents outstanding as of December 31, 2012 and 2011. The change in interest rate sensitivity for the Duke Energy Registrants’ is primarily due to changes in short-term debt balances and cash balances. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in the Duke Energy Registrants’ financial structure.

Marketable Securities Price Risk

As described further in Note 17 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” Duke Energy invests in debt and equity securities as part of various investment portfolios to fund certain obligations of the business. The vast majority of the investments in equity securities are within the NDTF and assets of the various pension and other post-retirement benefit plans.

Pension Plan Assets. Duke Energy and Progress Energy maintain investments to help fund the costs of providing non-contributory defined benefit retirement and other post-retirement benefit plans. These investments are exposed to price fluctuations in equity markets and changes in interest rates. The equity securities held in these pension plans are diversified to achieve broad market participation and reduce the impact of any single investment, sector or geographic region. Duke Energy and Progress Energy have established asset allocation targets for their pension plan holdings, which take into consideration the investment objectives and the risk profile with respect to the trust in which the assets are held. These target allocations are presented in the table below.

Asset	Target Allocation %
Equity securities	56	%
Debt securities	32	%
Other	12	%

A significant decline in the value of plan asset holdings could require Duke Energy to increase funding of its pension plans in future periods, which could adversely affect cash flows of the Duke Energy Registrants in those periods. Additionally, a decline in the fair value of plan assets, absent additional cash contributions to the plan, could increase the amount of pension cost required to be recorded in future periods, which could adversely affect the Duke Energy Registrants’ results of operations in those periods. Contributions to qualified pension plans during 2012 are presented in the table below.

Schedule of Qualified Pension Plan Contributions
	Year Ended
	December 31, 2012
Duke Energy	$	304
Progress Energy	$	346
Progress Energy Carolinas	$	141
Progress Energy Florida	$	128

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Duke Energy intends to contribute $350 million to its qualified pension plan in 2013. See Note 23 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information on pension plan assets.

NDTF.As required by the NRC, NCUC, PSCSC and the FPSC, Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida maintain trust funds to fund the costs of nuclear decommissioning. As of December 31, 2012, these funds were invested primarily in domestic and international equity securities, debt securities, fixed-income securities, cash and cash equivalents and short-term investments. Per the NRC, NCUC, PSCSC and FPSC requirements, these funds may be used only for activities related to nuclear decommissioning. The investments in equity securities are exposed to price fluctuations in equity markets. The Duke Energy Registrants actively monitor their portfolios by benchmarking the performance of their investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. Accounting for nuclear decommissioning recognizes that costs are recovered through Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s rates; therefore, fluctuations in equity prices do not affect their Consolidated Statements of Operations as changes in the fair value of these investments are deferred as regulatory assets or regulatory liabilities pursuant to an Order by the NCUC, PSCSC and FPSC. Earnings or losses of the fund will ultimately impact the amount of costs recovered through Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s rates. See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations” for additional information regarding nuclear decommissioning costs. See Note 17 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities” for additional information regarding NTDF assets.

Foreign Currency Risk

Duke Energy is exposed to foreign currency risk from investments in international businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations that are denominated in foreign currencies. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. Dollar/inflation rates and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

In 2012, Duke Energy’s primary foreign currency rate exposure was to the Brazilian Real. The table below summarizes the potential effect of foreign currency devaluations on Duke Energy’s Consolidated Statement of Operations and Consolidated Balance Sheets, based on a sensitivity analysis performed as of December 31, 2012 and December 31, 2011.

Summary of Sensitivity Analysis for Foreign Currency Risks
		Assuming 10% devaluation in the currency exchange rates in all exposure currencies
(in millions)		As of December 31, 2012		As of December 31, 2011
Income Statement impact(a)		$	(20)	$	(20)
Balance Sheet impact(b)		$	(150)	$	(160)
(a)	Amounts represent the potential annual net pre-tax loss on the translation of local currency earnings to the Consolidated Statement of Operations in 2012 and 2011, respectively.
(b)	Amounts represent the potential impact to the currency translation through the cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets

OTHER ISSUES

Fixed Charges Coverage Ratios

The Duke Energy Registrants’ fixed charges coverage ratios, as calculated using SEC guidelines, are included in the table below.

		Years Ended December 31,
		2012		2011	2010
Duke Energy		2.5	(a)	3.2	3.0
Duke Energy Carolinas		3.7		3.7	3.6
Progress Energy		1.6		2.1	2.6
Progress Energy Carolinas		2.2		4.2	5.1
Progress Energy Florida		2.3		2.8	3.4
Duke Energy Ohio		3.4		3.4	(b)
Duke Energy Indiana		0.1		2.2	3.6
(a)	Includes the results of Progress Energy, Inc. beginning on July 2, 2012.
(b)	Duke Energy Ohio's earnings were insufficient to cover fixed charges by $317 million in 2010 due primarily to non-cash goodwill and other asset impairment charges of $677 million in 2010.

Global Climate Change

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The EPA publishes an inventory of man-made U.S. greenhouse gas (GHG) emissions annually. In 2010, the most recent year reported, carbon dioxide (CO₂), a byproduct of all sources of combustion, accounted for approximately 84 percent of total U.S. GHG emissions. The Duke Energy Registrants’ GHG emissions consist primarily of CO₂ and most come from its fleet of coal-fired power plants in the U.S. In 2012, the Duke Energy Registrants’ U.S. power plants emitted approximately 132 million tons of CO2. The CO2 emissions from Duke Energy’s international electric operations were approximately 3 million tons. The Duke Energy Registrants’ future CO2 emissions will be influenced by variables including new regulations, economic conditions that affect electricity demand, and the Duke Energy Registrants’ decisions regarding generation technologies deployed to meet customer electricity needs.

The Duke Energy Registrants believe it is unlikely that legislation mandating reductions in GHG emissions or establishing a carbon tax will be passed by the 113th Congress which began on January 3, 2013. Beyond 2014 the prospects for enactment of any federal legislation mandating reductions in GHG emissions or establishing a carbon tax is highly uncertain. Given the high degree of uncertainty surrounding potential future federal GHG legislation, management cannot predict if or when such legislation might be enacted, what the requirements of any potential legislation might be, or the potential impact it might have on the Duke Energy Registrants. Among the outcomes of the 18th Conference of the Parties of the United Nations Framework Convention on Climate Change which concluded in December 2012 was an affirmation by the participating countries to complete negotiations on a new global agreement by 2015 that would take effect in 2020. The international climate change negotiating process is highly uncertain and management cannot predict what the outcome might be or the potential impact it might have on the Duke Energy Registrants.

      The Duke Energy Registrants do not anticipate any of the states in which it currently operates fossil-fueled electric generating units taking action absent a federal requirement to mandate reductions in GHG emissions from these facilities.

The Duke Energy Registrants are taking actions today that will result in reduced GHG emissions over time. These actions will lower the Duke Energy Registrants’ exposure to any future mandatory GHG emission reduction requirements or carbon tax, whether a result of federal legislation or EPA regulation. Under any future scenario involving mandatory GHG limitations, the Duke Energy Registrants would plan to seek recovery of their compliance costs through appropriate regulatory mechanisms.

The Duke Energy Registrants recognize that certain groups associate severe weather events with climate change, and forecast the possibility that these weather events could have a material impact on future results of operations should they occur more frequently and with greater severity. However, the uncertain nature of potential changes of extreme weather events (such as increased frequency, duration, and severity), the long period of time over which any potential changes might take place, and the inability to predict these with any degree of accuracy, make estimating any potential future financial risk to the Duke Energy Registrants’ operations that may result from the physical risks of potential changes in the frequency and/or severity of extreme weather events, whatever the cause or causes might be, impossible. Currently, the Duke Energy Registrants plan and prepare for extreme weather events that it experiences from time to time, such as ice storms, tornados, hurricanes, severe thunderstorms, high winds and droughts.

The Duke Energy Registrants’ past experiences preparing for and responding to the impacts of these types of weather-related events would reasonably be expected to help management plan and prepare for future severe weather events to reduce, but not eliminate, the operational, economic and financial impacts of such events. For example, the Duke Energy Registrants routinely take steps to reduce the potential impact of severe weather events on its electric distribution systems. The Duke Energy Registrants’ electric generating facilities are designed to withstand extreme weather events without significant damage. The Duke Energy Registrants maintain an inventory of coal and oil on site to mitigate the effects of any potential short-term disruption in its fuel supply so it can continue to provide its customers with an uninterrupted supply of electricity. The Duke Energy Registrants have a program in place to effectively manage the impact of future droughts on its operations.

Other EPA Regulations Recently Published and Under Development

The EPA has issued and is in various stages of developing several non-greenhouse gas (non-GHG) environmental regulations that will affect the Duke Energy Registrants. These include the final Mercury and Air Toxics Standards (MATS) for hazardous air pollutants, which is effective beginning in 2015, as well as proposed regulations for cooling water intake structures under the Clean Water Act 316(b) and proposed regulations for coal combustion residuals. As a group, these non-GHG environmental regulations will require the Duke Energy Registrants to install additional environmental controls and accelerate retirement of some coal-fired units. While the ultimate regulatory requirements for the Duke Energy Registrants from the group of EPA regulatory actions will not be known until all the rules have been finalized, for planning purposes, the Duke Energy Registrants currently estimate the cost of new control equipment that may need to be installed to comply with this group of rules could total $5 billion to $6 billion, excluding AFUDC, over the next 10 years. This range includes estimated costs for new control equipment necessary to comply with the MATS of $650 million to $800 million. The Duke Energy Registrants also expect to incur increased fuel, purchased power, operation and maintenance, and other expenses in conjunction with the non-GHG EPA regulations. In addition to the plant retirements associated with new generation the Duke Energy Registrants are constructing, the Duke Energy Registrants are planning to retire additional coal fired generating capacity that is not economic to bring into compliance with the EPA’s regulations. Beyond 2012, total planned and potential retirements could exceed 3,900 MW of coal-fired generating capacity. The Duke Energy Registrants would also expect to incur costs for replacement generation as a result of the potential coal-fired power plant retirements. Until the final regulatory requirements of the group of EPA regulations are known and can be fully evaluated, the potential compliance costs associated with these EPA regulatory actions are subject to considerable uncertainty. Therefore, the actual compliance costs incurred and MW to be retired may be materially different from these estimates based on the timing and requirements of the final EPA regulations.

For additional information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Nuclear Matters

Following the events at the Fukushima Daiichi nuclear power station in Japan, Duke Energy conducted thorough inspections at each of its four nuclear sites during 2011. Progress Energy also conducted inspections in 2011 at each of its three sites. The initial inspections have not identified any significant vulnerabilities, however, Duke Energy is reviewing designs to evaluate safety margins to external events. Emergency-response capabilities, written procedures and engineering specifications were reviewed to verify each site’s ability to respond in the unlikely event of station blackout. Duke Energy is working within the nuclear industry to improve the safety standards and margin using the three layers of safety approach used in the U.S.: protection, mitigation and emergency response. Emergency equipment is currently being added at each station to perform key safety functions in the event that backup power sources are lost permanently. These improvements are in addition to the numerous layers of safety measures and systems previously in place.

In March 2011, the NRC formed a task force to conduct a comprehensive review of processes and regulations to determine whether the agency should make additional improvements to the nuclear regulatory system. On July 13, 2011, the task force proposed a set of improvements designed to ensure protection, enhance accident mitigation, strengthen emergency preparedness and improve efficiency of NRC programs. The recommendations

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were further prioritized into three tiers based on the safety enhancement level. On March 12, 2012, the NRC issued three regulatory orders requiring safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at a plant, ensuring reliable hardened containment vents and enhancing spent fuel pool instrumentation.

In May 2012, the NRC endorsed guidance on re-evaluating emergency communications systems and staffing levels and performing seismic and flooding walkdowns. On July 13, 2012, the NRC outlined plans for implementing Tier 2 and Tier 3 recommendations. On August 30, 2012, the NRC issued implementation guidance to enable power plants to achieve compliance with the orders issued in March 2012. Plants are then required to submit implementation plans to the NRC by February 28, 2013, and complete implementation of the safety enhancements within two refueling outages or by December 31, 2016, whichever comes first. Each plant is also required to reassess their seismic and flooding hazards using present-day methods and information, conduct inspections to ensure protection against hazards in the current design basis, and re-evaluate emergency communications systems and staffing levels.

Duke Energy is committed to compliance with all safety enhancements ordered by the NRC in connection with the March 12, 2012, regulatory orders noted above, the cost of which could be material. Until such time as the NRC mandated reassessment of flooding and seismic hazards is complete the exact scope and cost of compliance modifications to our sites will not be known. With the NRC’s continuing review of the remaining recommendations, Duke Energy cannot predict to what extent the NRC will impose additional licensing and safety-related requirements, or the costs of complying with such requirements. The tight time frame required to complete the necessary safety enhancements by no later than 2016 could lead to even higher costs. Upon receipt of additional guidance from the NRC and a collaborative industry review, Duke Energy will be able to determine an implementation plan and associated costs. See Item 1A, “Risk Factors,” for further discussion of applicable risk factors.

New Accounting Standards

See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” for a discussion of the impact of new accounting standards.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Duke Energy Corporation (Duke Energy)
Report of Independent Registered Public Accounting Firm............................................................	83
Consolidated Statements of Operations........................................................................................	84
Consolidated Statements of Comprehensive Income.....................................................................	85
Consolidated Balance Sheets........................................................................................................	86
Consolidated Statements of Cash Flows.......................................................................................	87
Consolidated Statements of Equity................................................................................................	88
Duke Energy Carolinas, LLC (Duke Energy Carolinas)
Report of Independent Registered Public Accounting Firm............................................................	89
Consolidated Statements of Operations and Comprehensive Income...........................................	90
Consolidated Balance Sheets........................................................................................................	91
Consolidated Statements of Cash Flows.......................................................................................	92
Consolidated Statements of Member’s Equity................................................................................	93
Progress Energy, Inc. (Progress Energy)
Report of Independent Registered Public Accounting Firm............................................................	94
Consolidated Statements of Operations and Comprehensive Income...........................................	95
Consolidated Balance Sheets........................................................................................................	96
Consolidated Statements of Cash Flows.......................................................................................	97
Consolidated Statements of Common Stockholder’s Equity...........................................................	98
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (Progress Energy Carolinas)
Report of Independent Registered Public Accounting Firm............................................................	99
Consolidated Statements of Operations and Comprehensive Income...........................................	100
Consolidated Balance Sheets........................................................................................................	101
Consolidated Statements of Cash Flows.......................................................................................	102
Consolidated Statements of Common Stockholder’s Equity...........................................................	103
Florida Power Corporation d/b/a Progress Energy Florida, Inc. (Progress Energy Florida)
Report of Independent Registered Public Accounting Firm............................................................	104
Statements of Operations and Comprehensive Income.................................................................	105
Balance Sheets..............................................................................................................................	106
Statements of Cash Flows............................................................................................................	107
Statements of Common Stockholder’s Equity.................................................................................	108
Duke Energy Ohio, Inc. (Duke Energy Ohio)
Report of Independent Registered Public Accounting Firm............................................................	109
Consolidated Statements of Operations and Comprehensive Income...........................................	110
Consolidated Balance Sheets........................................................................................................	111
Consolidated Statements of Cash Flows.......................................................................................	112
Consolidated Statements of Common Stockholder’s Equity...........................................................	113
Duke Energy Indiana, Inc. (Duke Energy Indiana)
Report of Independent Registered Public Accounting Firm............................................................	114
Consolidated Statements of Operations and Comprehensive Income...........................................	115
Consolidated Balance Sheets........................................................................................................	116
Consolidated Statements of Cash Flows.......................................................................................	117
Consolidated Statements of Common Stockholder’s Equity...........................................................	118
Combined Notes to Consolidated Financial Statements
Note 1 – Summary of Significant Accounting Policies...................................................................	119
Note 2 – Acquisitions and Dispositions of Businesses and Sales of Other Assets.....................	130
Note 3 – Business Segments.........................................................................................................	135
Note 4 – Regulatory Matters..........................................................................................................	140
Note 5 – Commitments and Contingencies.....................................................................................	153
Note 6 – Debt and Credit Facilities.................................................................................................	164
Note 7 – Guarantees and Indemnifications....................................................................................	170
Note 8 – Joint Ownership of Generating and Transmission Facilities...........................................	171
Note 9 – Asset Retirement Obligations..........................................................................................	172
Note 10 – Property, Plant and Equipment.......................................................................................	175
Note 11 – Other Income and Expenses, Net..................................................................................	176
Note 12 – Goodwill, Intangible Assets and Impairments................................................................	177
Note 13 – Investments in Unconsolidated Affiliates.......................................................................	180
Note 14 – Related Party Transactions...........................................................................................	182
Note 15 – Risk Management, Derivative Instruments and Hedging Activities................................	183
Note 16 – Fair Value of Financial Instruments...............................................................................	195
Note 17 – Investments in Debt and Equity Securities.....................................................................	207
Note 18 – Variable Interest Entities................................................................................................	216
Note 19 – Earnings Per Common Share.........................................................................................	220
Note 20 – Preferred Stock of Subsidiaries....................................................................................	221
Note 21 – Severance.....................................................................................................................	222
Note 22 – Stock-Based Compensation..........................................................................................	223
Note 23 – Employee Benefit Plans.................................................................................................	226
Note 24 – Income Taxes................................................................................................................	246
Note 25 – Condensed Consolidating Statements...........................................................................	252
Note 26 – Subsequent Events.......................................................................................................	261
Note 27 – Quarterly Financial Data (Unaudited).............................................................................	261

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Duke Energy Corporation

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company's internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report On Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Duke Energy Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

February 28, 2013

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DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
			Years Ended December 31,
(in millions, except per-share amounts)				2012		2011		2010
Operating Revenues
	Regulated electric		$	15,621	$	10,589	$	10,723
	Non-regulated electric, natural gas, and other			3,534		3,383		2,930
	Regulated natural gas			469		557		619
	Total operating revenues			19,624		14,529		14,272
Operating Expenses
	Fuel used in electric generation and purchased power - regulated			5,582		3,309		3,345
	Fuel used in electric generation and purchased power - non-regulated			1,722		1,488		1,199
	Cost of natural gas and coal sold			264		348		381
	Operation, maintenance and other			5,006		3,770		3,825
	Depreciation and amortization			2,289		1,806		1,786
	Property and other taxes			985		704		702
	Goodwill and other impairment charges			666		335		726
		Total operating expenses		16,514		11,760		11,964
Gains on Sales of Other Assets and Other, net				16		8		153
Operating Income				3,126		2,777		2,461
Other Income and Expenses
	Equity in earnings of unconsolidated affiliates			148		160		116
	Impairments and gains on sales of unconsolidated affiliates			22		11		103
	Other income and expenses, net			397		376		370
		Total other income and expenses		567		547		589
Interest Expense				1,242		859		840
Income From Continuing Operations Before Income Taxes				2,451		2,465		2,210
Income Tax Expense from Continuing Operations				705		752		890
Income From Continuing Operations				1,746		1,713		1,320
Income From Discontinued Operations, net of tax				36		1		3
Net Income				1,782		1,714		1,323
Less: Net Income Attributable to Noncontrolling Interests				14		8		3
Net Income Attributable to Duke Energy Corporation			$	1,768	$	1,706	$	1,320
Earnings Per Share - Basic and Diluted
	Income from continuing operations attributable to Duke Energy Corporation common shareholders
		Basic	$	3.01	$	3.83	$	2.99
		Diluted	$	3.01	$	3.83	$	2.99
	Income from discontinued operations attributable to Duke Energy Corporation common shareholders
		Basic	$	0.06	$	―	$	0.01
		Diluted	$	0.06	$	―	$	0.01
	Net Income attributable to Duke Energy Corporation common shareholders
		Basic	$	3.07	$	3.83	$	3.00
		Diluted	$	3.07	$	3.83	$	3.00
	Dividends declared per share		$	3.03	$	2.97	$	2.91
	Weighted-average shares outstanding
		Basic		574		444		439
		Diluted		575		444		440

82

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DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
		Years Ended December 31,
(in millions)		2012		2011		2010
Net Income		$	1,782	$	1,714	$	1,323
Other Comprehensive (Loss) Income, Net of Tax
	Foreign currency translation adjustments		(75)		(149)		79
	Pension and OPEB adjustments(a)		19		(49)		276
	Net unrealized loss on cash flow hedges(b)		(28)		(57)		1
	Reclassification into earnings from cash flow hedges(c)		(1)		4		3
	Unrealized gain on investments in auction rate securities(d)		9		8		14
	Unrealized gain on investments in available for sale securities(e)		5		4		―
	Reclassification into earnings from available for sale securities(f)		(5)		(4)		―
Other Comprehensive (Loss) Income, Net of Tax			(76)		(243)		373
Comprehensive Income			1,706		1,471		1,696
Less:  Comprehensive Income Attributable to Noncontrolling Interests			10		1		2
Comprehensive Income Attributable to Duke Energy Corporation		$	1,696	$	1,470	$	1,694
(a)	Net of $9 million tax expense in 2012, $23 million tax benefit in 2011 and $150 million tax expense in 2010.
(b)	Net of $6 million tax expense in 2012, $31 million tax benefit in 2011 and $1 million tax expense in 2010.
(c)	Net of $1 million tax benefit in 2012, $1 million tax expense in 2011 and insignificant tax expense in 2010.
(d)	Net of $4 million tax expense in 2012, $4 million tax expense in 2011 and $8 million tax expense in 2010.
(e)	Net of $3 million tax expense in 2012 and $3 million tax expense in 2011.
(f)	Net of $2 million tax benefit in 2012 and $2 million tax benefit in 2011.

83

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DUKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
		December 31,		December 31,
(in millions)		2012		2011
ASSETS
Current Assets
Cash and cash equivalents		$	1,424	$	2,110
Short-term investments			333		190
Receivables (net of allowance for doubtful accounts of  $34 at December 31, 2012 and $35 at December 31, 2011)			1,516		784
Restricted receivables of variable interest entities (net of allowance for  doubtful accounts of $44 at December 31, 2012 and $40 at December 31, 2011)			1,201		1,157
Inventory			3,223		1,588
Other			2,425		1,051
	Total current assets		10,122		6,880
Investments and Other Assets
Investments in equity method unconsolidated affiliates			483		460
Nuclear decommissioning trust funds			4,242		2,060
Goodwill			16,365		3,849
Intangibles, net			372		363
Notes receivable			71		62
Restricted other assets of variable interest entities			62		135
Other			2,399		2,231
	Total investments and other assets		23,994		9,160
Property, Plant and Equipment
Cost			98,833		60,377
Cost, variable interest entities			1,558		913
Accumulated depreciation and amortization			(31,969)		(18,709)
Generation facilities to be retired, net			136		80
	Net property, plant and equipment		68,558		42,661
Regulatory Assets and Deferred Debits
Regulatory assets			11,004		3,672
Other			178		153
	Total regulatory assets and deferred debits		11,182		3,825
Total Assets		$	113,856	$	62,526
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	2,444	$	1,433
Notes payable and commercial paper			745		154
Non-recourse notes payable of variable interest entities			312		273
Taxes accrued			459		431
Interest accrued			448		252
Current maturities of long-term debt			3,110		1,894
Other			2,511		1,091
	Total current liabilities		10,029		5,528
Long-term Debt			35,499		17,730
Non-recourse long-term debt of variable interest entities			852		949
Deferred Credits and Other Liabilities
Deferred income taxes			10,490		7,581
Investment tax credits			458		384
Accrued pension and other post-retirement benefit costs			2,520		856
Asset retirement obligations			5,169		1,936
Regulatory liabilities			5,584		2,919
Other			2,221		1,778
	Total deferred credits and other liabilities		26,442		15,454
Commitments and Contingencies
Preferred stock of subsidiaries			93		―
Equity
Common stock, $0.001 par value, 2 billion shares authorized; 704 million  and 445 million shares outstanding at December 31, 2012 and  December 31, 2011, respectively			1		1
Additional paid-in capital			39,279		21,132
Retained earnings			1,889		1,873
Accumulated other comprehensive loss			(306)		(234)
	Total Duke Energy Corporation shareholders' equity		40,863		22,772
Noncontrolling interests			78		93
	Total equity		40,941		22,865
Total Liabilities and Equity		$	113,856	$	62,526

84

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DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
					Years Ended December 31,
(in millions)					2012		2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	1,782	$	1,714	$	1,323
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation, amortization and accretion (including amortization of nuclear fuel)			2,652		2,026		1,994
			Equity component of AFUDC			(300)		(260)		(234)
			Severance expense			92		―		―
			FERC mitigation costs			117		―		―
			Community support and charitable contributions expense			92		―		―
			Gains on sales of other assets			(44)		(19)		(268)
			Impairment of other long-lived assets			586		335		738
			Deferred income taxes			584		602		741
			Equity in earnings of unconsolidated affiliates			(148)		(160)		(116)
			Voluntary opportunity cost deferral			(101)		―		―
			Contributions to qualified pension plans			(304)		(200)		(400)
			Accrued pension and other post-retirement benefit costs			239		104		117
			(Increase) decrease in
				Net realized and unrealized mark-to-market and hedging transactions		60		(48)		15
				Receivables		39		2		19
				Inventory		(258)		(247)		198
				Other current assets		140		185		227
			Increase (decrease) in
				Accounts payable		131		41		167
				Taxes accrued		(142)		27		30
				Other current liabilities		295		(254)		43
			Other assets			(129)		12		157
			Other liabilities			(139)		(188)		(240)
				Net cash provided by operating activities		5,244		3,672		4,511
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures					(5,501)		(4,363)		(4,803)
	Investment expenditures					(6)		(50)		(52)
	Acquisitions					(451)		(51)		―
	Cash acquired from the merger with Progress Energy					71		―		―
	Purchases of available-for-sale securities					(4,719)		(3,194)		(2,166)
	Proceeds from sales and maturities of available-for-sale securities					4,537		3,063		2,261
	Net proceeds from the sales of other assets, and sales of and collections on notes receivable					212		118		406
	Change in restricted cash					(414)		22		(75)
	Other					74		21		6
				Net cash used in investing activities		(6,197)		(4,434)		(4,423)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from the:
		Issuance of long-term debt				4,170		2,570		2,738
		Issuance of common stock related to employee benefit plans				23		67		302
	Payments for the redemption of long-term debt					(2,498)		(278)		(1,647)
	Notes payable and commercial paper					278		208		(55)
	Distributions to noncontrolling interests					(25)		(26)		(10)
	Contributions from noncontrolling interests					76		―		―
	Dividends paid					(1,752)		(1,329)		(1,284)
	Other					(5)		(10)		(4)
				Net cash provided by financing activities		267		1,202		40
	Net (decrease) increase in cash and cash equivalents					(686)		440		128
	Cash and cash equivalents at beginning of period					2,110		1,670		1,542
	Cash and cash equivalents at end of period				$	1,424	$	2,110	$	1,670
	Supplemental Disclosures:
	Cash paid for interest, net of amount capitalized				$	1,032	$	813	$	795
	Cash paid for income taxes				$	72	$	26	$	64
	Merger with Progress Energy
		Fair value of assets acquired			$	48,944	$	―	$	―
		Fair value of liabilities assumed			$	30,873	$	―	$	―
		Issuance of common stock			$	18,071	$	―	$	―
	Significant non-cash transactions:
		Accrued capital expenditures			$	684	$	409	$	361
		Extinguishment of debt related to investment in Attiki Gas Supply, S. A.			$	66	$	―	$	―
		Debt associated with the consolidation of variable interest entities			$	―	$	―	$	342

See Notes to Consolidated Financial Statements

85

PART II

DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
									Duke Energy Corporation Shareholders
									Accumulated Other Comprehensive Income (Loss)
											Net Gains				Pension and
		Common			Additional				Foreign		(Losses) on				OPEB Related		Common
		Stock	Common		Paid-in		Retained		Currency		Cash Flow				Adjustments		Stockholders'		Noncontrolling		Total
(in millions)		Shares	Stock		Capital		Earnings		Adjustments		Hedges		Other		to AOCI		Equity		Interests		Equity
Balance at December 31, 2009		436	$	1	$	20,661	$	1,460	$	17	$	(22)	$	(31)	$	(336)	$	21,750	$	136	$	21,886
	Net income	―		―		―		1,320		―		―		―		―		1,320		3		1,323
	Other comprehensive income									80		4		14		276		374		(1)		373
	Common stock issuances, including dividend   reinvestment and employee benefits	7		―		362		―		―		―		―		―		362		―		362
	Common stock dividends	―		―		―		(1,284)		―		―		―		―		(1,284)		―		(1,284)
	Changes in noncontrolling interest in   subsidiaries(a)	―		―		―		―		―		―		―		―		―		(7)		(7)
Balance at December 31, 2010		443	$	1	$	21,023	$	1,496	$	97	$	(18)	$	(17)	$	(60)	$	22,522	$	131	$	22,653
	Net income	―		―		―		1,706		―		―		―		―		1,706		8		1,714
	Other comprehensive (loss) income									(142)		(53)		8		(49)		(236)		(7)		(243)
	Common stock issuances, including dividend   reinvestment and employee benefits	2		―		109		―		―		―		―		―		109		―		109
	Common stock dividends	―		―		―		(1,329)		―		―		―		―		(1,329)		―		(1,329)
	Changes in noncontrolling interest in   subsidiaries(a)	―		―		―		―		―		―		―		―		―		(39)		(39)
Balance at December 31, 2011		445	$	1	$	21,132	$	1,873	$	(45)	$	(71)	$	(9)	$	(109)	$	22,772	$	93	$	22,865
	Net income(b)	―		―		―		1,768		―		―		―		―		1,768		12		1,780
	Other comprehensive (loss) income									(71)		(29)		9		19		(72)		(4)		(76)
	Common stock issued in connection with the   Progress Energy Merger	258		―		18,071		―		―		―		―		―		18,071		―		18,071
	Common stock issuances, including dividend   reinvestment and employee benefits	1		―		76		―		―		―		―		―		76		―		76
	Common stock dividends	―		―		―		(1,752)		―		―		―		―		(1,752)		―		(1,752)
	Deconsolidation of DS Cornerstone, LLC(c)	―		―		―		―		―		―		―		―		―		(82)		(82)
	Contribution from noncontrolling interest in   DS Cornerstone, LLC(c)	―		―		―		―		―		―		―		―		―		76		76
	Changes in noncontrolling interest in   subsidiaries(a)	―		―		―		―		―		―		―		―		―		(17)		(17)
Balance at December 31, 2012		704	$	1	$	39,279	$	1,889	$	(116)	$	(100)	$	―	$	(90)	$	40,863	$	78	$	40,941
(a)	Includes $23 million, $26 million and $10 million in cash distributions to noncontrolling interests in 2012, 2011 and 2010, respectively.
(b)	For the year ended December 31, 2012, consolidated net income of $1,782 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.
(c)	Refer to Note 2 for further information on the deconsolidation of DS Cornerstone, LLC.

See Notes to Consolidated Financial Statements

86

PART II

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Duke Energy Carolinas, LLC

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Duke Energy Carolinas, LLC and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income, member's equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Duke Energy Carolinas, LLC and subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

February 28, 2013

See Notes to Consolidated Financial Statements

87

PART II

DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
			Years Ended December 31,
(in millions)			2012			2011	2010
Operating Revenues			$	6,665	$	6,493	$	6,424
Operating Expenses
	Fuel used in electric generation and purchased power			1,864		1,944		1,944
	Operation, maintenance and other			1,979		1,904		1,907
	Depreciation and amortization			921		814		787
	Property and other taxes			365		340		348
	Impairment charges			31		12		―
		Total operating expenses		5,160		5,014		4,986
Gains on Sales of Other Assets and Other, net				12		1		7
Operating Income				1,517		1,480		1,445
Other Income and Expenses, net				185		186		212
Interest Expense				384		360		362
Income Before Income Taxes				1,318		1,306		1,295
Income Tax Expense				453		472		457
Net Income				865		834		838
Other comprehensive income, net of tax
Reclassification into earnings from cash flow hedges(a)				2		3		4
Unrealized gain on investments in auction rate securities(b)				1		―		7
Comprehensive Income			$	868	$	837	$	849
(a)	Net of $1 million tax expense in 2012, $2 million tax expense in 2011 and $2 million tax expense in 2010.
(b)	Net of $1 million tax expense in 2012 and $5 million tax expense in 2010.

See Notes to Consolidated Financial Statements

88

PART II

DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED BALANCE SHEETS
		December 31,		December 31,
(in millions)		2012		2011
ASSETS
Current Assets
Cash and cash equivalents		$	19	$	289
Receivables (net of allowance for doubtful accounts of $3 at December 31, 2012 and December 31, 2011)			188		262
Restricted receivables of variable interest entities (net of allowance for doubtful accounts of $6 at December 31, 2012 and December 31, 2011)			637		581
Receivables from affiliated companies			3		2
Note receivable from affiliated companies			382		923
Inventory			1,062		917
Other			439		278
	Total current assets		2,730		3,252
Investments and Other Assets
Nuclear decommissioning trust funds			2,354		2,060
Other			934		968
	Total investments and other assets		3,288		3,028
Property, Plant and Equipment
Cost			34,190		32,840
Accumulated depreciation and amortization			(11,437)		(11,269)
Generation facilities to be retired, net			73		80
	Net property, plant and equipment		22,826		21,651
Regulatory Assets and Deferred Debits
Regulatory assets			1,727		1,894
Other			71		71
	Total regulatory assets and deferred debits		1,798		1,965
Total Assets		$	30,642	$	29,896
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities
Accounts payable		$	599	$	637
Accounts payable to affiliated companies			128		156
Taxes accrued			114		126
Interest accrued			96		115
Current maturities of long-term debt			406		1,178
Other			490		398
	Total current liabilities		1,833		2,610
Long-term Debt			7,735		7,496
Non-recourse long-term debt of variable interest entities			300		300
Long-term debt payable to affiliated companies			300		300
Deferred Credits and Other Liabilities
Deferred income taxes			5,181		4,555
Investment tax credits			215		233
Accrued pension and other post-retirement benefit costs			221		248
Asset retirement obligations			1,959		1,846
Regulatory liabilities			2,102		1,928
Other			924		926
	Total deferred credits and other liabilities		10,602		9,736
Commitments and Contingencies
Member's Equity
Member's Equity			9,888		9,473
Accumulated other comprehensive loss			(16)		(19)
	Total member's equity		9,872		9,454
Total Liabilities and Member's Equity		$	30,642	$	29,896

See Notes to Consolidated Financial Statements

89

PART II

DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
					Years Ended December 31,
(in millions)					2012		2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	865	$	834	$	838
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization (including amortization of nuclear fuel)			1,143		1,020		984
			Equity component of AFUDC			(154)		(168)		(174)
			FERC mitigation costs			46		―		―
			Community support and charitable contributions expense			56		―		―
			Gains on sales of other assets and other, net			(12)		(1)		(7)
			Impairment charges			―		12		―
			Deferred income taxes			479		564		456
			Voluntary opportunity cost deferral			(101)		―		―
			Accrued pension and other post-retirement benefit costs			41		32		34
			Contributions to qualified pension plans			―		(33)		(158)
			(Increase) decrease in
				Net realized and unrealized mark-to-market and hedging transactions		―		(91)		1
				Receivables		22		22		114
				Receivables from affiliated companies		(1)		88		(90)
				Inventory		(128)		(177)		134
				Other current assets		46		144		(55)
			Increase (decrease) in
				Accounts payable		(51)		120		86
				Accounts payable to affiliated companies		(28)		(39)		25
				Taxes accrued		(12)		12		(23)
				Other current liabilities		165		(170)		4
			Other assets			(117)		(46)		19
			Other liabilities			(126)		(249)		(158)
				Net cash provided by operating activities		2,133		1,874		2,030
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures					(1,908)		(2,272)		(2,280)
	Purchases of available-for-sale securities					(2,481)		(2,227)		(1,045)
	Proceeds from sales and maturities of available-for-sale securities					2,445		2,179		1,066
	Change in restricted cash					―		2		7
	Notes receivable from affiliated companies					541		(584)		250
	Other					(12)		(13)		―
				Net cash used in investing activities		(1,415)		(2,915)		(2,002)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from the issuance of long-term debt					645		1,498		692
	Payments for the redemption of long-term debt					(1,177)		(7)		(607)
	Distributions to parent					(450)		(299)		(350)
	Other					(6)		(15)		(4)
				Net cash (used in) provided by financing activities		(988)		1,177		(269)
	Net (decrease) increase in cash and cash equivalents					(270)		136		(241)
	Cash and cash equivalents at beginning of period					289		153		394
	Cash and cash equivalents at end of period				$	19	$	289	$	153
	Supplemental Disclosures:
	Cash paid for interest, net of amount capitalized				$	385	$	337	$	342
	Cash (received) paid for income taxes				$	(38)	$	(223)	$	69
	Significant non-cash transactions:
		Accrued capital expenditures			$	194	$	209	$	181

See Notes to Consolidated Financial Statements

90

PART II

DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
				Accumulated Other
				Comprehensive Income (Loss)
				Net  Gains
				(Losses) on
		Member's		Cash Flow
(in millions)		Equity		Hedges		Other		Total
Balance at December 31, 2009		$	8,304	$	(24)	$	(9)	$	8,271
	Net income		838		―		―		838
	Other comprehensive income		―		4		7		11
	Allocation of net pension and other post-retirement assets   from parent		146		―		―		146
	Distributions to parent		(350)		―		―		(350)
Balance at December 31, 2010		$	8,938	$	(20)	$	(2)	$	8,916
	Net income		834		―		―		834
	Other comprehensive income				3				3
	Distributions to parent		(299)		―		―		(299)
Balance at December 31, 2011		$	9,473	$	(17)	$	(2)	$	9,454
	Net income		865		―		―		865
	Other comprehensive income				2		1		3
	Distributions to parent		(450)		―		―		(450)
Balance at December 31, 2012		$	9,888	$	(15)	$	(1)	$	9,872

See Notes to Consolidated Financial Statements

91

PART II

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Progress Energy, Inc.

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Progress Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income, common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2012. We also have audited the Company's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report On Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Progress Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

February 28, 2013

See Notes to Consolidated Financial Statements

92

PART II

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
			Years Ended December 31,
(in millions)			2012		2011		2010
Operating Revenues			$	9,405	$	8,948	$	10,223
Operating Expenses
	Fuel used in electric generation and purchased power			4,304		4,043		4,621
	Operation, maintenance and other			2,445		2,060		2,045
	Depreciation and amortization			747		701		920
	Property and other taxes			570		562		580
	Impairment charges			200		3		5
		Total operating expenses		8,266		7,369		8,171
(Losses) Gains on Sales of Other Assets and Other, net				(2)		4		(8)
Operating Income				1,137		1,583		2,044
Other Income and Expenses, net				130		52		109
Interest Expense				740		725		747
Income From Continuing Operations Before Income Taxes				527		910		1,406
Income Tax Expense From Continuing Operations				172		323		539
Income From Continuing Operations				355		587		867
Income (Loss) From Discontinued Operations, net of tax				52		(5)		(4)
Net Income				407		582		863
Less: Net Income Attributable to Noncontrolling Interests				7		7		7
Net Income Attributable to Parent			$	400	$	575	$	856
Net Income			$	407	$	582	$	863
Other Comprehensive (Loss) Income, net of tax
	Pension and OPEB adjustments(a)			(4)		34		(13)
	Reclassification into earnings from pension and OPEB adjustments(b)			2		5		3
	Net unrealized loss on cash flow hedges(c)			(5)		(87)		(34)
	Reclassification into earnings from cash flow hedges(d)			8		8		6
	Reclassification of cash flow hedges to regulatory assets(e)			97		―		―
Other Comprehensive Income (Loss), net of tax				98		(40)		(38)
Comprehensive Income				505		542		825
Less: Comprehensive Income Attributable to Noncontrolling Interests				7		7		7
Comprehensive Income Attributable to Parent			$	498	$	535	$	818
(a)		Net of $1 million tax benefit in 2012, $24 million tax expense in 2011 and $8 million tax benefit in 2010.
(b)		Net of $1 million tax expense in 2012, $3 million tax expense in 2011 and $2 million tax expense in 2010.
(c)		Net of $3 million tax benefit in 2012, $56 million tax benefit in 2011 and $22 million tax benefit in 2010.
(d)		Net of $6 million tax expense in 2012, $5 million tax expense in 2011 and $4 million tax expense in 2010.
(e)		Net of $62 million tax expense in 2012.

See Notes to Consolidated Financial Statements

93

PART II

PROGRESS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
		December 31,		December 31,
(in millions)		2012		2011
ASSETS
Current Assets
Cash and cash equivalents		$	231	$	230
Receivables (net of allowance for doubtful accounts of $16 at December 31, 2012 and $27 at December 31, 2011)			790		883
Receivables from affiliated companies			15		―
Inventory			1,441		1,429
Other			766		778
	Total current assets		3,243		3,320
Investments and Other Assets
Nuclear decommissioning trust funds			1,888		1,647
Goodwill			3,655		3,655
Other			530		504
	Total investments and other assets		6,073		5,806
Property, Plant and Equipment
Cost			35,130		34,797
Cost, variable interest entities			16		16
Accumulated depreciation and amortization			(12,512)		(12,684)
Generation facilities to be retired, net			63		163
	Net property, plant and equipment		22,697		22,292
Regulatory Assets and Deferred Debits
Regulatory assets			5,292		3,424
Other			100		89
	Total regulatory assets and deferred debits		5,392		3,513
Total Assets		$	37,405	$	34,931
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	1,066	$	968
Accounts payable to affiliated companies			30		―
Notes payable and commercial paper			―		671
Notes payable to affiliated companies			455		―
Taxes accrued			83		56
Interest accrued			192		200
Current maturities of long-term debt			843		961
Other			1,118		1,163
	Total current liabilities		3,787		4,019
Long-term Debt			13,311		11,918
Long-term Debt Payable to Affiliated Companies			274		273
Deferred Credits and Other Liabilities
Deferred income taxes			2,558		2,193
Investment tax credits			95		103
Accrued pension and other post-retirement benefit costs			1,608		1,625
Asset retirement obligations			2,413		1,265
Regulatory liabilities			2,469		2,727
Other			612		690
	Total deferred credits and other liabilities		9,755		8,603
Commitments and Contingencies
Preferred Stock of Subsidiaries			93		93
Equity
Common stock, $0.01 par value, 100 shares authorized, issued and outstanding at December 31, 2012; no par value, 500 million shares authorized, 295 million shares issued and outstanding at December 31, 2011			―		7,418
Additional paid-in capital			7,465		16
Retained earnings			2,783		2,752
Accumulated other comprehensive loss			(67)		(165)
	Total common shareholders' equity		10,181		10,021
Noncontrolling interests			4		4
	Total equity		10,185		10,025
Total Liabilities and Equity		$	37,405	$	34,931

See Notes to Consolidated Financial Statements

94

PART II

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
					Years Ended December 31,
(in millions)					2012		2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	407	$	582	$	863
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation, amortization and accretion (including amortization of nuclear fuel)			897		850		1,044
			Equity component of AFUDC			(106)		(103)		(92)
			Severance expense			38		―		―
			FERC mitigation costs			71		―		―
			Community support and charitable contributions expense			36		―		―
			Gains (losses) on sales of other assets and other, net			(16)		(5)		9
			Impairment charges			146		3		5
			Deferred income taxes			263		353		478
			Amount to be refunded to customers			100		288		―
			Accrued pension and other post-retirement benefit costs			179		124		121
			Contributions to qualified pension plans			(346)		(331)		(129)
			(Increase) decrease in
				Net realized and unrealized mark-to-market and hedging transactions		7		(10)		(17)
				Receivables		49		167		(178)
				Receivables from affiliated companies		(15)		―		―
				Inventory		(71)		(210)		89
				Other current assets		2		(111)		84
			Increase (decrease) in
				Accounts payable		175		(64)		115
				Accounts payable to affiliated companies		30		―		―
				Taxes accrued		25		(16)		26
				Other current liabilities		81		67		78
			Other assets			(25)		(67)		(25)
			Other liabilities			(87)		98		60
				Net cash provided by operating activities		1,840		1,615		2,531
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures					(2,366)		(2,256)		(2,445)
	Purchases of available-for-sale securities					(1,374)		(5,017)		(7,009)
	Proceeds from sales and maturities of available-for-sale securities					1,325		4,970		6,990
	Insurance proceeds					7		79		64
	Change in restricted cash					24		(24)		―
	Other					102		36		―
				Net cash used in investing activities		(2,282)		(2,212)		(2,400)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from the:
		Issuance of long-term debt				2,074		1,286		591
		Issuance of common stock				6		53		434
	Payments for the redemption of long-term debt					(962)		(1,010)		(410)
	Payments of short-term debt with original maturities greater than 90 days					(65)		―		―
	Proceeds from issuance of short-term debt with original maturities greater than 90 days					65		―		―
	Notes payable and commercial paper					(671)		667		(140)
	Notes payable to affiliated companies					455		―		―
	Distributions to noncontrolling interests					(7)		(7)		(6)
	Dividends paid					(445)		(734)		(717)
	Other					(7)		(39)		3
				Net cash provided by (used in) financing activities		443		216		(245)
	Net increase (decrease) in cash and cash equivalents					1		(381)		(114)
	Cash and Cash Equivalents at Beginning of Period					230		611		725
	Cash and Cash Equivalents at End of Period				$	231	$	230	$	611
	Supplemental Disclosures:
	Cash paid for interest, net of amount capitalized				$	784	$	793	$	709
	Cash paid for (received from) income taxes				$	(4)	$	(78)	$	(56)
	Significant non-cash transactions:
		Accrued capital expenditures			$	375	$	380	$	364
		Asset retirement obligation additions and estimate revisions			$	837	$	(4)	$	(36)
		Capital expenditures financed through capital leases			$	140	$	―	$	―

See Notes to Consolidated Financial Statements

95

PART II

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
										Accumulated Other
										Comprehensive Income (Loss)
						Unearned				Net Gain		Pension and
				Additional		ESOP				(Losses) on		OPEB Related		Common
		Common		Paid-in		Common		Retained		Cash Flow		Adjustments		Stockholders'		Noncontrolling		Total
(in millions)		Stock		Capital		Stock		Earnings		Hedges		to AOCI		Equity		Interests		Equity
Balance at December 31, 2009		$	6,862	$	11	$	(12)	$	2,675	$	(35)	$	(52)	$	9,449	$	6	$	9,455
	Cumulative effect of change in accounting principle		―		―		―		―		―		―		―		(2)		(2)
	Net income(a)		―		―		―		856		―		―		856		3		859
	Other comprehensive loss		―		―		―		―		(28)		(10)		(38)		―		(38)
	Common stock issuances, including dividend   reinvestment and employee benefits		461		―		―		―		―		―		461		―		461
	Allocation of ESOP shares		9		―		12		―		―		―		21		―		21
	Common stock dividends		―		―		―		(726)		―		―		(726)		―		(726)
	Distributions to noncontrolling interests		―		―		―		―		―		―		―		(2)		(2)
	Other		―		―		―		―		―		―		―		(1)		(1)
Balance at December 31, 2010		$	7,332	$	11	$	―	$	2,805	$	(63)	$	(62)	$	10,023	$	4	$	10,027
	Net income(a)		―		―		―		575		―		―		575		3		578
	Other comprehensive (loss) income		―		―		―		―		(79)		39		(40)		―		(40)
	Common stock issuances, including dividend   reinvestment and employee benefits		86		5		―		―		―		―		91		―		91
	Common stock dividends		―		―		―		(628)		―		―		(628)		―		(628)
	Distributions to noncontrolling interests		―		―		―		―		―		―		―		(3)		(3)
Balance at December 31, 2011		$	7,418	$	16	$	―	$	2,752	$	(142)	$	(23)	$	10,021	$	4	$	10,025
	Net income(a)		―		―		―		400		―		―		400		3		403
	Other comprehensive income (loss)		―		―		―		―		100		(2)		98		―		98
	Common stock issuances, including dividend   reinvestment and employee benefits		18		13		―		―		―		―		31		―		31
	Common stock dividends		―		―		―		(369)		―		―		(369)		―		(369)
	Distributions to noncontrolling interests		―		―		―		―		―		―		―		(2)		(2)
	Recapitalization for merger with Duke Energy		(7,436)		7,436		―		―		―		―		―		―		―
	Other		―		―		―		―		―		―		―		(1)		(1)
Balance at December 31, 2012		$	―	$	7,465	$	―	$	2,783	$	(42)	$	(25)	$	10,181	$	4	$	10,185
(a)	For the year ended December 31, 2012, consolidated net income of $407 million includes $4 million attributable to preferred shareholders of subsidiaries. For the year ended December 31, 2011, consolidated net income of $582 million includes $4 million attributable to preferred shareholders of subsidiaries. For the year ended December 31, 2010, consolidated net income of $863 million includes $4 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

See Notes to Consolidated Financial Statements

96

PART II

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of and Stockholders of

Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

February 28, 2013

See Notes to Consolidated Financial Statements

97

PART II

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
			Years Ended December 31,
(in millions)			2012		2011		2010
Operating Revenues			$	4,706	$	4,547	$	4,933
Operating Expenses
	Fuel used in electric generation and purchased power			1,895		1,755		2,008
	Operation, maintenance and other			1,494		1,191		1,158
	Depreciation and amortization			535		514		478
	Property and other taxes			219		211		218
	Impairment charges			54		3		5
		Total operating expenses		4,197		3,674		3,867
Gains on Sales of Other Assets and Other, net				1		3		1
Operating Income				510		876		1,067
Other Income and Expenses, net				79		80		71
Interest Expense				207		184		186
Income Before Income Taxes				382		772		952
Income Tax Expense				110		256		350
Net Income				272		516		602
Less: Net Income (Loss) Attributable to Noncontrolling Interests				―		―		(1)
Net Income Attributable to Controlling Interests				272		516		603
Less: Preferred Stock Dividend Requirement				3		3		3
Net Income Available to Parent			$	269	$	513	$	600
Net Income			$	272	$	516	$	602
Other Comprehensive (Loss) Income, net of tax
	Net unrealized loss on cash flow hedges(a)			(4)		(43)		(10)
	Reclassification into earnings from cash flow hedges(b)			4		5		4
	Reclassification of cash flow hedges to regulatory assets(c)			71		―		―
Other Comprehensive Income (Loss), net of tax				71		(38)		(6)
Comprehensive Income				343		478		596
Less: Comprehensive Income (Loss) Attributable to Noncontrolling Interests				―		―		(1)
Comprehensive Income Attributable to Controlling Interests			$	343	$	478	$	597
(a)		Net of $3 million tax benefit in 2012, $28 million tax benefit in 2011 and $6 million tax benefit in 2010.
(b)		Net of $2 million tax expense in 2012, $3 million tax expense in 2011 and $3 million tax expense in 2010.
(c)		Net of $46 million tax expense in 2012.

See Notes to Consolidated Financial Statements

98

PART II

CAROLINA POWER & LIGHT d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED BALANCE SHEETS
		December 31,		December 31,
(in millions)		2012		2011
ASSETS
Current Assets
Cash and cash equivalents		$	18	$	20
Receivables (net of allowance for doubtful accounts of $9 at December 31, 2012 and 2011)			458		492
Receivables from affiliated companies			5		1
Inventory			828		770
Other			313		226
	Total current assets		1,622		1,509
Investments and Other Assets
Nuclear decommissioning trust funds			1,259		1,088
Other			251		210
	Total investments and other assets		1,510		1,298
Property, Plant and Equipment
Cost			21,168		19,367
Cost, variable interest entities			16		16
Accumulated depreciation and amortization			(8,185)		(7,991)
Generation facilities to be retired, net			63		163
	Net property, plant and equipment		13,062		11,555
Regulatory Assets and Deferred Debits
Regulatory assets			1,845		1,682
Other			29		22
	Total regulatory assets and deferred debits		1,874		1,704
Total Assets		$	18,068	$	16,066
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	542	$	518
Accounts payable to affiliated companies			76		29
Notes payable and commercial paper			―		188
Notes payable to affiliated companies			364		31
Taxes accrued			23		23
Interest accrued			69		77
Current maturities of long-term debt			407		502
Other			517		417
	Total current liabilities		1,998		1,785
Long-term Debt			4,433		3,704
Deferred Credits and Other Liabilities
Deferred income taxes			2,162		1,903
Investment tax credits			92		98
Accrued pension and other post-retirement benefit costs			715		687
Asset retirement obligations			1,649		896
Regulatory liabilities			1,538		1,543
Other			295		303
	Total deferred credits and other liabilities		6,451		5,430
Commitments and Contingencies
Preferred Stock			59		59
Equity
Common stock, no par value, 200 million shares authorized; 160 million shares issued and outstanding at December 31, 2012 and 2011			2,159		2,148
Retained earnings			2,968		3,011
Accumulated other comprehensive loss			―		(71)
	Total common stockholder's equity		5,127		5,088
Total Liabilities and Equity		$	18,068	$	16,066

See Notes to Consolidated Financial Statements

99

PART II

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
				Years Ended December 31,
(in millions)				2012		2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income			$	272	$	516	$	602
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, amortization and accretion (including amortization of nuclear fuel)			676		654		593
		Equity component of AFUDC			(69)		(71)		(64)
		Severance expense			18		―		―
		FERC mitigation costs			71		―		―
		Community support and charitable contributions expense			36		―		―
		Gains on sales of other assets and other, net			(1)		(3)		(1)
		Impairment charges			―		3		5
		Deferred income taxes			164		262		285
		Accrued pension and other post-retirement benefit costs			70		43		43
		Contributions to qualified pension plans			(141)		(217)		(95)
		(Increase) decrease in
			Net realized and unrealized mark-to-market and hedging transactions		(25)		(23)		(11)
			Receivables		2		84		(68)
			Receivables from affiliated companies		(4)		8		5
			Inventory		(58)		(182)		83
			Other current assets		(24)		116		22
		Increase (decrease) in
			Accounts payable		149		(22)		49
			Accounts payable to affiliated companies		47		(45)		20
			Taxes accrued		(5)		(4)		(4)
			Other current liabilities		23		40		39
		Other assets			(28)		(38)		(22)
		Other liabilities			(6)		16		37
			Net cash provided by operating activities		1,167		1,137		1,518
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures				(1,525)		(1,426)		(1,382)
	Purchases of available-for-sale securities				(582)		(572)		(490)
	Proceeds from sales and maturities of available-for-sale securities				532		515		437
	Notes receivable from affiliated companies				―		2		202
	Other				91		12