form10k-2010.htm

10-K 1 form10k-2010.htm 2010 10K form10k-2010.htm f

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

	(Mark One)
	[ X ]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

[ ]

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 their charters, state of incorporation, address of principal executive offices, and telephone number	I.R.S. Employer Identification Number

1-15929	Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 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 Telephone: (919) 546-6111 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 Telephone: (727) 820-5151 State of Incorporation: Florida	59-0247770

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

Title of each class	Name of each exchange on which registered
Progress Energy, Inc.:
Common Stock (Without Par Value)	New York Stock Exchange
Carolina Power & Light Company:	None
Florida Power Corporation:	None

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

Progress Energy, Inc.:	None
Carolina Power & Light Company:	$5 Preferred Stock, No Par Value
	Serial Preferred Stock, No Par Value
Florida Power Corporation:	None

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

Progress Energy, Inc. (Progress Energy)	Yes	(X)	No	( )
Carolina Power & Light Company (PEC)	Yes	( )	No	(X)
Florida Power Corporation (PEF)	Yes	( )	No	(X)

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

Progress Energy	Yes	( )	No	(X)
PEC	Yes	( )	No	(X)
PEF	Yes	(X)	No	( )

Indicate by check mark whether each 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.

Progress Energy	Yes	(X)	No	( )
PEC	Yes	(X)	No	( )
PEF	Yes	( )	No	(X)

Indicate by check mark whether each registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

Progress Energy	Yes	(X)	No	( )
PEC	Yes	( )	No	( )
PEF	Yes	( )	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 each 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.

Progress Energy	(X)
PEC	(X)
PEF	(X)

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

Progress Energy	Large accelerated filer	(X)	Accelerated filer	( )
	Non-accelerated filer	( )	Smaller reporting company	( )

PEC	Large accelerated filer	( )	Accelerated filer	( )
	Non-accelerated filer	(X)	Smaller reporting company	( )

PEF	Large accelerated filer	( )	Accelerated filer	( )
	Non-accelerated filer	(X)	Smaller reporting company	( )

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

Progress Energy	Yes	( )	No	(X)
PEC	Yes	( )	No	(X)
PEF	Yes	( )	No	(X)

As of June 30, 2010, the aggregate market value of the voting and nonvoting common equity of Progress Energy held by nonaffiliates was $11,477,572,820. As of June 30, 2010, the aggregate market value of the common equity of PEC held by nonaffiliates was $0. All of the common stock of PEC is owned by Progress Energy. As of June 30, 2010, the aggregate market value of the common equity of PEF held by nonaffiliates was $0. All of the common stock of PEF is indirectly owned by Progress Energy.

As of February 22, 2011, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	293,541,665
PEC	Common Stock (Without Par Value)	159,608,055
PEF	Common Stock (Without Par Value)	100

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Progress Energy and PEC definitive proxy statements for the 2011 Annual Meeting of Shareholders are incorporated into PART III, Items 10, 11, 12 , 13 and 14 hereof.

This combined Form 10-K is filed separately by three registrants: Progress Energy, PEC and PEF (collectively, the Progress 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.

PEF meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format permitted by General Instruction I (2) to such Form 10-K.

TABLE OF CONTENTS

GLOSSARY OF TERMS

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

PART I
ITEM 1.	BUSINESS

ITEM 1A.	RISK FACTORS

ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 2.	PROPERTIES

ITEM 3.	LEGAL PROCEEDINGS

ITEM 4.	(REMOVED AND RESERVED)

	EXECUTIVE OFFICERS OF THE REGISTRANTS

PART II
ITEM 5.	MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

ITEM 6.	SELECTED FINANCIAL DATA

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

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

SIGNATURES

GLOSSARY OF TERMS

We use the words “Progress Energy,” “we,” “us” or “our” to indicate that certain information relates to Progress Energy, Inc. and its subsidiaries on a consolidated basis. When appropriate, the parent holding company or the subsidiaries of Progress Energy are specifically identified on an unconsolidated basis as we discuss their various business activities.

The following abbreviations, acronyms or initialisms are used by the Progress Registrants:

TERM	DEFINITION

401(k)	Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASLB	Atomic Safety and Licensing Board
the Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
ASU	Accounting Standards Update
Audit Committee	Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART	Best Available Retrofit Technology
Base Revenues	Non-GAAP measure defined as operating revenues excluding clause recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CCRC	Capacity Cost-Recovery Clause
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Smokestacks Act	North Carolina Clean Smokestacks Act
the Code	Internal Revenue Code
CO2	Carbon dioxide
COL	Combined license
Corporate and Other	Corporate and Other segment primarily includes the Parent, Progress Energy Service Company and miscellaneous other nonregulated businesses
CR1 and CR2	PEF’s Crystal River Units No. 1 and No. 2 coal-fired steam turbines
CR3	PEF’s Crystal River Unit No. 3 Nuclear Plant
CR4 and CR5	PEF’s Crystal River Units No. 4 and No. 5 coal-fired steam turbines
CVO	Contingent value obligation
D.C. Court of Appeals	U.S. Court of Appeals for the District of Columbia Circuit
DOE	United States Department of Energy
DSM	Demand-side management
Duke Energy	Duke Energy Corporation
Earthco	Four coal-based solid synthetic fuels limited liability companies of which three were wholly owned
ECCR	Energy Conservation Cost Recovery Clause
ECRC	Environmental Cost Recovery Clause
EE	Energy efficiency
EIP	Equity Incentive Plan
EPA	United States Environmental Protection Agency
EPC	Engineering, procurement and construction
ESOP	Employee Stock Ownership Plan

FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company, LLC
Fitch	Fitch Ratings
the Florida Global Case	U.S. Global, LLC v. Progress Energy, Inc. et al.
Florida Progress	Florida Progress Corporation
FPSC	Florida Public Service Commission
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
Global	U.S. Global, LLC
GWh	Gigawatt-hours
Harris	PEC’s Shearon Harris Nuclear Plant
IPP	Progress Energy Investor Plus Plan
kV	Kilovolt
kVA	Kilovolt-ampere
kWh	Kilowatt-hours
Levy	PEF’s proposed nuclear plant in Levy County, Fla.
LIBOR	London Inter Bank Offered Rate
MACT	Maximum achievable control technology
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in PART II, Item 7 of this Form 10-K
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
the Merger	Proposed merger between Progress Energy and Duke Energy
the Merger Agreement	Agreement and Plan of Merger, dated as of January 8, 2011, by and among Progress Energy and Duke Energy
MGP	Manufactured gas plant
MW	Megawatts
MWh	Megawatt-hours
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NC REPS	North Carolina Renewable Energy and Energy Efficiency Portfolio Standard
NCUC	North Carolina Utilities Commission
NDT	Nuclear decommissioning trust
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
NOx	Nitrogen oxides
NRC	Nuclear Regulatory Commission
O&M	Operation and maintenance expense
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income
Ongoing Earnings	Non-GAAP financial measure defined as GAAP net income attributable to controlling interests after excluding discontinued operations and the effects of certain identified gains and charges
OPEB	Postretirement benefits other than pensions
the Parent	Progress Energy, Inc. holding company on an unconsolidated basis
PEC	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
PEF	Florida Power Corporation d/b/a Progress Energy Florida, Inc.
PESC	Progress Energy Service Company, LLC
Power Agency	North Carolina Eastern Municipal Power Agency

PPACA	Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act
Preferred Securities	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Affiliates	Five affiliated coal-based solid synthetic fuels facilities
Progress Energy	Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants	The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
QF	Qualifying facility
RCA	Revolving credit agreement
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
REPS	Renewable energy portfolio standard
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity
RSU	Restricted stock unit
SCPSC	Public Service Commission of South Carolina
Section 29	Section 29 of the Code
Section 29/45K	General business tax credits earned after December 31, 2005 for synthetic fuels production in accordance with Section 29
Section 45K	Section 45K of the Code
Section 316(b)	Section 316(b) of the Clean Water Act
(See Note/s “#”)	For all sections, this is a cross-reference to the Combined Notes to the Financial Statements contained in PART II, Item 8 of this Form 10-K
SERC	SERC Reliability Corporation
S&P	Standard & Poor’s Rating Services
SO2	Sulfur dioxide
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
the Trust	FPC Capital I
the Utilities	Collectively, PEC and PEF
VIE	Variable interest entity
Ward	Ward Transformer site located in Raleigh, N.C.
Ward OU1	Operable unit for stream segments downstream from the Ward site
Ward OU2	Operable unit for further investigation at the Ward facility and certain adjacent areas

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

In this combined report, each of the Progress Registrants makes forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-K that are not historical facts are forward looking and, accordingly, 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. Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

In addition, examples of forward-looking statements discussed in this Form 10-K include, but are not limited to, 1) statements made in PART I, Item 1A, “Risk Factors” and 2) PART II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the following headings: a) “Merger” about the proposed merger between Progress Energy and Duke Energy Corporation (Duke Energy) (the Merger) and the impact of the Merger on our strategy and liquidity; b) “Strategy” about our future strategy and goals; c) “Results of Operations” about trends and uncertainties; d) “Liquidity and Capital Resources” about operating cash flows, future liquidity requirements and estimated capital expenditures; and e) “Other Matters” about the effects of new environmental regulations, changes in the regulatory environment, meeting anticipated demand in our regulated service territories, potential nuclear construction and our synthetic fuels tax credits.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following:

·	our ability to obtain the approvals required to complete the Merger and the impact of compliance with material restrictions or conditions potentially imposed by our regulators;

·	the risk that the Merger is terminated prior to completion and results in significant transaction costs to us;

·	our ability to achieve the anticipated results and benefits of the Merger;

·	the impact of business uncertainties and contractual restrictions while the Merger is pending;

·	the impact of fluid and complex laws and regulations, including those relating to the environment and energy policy;

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

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

·	the impact on our facilities and businesses from a terrorist attack;

·	the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks;

·	our ability to meet current and future renewable energy requirements;

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

·	the financial resources and capital needed to comply with environmental laws and regulations;

·	risks associated with climate change;

·	weather and drought conditions that directly influence the production, delivery and demand for electricity;

·	recurring seasonal fluctuations in demand for electricity;

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

·	fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process;

·	the Progress Registrants’ ability to control costs, including operations and maintenance expense (O&M) and large construction projects;

·	the ability of our subsidiaries to pay upstream dividends or distributions to Progress Energy, Inc. holding company (the Parent);

·	current economic conditions;

·	the ability to successfully access capital markets on favorable terms;

·	the stability of commercial credit markets and our access to short- and long-term credit;

·	the impact that increases in leverage or reductions in cash flow may have on each of the Progress Registrants;

·	the Progress Registrants’ ability to maintain their current credit ratings and the impacts in the event their credit ratings are downgraded;

·	the investment performance of our nuclear decommissioning trust (NDT) funds;

·	the investment performance of the assets of our pension and benefit plans and resulting impact on future funding requirements;

·	the impact of potential goodwill impairments;

·	our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); and

·	the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements.

Many of these risks similarly impact our nonreporting subsidiaries.

These and other risk factors are detailed from time to time in the Progress Registrants’ filings with the SEC. Many, but not all, of the factors that may impact actual results are discussed in Item 1A, “Risk Factors,” which should be read carefully. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on the Progress Registrants.

PART I

ITEM 1.

BUSINESS

GENERAL

ORGANIZATION

Progress Energy, Inc. is a public utility holding company primarily engaged in the regulated electric utility business. Headquartered in Raleigh, N.C., it owns, directly or indirectly, all of the outstanding common stock of its utility subsidiaries, PEC and PEF. In this report, Progress Energy, which includes the Parent and its subsidiaries on a consolidated basis, is at times referred to as “we,” “our” or “us.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself. The Parent was incorporated on August 19, 1999, initially as CP&L Energy, Inc. and became the holding company for PEC on June 19, 2000. We acquired PEF through our November 2000 acquisition of its parent, Florida Progress Corporation (Florida Progress).

Our reportable segments are PEC and PEF, which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 19 for information regarding the revenues, income and assets attributable to our business segments.

The Utilities have more than 22,000 megawatts (MW) of regulated electric generation capacity and serve approximately 3.1 million retail electric customers as well as other load-serving entities. We are dedicated to meeting the growth needs of our service territories and delivering reliable, competitively priced energy from a diverse portfolio of power plants. The Utilities operate in retail service territories that have historically had population growth higher than the U.S. average. However, like other parts of the United States, our service territories and business have been negatively impacted by the current economic conditions. The timing and extent of the recovery of the economy cannot be predicted.

For the year ended December 31, 2010, our consolidated revenues were $10.190 billion and our consolidated assets at year-end were $33.054 billion.

The Progress Registrants’ annual reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge through the Investors section of our website at www.progress-energy.com. Information on our website is not incorporated herein and should not be deemed part of this Report. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished with the SEC. The public may read and copy any material we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information regarding the operations of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains a website, www.sec.gov, containing reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

RECENT DEVELOPMENTS

On January 8, 2011, Duke Energy and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction and continue as a wholly owned subsidiary of Duke Energy (the Merger). Both companies’ boards of directors have unanimously approved the Merger Agreement. However, consummation of the Merger is subject to customary conditions, including, among other things, approval of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approval, to the extent required,

from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission, the Nuclear Regulatory Commission (NRC), the North Carolina Utilities Commission (NCUC), the Kentucky Public Service Commission and the South Carolina Public Service Commission (SCPSC), the Florida Public Service Commission (FPSC), the Indiana Utility Regulatory Commission, and the Ohio Public Utilities Commission . See Item IA, “Risk Factors,” MD&A – “Introduction – Merger,” and Note 25 for additional information related to the Merger.

On June 1, 2010, the FPSC approved a settlement agreement between PEF and interveners, with the exception of the Florida Association for Fairness in Ratemaking, to the 2009 rate case and a PEF-proposed accounting order. Among other provisions, under the terms of the settlement agreement, PEF will maintain base rates at current levels through the last billing cycle of 2012. The settlement agreement also provides that PEF will have the discretion to reduce amortization expense (cost of removal component) in 2010, 2011 and 2012. The settlement agreement also provides that if PEF’s actual retail base rate earnings fall below a 9.5 percent return on equity (ROE) on an adjusted or pro forma basis, as reported on a historical 12-month basis during the term of the agreement, PEF may seek general, limited or interim base rate relief, or any combination thereof. Prior to requesting any such relief, PEF must have reflected on its referenced surveillance report associated amortization expense reductions of at least $150 million. The settlement agreement does not preclude PEF from requesting the FPSC to approve the recovery of costs (a) that are of a type which traditionally and historically would be, have been or are presently recovered through cost-recovery clauses or surcharges, or (b) that are incremental costs not currently recovered in base rates, which the legislature or FPSC determines are clause recoverable, or (c) which are recoverable through base rates under the nuclear cost-recovery legislation or the FPSC’s nuclear cost-recovery rule. See Note 7C for additional provisions of the settlement agreement.

In September 2009, PEF’s nuclear generating unit, Crystal River Unit No. 3 (CR3), began an outage for normal refueling and maintenance as well as its uprate project to increase the unit’s generating capability and to replace two steam generators. During preparations to replace the steam generators, we discovered a delamination within the concrete of the outer wall of the containment structure, which has resulted in an extension of the outage. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. Nuclear safety remains our top priority, and our plans and actions will continue to reflect that commitment. A number of factors affect the return to service date, including regulatory reviews by the NRC and other agencies, emergent work, final engineering designs, testing, weather and other developments. PEF anticipates recovering the costs related to the extended outage through a combination of insurance and customer rates. See “Nuclear Matters – General” and Note 7C.

Although we have not made a final determination on new nuclear construction, we have taken steps to keep open the option of building one or more plants at Shearon Harris Nuclear Plant (Harris) in North Carolina and at a greenfield site in Levy County, Florida (Levy). We have focused on Levy given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce greenhouse gas (GHG) emissions, as well as existing state legislative policy, which is supportive of nuclear projects. PEF has received two of the three key approvals (with the issuance of a combined license [COL] by the NRC remaining) and entered into an engineering, procurement and construction (EPC) agreement for the two proposed Levy units. As discussed in “Nuclear Matters – Potential New Construction,” with the 2010 amendment to the EPC agreement, PEF will postpone major construction activities at Levy until after the NRC issues the COL. If the licensing schedule remains on track and if the decision to build is made, the first of PEF’s two proposed units could be in service in 2021. The second unit could be in service 18 months later.

We are preparing for a carbon-constrained future given the state, federal and international focus on global climate change. We are expanding and enhancing our demand-side management (DSM), energy-efficiency (EE) and energy conservation programs. In 2010, we accepted a grant from the United States Department of Energy (DOE) for $200 million in federal matching infrastructure funds in support of our smart grid initiatives. In addition to providing the Utilities real-time information about the state of their electric grids, the smart grid transition will enable customers to better understand and manage their energy use, and will provide for more efficient integration of renewable energy resources. We continue to actively pursue alternative energy projects. We have executed contracts to purchase 311 MW of electricity generated from solar, biomass and municipal solid waste sources. We have adopted a major coal-to-gas modernization strategy whereby the 11 remaining coal-fired generating facilities in North Carolina that do not have scrubbers would be retired by the end of 2014 (prior to the end of their useful lives) and their approximately 1,500 MW of generating capacity replaced with new natural gas-fueled facilities. This will provide rate base growth

while reducing our carbon emissions. After 2014, PEC will continue to operate its Roxboro, Mayo and Asheville coal-fired plants in North Carolina, which have state-of-the-art emission controls.

COMPETITION

RETAIL COMPETITION

To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give the Utilities’ retail customers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. However, the Utilities compete 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 the Utilities become subject to deregulation, the recovery of “stranded costs” could become a significant consideration. Stranded costs primarily include the generation assets of 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). Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs.

Our largest stranded cost exposure is for PEF’s purchased power commitments with QFs, under which PEF has future minimum expected capacity payments through 2025 of $4.7 billion (See Notes 22A and 22B). PEF was obligated to enter into these contracts under provision of the Public Utilities Regulatory Policies Act of 1978. PEF 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. PEC does not have significant future minimum expected capacity payments under its purchased power commitments with QFs.

WHOLESALE COMPETITION

The Utilities compete with other utilities and merchant generators for bulk power sales and for sales to municipalities and cooperatives.

Increased competition in the wholesale electric utility industry and the availability of transmission access could affect the Utilities’ 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 the Utilities to attract new wholesale customers and to retain current wholesale customers who have existing contracts with PEC or PEF.

The FERC adopted final rules designed to 1) strengthen the pro forma open access transmission tariff (OATT) to ensure that it achieves its original purpose of remedying undue discrimination; 2) provide greater specificity in the pro forma OATT to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and facilitate the FERC’s enforcement; and 3) increase transparency in the rules applicable to planning and use of the transmission system. One of the most significant revisions to the pro forma OATT relates to the development of consistent methodologies for calculating available transfer capability, which determines whether transmission customers can access alternative power supplies. Other significant revisions include: changes to the transmission planning process; reform of energy and generator imbalance penalties; adoption of a “conditional firm” component to long-term point-to-point transmission service and reform of existing requirements for the provision of redispatch service; reform of rollover rights policy; clarification of tariff ambiguities; and increased transparency and customer access to information.

Certain details related to the rules, such as the precise methodology that will be used to calculate available transfer capability, remain to be determined, and thus it is difficult to make a determination of the overall effect of the new rules on the Utilities’ transmission operations or wholesale marketing function. However, on a preliminary basis, the rule is not anticipated to have a significant impact on the Utilities’ financial results. Nonetheless, the final rule is anticipated to include a wide range of provisions addressing transmission services, and as the new tariff is implemented there is likely to be a significant impact on the Utilities’ transmission operations, planning and wholesale marketing functions.

PEC and PEF are subject to regulation by the FERC with respect to transmission service, including generator interconnection service for facilities making sales for resale and wholesale sales of electric energy. FERC has approved, subject to modification, regional grid planning processes covering PEC and PEF. PEC and PEF made compliance filings with FERC in 2008. PEC received approval from the FERC in January 2010, and PEF is still awaiting FERC approval.

The FERC requires that entities desiring to make wholesale sales of electricity at market-based rates document that they do not possess market power. Market power is exercised when an entity profitably drives up prices through its control of a single activity, such as electricity generation, where it controls a significant share of the total capacity available to the market. The FERC has established screening measures for such determinations. Given the difficulty PEC believed it would experience in passing one of the screens, PEC revised its market-based rate tariffs in 2005 to restrict PEC to sales outside of its control area and peninsular Florida, and filed a new cost-based tariff for sales within PEC’s control area. Accordingly, PEC and PEF make wholesale sales of electricity at cost-based rates in areas inside of PEC’s control area and peninsular Florida and at market-based rates in areas outside of PEC’s control area and peninsular Florida. We do not anticipate that the operations of the Utilities will be materially impacted by this market-based rates decision.

FRANCHISE MATTERS

PEC has nonexclusive franchises with varying expiration dates in most of the municipalities in North Carolina and South Carolina in which it distributes electricity. In North Carolina, franchises generally continue for 60 years. In South Carolina, franchises continue in perpetuity unless terminated according to certain statutory methods. The general effect of these franchises is to provide for the manner in which PEC occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. Of PEC’s 240 franchises, the majority covers 60-year periods from the date enacted, and 45 have no specific expiration dates. Of the PEC franchise agreements with expiration dates, 13 expire during the period 2011 through 2015, and the remaining agreements expire between 2016 and 2070. PEC also provides service within a number of municipalities and in all of the unincorporated areas within its service area without franchise agreements.

PEF has nonexclusive franchises with varying expiration dates in 111 of the Florida municipalities in which it distributes electricity. PEF also provides service to 10 other municipalities and in all of the unincorporated areas within its service area without franchise agreements. The general effect of these franchises is to provide for the manner in which PEF occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. The PEF franchise agreements cover periods ranging from 10 to 30 years with the majority covering 30-year periods from the date enacted. Of PEF’s 111 franchise agreements, 39 expire between 2011 and 2015, and the remaining agreements expire between 2016 and 2040.

REGULATORY MATTERS

HOLDING COMPANY REGULATION

The Parent is a registered public utility holding company subject to regulation by the FERC, including provisions relating to the establishment of intercompany extensions of credit, sales, acquisitions of securities and utility assets, and services performed by PESC. The FERC also has authority over accounting and record retention and cost allocation jurisdiction at the election of the holding company system or the state utility commissions with jurisdiction over its utility subsidiaries.

UTILITY REGULATION

FEDERAL REGULATION

The Utilities are subject to regulation by a number of federal regulatory agencies, including the DOE, the North American Electric Reliability Corporation (NERC), the NRC and the United States Environmental Protection Agency (EPA).

Reliability Standards

The FERC has certified the NERC as the electric reliability organization that will propose and enforce mandatory reliability standards for the bulk power electric system. Included in this certification was a provision for the delegation of authority to audit, investigate and enforce reliability standards in particular regions of the country by entering into delegation agreements with regional entities. In addition, the regional entities have the ability to formulate additional reliability standards in their respective regions, which are required to supplement and be more stringent than the NERC reliability standards. The SERC Reliability Corporation (SERC) and the Florida Reliability Coordinating Council are the regional entities for PEC and PEF, respectively.

PEC and PEF are currently subject to certain reliability standards as registered users, owners and operators of the bulk power electric system. We expect existing reliability standards to migrate to more definitive and enforceable requirements over time and additional NERC and regional reliability standards to be approved by the FERC in coming years requiring us to take additional steps to remain compliant. The financial impact of mandatory compliance cannot currently be determined. Failure to comply with the reliability standards could result in the imposition of fines and civil penalties. If we are unable to meet the reliability standards for the bulk power electric system in the future, it could have a material adverse effect on our financial condition, results of operations and liquidity.

PEC and PEF have self-reported to the SERC and Florida Reliability Coordinating Council noncompliances and violations with the voluntary and mandatory standards from time to time. The noncompliances and violations have led to the development and implementation of mitigation plans at the Utilities. None of the noncompliances or violations noted above nor the costs of executing the mitigation plans are expected to have a significant impact on our overall compliance efforts, results of operations or liquidity.

Nuclear

The Utilities’ nuclear generating units are regulated by the NRC. The NRC is responsible for granting licenses for the construction, operation and retirement of nuclear power plants and subjects these plants to continuing review and regulation. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. See “Nuclear Matters.”

Environmental

The Utilities are also subject to regulation by the EPA. See “Environmental.”

STATE REGULATION

PEC is subject to regulation in North Carolina by the NCUC, and in South Carolina by the SCPSC. PEF is subject to regulation in Florida by the FPSC. The Utilities are regulated by their respective regulatory bodies with respect to, among other things, rates and service for electricity sold at retail; retail cost recovery of unusual or unexpected expenses, such as severe storm costs; and issuances of 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.

Retail Rate Matters

Each of the Utilities’ state utility commissions authorizes retail “base rates” that are designed to provide the respective utility with the opportunity to earn a reasonable rate of return on its “rate base,” or net investment in utility plant. These rates are intended to cover all reasonable and prudent expenses of constructing, operating and maintaining the utility system, except those covered by specific cost-recovery clauses.

In PEC’s most recent rate cases in 1988, the NCUC and the SCPSC each authorized a ROE of 12.75 percent.

In PEF’s most recent rate case settlement agreement approved by the FPSC in 2010, the FPSC authorized PEF the opportunity to earn a ROE of up to 11.5 percent.

On September 14, 2010, the FPSC approved a reduction to PEF’s AFUDC rate, from 8.848 percent to 7.44 percent, based on PEF’s updated authorized ROE. This new rate will be used for all purposes except for nuclear recoveries with original need petitions submitted on or before December 31, 2010, as permitted by FPSC regulations.

Retail Cost-Recovery Clauses

Each of the Utilities’ state utility commissions allows recovery of certain costs through various cost-recovery clauses, to the extent the respective commission determines in an annual hearing that such costs, including any past over- or under-recovered costs, are prudent. The clauses are in addition to the Utilities’ approved base rates. The Utilities generally do not earn a return on the recovery of eligible operating expenses under such clauses; however, in certain jurisdictions, the Utilities may earn interest 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. See MD&A – “Regulatory Matters and Recovery of Costs” for additional discussion regarding cost-recovery clauses.

Costs recovered by the Utilities through cost-recovery clauses, by retail jurisdiction, were as follows:

North Carolina Retail – fuel costs, the fuel and other portions of purchased power (capacity costs for purchases from dispatchable QFs are also recoverable), costs of new DSM and EE programs, costs of commodities such as ammonia and limestone used in emissions control technologies (Reagents), and eligible renewable energy costs;

·	South Carolina Retail – fuel costs, certain purchased power costs, costs of Reagents, sulfur dioxide (SO2) and nitrogen oxides (NOx) emission allowance expenses, and costs of new DSM and EE programs; and

·	Florida Retail – fuel costs, purchased power costs, capacity costs, qualified nuclear costs, energy conservation expense and specified environmental costs, including Clean Air Interstate Rule (CAIR) compliance costs, and SO2 and NOx emission allowance expenses.

Fuel, fuel-related costs and certain purchased power costs are eligible for recovery by the Utilities. The Utilities use coal, oil, hydroelectric (PEC only), 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 the Utilities, 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 the Utilities. PEF is obligated to file for a midcourse recovery between annual fuel hearings in the event its estimated over- or under-recovery of fuel costs meets or exceeds a threshold of 10 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.

Renewable Energy and Energy-Efficiency Standards

PEC is allowed to recover the costs of DSM and EE programs in North Carolina and South Carolina through an annual DSM and EE clause in each jurisdiction. PEC is allowed to capitalize DSM and EE costs intended to produce future benefits. In addition, the NCUC and the SCPSC have approved other forms of financial incentives for DSM and EE programs, including the recovery of net lost revenues and a performance incentive. DSM programs include, but are not limited to, any program or initiative that shifts the timing of electricity use from peak to nonpeak periods and includes load management, electricity system and operating controls, direct load control, interruptible load and electric system equipment and operating controls. EE programs include any equipment, physical or program change implemented after January 1, 2007, that results in less energy used to perform the same function. PEC has implemented a series of DSM and EE programs and will continue to pursue additional programs, which must be approved by the respective utility commissions. We cannot predict the outcome of DSM and EE filings currently pending approval or whether the implemented programs will produce the expected operational and economic results.

PEC is subject to renewable energy standards at the state level in North Carolina. North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS) establishes minimum standards for the use of energy

from specified renewable energy resources or implementation of energy-efficiency measures by the state’s electric utilities beginning with a 3 percent requirement in 2012 and increasing to 12.5 percent in 2021 for regulated public utilities, including PEC. The premium to be paid by electric utilities to comply with the requirements above the cost they would have otherwise incurred to meet consumer demand is to be recovered through an annual clause. The annual amount that can be recovered through the NC REPS clause is capped and once a utility has expended monies equal to the cap, the utility is deemed to have met its obligations, regardless of the actual renewables generated or purchased. The NCUC has the authority to modify or alter the NC REPS requirements if the NCUC determines it is in the public interest to do so.

Florida energy law enacted in 2008 includes provisions for development of a renewable portfolio standard for Florida utilities. The FPSC provided a draft Florida renewable portfolio standard rule with a goal of 20 percent renewable energy production by 2020 to the Florida legislature in February 2009, but the legislature has not taken action on the draft rule. We cannot predict the outcome of this matter. Until the rulemaking processes are completed, we cannot predict the costs of complying with the law, but PEF would be able to recover its reasonable and prudent compliance costs.

On December 30, 2009, the FPSC ordered PEF to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. As subsequently revised by the FPSC in 2010, PEF’s aggregate conservation goals over the next 10 years are: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). PEF filed a revised proposed DSM plan on November 29, 2010, which would result in 1,540 GWh of energy savings from 2011-2019, seven times more than PEF’s historic goals. We cannot predict the outcome of this matter.

See Note 7 for further discussion of regulatory matters.

NUCLEAR MATTERS

GENERAL

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.

PEC owns and operates four nuclear generating units: Brunswick Nuclear Plant (Brunswick) Unit No. 1 and Unit No. 2, Harris, and Robinson Nuclear Plant (Robinson). The NRC has renewed the operating licenses for all of PEC’s nuclear plants. The renewed operating licenses for Brunswick No. 1 and No. 2, Harris and Robinson expire in September 2036, December 2034, October 2046 and July 2030, respectively.

PEF owns and operates one nuclear generating unit, CR3. The NRC operating license for CR3 currently expires in December 2016. On March 9, 2009, the NRC docketed, or accepted for review, PEF’s application for a 20-year renewal on the operating license for CR3, which, if approved, would extend the operating license through 2036, the current useful life used by the FPSC in base rates. The license renewal application for CR3 is currently under review by the NRC with a decision expected in 2011.

Over time, PEC and PEF have made various modifications to their nuclear facilities to increase the energy output. During CR3’s fueling and maintenance outage that began in September 2009, PEF commenced a project to replace CR3’s steam generators. During preparations to replace the steam generators, we discovered a delamination within the concrete of the outer wall of the containment structure. After a comprehensive analysis, we have determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when we created an opening to accommodate the replacement of the unit’s steam generators. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. Nuclear safety remains our top priority, and our plans and actions will continue to reflect that commitment. A number of factors affect the return to service date, including regulatory reviews by the NRC and

other agencies, emergent work, final engineering designs, testing, weather and other developments. PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages as well as accidental property damage. PEF’s insurer has confirmed that the CR3 delamination event is a covered accident. PEF is working with its insurer for recovery of applicable repair costs and replacement power. See Note 7C.

The NRC periodically issues bulletins and orders addressing industry issues of interest or concern that necessitate a response from the industry. It is our intent to comply with and to complete required responses in a timely and accurate manner. Any potential impact to company operations will vary and will be dependent upon the nature of the requirement(s).

POTENTIAL NEW CONSTRUCTION

While we have not made a final determination on new nuclear construction, we continue to take steps to keep open the option of building one or more plants. During 2008, PEC and PEF filed COL applications to potentially construct new nuclear plants in North Carolina and Florida. The NRC estimates that it will take approximately three to four years to review and process the COL applications. We have focused on PEF’s potential construction at Levy given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce GHG emissions as well as existing state legislative policy that is supportive of nuclear projects.

LEVY

In 2006, we announced that PEF selected a greenfield site at Levy to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application submission. In 2007, PEF completed the purchase of approximately 5,000 acres for Levy and associated transmission needs.

In 2008, the FPSC issued a final order granting PEF’s petition for a Determination of Need for Levy. In 2009, the Power Plant Siting Board, comprised of the governor and the Cabinet, issued the Levy site certification that addresses permitting, land use and zoning, and property interests and replaces state and local permits. Certification grants approval for the location of the power plant and its associated facilities such as roadways and electrical transmission lines carrying power to the electrical grid, among others. Certification does not include licenses required by the federal government.

On July 30, 2008, PEF filed its COL application with the NRC for two reactors, which was docketed, or accepted for review, by the NRC on October 6, 2008. Docketing the application does not preclude additional requests for information as the review proceeds, nor does it indicate whether the NRC will issue the license. On February 24, 2009, PEF received the NRC’s schedule for review and approval of the COL. One joint petition to intervene in the licensing proceeding was filed with the NRC within the 60-day notice period by the Green Party of Florida, the Nuclear Information and Resource Service and the Ecology Party of Florida. On April 20-21, 2009, the Atomic Safety Licensing Board (ASLB) heard oral arguments on whether any of the joint interveners’ proposed contentions will be admitted in the Levy COL proceeding. On July 8, 2009, the ASLB issued a decision accepting three of the 12 contentions submitted. The admitted contentions involved questions about the potential safety and environmental impact of storage of low-level radioactive waste, the potential impacts of plant construction and operation on the aquifer and surrounding waters and the potential impact of salt water drift from cooling tower operation. In April 2010, the ASLB dismissed the contention regarding the safety of storage of low-level radioactive waste; however, interveners have resubmitted their contention regarding the potential safety of storage of low-level waste, which is being considered by the ASLB. PEF’s appeal of the ASLB’s 2009 decision was denied and a hearing on the remaining contentions will be conducted in 2012. Other COL applicants have received similar petitions raising similar potential contentions. We cannot predict the outcome of this matter.

PEF also completed and submitted a Limited Work Authorization request for Levy concurrent with the COL application. PEF’s initial schedule anticipated performing certain site work pursuant to the Limited Work Authorization prior to COL receipt. However, in 2009, the NRC Staff determined that certain schedule-critical work that PEF had proposed to perform within the scope of the Limited Work Authorization will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work will be shifted until after COL

issuance. This factor alone resulted in a minimum 20-month schedule shift later than the projected in-service dates for Units No. 1 and No. 2 of June 2016 and June 2017, respectively, included in the petition for a Determination of Need. Subsequent changes in regulatory and economic conditions have resulted in additional schedule shifts. These conditions include the permitting and licensing process, national and state economic conditions, recent FPSC DSM goals and the resulting impact on ratepayers, and other FPSC decisions. Uncertainty regarding PEF’s access to capital on reasonable terms, its ability to secure joint owners and increasing uncertainty surrounding carbon regulation and its costs could be other factors to affect the Levy schedule.

As disclosed in PEF’s 2010 nuclear cost-recovery filing, the schedule shifts will reduce the near-term capital expenditures for the project and also reduce the near-term impact on customer rates (See Note 7C). PEF will postpone major construction activities on the project until after the NRC issues the COL, which is expected to be in 2013 if the current licensing schedule remains on track. The schedule shifts will also allow more time for certainty around federal climate change policy. We believe that continuing, although at a slower pace than initially anticipated, is a reasonable and prudent course at this early stage of the project. Taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification, we consider Levy to be PEF’s preferred baseload generation option. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, public, regulatory and political support; adequate financial cost-recovery mechanisms; adequate levels of joint owner participation; customer rate impacts; project feasibility, including comparison to other generation options, DSM and EE programs; and availability and terms of capital financing. If the licensing schedule remains on track and if the decision to build is made, the first of the two proposed units could be in service in 2021. The second unit could be in service 18 months later.

PEF signed the EPC agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two Westinghouse AP1000 nuclear units to be constructed at Levy. More than half of the approximate $7.650 billion contract price is fixed or firm with agreed upon escalation factors. The EPC agreement includes various incentives, warranties, performance guarantees, liquidated damage provisions and parent guarantees designed to incent the contractor to perform efficiently. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. We executed an amendment to the EPC agreement in 2010 due to the schedule shifts previously discussed. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items and PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. In its 2010 nuclear cost-recovery filing, approved by the FPSC on October 26, 2010, PEF included for rate-making purposes a point estimate of potential Levy disposition fees and charges of $50 million, subject to true-up. However, the amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed. We cannot predict the outcome of this matter.

The total escalated cost for the two generating units was estimated in PEF’s petition for the Determination of Need for Levy to be approximately $14 billion. This total cost estimate included land, plant components, financing costs, construction, labor, regulatory fees and the initial core for the two units. An additional $3 billion was estimated for the necessary transmission equipment and approximately 200 miles of transmission lines associated with the project. PEF’s 2010 nuclear cost-recovery filing included an updated analysis that demonstrated continued feasibility of the Levy project with PEF’s current estimated range of total escalated cost, including transmission, of $17.2 billion to $22.5 billion. The filed estimated cost range primarily reflects cost escalation resulting from the schedule shifts. Many factors will affect the total cost of the project and once PEF receives the COL, it will further refine the project timeline and budget. As previously discussed, we will continue to evaluate the Levy project on an ongoing basis.

Florida regulations allow investor-owned utilities such as PEF to recover the retail portion of prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balances of a nuclear power plant prior to commercial operation. The costs are recovered on an annual basis through the Capacity Cost-Recovery

Clause (CCRC). Such amounts will not be included in a utility’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered retail portion of construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility (See Note 7C).

HARRIS

In 2006, we announced that PEC selected a site at Harris to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. On February 19, 2008, PEC filed its COL application with the NRC for two additional reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application. If we receive approval from the NRC and applicable state agencies, and if the decision to build is made, a new plant would not be online until the middle of the next decade.

PEC’s jurisdictions also have laws regarding nuclear baseload generation. South Carolina law includes provisions for cost-recovery mechanisms associated with nuclear baseload generation. North Carolina law authorizes the NCUC to allow annual prudence reviews of baseload generating plant construction costs and inclusion of construction work in progress in rate base with corresponding rate adjustment in a general rate case while a baseload generating plant is under construction.

SECURITY

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. We are working to complete the requirements as outlined in the orders by November 30, 2011. 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.

SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE

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. We will continue to maximize the use of spent fuel storage capability within our own facilities for as long as feasible.

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. We 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, Nev. See Note 22C for information about the complaint filed by the Utilities 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 the 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, the Utilities 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, Brunswick and CR3, the Utilities’ 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.

DECOMMISSIONING

In the Utilities’ retail jurisdictions, provisions for nuclear decommissioning costs are approved by the respective state utility commissions and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are approved by the FERC. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. See Note 4C for a discussion of the Utilities’ nuclear decommissioning costs.

ENVIRONMENTAL

GENERAL

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot be precisely estimated. The current estimated capital costs associated with compliance with pollution control laws and regulations that we expect to incur are included within MD&A – “Liquidity and Capital Resources – Capital Expenditures.”

The foundation for Progress Energy’s environmental leadership strategy begins with its environmental management system. Under the environmental management system, the Environmental, Health and Safety Performance Council, which is comprised of senior executives, provides overall strategic direction, guides corporate environmental policy, monitors environmental regulatory compliance and approves targets that measure, track and drive performance. Our environmental activities are reported to our board of directors’ Operations and Nuclear Oversight Committee. The committee is responsible for climate change oversight and strategy and, therefore, assesses our plans and activities and makes recommendations to the full board regarding these matters. We have established a process to identify environmental risks, take prompt action to address these issues and ensure appropriate senior management oversight on a routine basis.

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida or potentially responsible parties (PRP) groups. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 7 and 21). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted.

While we accrue for probable costs that can be reasonably estimated, based upon the current status of some sites, not all costs can be reasonably estimated or accrued and actual costs may materially exceed our accruals. Material costs in excess of our accruals could have an adverse impact on our financial condition and results of operations. Hazardous and solid waste management matters are discussed in detail in Note 21A.

GLOBAL CLIMATE CHANGE

Global climate change is one of the primary corporate environmental risks identified by our environmental management system. Our risks associated with climate change are discussed under Item 1A, “Risk Factors.”

Growing state, federal and international attention to global climate change may result in the regulation of carbon dioxide (CO2) and other GHGs. The EPA has announced a schedule for development of a new source performance standard for new and existing fossil fuel-fired electric utility units. Under the schedule, the EPA will propose the standard by July 2011 and issue the final rule by May 2012. The full impact of regulation under GHG initiatives and final legislation, if enacted, cannot be determined at this time; however, we anticipate that it could result in significant rate increases over time to recover the costs of compliance.

As previously discussed under “Recent Developments,” we are preparing for a carbon-constrained future and are actively engaged in helping shape effective policies to address the issue. We are taking steps to address global climate change by changing the way we generate electricity through our balanced solution strategy of EE, alternative energy and a state-of-the-art power system as discussed in MD&A – “Other Matters – Energy Demand.” We continuously evaluate new generation options to determine if they are cost effective for the Southeastern United States where our operations are located.

See Note 21 and MD&A – “Other Matters – Environmental Matters” for additional discussion of our environmental matters, including specific environmental issues, the status of the issues, accruals associated with issue resolutions and our associated exposures.

EMPLOYEES

At February 22, 2011, we employed approximately 11,000 full-time employees. Of this total, approximately 2,000 employees at PEF are represented by the International Brotherhood of Electrical Workers (IBEW). The three-year labor contract with the IBEW expires in December 2011. Contract negotiations are expected to begin in the fall of 2011. We cannot predict the outcome of the contract negotiations. We consider our relationship with employees, including those covered by collective bargaining agreements, to be good.

We have a noncontributory defined benefit retirement (pension) plan for substantially all full-time employees and an employee stock ownership plan among other employee benefits. We also provide contributory postretirement benefits, including certain health care and life insurance benefits, for substantially all retired employees.

At February 22, 2011, PEC and PEF employed approximately 5,500 and 4,000 full-time employees, respectively.

SEASONALITY AND THE IMPACT OF WEATHER

Seasonal differences in the weather affect demand for electricity. The Utilities experience higher demand during the summer and winter months. As a result, our overall operating results may fluctuate substantially on a seasonal basis.

Beyond the impact of seasonality, deviations from normal weather conditions can significantly affect our financial performance. Our residential and commercial customers are most impacted by weather. Industrial customers are less weather sensitive. We define normal weather conditions as the long-term average of actual historical weather conditions. The number of years used to calculate normal weather is determined by management and differs by jurisdiction.

We estimate the impact of weather on our earnings based on the number of customers, temperature variances from a normal condition and the amount of electricity the average residential, commercial and some governmental customers historically demonstrated to use per degree day. Our 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. PEC’s base temperature for heating- and cooling-degree days is

65° Fahrenheit for all customer classes. PEF’s base temperatures vary by customer class, ranging from 65° to 70° Fahrenheit for cooling-degree days and 55° to 65° Fahrenheit for heating-degree days.

PEC

GENERAL

PEC 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. At December 31, 2010, PEC had a total summer generating capacity (including jointly owned capacity) of 12,554 MW. For additional information about PEC’s generating plants, see “Electric – PEC” in Item 2, “Properties.” PEC’s system normally experiences its highest peak demands during the summer, and the all-time system peak of 12,656 megawatt-hours (MWh) was set on August 9, 2007.

PEC’s service territory 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, 2010, PEC was providing electric services, retail and wholesale, to approximately 1.5 million customers. Major wholesale power sales customers include North Carolina Eastern Municipal Power Agency (Power Agency), North Carolina Electric Membership Corporation and Public Works Commission of the City of Fayetteville, North Carolina. Major industries in PEC’s service area include chemicals, textiles, paper, food, metals, wood products, rubber and plastics and stone products. No single customer accounts for more than 10 percent of PEC’s revenues.

PEC’s net income available to parent was $600 million, $513 million and $531 million for the years ended December 31, 2010, 2009 and 2008, respectively. PEC’s total assets were $14.899 billion and $13.502 billion at December 31, 2010 and 2009, respectively.

REVENUES

See “Electric Utility Regulated Operating Statistics – PEC” for information about energy sales and operating revenues.

FUEL AND PURCHASED POWER

SOURCES OF GENERATION

PEC’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEC’s customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies.

See “Electric Utility Regulated Operating Statistics – PEC” for generated and purchased energy supply by source and PEC’s average fuel cost.

PEC’s total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table:

	2010			2009			2008
Coal		47	%		44	%		45	%
Nuclear		38	%		44	%		43	%
Oil/Gas		8	%		6	%		4	%
Purchased Power		6	%		5	%		7	%
Hydro		1	%		1	%		1	%

PEC is generally permitted to pass the cost of fuel and certain purchased power costs to its customers through fuel cost-recovery clauses. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. See “Commodity Price Risk” under Item 7A,

“Quantitative and Qualitative Disclosures About Market Risk” and Item 1A, “Risk Factors.” However, PEC believes that its fuel supply contracts, as described below and in Note 22A, will be adequate to meet its fuel supply needs.

Coal

PEC anticipates a burn requirement of approximately 11.2 million tons of coal in 2011. Approximately 90 percent of the coal is expected to be supplied from Central Appalachian, 5 percent from Northern Appalachian, and 5 percent from Illinois Basin coal sources and will be primarily delivered by rail.

For 2011, PEC has short-term, intermediate and long-term agreements from various sources for approximately 100 percent of its estimated burn requirements of its coal units. The contracts have expiration dates ranging from one to ten years. PEC will continue to sign contracts of various lengths, terms and quality to meet its expected burn requirements.

As discussed within Note 7B, PEC has announced that it intends to retire certain coal-fired units representing approximately 30 percent of its coal-fired power generation fleet no later than the end of 2014 as part of a major coal-to-gas modernization strategy. See “Oil and Gas” for planned gas facilities.

Nuclear

Nuclear fuel is processed through four distinct stages: uranium ore mining and milling, conversion, enrichment, and fabrication. PEC has sufficient contracts for each stage to meet its nuclear fuel requirement needs for the foreseeable future. PEC’s nuclear fuel contracts typically have terms ranging from three to fifteen years. For a discussion of PEC’s plans with respect to spent fuel storage, see “Nuclear Matters.”

Oil and Gas

The NCUC has granted PEC permission to construct three new generating facilities: an approximately 600-MW combined cycle dual-fuel facility at its Richmond County, N.C., generating facility, an approximately 950-MW combined cycle natural gas-fueled facility at a site in Wayne County, N.C., and an approximately 620-MW natural gas-fueled generating facility at its Sutton coal plant site in New Hanover County, N.C. The facilities are expected to be placed in service in June 2011, January 2013 and December 2013, respectively.

Oil and natural gas supply for PEC’s generation fleet is purchased under term and spot contracts from various suppliers. PEC uses derivative instruments to limit its exposure to price fluctuations for natural gas. PEC has dual-fuel generating facilities that can operate with both oil and gas. The cost of PEC’s oil and gas is either at a fixed price or determined by market prices as reported in certain industry publications. PEC believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. PEC’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate and intrastate pipelines. PEC may also purchase additional shorter-term transportation for its load requirements during peak periods.

Purchased Power

PEC purchased approximately 4.0 million MWh, 3.3 million MWh and 4.7 million MWh of its system energy requirements during 2010, 2009 and 2008, respectively, under purchase obligations and operating leases and had 1,332 MW of firm purchased capacity under contract during 2010. PEC may need to acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. PEC 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.

Hydroelectric

PEC has three hydroelectric generating plants licensed by the FERC: Walters, Tillery and Blewett. PEC also owns the Marshall Plant, which has a license exemption. The total summer generating capacity for all four units is 225 MW. PEC submitted an application to relicense its Tillery and Blewett Plants for 50 years and anticipates a decision by the FERC in 2011. The Walters Plant license will expire in 2034.

PEF

GENERAL

PEF 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. At December 31, 2010, PEF had a total summer generating capacity (including jointly owned capacity) of 10,025 MW. For additional information about PEF’s generating plants, see “Electric – PEF” in Item 2, “Properties.” PEF’s system normally experiences its highest peak demands during the winter, and the all-time system peak of 10,822 MWh was set on January 11, 2010.

PEF’s service territory 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. PEF is interconnected with 22 municipal and 9 rural electric cooperative systems. At December 31, 2010, PEF was providing electric services, retail and wholesale, to approximately 1.6 million customers. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., the city of Gainesville, Reedy Creek Improvement District, Florida Municipal Power Agency and the city of Winter Park. Major industries in PEF’s territory include phosphate rock mining and processing, electronics design and manufacturing, and citrus and other food processing. Other major commercial activities are tourism, health care, construction and agriculture. No single customer accounts for more than 10 percent of PEF’s revenues.

PEF’s net income available to parent was $451 million, $460 million and $383 million for the years ended December 31, 2010, 2009 and 2008, respectively. PEF’s total assets were $14.056 billion and $13.100 billion at December 31, 2010 and 2009, respectively.

REVENUES

See “Electric Utility Regulated Operating Statistics – PEF” for information about energy sales and operating revenues.

FUEL AND PURCHASED POWER

SOURCES OF GENERATION

PEF’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEF’s customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies.

See “Electric Utility Regulated Operating Statistics – PEF” for PEF’s energy supply by source and energy fuel cost.

PEF’s total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table:

	2010			2009			2008
Oil/Gas		54	%		44	%		34	%
Coal		26	%		25	%		30	%
Purchased Power		20	%		20	%		21	%
Nuclear(a)		-	%		11	%		15	%

(a)

Due to the extended outage at CR3 nuclear generating unit that began in September 2009, no nuclear power was generated in 2010.

PEF is generally permitted to pass the cost of fuel and certain purchased power to its customers through fuel cost-recovery clauses. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. See “Commodity Price Risk” under Item 7A, “Quantitative

and Qualitative Disclosures About Market Risk” and Item 1A, “Risk Factors.” However, PEF believes that its fuel supply contracts, as described below and in Note 22A, will be adequate to meet its fuel supply needs.

Oil and Gas

Oil and natural gas supply for PEF’s generation fleet is purchased under term and spot contracts from various suppliers. PEF uses derivative instruments to limit its exposure to price fluctuations for natural gas and oil. PEF has dual-fuel generating facilities that can operate with both oil and gas. The cost of PEF’s oil and gas is either at a fixed price or determined by market prices as reported in certain industry publications. PEF believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. PEF’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate pipelines. PEF may also purchase additional shorter-term transportation for its load requirements during peak periods.

Coal

PEF anticipates a burn requirement of approximately 4.5 million tons of coal in 2011. Approximately 75 percent of the coal is expected to be supplied from the Illinois Basin, 20 percent from Central Appalachian and 5 percent from Northern Appalachian coal sources. Approximately 20 percent of the coal is expected to be delivered by rail and the remainder by water.

For 2011, PEF has intermediate and long-term contracts from various sources for approximately 90 percent of its estimated burn requirements of its coal units. These contracts have price adjustment provisions and have expiration dates ranging from one to ten years.

Purchased Power

PEF purchased approximately 9.5 million MWh, 8.7 million MWh and 10.2 million MWh of its system energy requirements during 2010, 2009 and 2008, respectively, under purchase obligations, operating leases and capital leases and had 3,275 MW of firm purchased capacity under contract during 2010. These agreements include approximately 682 MW of firm capacity under contract with certain QFs. PEF may need to acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. PEF 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.

Nuclear

Nuclear fuel is processed through four distinct stages: uranium ore mining and milling, conversion, enrichment, and fabrication. PEF has sufficient contracts for each stage to meet its nuclear fuel requirement needs for the foreseeable future. PEF’s nuclear fuel contracts typically have terms ranging from three to fifteen years. For a discussion of PEF’s plans with respect to spent fuel storage, see “Nuclear Matters.”

CORPORATE AND OTHER

Corporate and Other primarily includes the operations of the Parent and PESC. The Parent’s unallocated interest expense is included in Corporate and Other. PESC provides centralized administrative, management and support services to our subsidiaries, which generates essentially all of the segment’s revenues. See Note 18 for additional information about PESC services provided and costs allocated to subsidiaries. This segment also includes miscellaneous nonregulated business areas that do not separately meet the quantitative disclosure requirements as a reportable business segment.

The Corporate and Other segment’s net loss attributable to controlling interests was $195 million, $216 million and $84 million for the years ended December 31, 2010, 2009 and 2008, respectively. Corporate and Other segment total assets were $21.110 billion and $20.538 billion at December 31, 2010 and 2009, respectively, which were primarily comprised of the Parent’s investments in subsidiaries.

ELECTRIC UTILITY REGULATED OPERATING STATISTICS – PROGRESS ENERGY
	Years Ended December 31
	2010		2009		2008			2007			2006
Energy supply (millions of kWH)
Generated
Steam		44,971		40,420		46,771			51,163			48,770
Nuclear		21,624		29,412		30,565			30,336			30,602
Combustion turbines/combined cycle		27,856		21,254		15,557			13,319			11,857
Hydro		608		651		429			415			594
Purchased		13,473		11,996		14,956			14,994			14,664
Total energy supply (company share)(a)		108,532		103,733		108,278			110,227			106,487
Jointly owned share(a) (b)		5,228		5,500		5,780			5,351			5,224
Total system energy supply		113,760		109,233		114,058			115,578			111,711
Average fuel costs (per million Btu)
Oil	$	13.15	$	11.78	$	9.60		$	8.70		$	7.14
Gas	$	6.92	$	8.36	$	10.14		$	8.67		$	7.90
Coal	$	3.70	$	3.85	$	3.50		$	3.06		$	2.99
Nuclear	$	0.59	$	0.53	$	0.46		$	0.45		$	0.44
Weighted-average	$	3.90	$	3.79	$	3.66		$	3.17		$	2.86
Energy sales (millions of kWH)
Retail
Residential		39,632		36,516		36,328			37,112			36,280
Commercial		26,080		25,523		26,080			26,215			25,333
Industrial		13,884		13,653		15,174			15,721			16,553
Other retail		4,860		4,753		4,768			4,805			4,695
Unbilled		630		491		(107	)		(61	)		(272	)
Wholesale		17,856		17,801		21,063			21,333			19,018
Total energy sales		102,942		98,737		103,306			105,125			101,607
Company uses and losses		5,590		4,996		4,972			5,102			4,880
Total energy requirements		108,532		103,733		108,278			110,227			106,487
Operating revenues (in millions)
Retail
Billed	$	8,714	$	8,449	$	7,585		$	7,672		$	7,429
Unbilled		28		14		7			1			(6	)
Wholesale		1,080		1,114		1,288			1,191			1,039
Miscellaneous revenue		354		301		280			270			263
Total operating revenues of the Utilities	$	10,176	$	9,878	$	9,160		$	9,134		$	8,725

(a)

The extended outage at PEF's CR3 nuclear generating unit that began in September 2009 impacted the energy supply mix in 2010 and 2009.

(b)

Amounts represent joint owners' share of the energy supplied from the six generating facilities that are jointly owned.

ELECTRIC UTILITY REGULATED OPERATING STATISTICS – PEC
	Years Ended December 31
	2010		2009		2008			2007			2006
Energy supply (millions of kWH)
Generated
Steam		30,528		27,261		28,363			30,770			28,985
Nuclear		21,624		24,467		24,140			24,212			24,220
Combustion turbines/combined cycle		5,429		3,634		2,795			2,960			2,106
Hydro		608		651		429			415			594
Purchased		3,985		3,251		4,735			3,901			4,229
Total energy supply (company share)		62,174		59,264		60,462			62,258			60,134
Jointly owned share(a)		5,228		5,057		5,205			4,800			4,649
Total system energy supply		67,402		64,321		65,667			67,058			64,783
Average fuel costs (per million Btu)
Oil	$	14.34	$	14.84	$	16.05		$	12.28		$	11.04
Gas	$	6.59	$	8.17	$	10.66		$	9.19		$	9.87
Coal	$	3.56	$	3.82	$	3.39		$	2.96		$	2.90
Nuclear	$	0.59	$	0.53	$	0.46		$	0.44		$	0.43
Weighted-average	$	2.69	$	2.60	$	2.44		$	2.21		$	2.06
Energy sales (millions of kWH)
Retail
Residential		19,108		17,117		17,000			17,200			16,259
Commercial		14,184		13,639		13,941			14,032			13,358
Industrial		10,665		10,368		11,388			11,901			12,393
Other retail		1,574		1,497		1,466			1,438			1,419
Unbilled		172		360		(8	)		(55	)		(137	)
Wholesale		13,999		13,966		14,329			15,309			14,584
Total energy sales		59,702		56,947		58,116			59,825			57,876
Company uses and losses		2,472		2,317		2,346			2,433			2,258
Total energy requirements		62,174		59,264		60,462			62,258			60,134
Operating revenues (in millions)
Retail
Billed	$	4,044	$	3,801	$	3,582		$	3,534		$	3,268
Unbilled		11		5		8			-			(1	)
Wholesale		729		707		737			754			720
Miscellaneous revenue		138		114		102			97			99
Total operating revenues	$	4,922	$	4,627	$	4,429		$	4,385		$	4,086

(a)

Amounts represent joint owners' share of the energy supplied from the four generating facilities that are jointly owned.

ELECTRIC UTILITY REGULATED OPERATING STATISTICS – PEF
	Years Ended December 31
	2010		2009		2008			2007			2006
Energy supply (millions of kWH)
Generated
Steam		14,443		13,159		18,408			20,393				19,785
Nuclear		-		4,945		6,425			6,124				6,382
Combustion turbines/combined cycle		22,427		17,620		12,762			10,359				9,751
Purchased		9,488		8,745		10,221			11,093				10,435
Total energy supply (company share)(a)		46,358		44,469		47,816			47,969				46,353
Jointly owned share(a) (b)		-		443		575			551				575
Total system energy supply		46,358		44,912		48,391			48,520				46,928
Average fuel costs (per million Btu)
Oil	$	12.96	$	11.43	$	9.24		$	8.54			$	7.03
Gas	$	7.00	$	8.40	$	10.03		$	8.51			$	7.41
Coal	$	4.09	$	4.25	$	3.74		$	3.28			$	3.16
Nuclear	$	-	$	0.52	$	0.49		$	0.48			$	0.50
Weighted-average	$	6.14	$	5.88	$	5.67		$	4.85			$	4.21
Energy sales (millions of kWH)
Retail
Residential		20,524		19,399		19,328			19,912				20,021
Commercial		11,896		11,884		12,139			12,183				11,975
Industrial		3,219		3,285		3,786			3,820				4,160
Other retail		3,286		3,256		3,302			3,367				3,276
Unbilled		458		131		(99	)		(6	)			(135	)
Wholesale		3,857		3,835		6,734			6,024				4,434
Total energy sales		43,240		41,790		45,190			45,300				43,731
Company uses and losses		3,118		2,679		2,626			2,669				2,622
Total energy requirements		46,358		44,469		47,816			47,969				46,353
Operating revenues (in millions)
Retail
Billed	$	4,670	$	4,648	$	4,003		$	4,138			$	4,161
Unbilled		17		9		(1	)		1				(5	)
Wholesale		351		407		551			437				319
Miscellaneous revenue		216		187		178			173				164
Total operating revenues	$	5,254	$	5,251	$	4,731		$	4,749			$	4,639

(a)

The extended outage at PEF's CR3 nuclear generating unit that began in September 2009 impacted the energy supply mix in 2010 and 2009.

(b)

Amounts represent joint owners' share of the energy supplied from the two generating facilities that are jointly owned. Replacement power was supplied to the CR3 joint owners in 2010 from other generation sources or purchased power.

ITEM 1A. RISK FACTORS

Investing in the securities of the Progress Registrants involves risks, including the risks described below, that could affect the Progress Registrants and their businesses, as well as the energy industry in general. Most of the business information, as well as the financial and operational data contained in our risk factors, is updated periodically in the reports the Progress Registrants file with the SEC. Before purchasing securities of the Progress Registrants, you should carefully consider the following risks and the other information in this combined Annual Report, as well as the documents the Progress Registrants file with the SEC from time to time. Each of the risks described below could result in a decrease in the value of the securities of the Progress Registrants and your investment therein.

Solely with respect to this Item 1A, “Risk Factors,” unless the context otherwise requires or the disclosure otherwise indicates, references to “we,” “us” or “our” are to each of the individual Progress Registrants, and the matters discussed are generally applicable to each Progress Registrant.

We may be unable to obtain the approvals required to complete our merger with Duke Energy or, obtaining required governmental and regulatory approvals may require the combined company to comply with restrictions or conditions that may materially impact the anticipated benefits of the Merger.

On January 10, 2011, we announced the execution of a definitive merger agreement with Duke Energy. Before the Merger may be completed, shareholder approval must be obtained by both companies. In addition, various filings must be made with the NCUC, the SCPSC, the Kentucky Public Service Commission, the FERC, the NRC and various utility regulatory, antitrust and other regulatory authorities in the United States. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following consummation that may materially impact the anticipated benefits of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, which could have a material adverse effect on the financial results of the combined company and/or cause either party to abandon the Merger.

We are also subject to the risk that a required condition to the Merger may not be satisfied. Both companies are targeting to complete the Merger in 2011 but are subject to uncertainties related to the timing needed to consummate the Merger.

In the event that the Merger Agreement is terminated prior to the completion of the Merger, we could incur significant transaction costs that could materially impact our financial performance and results. Failure to complete the Merger could also negatively impact our stock price and our future business and financial results.

We will incur significant merger transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the Merger. If the Merger is not completed, depending upon the reasons for not completing the Merger, including whether we have received or entered into a competing takeover proposal, we may be required to pay Duke Energy a termination fee of $400 million. The occurrence of either of these events individually or in combination could have a material adverse affect on our financial results.

If completed, our merger with Duke Energy may not achieve the anticipated results and benefits.

We and Duke Energy entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies primarily relating to the regulated businesses. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether our businesses and the businesses of Duke Energy can be integrated in an efficient, effective and timely manner. As noted above, as a result of obtaining all necessary regulatory approvals, certain restrictions or conditions may be imposed on the combined company that materially impact or limit the benefits anticipated by us as a result of the Merger. The combined company is also subject to the risk that the expected cost savings and operational synergies may not be fully realized. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected liquidity provided by the combined company and diversion of management's time and energy and could have an adverse effect on the combined company's business, financial results and prospects.

We will be subject to business uncertainties and contractual restrictions while the merger with Duke Energy is pending that could adversely affect our financial results.

Uncertainty about the effect of the Merger on employees or suppliers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause suppliers and others that deal with us to seek to change existing business relationships.

Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our business operations and financial results could be adversely affected.

Merger- and integration-related issues will place a significant burden on management and internal resources. The diversion of management time on merger-related issues could affect our financial results.

In addition, the Merger Agreement restricts us, without Duke Energy's consent, from making certain acquisitions and taking other specified actions, including limiting our total capital spending, limiting the extent to which we can obtain financing through long-term debt and equity issuances or increasing the Parent’s common stock dividend rate until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to consummation of the Merger or termination of the Merger Agreement. Unless the Merger Agreement is terminated earlier, we and Duke Energy will each have the right to terminate the Merger Agreement if the Merger has not been completed by January 8, 2012 (which date is subject to extension under certain circumstances).

We are subject to fluid and complex government regulations that may have a negative impact on our business, financial condition and results of operations.

We are subject to comprehensive regulation by multiple federal, state and local regulatory agencies, which significantly influences our operating environment and may affect our ability to recover costs from utility customers. We are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of our business, including customer rates, retail service territories, reliability of our transmission system, applicable renewable energy and energy-efficiency standards, environmental compliance, issuances of securities, asset acquisitions and sales, accounting policies and practices, and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws. Changes in laws and regulations as well as changes in federal administrative policy are ongoing and the ultimate costs of compliance cannot be precisely estimated. Such changes could have an adverse impact on our financial condition and results of operations, particularly if the costs of those changes are not fully recoverable from our ratepayers.

The rates that PEC and PEF may charge retail customers for electric power are subject to the authority of state regulators. Accordingly, our profit margins and ability to earn an adequate return on investment could be adversely affected if we do not control and prudently manage costs to the satisfaction of regulators, or if we do not obtain successful outcomes in our regulatory proceedings. Such regulatory decisions may be impacted by economic and public policy considerations within the respective jurisdictions.

The NCUC, the SCPSC and the FPSC each exercise regulatory authority for review and approval of the retail electric power rates charged within its respective state. The Utilities’ state utility commissions approve base rates, which by law must give a utility a reasonable opportunity to recover its operating costs and return on invested capital. They also approve recovery through cost-recovery clauses of certain additional costs, known as “pass-through” costs, which vary by jurisdiction; examples include fuel costs, certain purchased power costs, qualified nuclear costs and specified environmental costs. The commissions can disagree with our request of appropriate base

rates, and can disallow either requested base rates or pass-through recoveries on the grounds that such costs were not reasonable and prudent.

The Utilities expect increased future expenditures in several key areas including, but not limited to, environmental compliance, new and existing generation, transmission and distribution facilities, renewable energy and energy-efficiency standards compliance (as applicable), DSM programs and fuel and other commodities. Such cost increases will be subject to scrutiny from regulators, policymakers and ratepayers. As referenced above, the commissions may disallow any costs that they find unreasonable and imprudent.

Our financial performance depends on the successful operation of electric generating facilities by the Utilities and their ability to deliver electricity to customers.

Operating our electric generating facilities and delivery systems involves many risks, including:

§	operator error and breakdown or failure of equipment or processes, including repair and replacement power costs;

§	failure of information technology systems and network infrastructure;

§	operational limitations imposed by environmental or other regulatory requirements;

§	limitations imposed on our nuclear generating units by regulatory agencies or a failure to obtain required licenses for our nuclear generating units, as discussed later;

§	inadequate or unreliable access to transmission and distribution assets;

§	labor disputes and inability to recruit and retain skilled technical workers;

§	inability to successfully and timely execute repair, maintenance and/or refueling outages;

§	interruptions to the supply of fuel and other commodities used in generation;

§	failure to comply with FERC-mandated reliability standards for the bulk power electric system;

§	inadequate coal combustion product management (disposal or beneficial use) capabilities;

§	failure to adequately forecast system requirements and commodity requirements; and

§	catastrophic events such as hurricanes, floods, extreme drought, earthquakes, fires, explosions, terrorist attacks, pandemic health events or other similar occurrences.

Occurrences of these events could adversely affect our financial condition or results of operations.

A significant portion of our generating facilities was constructed many years ago. Aging equipment, even if maintained in accordance with industry practices, may require significant capital expenditures. Failure of equipment or facilities could potentially increase O&M expense, purchased power expenses and capital expenditures.

Meeting the anticipated demand in our service territories and fulfilling our environmental compliance strategies will require, among other things, modernization of coal generating facilities, the construction of new generating facilities and the siting and construction of associated transmission facilities. We may not be able to obtain required licenses, permits and rights-of-way; successfully and timely complete construction; or recover the cost of such new generation and transmission facilities through our base rates or other recovery mechanisms, any of which could adversely impact our financial condition, cash flows or results of operations.

Meeting the anticipated demand within the Utilities’ service territories and complying with existing and potential environmental laws and regulations will require a balanced approach. The three main elements of this balanced solution are: (1) expanding our energy-efficiency programs; (2) investing in the development of alternative energy resources for the future; and (3) operating state-of-the-art power systems that produce energy cleanly and efficiently by modernizing existing plants and pursuing options for building new plants and associated transmission facilities.

The risks of each of the elements of our balanced solution include, but are not limited to, the following:

Energy-Efficiency and New Energy Resources

We are expanding our DSM, energy-efficiency and conservation programs and will continue to pursue additional initiatives as these programs can be effective ways to reduce energy costs, offset the need for new power plants and protect the environment.

We are subject to the risk that our customers may not participate in our conservation programs or that the results from these programs may be less than anticipated. This could impact our compliance with state-mandated energy-efficiency standards as discussed in the risks regarding renewable energy standards. Also, not achieving the energy-efficiency and conservation measurements we assumed in our long-term resource planning could require us to further expand our generation capacity or purchase additional power at prevailing market rates.

We are also subject to the risk that customer participation in these programs or new technologies that impact the quantity and pattern of electricity usage may decrease our electric sales and require us to seek future rate increases to cover our prudently incurred costs.

As discussed further in the risk factor related to renewable energy standards, we are actively engaged in a variety of alternative energy projects. These alternative energy projects may be determined to not be cost-efficient or cost-effective.

Modernization and Construction of Generating Plants

We are currently evaluating our options for new generating plants, including gas and nuclear technologies. We intend to retire certain coal-fired units in North Carolina that do not have emission control equipment by the end of 2014 and to construct new natural gas-fueled units at certain of these facilities. We are also evaluating the possibility of converting certain of these facilities to be fueled by natural gas or biomass. At this time, no definitive decision has been made regarding the construction of nuclear plants.

Decisions to build new power plants and successful completion of such construction projects are based on many factors including:

§	projected system load growth;

§	performance of existing generation fleet;

§	availability of competitively priced alternative energy sources;

§	projections of fuel prices, availability and security;

§	the regulatory environment, including the ability to recover costs and earn an appropriate return on investment;

§	operational performance of new technologies;

§	the time required to permit and construct;

§	environmental impact;

§	both public and policymaker support, including support for siting of power plant and associated transmission;

§	siting and construction of transmission facilities;

§	cost and availability of construction equipment, materials and skilled labor;

§	nuclear decommissioning costs, insurance, and costs of security;

§	ability to obtain financing on favorable terms; and

§	availability of adequate water supply.

There is no assurance that we will be able to successfully and timely construct new generating facilities or to expand or modernize existing facilities within our projected budgets or that those expenditures will be recoverable through our base rates or other recovery mechanisms. As with any major construction undertaking, completion could be delayed or prevented, or cost overruns could be incurred, as a result of numerous factors, including shortages of material and labor, labor disputes, weather interferences, difficulties in obtaining necessary licenses or permits or complying with license or permit conditions, and unforeseen engineering, environmental or geological problems. These construction projects are long-term and may involve facility designs that have not been previously constructed or that have not been finalized when that project is commenced. Consequently, the projects could be subject to significant cost increases for labor, materials, scope changes and changes in design. Unsuccessful construction, expansion or modernization efforts could be subject to additional costs and/or the write-off of our investment in the project or improvement.

The construction of new power plants and associated expansion of our transmission system will require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to

support the construction. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital. For certain new baseload generating facilities, we may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks, but we cannot be certain we will be able to successfully negotiate any such arrangement. Furthermore, joint ventures or joint ownership arrangements also present risks and uncertainties, including those associated with sharing control over the construction and operation of a facility and reliance on the other party’s financial or operational strength.

Our assumptions regarding future growth and resulting power demand in our service territories may not be realized. Like other parts of the United States, our service territories and business have been negatively impacted by the current economic conditions. The timing and extent of the recovery of the economy cannot be predicted. We may increase our baseload capacity based on anticipated growth levels and have excess capacity if those levels are not realized. The resulting excess capacity may exceed the reserve margins established by the NCUC, SCPSC and FPSC to meet our obligation to serve retail customers and, as a result, may not be recoverable.

Nuclear

In addition to the risks discussed above, the successful construction of a new nuclear power plant requires the satisfaction of a number of conditions. The conditions include, but are not limited to, the continued operation of the industry’s existing nuclear fleet in a safe, reliable and cost-effective manner, an efficient and successful licensing process and a viable program for managing spent nuclear fuel. We cannot provide certainty that these conditions will exist. While we have not made a final determination on nuclear construction, we have taken steps to keep open the option of building a plant or plants. We will continue to evaluate the ongoing viability of our nuclear construction projects based on certain criteria, including obtaining the COL; public, regulatory and political support; adequate financial cost-recovery mechanisms; and availability and terms of capital financing. Adverse changes in these criteria could result in project cost increases or project termination.

PEF has entered into an EPC agreement for Levy. However, because of schedule shifts, we executed an amendment to the EPC agreement and will postpone major construction activities on the project until after the NRC issues the COL. Because we have executed an amendment to the EPC agreement and anticipate negotiating additional amendments upon receipt of the COL, we cannot currently predict the timing of when those obligations will be satisfied or the magnitude of any change. In light of the schedule shifts, PEF may incur disposition fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. PEF is in suspension negotiations with the equipment vendors regarding those long lead time equipment items for which work was suspended. The amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed.

In addition, other COL applicants would be pursuing regulatory approval, permitting and construction at roughly the same time as we would. Consequently, there may be shortages of qualified individuals to design, construct and operate these proposed new nuclear facilities.

Gas

In addition to the risks discussed above, the successful construction of a gas-fired plant requires access to an adequate supply of natural gas. The gas pipeline infrastructure in eastern and western North Carolina is limited. Existing pipelines will have to be extended to the new plant locations prior to commencement of operations, which introduces the risks associated with a critical construction project not under our direct control. Power plants fueled by fossil fuels such as natural gas and fuel oil emit GHG, which may be subject to future regulation.

Coal

In addition to the risks discussed above, the successful modernization of a coal-fired power plant requires the satisfaction of a number of conditions, including, but not limited to, consideration of emissions that impact air and water quality and management of coal combustion products such as slag, bottom ash and fly ash.

We are subject to renewable energy standards that may have a negative impact on our business, financial condition and results of operations.

We are subject to state renewable energy standards in North Carolina. North Carolina’s standards include use of energy from specified renewable energy resources or implementation of energy-efficiency measures totaling 12.5 percent by 2021. Florida energy law enacted in 2008 includes provisions for development of a renewable portfolio standard but the rulemaking process is not complete. We may be subject to additional state or federal level standards in the future that could require the Utilities to produce or buy a higher portion of their energy from renewable energy sources. Mandated state and federal standards could result in the use of renewable energy sources that are not cost-effective in order to comply with requirements. If we are not able to receive retail rates reflecting our costs or investments to comply with the state or federal standards, our financial condition and results of operation may be adversely affected.

There are inherent potential risks in the operation of nuclear facilities, including environmental, health, safety, regulatory, terrorism, and financial risks, that could result in fines or the shutdown of our nuclear units, which may present potential financial exposures in excess of our insurance coverage.

PEC operates four nuclear units (three of which are jointly owned) and PEF jointly owns and operates one nuclear unit. In addition, we are exploring the possibility of expanding our nuclear generating capacity to meet future expected baseload generation needs. Our nuclear facilities are subject to operational, environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, maintaining adequate capital reserves for decommissioning, limitations on amounts and types of insurance available, potential operational liabilities and extended outages, and the costs of securing the facilities against possible terrorist attacks. We maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, damages from an accident or business interruption at our nuclear units could exceed the amount of our insurance coverage. For PEF, it may incur liabilities to co-owners in the event of extended outages or operation at less than full capacity. If the Utilities are not allowed to recover the additional costs incurred either through insurance or regulatory mechanisms, our results of operations could be negatively impacted.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require us to make substantial expenditures at our nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.

Our nuclear facilities have operating licenses that need to be renewed periodically. We anticipate successful renewal of these licenses. However, potential terrorist threats and increased public scrutiny of utilities could result in an extended process with higher licensing or compliance costs.

With construction beginning on a number of new nuclear facilities around the world, and the prospect of several projects across the United States, there will be increased competition within the energy sector for skilled technical workers for both the construction and operation of nuclear facilities. Our ability to successfully operate our nuclear facilities is dependent upon our continued ability to recruit and retain skilled technical workers.

We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and may impact or limit our business plans, or expose us to environmental liabilities.

We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste production, handling and disposal. These laws and regulations can result in increased capital, operating and other costs, particularly with regard to enforcement efforts focused on existing power plants and compliance plans with regard to new and existing power plants. These laws and regulations generally require us to obtain and comply with a wide

variety of environmental licenses, permits, authorizations and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable regulations and permits might result in the imposition of fines and penalties by regulatory authorities. We cannot provide assurance that existing environmental regulations will not be revised or that new environmental regulations will not be adopted or become applicable to us. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a material adverse effect on our results of operations, particularly if those costs are not fully recoverable from our ratepayers.

In addition, we may be deemed a responsible party for environmental clean-up at sites identified by a regulatory body or private party. We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs. While we accrue for probable costs that can be reasonably estimated, not all costs can be reasonably estimated or accrued and actual costs may materially exceed our accruals. Material costs in excess of our accruals could have an adverse impact on our financial condition and results of operations.

Our coal-fired plants produce coal combustion products, primarily ash. The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or additional environmental controls for groundwater protection, and future mitigation of related impacts could have a material impact on our results of operations or financial condition. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures.

Our compliance with evolving environmental regulations, including those regarding water quality and the reduction of emissions of NOx, SO2 and mercury from coal-fired power plants, is anticipated to require significant capital expenditures that could impact our financial condition. These costs are anticipated to be eligible for regulatory recovery through either base rates or cost-recovery clauses.

The operation of emission control equipment needed to comply with requirements set by various environmental regulations increases our operating costs and reduces the generating capacity of our coal-fired plants. O&M expenses significantly increase due to the additional personnel, materials and general maintenance associated with operation of the equipment. Operation of the emission control equipment requires the procurement of significant quantities of reagents, such as limestone and ammonia. Future increases in demand for these items from other utility companies operating similar equipment could increase our costs associated with operating the equipment. Additionally, the operation of emission control equipment may result in the development of collateral issues that require further remedial actions, resulting in additional expenditures and operating costs.

We are subject to risks associated with climate change, which could have a negative impact on our business, financial condition and results of operations. Future legislation or regulations related to climate change may impose significant restrictions on CO2 and other GHG emissions. We may incur significant costs to comply with such legislation or regulations or in connection with related litigation. Physical risks associated with climate change could impact us.

Growing state, federal and international attention to global climate change may result in the regulation of CO2 and other GHGs. Any future legislative or regulatory actions taken to address global climate change represent a business risk to our operations and the full impact of such initiatives on our operations cannot be determined at this time; however, we anticipate that it could result in significant cost increases over time, for which the Utilities would seek corresponding rate recovery. Reductions in CO2 emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from ratepayers.

According to the Intergovernmental Panel on Climate Change, potential climate change impacts in the southeastern United States could include warmer days and nights, increased total rainfall from heavy storms, increased severe weather events, sea level rise and increased drought conditions. An increase in the number of heat waves, periods of

drought and sea level rise could result in changes in energy demand due to shifting populations and industry. As noted below, severe weather may adversely affect our results of operations.

We could become subject to litigation related to the purported impacts of GHG emissions. A number of legal actions have been filed against other electric utilities asserting public and private nuisance, trespass and negligence claims.

Because weather conditions directly influence the demand for, our ability to provide, and the cost of providing electricity, our results of operations, financial condition and cash flows can fluctuate on a seasonal or quarterly basis and can be negatively affected by changes in weather conditions and severe weather.

Weather conditions in our service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to our customers. As a result, our future overall operating results may fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions were mild. Unusually mild weather could diminish our results of operations and harm our financial condition.

Sustained severe drought conditions could impact generation by PEC’s hydroelectric plants, as well as our 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.

Our ability 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 our financial conditions.

We are subject to incurring significant costs resulting from damage sustained during severe weather events. While the Utilities have historically been granted regulatory approval to defer and amortize or collect from customers the majority of significant storm costs incurred, the Utilities’ storm cost-recovery petitions may not always be granted or may not be granted in a timely manner. If we cannot recover costs associated with future severe weather events in a timely manner, or in an amount sufficient to cover our actual costs, our financial conditions and results of operations could be materially and adversely impacted.

Under its base rate settlement agreement, PEF is allowed to recover the costs of named storms on an expedited basis through a surcharge on monthly residential customer bills for storm costs. In the event the storm costs exceed the maximum allowed surcharge, excess additional costs can be deferred and recovered in a subsequent year or years as determined by the FPSC. Additionally, the order approving the settlement agreement allows PEF to use the surcharge to replenish the storm damage reserve to a specified level after storm costs are fully recovered.

PEC does not maintain a storm damage reserve account and does not have a cost-recovery clause to recover storm costs. PEC may request recovery of significant storm-related costs; PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over agreed-upon time periods.

Our revenues, operating results and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions. We are also impacted by the demand and competitive state of the wholesale market.

Our revenues, operating results and financial condition are impacted by customer growth and usage. Customer growth can be impacted by population growth as well as by economic factors, including but not limited to, job growth and housing market trends. The Utilities are impacted by the economic cycles of the customers we serve. As our service territories experience economic downturns, residential customer consumption patterns may change and our revenues may be negatively impacted. If our commercial and industrial customers experience economic downturns, their consumption of electricity may decline and our revenues can be negatively impacted. Like other parts of the United States, our service territories and business have been impacted by the current economic conditions. The timing and extent of the recovery of the economy cannot be predicted. Additionally, our customers

could voluntarily reduce their consumption of electricity in response to decreases in their disposable income or individual energy conservation efforts.

Wholesale revenues fluctuate with regional demand, fuel prices and contracted capacity. Our wholesale profitability is dependent upon market conditions and our ability to renew or replace expiring wholesale contracts on favorable terms. Based on economic conditions in effect when wholesale contracts expire, the Utilities may not be successful in renewing or replacing expiring contracts.

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

We 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 our ownership of energy-related assets. Fuel costs are recovered primarily through cost-recovery clauses, subject to the Utilities’ state utility commissions’ approval. Additionally, we have hedging strategies in place to mitigate fluctuations in commodity supply prices, but to the extent that we do not cover our entire exposure to commodity price fluctuations, or our hedging procedures do not work as planned, there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. Additionally, we are exposed to risk that our counterparties will not be able to perform their obligations. Should our counterparties fail to perform, we might be forced to replace the underlying commitment at prevailing market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.

Volatility in market prices for fuel and power may result from, among other items:

§	weather conditions;

§	seasonality;

§	power usage;

§	illiquid markets;

§	transmission or transportation constraints or inefficiencies;

§	technological changes;

§	availability of competitively priced alternative energy sources;

§	demand for energy commodities;

§	natural gas, crude oil and refined products, nuclear fuel and coal production levels;

§	natural disasters, wars, terrorism, embargoes and other catastrophic events; and

§	federal, state and foreign energy and environmental regulation and legislation.

In addition, we anticipate significant capital expenditures for environmental compliance and baseload generation. The completion of these projects within established budgets is contingent upon many variables including the securing of labor and materials at estimated costs. The demand and prices for labor and materials are subject to volatility and may increase in the future. We are subject to the risk that cost overages may not be recoverable from ratepayers and our financial condition, results of operations or cash flows may be adversely impacted.

Prices for emission allowance credits fluctuate. While allowances are eligible for annual recovery in PEF’s jurisdictions in Florida and PEC’s in South Carolina, no such annual recovery exists in North Carolina for PEC. Future changes in the price of allowances could have a significant adverse financial impact on us and PEC and, consequently, on our results of operations and cash flows.

As a holding company with no revenue-generating operations, the Parent is dependent on upstream cash flows from its subsidiaries, primarily the Utilities; its commercial paper and credit facilities; and its ability to access the long-term debt and equity capital markets.

The Parent is a holding company and, as such, has no revenue-generating operations of its own. The primary cash needs at the Parent level are our common stock dividend, interest and principal payments on the Parent’s senior unsecured debt and potentially funding a portion of the Utilities’ capital expenditures through equity contributions. The Parent’s ability to meet these needs is typically funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; repayment of funds due to the Parent by its subsidiaries; the Parent’s credit facility; and/or the Parent’s ability to access the short-term and long-term debt and equity capital markets.

Prior to funding the Parent, its subsidiaries have financial obligations that must be satisfied, including, among others, their respective debt service, preferred dividends and obligations to trade creditors. Additionally, the Utilities could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from the Parent. Should the Utilities not be able to pay dividends or repay funds due to the Parent or if the Parent cannot access the commercial paper market, its credit facilities or the long-term debt and equity capital markets, the Parent’s ability to pay principal, interest and dividends would be restricted. The Parent could change its existing common stock dividend policy based upon these and other business factors

Our business is dependent on our ability to successfully access capital markets on favorable terms. Limits on our access to capital may adversely impact our ability to execute our business plan or pursue improvements that we would otherwise rely on for future growth.

Our cash requirements are driven by the capital-intensive nature of our Utilities. In addition to operating cash flows, we rely heavily on commercial paper, long-term debt and equity issuances. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy will be adversely affected. Market disruptions or a downgrade of our credit ratings could increase our cost of borrowing and may adversely affect our ability to access the financial markets. If we cannot fund our expected capital expenditures and debt maturities through normal operations or by accessing capital markets, our business plans, financial condition, results of operations or cash flows may be adversely impacted.

We typically issue commercial paper to meet short-term liquidity needs. When financial and economic conditions result in tightened short-term credit markets, coupled with corresponding volatility in commercial paper durations and interest rates, we evaluate other options for meeting our short-term liquidity needs, which may include borrowing from our revolving credit agreements (RCAs), issuing short-term notes, issuing long-term debt and/or issuing equity. In addition, if our short-term credit ratings are downgraded below Tier 2 (A-2/P-2/F2) we could experience increased volatility in commercial paper durations and interest rates and our access to the commercial paper markets may be negatively impacted. In that case, we would evaluate other options for meeting our short-term liquidity needs as previously described. These alternative sources of liquidity may not be available or may not have comparable favorable terms and, thus, may impact adversely our business plans, financial condition, and results of operations or cash flows.

Increases in our leverage or reductions in our cash flow could adversely affect our competitive position, business planning and flexibility, financial condition, ability to service our debt obligations and to pay dividends on our common stock, and ability to access capital on favorable terms.

As discussed above, we typically rely heavily on our commercial paper and long-term debt. Our credit agreements contain certain provisions and impose various limitations that could impact our liquidity, such as cross-default provisions and defined maximum total debt to total capital (leverage) ratios. Under these revolving credit facilities, indebtedness includes certain letters of credit and guarantees that are not recorded on the Consolidated Balance Sheets.

As previously discussed, we are anticipating extensive capital needs for new generation, transmission and distribution facilities, and environmental compliance expenditures. Funding these capital needs could increase our leverage and present numerous risks including those addressed below.

In the event our leverage increases such that we approach the permitted ratios, our access to capital and additional liquidity could decrease. A limitation in our liquidity could have a material adverse impact on our business strategy and our ongoing financing needs. Additionally, a significant increase in our leverage or reductions in cash flow could adversely affect us by:

§	increasing the cost of future debt financing;

§	impacting our ability to pay dividends on our common stock at the current rate;

§	making it more difficult for us to satisfy our existing financial obligations;

§	increasing our vulnerability to adverse economic and industry conditions;

§	requiring us to dedicate a substantial portion of our cash flow from operations to debt repayment, thereby reducing funds available for operations, future business opportunities or other purposes;

§	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete;

§	requiring the issuance of additional equity;

§	placing us at a competitive disadvantage compared to competitors who have less debt; and

§	causing a downgrade in our credit ratings.

Any reduction in our credit ratings below investment grade would likely increase our financing costs, limit our access to additional capital and require posting of collateral, all of which could materially and adversely affect our business, results of operations and financial condition.

While the long-term target credit ratings for the Parent and the Utilities are above the minimum investment grade rating, we cannot provide certainty that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Such circumstances could include, among others, increases in leverage, adverse changes in other financial metrics, and adverse regulatory outcomes. Our debt indentures and credit agreements do not contain any “ratings triggers,” which would cause the acceleration of interest and principal payments in the event of a ratings downgrade. Any downgrade could increase our borrowing costs, may adversely affect our access to capital and could result in the posting of additional collateral for derivatives in a liability position, which could negatively impact our financial results and business plans. Any reduction in our credit ratings below investment grade could also result in collateral posting requirements for certain of our natural gas transportation contracts. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities or those of PEC or PEF and that each agency’s rating should be evaluated independently of any other agency’s rating.

Market performance and other changes may decrease the value of nuclear decommissioning trust funds and benefit plan assets, 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 the Utilities’ nuclear plants and under our defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. Although a number of factors impact our funding requirements, a decline in the market value of the assets may increase the funding requirements of the obligations for decommissioning the Utilities’ nuclear plants and under our defined benefit pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, the funding requirements of the obligations related to these benefit plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or changes in life expectancy assumptions. If we are unable to successfully manage the nuclear decommissioning trust funds and benefit plan assets, our results of operation and financial position could be negatively affected.

Impairment of goodwill could have a significant negative impact on our financial condition and results of operations.

We calculate the fair value of our utility reporting units by considering various factors, including valuation studies based primarily on income and market approaches. The calculations in both approaches are highly dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates from a marketplace participant’s perspective, and the selection of peer utilities and marketplace transactions for comparative valuation purposes. The estimated future cash flows are based on the Utilities’ business plans that assume the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, the timing of anticipated significant future capital investments, the anticipated earnings and returns related to such capital investments, continued recovery of cost of service and renewal of certain contracts. These underlying assumptions and estimates are made as of a point in time. If these assumptions change or should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, the fair value of the utility reporting units could be significantly different in future periods, which could result in a future impairment charge to goodwill. Impairment of our recorded goodwill could result in volatility in our earnings under accounting principles generally accepted in the United States of America (GAAP) and an increase in our leverage, which could trigger a downgrade of our credit ratings leading to higher borrowing costs and/or dilution through additional issuances of common stock. However, in the event of a goodwill impairment, we do not expect any such impairment to cause us to violate any financial or restrictive covenants contained in our indebtedness or other contractual arrangements.

Our ability to fully utilize tax credits generated under Section 29/45K may be limited. This risk is not applicable to PEC and PEF.

In accordance with the provisions of Section 29/45K, we 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 our taxable income, which can be impacted by a number of factors. The timing of the utilization can also be impacted by certain substantial changes in ownership, including the Merger. Additionally, in the normal course of business, our tax returns are audited by the IRS. If our 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 our earnings and cash flows. Although we 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.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None

ITEM 2.

PROPERTIES

We believe that our physical properties and those of our subsidiaries are adequate to carry on our and their businesses as currently conducted. We maintain property insurance against loss or damage by fire or other perils to the extent that such property is usually insured.

ELECTRIC - PEC

PEC’s 18 generating plants represent a flexible mix of fossil steam, nuclear, combustion turbines, combined cycle, and hydroelectric resources, with a total summer generating capacity of 12,554 MW. Of this total, Power Agency owns approximately 700 MW. On December 31, 2010, PEC had the following generating facilities:

							PEC			Summer Net
		No. of					Ownership			Capability(a)
Facility	Location	Units		In-Service Date		Fuel	(in %)			(in MW)
FOSSIL STEAM
Asheville	Arden, N.C.		2		1964-1971	Coal		100			376
Cape Fear(b)	Moncure, N.C.		2		1956-1958	Coal		100			316
Lee(b)	Goldsboro, N.C.		3		1951-1962	Coal		100			391
Mayo	Roxboro, N.C.		1		1983	Coal		83.83			727	(c)
Robinson	Hartsville, S.C.		1		1960	Coal		100			177
Roxboro	Semora, N.C.		4		1966-1980	Coal		96.3	(d)		2,417	(c)
Sutton(b)	Wilmington, N.C.		3		1954-1972	Coal		100			590
Weatherspoon(b)	Lumberton, N.C.		3		1949-1952	Coal		100			170
	Total		19								5,164
NUCLEAR
Brunswick	Southport, N.C.		2		1975-1977	Uranium		81.67			1,858	(c)
Harris	New Hill, N.C.		1		1987	Uranium		83.83			900	(c)
Robinson	Hartsville, S.C.		1		1971	Uranium		100			724
	Total		4								3,482
COMBUSTION TURBINES
Asheville	Arden, N.C.		2		1999-2000	Gas/Oil		100			324
Blewett	Lilesville, N.C.		4		1971	Oil		100			52
Darlington	Hartsville, S.C.		13		1974-1997	Gas/Oil		100			802
Lee	Goldsboro, N.C.		4		1968-1971	Oil		100			75
Morehead City	Morehead City, N.C.		1		1968	Oil		100			12
Richmond	Hamlet, N.C.		5		2001-2002	Gas/Oil		100			820
Robinson	Hartsville, S.C.		1		1968	Gas/Oil		100			11
Sutton	Wilmington, N.C.		3		1968-1969	Gas/Oil		100			61
Wayne County	Goldsboro, N.C.		5		2000-2009	Gas/Oil		100			863
Weatherspoon	Lumberton, N.C.		4		1970-1971	Gas/Oil		100			131
	Total		42								3,151
COMBINED CYCLE
Cape Fear	Moncure, N.C.		2		1969	Oil		100			62
Richmond	Hamlet, N.C.		1		2002	Gas/Oil		100			470
	Total		3								532
HYDRO
Blewett	Lilesville, N.C.		6		1912	Water		100			22
Marshall	Marshall, N.C.		2		1910	Water		100			4
Tillery	Mount Gilead, N.C.		4		1928-1960	Water		100			87
Walters	Waterville, N.C.		3		1930	Water		100			112
	Total		15								225
TOTAL			83								12,554

(a)	Summer ratings reflect compliance with NERC reliability standards and are gross of joint ownership interest.
(b)	PEC has announced that it intends to retire these units no later than the end of 2014. See Item I, "Business - PEC - Fuel and Purchased Power - Oil and Gas" regarding PEC's plans to build new generation fueled by natural gas.
(c)	Facilities are jointly owned by PEC and Power Agency. The capacities shown include Power Agency's share.
(d)	PEC and Power Agency are joint owners of Unit 4 at the Roxboro Plant. PEC's ownership interest in this 698-MW unit is 87.06 percent.

At December 31, 2010, including both the total generating capacity of 12,554 MW and the total firm contracts for purchased power of 1,332 MW, PEC had total capacity resources of approximately 13,886 MW.

Power Agency has undivided ownership interests of 18.33 percent in Brunswick Unit Nos. 1 and 2, 12.94 percent in Roxboro Unit No. 4, 3.77 percent in Roxboro Common facilities, and 16.17 percent in Harris and Mayo Unit No. 1. Otherwise, PEC has good and marketable title to its principal plants and units, subject to the lien of its mortgage and deed of trust, with minor exceptions, restrictions, and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. PEC also owns certain easements over private property on which transmission and distribution lines are located.

At December 31, 2010, PEC had approximately 6,000 circuit miles of transmission lines including 300 miles of 500 kilovolt (kV) lines and 3,000 miles of 230-kV lines. PEC also had approximately 45,000 circuit miles of overhead distribution conductor and 22,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 52 million kilovolt-ampere (kVA) in approximately 900 transformers. Distribution line transformers numbered approximately 538,000 with an aggregate capacity of approximately 24 million kVA.

ELECTRIC - PEF

PEF’s 14 generating plants represent a flexible mix of fossil steam, combustion turbines, combined cycle, and nuclear resources, with a total summer generating capacity of 10,025 MW. Of this total, joint owners own approximately 120 MW. On December 31, 2010, PEF had the following generating facilities:

							PEF		Summer Net
		No. of					Ownership		Capability(a)
Facility	Location	Units		In-Service Date		Fuel	(in %)		(in MW)
FOSSIL STEAM
Anclote	Holiday, Fla.		2		1974-1978	Gas/Oil		100		1,011
Crystal River	Crystal River, Fla.		4		1966-1984	Coal		100		2,291
Suwannee River	Live Oak, Fla.		3		1953-1956	Gas/Oil		100		131
	Total		9							3,433
COMBINED CYCLE
Bartow	St. Petersburg, Fla.		1		2009	Gas/Oil		100		1,133
Hines	Bartow, Fla.		4		1999-2007	Gas/Oil		100		1,912
Tiger Bay	Fort Meade, Fla.		1		1997	Gas		100		205
	Total		6							3,250
COMBUSTION TURBINES
Avon Park	Avon Park, Fla.		2		1968	Gas/Oil		100		48
Bartow	St. Petersburg, Fla.		4		1972	Gas/Oil		100		177
Bayboro	St. Petersburg, Fla.		4		1973	Oil		100		174
DeBary	DeBary, Fla.		10		1975-1992	Gas/Oil		100		637
Higgins	Oldsmar, Fla.		4		1969-1971	Gas/Oil		100		113
Intercession City	Intercession City, Fla.		14		1974-2000	Gas/Oil	(b)			982	(c)
Rio Pinar	Rio Pinar, Fla.		1		1970	Oil		100		12
Suwannee River	Live Oak, Fla.		3		1980	Gas/Oil		100		154
Turner	Enterprise, Fla.		4		1970-1974	Oil		100		139
University of Florida
Cogeneration	Gainesville, Fla.		1		1994	Gas		100		46
	Total		47							2,482
NUCLEAR
Crystal River	Crystal River, Fla.		1		1977	Uranium		91.78		860	(c)
	Total		1							860
TOTAL			63							10,025

(a)	Summer ratings reflect compliance with NERC reliability standards and are gross of joint ownership interest.
(b)	PEF and Georgia Power Company are joint owners of a 143-MW advanced combustion turbine located at PEF's Intercession City site. Georgia Power Company has the exclusive right to the output of this unit during the months of June through September. PEF has the right for the remainder of the year.
(c)	Facilities are jointly owned. The capacities shown include joint owners' share.

At December 31, 2010, including both the total generating capacity of 10,025 MW and the total firm contracts for purchased power of 3,275 MW, PEF had total capacity resources of approximately 13,300 MW.

Several entities have acquired undivided ownership interests in CR3 in the aggregate amount of 8.22 percent. The joint ownership participants are: City of Alachua – 0.08 percent, City of Bushnell – 0.04 percent, City of Gainesville – 1.41 percent, Kissimmee Utility Authority – 0.68 percent, City of Leesburg – 0.82 percent, Utilities Commission of the City of New Smyrna Beach – 0.56 percent, City of Ocala – 1.33 percent, Orlando Utilities Commission – 1.60 percent and Seminole Electric Cooperative, Inc. – 1.70 percent. PEF and Georgia Power Company are co-owners of a 143-MW advance combustion turbine located at PEF’s Intercession City Unit P11. Georgia Power Company has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year. Otherwise, PEF has good and marketable title to its principal plants and units, subject to the

lien of its mortgage and deed of trust, with minor exceptions, restrictions and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. PEF also owns certain easements over private property on which transmission and distribution lines are located.

At December 31, 2010, PEF had approximately 5,000 circuit miles of transmission lines including 200 miles of 500 kV lines and approximately 1,500 miles of 230-kV lines. PEF also had approximately 18,000 circuit miles of overhead distribution conductor and 13,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 47 million kVA in approximately 800 transformers. Distribution line transformers numbered approximately 390,000 with an aggregate capacity of approximately 20 million kVA.

ITEM 3.

LEGAL PROCEEDINGS

Legal proceedings are included in the discussion of our business in PART I, Item 1 under “Environmental,” and are incorporated by reference herein. See Note 22D for a discussion of certain other legal matters.

ITEM 4.

(REMOVED AND RESERVED)

EXECUTIVE OFFICERS OF THE REGISTRANTS AT FEBRUARY 28, 2011

Name	Age	Recent Business Experience

William D. Johnson	57	Chairman, President and Chief Executive Officer, Progress Energy and Florida Progress, October 2007 to present; Chairman, PEC and PEF, from November 2007 to present; President and Chief Operating Officer, Progress Energy, from January 2005 to October 2007; Group President, PEC, from January 2004 to October 2007; Executive Vice President, PEF, from November 2000 to November 2007; Executive Vice President, Florida Progress, from November 2000 to December 2003; and Corporate Secretary, PEC, PEF, Progress Energy Service Company, LLC and Florida Progress, from November 2000 to December 2003. Mr. Johnson has been with Progress Energy (formerly CP&L) since 1992 and served as Group President, Energy Delivery, Progress Energy, from January 2004 to December 2004. Prior to that, he was President, CEO and Corporate Secretary, Progress Energy Service Company, LLC, from October 2002 to December 2003. He also served as Executive Vice President – Corporate Relations & Administrative Services, General Counsel and Secretary of Progress Energy. Mr. Johnson served as Vice President – Legal Department and Corporate Secretary, CP&L, from 1997 to 1999. Before joining Progress Energy, Mr. Johnson was a partner with the Raleigh, N.C., law office of Hunton & Williams LLP where he specialized in the representation of utilities. He previously served as a law clerk to the Honorable J. Dickson Phillips Jr. of the U.S. Court of Appeals for the Fourth Circuit.

Jeffrey A. Corbett	51	Senior Vice President, Energy Delivery, PEC, January 2008 to present. Mr. Corbett oversees operations and services in the Carolinas, including engineering, distribution, construction, metering, power restoration, community relations and customer service. He previously served as Senior Vice President, Energy Delivery, PEF, from June 2006 to January 2008, with the same responsibilities in Florida as mentioned above. Mr. Corbett served as Vice President – Distribution for PEC, from January 2005 to June 2006. He also served PEC as Vice President – Eastern Region, from September 2002 to January 2005. Mr. Corbett joined Progress Energy in 1999 and has served in a number of roles, including General Manager of the Eastern Region and Director of Distribution Power Quality and Reliability. Before joining Progress Energy, Mr. Corbett spent 17 years with Virginia Power, serving in a variety of engineering and leadership roles.

*Vincent M. Dolan	56	President and Chief Executive Officer, PEF, July 2009 to present. Mr. Dolan oversees all aspects of PEF’s delivery operations, including distribution and customer service, transmission, and products and services. He previously served as Vice President – External Relations, PEF, from December 2006 to July 2009; Vice President – Regulatory & Customer Relations, PEF, from March 2005 to December 2006; and Vice President – Corporate Relations & Administrative Services, PEF, from April 2002 to March 2005. Mr. Dolan has been with PEF since 1986 in positions of increasing responsibility in the areas of operations, strategic development, customer services, and regulatory affairs. Before joining PEF, Mr. Dolan was with Foster Wheeler Energy Corporation, an international engineering and manufacturing firm.

*Michael A. Lewis	48	Senior Vice President, Energy Delivery, PEF, January 2008 to present. Mr. Lewis oversees operations and services in Florida, including engineering, distribution, construction, metering, power restoration, community relations, energy-efficiency, and alternative energy strategies. He previously served as Vice President, Distribution, PEF, from August 2007 to January 2008; Vice President, Distribution Engineering & Operations, PEF, from December 2005 to August 2007; Vice President, Distribution Operations & Support, PEF, from April 2004 to December 2005; and Vice President, Coastal Region, PEF, from December 2000 to April 2004. Mr. Lewis has been with PEF in a number of engineering and management positions since 1986, including District Manager, Distribution Operations Manager in Pasco County, General Manager for the South Coastal region and Regional Vice President of both the North and South Coastal regions.

Jeffrey J. Lyash	49	Executive Vice President, Energy Supply, Progress Energy, June 2010 to present. In his role, Mr. Lyash oversees all power generation plants in the Carolinas and Florida. He also serves as Executive Vice President, PEC, since August 2009, and PEF, since July 2009. Mr. Lyash previously served as Executive Vice President, Corporate Development, Progress Energy, from July 2009 to June 2010; President and Chief Executive Officer, PEF, from June 2006 to July 2009; Senior Vice President, PEF, from November 2003 to June 2006; and Vice President – Transmission in Energy Delivery, PEC, from January 2002 to October 2003. Mr. Lyash joined Progress Energy (formerly CP&L) in 1993 and spent his first eight years at the Brunswick Nuclear Plant in Southport, N.C., in a number of management roles. His last position at Brunswick was as Director of site operations. Before joining Progress Energy, Mr. Lyash worked with the NRC in a number of capacities between 1984 and 1993.

John R. McArthur	55	Executive Vice President, Progress Energy, September 2008 to present. In this role, Mr. McArthur is responsible for corporate and utility support functions, including Audit Services, Corporate Services, Corporate Communications, External Relations, Human Resources and Legal. He also serves as General Counsel, since April 2010, and previously from 2004 until 2009, and Corporate Secretary, since 2004, of Progress Energy. Mr. McArthur is also Executive Vice President of PEC since September 2008, Executive Vice President of PEF since November 2008 and Executive Vice President of Florida Progress Corporation since January 2010. Mr. McArthur has been with Progress Energy in a number of roles since 2001, including General Counsel, Senior Vice President, Corporate Relations and Vice President, Public Affairs. Before joining Progress Energy, Mr. McArthur was a senior adviser to N.C. Governor Mike Easley, handling major policy initiatives as well as media and legal affairs. Previously, he handled state government affairs for General Electric Co. He also served as chief counsel in the N.C. Attorney General’s office, where he supervised utility, consumer, health care, and environmental protection issues. Prior to that Mr. McArthur was a partner with the Raleigh, N.C., law office of Hunton & Williams LLP and served as a law clerk to the Honorable Sam J. Ervin III of the U.S. Court of Appeals for the Fourth Circuit.

Mark F. Mulhern	51	Senior Vice President and Chief Financial Officer, Progress Energy, PEC and PEF, September 2008 to present. He previously served as Senior Vice President, Finance, PEC and PEF, from November 2007 to September 2008, and Senior Vice President, Finance, Progress Energy, from July 2007 to September 2008. Mr. Mulhern also served as President of Progress Ventures (the unregulated subsidiary of Progress Energy), from 2005 to 2008; Senior Vice President of Competitive Commercial Operations of Progress Ventures, from 2003 to 2005; Vice President, Strategic Planning of Progress Energy, from 2000 to 2003; Vice President and Treasurer of Progress Energy, from 1997 to 2000; and Vice President and Controller of Progress Energy, from 1996 to 1997. Before joining Progress Energy (formerly CP&L) in 1996, Mr. Mulhern was the Chief Financial Officer at Hydra Co Enterprises, the independent power subsidiary of Niagara Mohawk. He also spent eight years at Price Waterhouse, serving a wide variety of manufacturing and service businesses.

James Scarola	54	Senior Vice President and Chief Nuclear Officer, PEC and PEF, January 2008 to present. Mr. Scarola oversees all aspects of our nuclear program. He previously served as Vice President at the Brunswick Nuclear Plant from October 2005 to December 2007. Mr. Scarola joined Progress Energy (formerly CP&L) in 1998, where he served as Vice President at the Harris Nuclear Power Plant until October 2005. Mr. Scarola entered the nuclear power field in 1978 as a design engineer and has held positions in construction, start-up testing, maintenance, engineering and operations. He was the Plant General Manager at the St. Lucie Nuclear Plant with Florida Power & Light Company prior to joining Progress Energy.

Paula J. Sims	49	Senior Vice President, Corporate Development and Improvement, Progress Energy, June 2010 to present. Ms. Sims is responsible for implementing Progress Energy’s balanced solution strategy for meeting the future energy needs of its customers. In addition, she oversees program development and construction of new generation projects, renewable energy and efficiency programs, supply chain, information technology and wholesale power operations. Ms. Sims is the executive sponsor for Continuous Business Excellence, Progress Energy’s framework for improving processes, efficiency and overall cost management and has responsibility for environmental, health and safety. She also serves as Senior Vice President, PEC and PEF, since April 2006. Ms. Sims previously served as Senior Vice President, Power Operations, PEC and PEF, from July 2007 to June 2010; Senior Vice President, Regulated Services of PEC, from January 2006 to July 2007; Vice President, Fossil Fuel Generation of Progress Energy and PEF, from January 2006 to April 2006; Vice President, Regulated Fuels of Progress Energy, from December 2004 to December 2005; Chief Operating Officer of Progress Fuels Corporation, from February 2002 to December 2004; and Vice President, Business Operations & Strategic Planning of Progress Fuels Corporation, from June 2001 to February 2002. Before joining Progress Energy in 1999, Ms. Sims was with GE Aircraft Engines, where she served in a number of engineering, operations and plant management roles for over 15 years.

Jeffrey M. Stone	49	Chief Accounting Officer and Controller, Progress Energy and Florida Progress, June 2005 to present; Chief Accounting Officer, PEC and PEF, from June 2005 and November 2005, respectively, to present; and Vice President and Controller, Progress Energy Service Company, LLC, from January 2005 and June 2005, respectively to present. Mr. Stone previously served as Controller of PEF and PEC, from June 2005 to November 2005. Since 1999, Mr. Stone has served Progress Energy in a number of roles in corporate support including Vice President – Capital Planning and Control; and Executive Director – Financial Planning & Regulatory Services, as well as in various management positions with Energy Supply and Audit Services. Prior to joining Progress Energy, Mr. Stone worked as an auditor with Deloitte & Touche in Charlotte, N.C.

Lloyd M. Yates

President and Chief Executive Officer, PEC, July 2007 to present. Mr. Yates oversees all aspects of PEC’s delivery operations, including distribution and customer service, transmission, and products and services. He previously served as Senior Vice President, PEC, from January 2005 to July 2007, where he was responsible for overseeing the four operational and customer service regions in the Carolinas, as well as the distribution function. Mr. Yates served PEC as Vice President – Transmission, from November 2003 to December 2004 and as Vice President – Fossil Generation, from November 1998 to November 2003.

Before joining Progress Energy (formerly CP&L) in 1998, Mr. Yates was with PECO Energy for over 16 years in several line operations and management positions.

*Indicates individual is an executive officer of Progress Energy, Inc., but not PEC.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

PROGRESS ENERGY

Progress Energy’s Common Stock is listed on the New York Stock Exchange under the symbol PGN. The high and low intra-day stock prices for each quarter for the past two years, and the cash dividends declared per share are as follows:

	High		Low		Dividends Declared
2010
First Quarter	$	41.35	$	37.04	$	0.620
Second Quarter		40.69		37.13		0.620
Third Quarter		44.82		38.96		0.620
Fourth Quarter		45.61		43.08		0.620
2009
First Quarter	$	40.85	$	31.35	$	0.620
Second Quarter		38.20		33.50		0.620
Third Quarter		40.05		35.97		0.620
Fourth Quarter		42.20		36.67		0.620

The December 31 closing price of our Common Stock was $43.48 for 2010 and $41.01 for 2009. At February 22, 2011, we had 51,975 holders of record of Common Stock.

Progress Energy expects to continue its policy of paying regular cash dividends; however, dividends are subject to declaration by the board of directors and the existing common stock dividend policy could change based upon business factors, including future earnings, capital requirements, and financial condition. Additionally, the Merger Agreement restricts our ability, without Duke Energy’s consent, to increase the common stock dividend rate until consummation or termination of the Merger Agreement. See MD&A “Introduction – Merger.”

Neither Progress Energy’s Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends, so long as no shares of preferred stock are outstanding. Our subsidiaries have provisions restricting dividends on their securities in certain limited circumstances (See Notes 9 and 11B).

Information regarding securities authorized for issuance under our equity compensation plans is included in Progress Energy’s definitive proxy statement for its 2011 Annual Meeting of Shareholders.

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a)

Securities Delivered. On October 8, 2010, 2,155 shares, of our common stock were delivered to a former employee pursuant to the terms of the Progress Energy 2002 and 2007 Equity Incentive Plans (individually and collectively, the “EIP”) which have been approved by Progress Energy’s shareholders. Additionally, on October 1, 2010, 1,000 shares of our common stock were delivered to a current employee pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

(b)	Underwriters and Other Purchasers. No underwriters were used in connection with the delivery of our common stock described above.

(c)	Consideration. The restricted stock unit awards were granted to provide an incentive to the former and current employees to exert their utmost efforts on Progress Energy’s behalf and thus enhance our performance while aligning the employees’ interest with those of our shareholders.

(d)

Exemption from Registration Claimed. The common shares described in this Item were delivered pursuant to a broad-based involuntary, non-contributory employee benefit plan, and thus did not involve an offer to sell or sale of securities within the meaning of Section 2(3) of the Securities Act of 1933. Receipt of the shares of our common stock required no investment decision on the part of the recipient.

ISSUER PURCHASES OF EQUITY SECURITIES FOR FOURTH QUARTER OF 2010

Period

(a)

Total

Number of

(or Units)

Purchased

(1)(2)(3)(4)

(b)

Average

Price

Paid

Per

(or Unit)

(c)

Total Number of

Shares (or Units) Purchased as Part

of Publicly

Announced Plans

or Programs (1)

(d)

Maximum Number (or Approximate Dollar Value) of Shares(or Units)

that May Yet Be

Purchased Under the

Plans or Programs (1)

October 1 – October 31

465,094

44.8064

N/A

November 1 – November 30

314,900

44.3468

N/A

December 1 – December 31

166,000

43.4638

N/A

Total

945,994

44.4178

N/A

(1)	At December 31, 2010, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2)	The plan administrator purchased 788,176 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)).

(3)	The plan administrator purchased 156,900 shares of our common stock in open-market transactions to meet share delivery obligations under the Savings Plan for Employees of Florida Progress Corporation.

(4)	Progress Energy withheld 918 shares of our common stock during the fourth quarter of 2010 to pay taxes due upon the payout of certain Restricted Stock Unit awards pursuant to the terms of the EIP.

PEC

Since 2000, the Parent has owned all of PEC’s common stock, and as a result, there is no established public trading market for the stock. PEC has neither issued nor repurchased any equity securities since becoming a wholly owned subsidiary of the Parent. During 2010 and 2009, PEC paid dividends to the Parent totaling the amounts shown in PEC’s Consolidated Statements of Changes in Total Equity included in the financial statements in PART II, Item 8. During 2008, PEC paid no dividends to the Parent. PEC has provisions restricting dividends in certain circumstances (See Notes 9 and 11). PEC does not have any equity compensation plans under which its equity securities are issued.

PEF

All shares of PEF’s common stock are owned by Florida Progress and, as a result, there is no established public trading market for the stock. PEF has neither issued nor repurchased any equity securities since becoming an indirect subsidiary of the Parent. During 2010, PEF paid dividends to Florida Progress totaling the amounts shown in PEF’s Statements of Changes in Common Stock Equity included in the financial statements in PART II, Item 8. During 2009 and 2008, PEF paid no dividends to Florida Progress. PEF has provisions restricting dividends in certain circumstances (See Notes 9 and 11). PEF does not have any equity compensation plans under which its equity securities are issued.

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data should be read in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this report.

PROGESS ENERGY
	Years Ended December 31
(in millions, except per share data)	2010		2009		2008		2007		2006
OPERATING RESULTS
Operating revenues	$	10,190	$	9,885	$	9,167	$	9,153	$	8,724
Income from continuing operations		867		840		778		702		567
Net income		863		761		836		496		620
Net income attributable to controlling interests		856		757		830		504		571

PER SHARE DATA
Basic and diluted earnings
Income from continuing operations attributable to controlling interests, net of tax	$	2.96	$	2.99	$	2.95	$	2.70	$	2.19
Net income attributable to controlling interests		2.95		2.71		3.17		1.96		2.27

ASSETS	$	33,054	$	31,236	$	29,873	$	26,338	$	25,832

CAPITALIZATION AND DEBT
Common stock equity	$	10,023	$	9,449	$	8,687	$	8,395	$	8,259
Noncontrolling interests		4		6		6		84		10
Preferred stock of subsidiaries		93		93		93		93		93
Long-term debt, net(a)		12,137		12,051		10,659		8,737		8,835
Current portion of long-term debt		505		406		-		877		324
Short-term debt		-		140		1,050		201		-
Capital lease obligations		221		231		239		247		72
Total capitalization and debt	$	22,983	$	22,376	$	20,734	$	18,634	$	17,593
Dividends declared per common share	$	2.480	$	2.480	$	2.465	$	2.445	$	2.425

(a)

Includes long-term debt to affiliated trust of $273 million at December 31, 2010, $272 million at December 31, 2009 and 2008 and $271 million at December 31, 2007 and 2006 (See Note 23).

PEC
	Years Ended December 31
(in millions)	2010		2009		2008		2007		2006
OPERATING RESULTS
Operating revenues	$	4,922	$	4,627	$	4,429	$	4,385	$	4,086
Net income		602		514		534		501		457
Net income attributable to controlling interests		603		516		534		501		457
Net income attributable to parent		600		513		531		498		454

ASSETS	$	14,899	$	13,502	$	13,165	$	11,955	$	11,999

CAPITALIZATION AND DEBT
Common stock equity	$	5,180	$	4,657	$	4,301	$	3,752	$	3,363
Noncontrolling interests		-		3		4		4		4
Preferred stock of subsidiaries		59		59		59		59		59
Long-term debt, net		3,693		3,703		3,509		3,183		3,470
Current portion of long-term debt		-		6		-		300		200
Short-term debt(a)		-		-		110		154		-
Capital lease obligations		14		15		16		17		18
Total capitalization and debt	$	8,946	$	8,443	$	7,999	$	7,469	$	7,114

(a)

Includes notes payable to affiliated companies, related to the money pool program of $154 million at December 31, 2007.

PEF

The information called for by Item 6 is omitted for PEF pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is separately filed by Progress Energy, Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF). As used in this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. Information contained herein relating to PEC and PEF individually is filed by such company on its own behalf. Neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

The following MD&A contains 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 “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” for a discussion of the factors that may impact any such forward-looking statements made herein.

MD&A includes financial information prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), as well as certain non-GAAP financial measures, “Ongoing Earnings” and “Base Revenues,” 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.

MD&A should be read in conjunction with the accompanying financial statements found elsewhere in this report. Certain amounts for 2009 and 2008 have been reclassified to conform to the 2010 presentation.

PROGRESS ENERGY

INTRODUCTION

Our reportable business segments are PEC and PEF, and their primary operations are the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively. The “Corporate and Other” segment primarily includes the operations of the Parent, Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses that do not separately meet the quantitative requirements as a separate reportable business segment.

MERGER

On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction (the Merger) and continue as a wholly owned subsidiary of Duke Energy. Consummation of the Merger is subject to customary conditions, including, among other things, approval of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of all approvals, to the extent required, from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission, the Nuclear Regulatory Commission (NRC), the North Carolina Utilities Commission (NCUC), the Kentucky Public Service Commission, the South Carolina Public Service Commission (SCPSC), the Florida Public Service Commission (FPSC), the Indiana Utility Regulatory Commission and the Ohio Public Utilities Commission.

See Item 1A, “Risk Factors,” and Note 25 for additional risks and information related to the Merger.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the Merger as discussed below. At this time, we do not anticipate modifying our 2011 strategy discussed below but cannot predict the impact consummation of the Merger will have on our long-term strategy. The combined company’s expected balance sheet and credit metrics are anticipated to enhance our growth opportunities and strategic options.

We do not expect the Merger to have a significant impact on our cash requirements and sources of liquidity during 2011, except that we do not expect to issue a material amount of equity. Pursuant to the Merger Agreement, only limited equity issuances through certain employee benefit plans and stock option plans are permitted. Additionally, the Merger Agreement restricts our ability, without Duke Energy’s consent, to increase the common stock dividend rate until consummation or termination of the Merger Agreement. Total capital spending and the extent to which we can obtain financing through long-term debt issuances are also limited.

The Parent’s credit facility expires May 3, 2012, and the combined shelf registration statement for the Parent, PEC and PEF expires November 18, 2011. The timing and structure of refinancing the Parent’s credit facility and filing the combined shelf registration statement with the SEC will be evaluated as more definitive timelines for the Merger and integration are developed (see “Future Liquidity and Capital Resources – Credit Facilities and Registration Statements” below).

Certain substantial changes in ownership of Progress Energy, including the Merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 14).

The companies are targeting for the Merger to close by the end of 2011. Until the Merger has received all necessary approvals and has closed, the companies will continue to operate as separate entities. Accordingly, the information presented in this Form 10-K is presented solely for the Progress Registrants on a pre-merger basis.

STRATEGY

We are an integrated energy company primarily focused on the end-use electricity markets. We own two electric utilities that operate in regulated retail utility markets in North Carolina, South Carolina and Florida and have access to attractive wholesale markets in the eastern United States. The Utilities have more than 22,000 megawatts (MW) of regulated electric generation capacity and serve approximately 3.1 million retail electric customers as well as other load-serving entities.

We have a strong track record of meeting our financial commitments. We have maintained liquidity and financial stability and sustained our dividend rate during the current economic downturn, and we believe that we have good prospects for growth once the economy begins to recover. In terms of our priorities for Progress Energy as a whole, we first focus on excelling in the fundamentals of our business. These fundamentals include safety, operational excellence, customer service, consistently achieving our financial objectives, maintaining constructive relations with regulators, political leaders and the general public as well as an internal focus on strong leadership that fully engages our workforce for high performance. In addition to excelling in these fundamentals, management has the following four focus areas for 2011:

·	Improve the performance of our nuclear fleet

·	Accelerate Continuous Business Excellence

·	Optimize our balanced solution strategy

·	Achieve effective integration planning and timely merger approvals

IMPROVE NUCLEAR FLEET PERFORMANCE

We are implementing a comprehensive improvement plan designed to strengthen and align the performance of our nuclear fleet. We are committed to raising our nuclear fleet performance to a consistently high level of safety, reliability and value. To do that, we have made a number of organizational changes and have intensified our focus on plant operations, outage planning and execution, and continuous improvement. We are also leveraging the expertise and capabilities of our company as a whole to meet these nuclear fleet objectives.

CONTINUOUS BUSINESS EXCELLENCE

For the past several years, we have been applying a continuous improvement framework to our operations through our Continuous Business Excellence initiative. Through a disciplined approach to identifying and eliminating waste and continuously improving our business, we are developing sustainable process improvements. We are gaining a clearer understanding of our cost drivers and of the dynamics shaping our near- and longer-term workforce planning needs. In addition, we have been applying the “Lean” process to our operations (Lean is a set of principles, tools, and techniques for improving the operating performance of any business). During 2010, we held more than 200 Lean events, a 50 percent increase over the prior year. The process changes resulting from these events are improving our safety and operational performance, enhancing the productivity and engagement of our employees, managing our rising costs and, ultimately, increasing customer satisfaction.

BALANCED SOLUTION STRATEGY

Our balanced solution strategy is a portfolio of investments and initiatives to meet future customer needs and evolving public policies in a way that creates long-term value for our customers and shareholders. The strategy is focused on expanding the diversity of our resources, including energy efficiency, alternative energy and a state-of-the-art power system. Expenditures to achieve our balanced solution are anticipated to be recoverable under base rates or cost-recovery mechanisms implemented by our state jurisdictions. Updates on our implementation of this strategy are discussed below.

First, we are continuing to expand and enhance our demand-side management (DSM), energy-efficiency (EE) and energy-conservation programs. We have implemented customer energy-saving programs, provided customers with incentives for efficiency improvements and expanded our customer education and outreach efforts. In addition, we are a leader in the utility industry in promoting and preparing for plug-in electric vehicles. We are participating, along with nine other utilities across the nation, in Chevrolet’s two-year demonstration and research program for its Volt electric vehicle. As a program participant, we will use 12 electric vehicles to conduct a variety of utility service roles. Additionally, we will gather data from driver surveys and charging stations and study the impact of the vehicles on the electric grid.

Second, we are actively engaged in a variety of alternative energy projects. We have executed contracts to purchase 311 MW of electricity generated from solar, biomass and municipal solid waste sources. While this currently represents a small percentage of our total capacity, we will continue to pursue additional contracts for these and other alternative energy sources. PEC is on track to meet the first of the targets set under North Carolina’s renewable energy portfolio standard, 3 percent of retail electric sales by 2012.

Third, we are pursuing numerous options to create a state-of-the-art power system. We are making a significant investment in smart grid technology with the initiatives partially funded by $200 million of federal matching infrastructure funds. Our strategy also includes advanced environmental controls on our coal-fired plants, and we have successfully completed the $2 billion of emission control installations planned for our coal fleets in North Carolina and Florida. Of our approximately 7,500 MW of coal-fired generation, we have scrubbed and installed emission control equipment on almost 5,000 MW. We are also moving forward with our previously announced coal-to-gas modernization strategy, which includes retiring our North Carolina coal-fired plants that do not have scrubbers (totaling approximately 1,500 MW) and replacing them with new combined-cycle natural gas plants. We expect to retire these coal-fired generating facilities no later than the end of 2014, and the new natural gas plants are expected to be placed in service in 2013 and 2014. As a result of the installation of environmental controls and the retirement of unscrubbed coal-fired plants, our emissions profile will be significantly reduced while strengthening our fuel diversification. A reduced emissions profile puts us in a better position to comply with the more stringent environmental regulations anticipated in the future.

New nuclear generation is a vital long-term part of our balanced solution strategy. While we have not made a final determination on nuclear construction, we have taken steps to keep open the option of building one or more plants. The Utilities have each filed a combined license (COL) application with the NRC for two additional reactors each at Shearon Harris Nuclear Plant (Harris) and at a greenfield site in Levy County, Florida (Levy).

We have focused on Levy given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce greenhouse gas (GHG) emissions, as well as existing state legislative policy that is supportive of nuclear projects. PEF has entered into an engineering, procurement and construction (EPC) agreement and received two of the three key approvals needed for the proposed Levy units (with the issuance of the COL remaining). In light of a regulatory schedule shift and other factors, we have amended the EPC agreement and are deferring major construction on Levy until we receive the COL, expected in 2013. This decision will reduce the near-term price impact on customers and allows time for economic recovery and greater clarity on federal and state policies. Once we have received the COL, we will assess the project and determine the schedule.

INTEGRATION PLANNING AND TIMELY MERGER APPROVALS

We are in the early stages of integration planning for the Merger, and are also preparing for the various steps in the merger approval process. We believe our Continuous Business Excellence initiative will help us in the merger integration process. One important element of the initiative is getting a better understanding of the dynamics shaping near- and long-term workforce needs, which will be beneficial in integration planning. Integration planning efforts will also focus on savings from the fuel purchasing power and joint dispatch of generating plants of the combined companies. Maintaining constructive relations with regulators, public leaders and the general public is fundamental to our business, which will be critical for obtaining needed merger approvals in a timely manner.

MATTERS IMPACTING FUTURE RESULTS AND LIQUIDITY

The impact of favorable weather on the Utilities’ revenues in 2010 offset the impacts of a continuing sluggish economy and cost pressures facing the utility industry. An improving national economy may lead to greater mobility for homeowners around the country and a return of migration to the Southeast region that is more consistent with our historical levels. However, the utility industry, as a whole, faces significant cost pressures and, in the near term, lower retail electricity sales. Current economic conditions and anticipated higher expenditures (including expenditures for environmental compliance, renewable energy standards compliance and new generation and transmission facilities) may subject us to an even higher level of scrutiny from regulators and lead to a more uncertain regulatory environment. Timely regulatory recovery of costs recoverable under the Utilities’ pass-through clauses (such as fuel and environmental compliance) is important to maintaining appropriate levels of liquidity.

We are preparing for an energy future that includes, among other things, carbon reductions and emerging technologies such as smart grid and plug-in electric vehicles. We believe that our balanced solution strategy provides an effective, flexible framework that will prepare us for this new energy future.

RESULTS OF OPERATIONS

In this section, we provide analysis and discussion of earnings and the factors affecting earnings on both a GAAP and non-GAAP basis. We introduce our results of operations in an overview section followed by a more detailed analysis and discussion by business segment.

We compute our non-GAAP financial measurement “Ongoing Earnings” as GAAP net income attributable to controlling interests after excluding discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Ongoing Earnings is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to, and not a substitute for, our results of operations presented in accordance with GAAP.

A reconciliation of Ongoing Earnings to GAAP net income attributable to controlling interests follows:


(in millions except per share data)	PEC			PEF			Corporate and Other			Total			Per Share
Year ended December 31, 2010
Ongoing Earnings	$	618		$	462		$	(191	)	$	889		$	3.06
Impairment, net of tax(a)		(5	)		(1	)		-			(6	)		(0.02	)
Plant retirement charge, net of tax(a)		(1	)		-			-			(1	)		-
Change in the tax treatment of the Medicare Part D subsidy		(12	)		(10	)		-			(22	)		(0.08	)
Discontinued operations attributable to controlling interests, net of tax		-			-			(4	)		(4	)		(0.01	)
Net income (loss) attributable to controlling interests(b)	$	600		$	451		$	(195	)	$	856		$	2.95

Year ended December 31, 2009
Ongoing Earnings	$	540		$	460		$	(154	)	$	846		$	3.03
CVO mark-to-market		-			-			19			19			0.07
Impairment, net of tax(a)		-			-			(2	)		(2	)		(0.01	)
Plant retirement charge, net of tax(a)		(17	)		-			-			(17	)		(0.06	)
Cumulative prior period adjustment related to certain employee life insurance benefits, net of tax(a)		(10	)		-			-			(10	)		(0.04	)
Discontinued operations attributable to controlling interests, net of tax		-			-			(79	)		(79	)		(0.28	)
Net income (loss) attributable to controlling interests(b)	$	513		$	460		$	(216	)	$	757		$	2.71

Year ended December 31, 2008
Ongoing Earnings	$	531		$	383		$	(138	)	$	776		$	2.96
Valuation allowance and related net operating loss carry forward		-			-			(3	)		(3	)		(0.01	)
Discontinued operations attributable to controlling interests, net of tax		-			-			57			57			0.22
Net income (loss) attributable to controlling interests(b)	$	531		$	383		$	(84	)	$	830		$	3.17

(a)

Calculated using assumed tax rate of 40 percent.

(b)

Net income attributable to controlling interests is shown net of preferred stock dividend requirement of $3 million and $2 million at PEC and PEF, respectively.

Management uses the non-GAAP financial measure Ongoing Earnings (i) as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; (iii) as a measure for determining levels of incentive compensation; and (iv) in communications with our board of directors, employees, shareholders, analysts and investors concerning our financial performance. Management believes this non-GAAP measure is appropriate for understanding the business and assessing our potential future performance, because excluded items are limited to those that management believes are not representative of our fundamental core earnings (See Note 19).

OVERVIEW

FOR 2010 AS COMPARED TO 2009 and 2009 AS COMPARED TO 2008

For the year ended December 31, 2010, our net income attributable to controlling interests was $856 million, or $2.95 per share, compared to net income attributable to controlling interests of $757 million, or $2.71 per share, for the same period in 2009. The increase as compared to prior year was primarily due to:

·	favorable weather at the Utilities and

·	lower loss from discontinued non-utility businesses (Ongoing Earnings adjustment).

Partially offsetting these items was:

·	higher operation and maintenance (O&M) expenses at the Utilities.

For the year ended December 31, 2009, our net income attributable to controlling interests was $757 million, or $2.71 per share, compared to net income attributable to controlling interests of $830 million, or $3.17 per share, for the same period in 2008. The decrease as compared to prior year was primarily due to:

·	unfavorable impact of discontinued non-utility businesses (Ongoing Earnings adjustment);

·	unfavorable net retail customer growth and usage at the Utilities;

·	higher interest expense; and

·	higher base depreciation and amortization at the Utilities.

Partially offsetting these items were:

·	net impact of returns earned on higher levels of nuclear and environmental cost recovery clause (ECRC) assets at PEF;

·	favorable impact of interim and limited base rate relief at PEF;

·	depreciation and amortization expense recognized in 2008 at PEC related to North Carolina Clean Smokestacks Act (Clean Smokestacks Act) amortization expense and depreciation expense associated with the accelerated cost-recovery program for nuclear generating assets; and

·	favorable weather at the Utilities.

PROGRESS ENERGY CAROLINAS

PEC contributed net income available to parent totaling $600 million, $513 million and $531 million in 2010, 2009 and 2008, respectively. The increase in net income available to parent for 2010 as compared to 2009 was primarily due to the favorable impact of weather, favorable allowance for funds used during construction (AFUDC) equity and favorable retail customer growth and usage, partially offset by higher O&M expenses. The decrease in net income available to parent for 2009 as compared to 2008 was primarily due to unfavorable net retail customer growth and usage, coal plant retirement charges, higher base depreciation and amortization expense and a cumulative prior period adjustment related to certain employee life insurance benefits, partially offset by Clean Smokestacks Act amortization and depreciation expense associated with the accelerated cost-recovery program for nuclear generating assets recognized in 2008 and the favorable impact of weather.

PEC contributed Ongoing Earnings of $618 million, $540 million and $531 million for 2010, 2009 and 2008, respectively. The 2010 Ongoing Earnings adjustments to net income available to parent were due to PEC recording a $12 million charge for the change in the tax treatment of the Medicare Part D subsidy, a $5 million impairment of certain miscellaneous investments and other assets, net of tax and a $1 million plant retirement adjustment, net of tax, related to PEC’s decision to retire certain coal-fired generating units prior to the end of their estimated useful lives. The 2009 Ongoing Earnings adjustments to net income available to parent were due to PEC recording a $17 million plant retirement charge, net of tax, and recording a $10 million charge, net of tax, for a cumulative prior period adjustment related to certain employee life insurance benefits. Management does not consider these charges to be representative of PEC’s fundamental core earnings and excluded these charges in computing PEC’s Ongoing Earnings. There were no Ongoing Earnings adjustments in 2008.

REVENUES

The revenue tables that follow present the total amount and percentage change of total operating revenues and its components. “Base Revenues" is a non-GAAP measure and is defined as operating revenues excluding clause-recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues. We and PEC consider Base Revenues a useful measure to evaluate PEC’s electric operations because fuel and other pass-through revenues primarily represent the recovery of fuel, applicable portions of purchased power expenses and other pass-through expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. Clause-recoverable regulatory returns include the return on asset component of DSM, EE and renewable energy clause revenues. We and PEC have included the reconciliation and analysis that follows as a complement to the financial information we provide in accordance with GAAP.

A reconciliation of Base Revenues to GAAP operating revenues, including the percentage change by customer class and by year follows:


(in millions) Customer Class		2010	% Change		2009	% Change		2008
Residential	$	1,242	10.1	$	1,128	1.3	$	1,113
Commercial		726	2.7		707	(1.4)		717
Industrial		365	2.5		356	(10.6)		398
Governmental		65	10.2		59	(3.3)		61
Unbilled		10	-		5	-		8
Total retail base revenues		2,408	6.8		2,255	(1.8)		2,297
Wholesale base revenues		305	(1.0)		308	0.3		307
Total Base Revenues		2,713	5.9		2,563	(1.6)		2,604
Clause-recoverable regulatory returns		13	44.4		9	-		-
Miscellaneous		138	21.1		114	11.8		102
Fuel and other pass-through revenues		2,058	-		1,941	-		1,723
Total operating revenues	$	4,922	6.4	$	4,627	4.5	$	4,429

PEC’s total Base Revenues were $2.713 billion and $2.563 billion for 2010 and 2009, respectively. The $150 million increase in Base Revenues was due primarily to the $115 million favorable impact of weather and the $36 million favorable impact of retail customer growth and usage. The favorable impact of weather was driven by 15 percent higher heating-degree days and 24 percent higher cooling-degree days than 2009. Additionally, cooling degree-days were 30 percent higher and heating degree-days were 14 percent higher than normal. The favorable impact of retail customer growth and usage was driven by an increase in the average usage per retail customer and a net 10,000 increase in the average number of customers for 2010 compared to 2009. See “Seasonality and the Impact of Weather” in Item 1, “Business,” for a summary of degree days and weather estimation.

PEC’s miscellaneous revenues increased $24 million in 2010, which includes $10 million higher transmission revenues driven by higher rates resulting from transmission asset additions.

PEC’s total Base Revenues were $2.563 billion and $2.604 billion for 2009 and 2008, respectively. The $41 million decrease in Base Revenues was due primarily to the $64 million unfavorable impact of net retail customer growth

and usage, partially offset by the $23 million favorable impact of weather. The unfavorable impact of net retail customer growth and usage was driven by a decrease in the average usage per retail customer, partially offset by a net 11,000 increase in the average number of customers for 2009 compared to 2008. The favorable impact of weather was driven by higher heating- and cooling-degree days than 2008 of 3 percent and 5 percent, respectively. Additionally, cooling-degree days were 6 percent higher than normal in 2009.

PEC’s miscellaneous revenues increased $12 million in 2009 primarily due to higher transmission revenues.

PEC’s electric energy sales in kilowatt-hours (kWh) and the percentage change by customer class and by year were as follows:


(in millions of kWh)
Customer Class	2010		% Change		2009		% Change			2008
Residential		19,108		11.6		17,117		0.7			17,000
Commercial		14,184		4.0		13,639		(2.2	)		13,941
Industrial		10,665		2.9		10,368		(9.0	)		11,388
Governmental		1,574		5.1		1,497		2.1			1,466
Unbilled		172		-		360		-			(8	)
Total retail kWh sales		45,703		6.3		42,981		(1.8	)		43,787
Wholesale		13,999		0.2		13,966		(2.5	)		14,329
Total kWh sales		59,702		4.8		56,947		(2.0	)		58,116

The increase in retail kWh sales in 2010 was primarily due to favorable weather, as previously discussed.

The decrease in retail kWh sales in 2009 was primarily due to a decrease in average usage per retail customer due to economic conditions in the United States. PEC’s industrial kWh sales decreased 9.0 percent from 2008, primarily due to reductions in textile manufacturing in the Carolinas as a result of global competition and domestic consolidation as well as a downturn in the lumber and building materials segment as a result of declines in construction. Wholesale kWh sales decreased for 2009 primarily due to decreased excess generation sales resulting from unfavorable market dynamics.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation and energy purchased in the market to meet customer load. Fuel and a portion of purchased power expenses are recovered primarily through cost-recovery clauses, and as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection from or refund to customers and is recorded as deferred fuel expense, which is included in fuel used in electric generation on the Consolidated Statements of Income.

Fuel and purchased power expenses totaled $1.988 billion for 2010, which represents a $79 million increase compared to 2009. This increase was primarily due to the $324 million impact of higher system requirements resulting from favorable weather and the impact of nuclear plant outages on PEC’s generation mix, partially offset by $151 million decreased current year fuel costs driven by lower coal and gas prices and $104 million lower deferred fuel expense. The decrease in deferred fuel expense was primarily due to higher fuel and purchased power expenses and lower fuel rates in North Carolina. See “Electric Utility Regulated Operating Statistics - PEC” in Item 1, “Business,” for a summary of average fuel costs.

Fuel and purchased power expenses totaled $1.909 billion for 2009, which represents a $217 million increase compared to 2008. This increase was primarily due to $248 million higher deferred fuel expense and the $86 million net impact of higher fuel costs driven by higher coal prices, partially offset by $128 million impact of lower system requirements. The increase in deferred fuel expense was primarily due to the implementation of higher fuel rates in North Carolina.

Operation and Maintenance

O&M expense was $1.158 billion for 2010, which represents an $86 million increase compared to 2009. This increase was primarily due to $78 million higher nuclear plant outage and maintenance costs, $11 million higher employee benefits expense driven by revised actuarial estimates, $7 million higher emission expense primarily due to sales of nitrogen oxides (NOx) emission allowances in the prior year and the $2 million impairment of other assets, partially offset by $27 million lower coal plant retirement charges. The higher nuclear plant outage and maintenance costs are primarily due to three nuclear refueling and maintenance outages in 2010 compared to two in 2009 as well as extended outages and more emergent work in 2010 as compared to 2009. Management does not consider impairments and charges recognized for the retirement of generating units prior to the end of their estimated useful lives to be representative of PEC’s fundamental core earnings. Therefore, the impacts of these items are excluded in computing PEC’s Ongoing Earnings. Certain O&M expense such as the cost of reagents for emission control equipment and wheeling charges are recoverable through cost-recovery clauses. In aggregate, O&M expenses primarily recoverable through base rates increased $69 million compared to the same period in 2009.

O&M expense was $1.072 billion for 2009, which represents a $42 million increase compared to 2008. This increase was primarily due to coal plant retirement charges of $28 million, higher employee benefits expense of $12 million and storm costs of $9 million, partially offset by lower emission allowance expense of $13 million resulting from lower system requirements, changes in generation mix and sales of NOx allowances. As previously discussed, coal plant retirement charges are excluded in computing PEC’s Ongoing Earnings. Also, as previously discussed, certain O&M expenses are recoverable through cost-recovery clauses. In aggregate, O&M expenses primarily recoverable through base rates increased $29 million compared to the same period in 2008.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $479 million, $470 million and $518 million for 2010, 2009 and 2008, respectively. The $48 million decrease in 2009 compared to 2008 was primarily attributable to the $52 million of depreciation associated with the accelerated cost-recovery program for nuclear generating assets recognized in 2008 and the $15 million of Clean Smokestacks Act amortization recognized in 2008, partially offset by the $21 million impact of depreciable asset base increases. The North Carolina jurisdictional aggregate minimum amount of accelerated cost recovery has been met, and the South Carolina jurisdictional obligation was terminated by the SCPSC. PEC does not anticipate recording additional accelerated depreciation in the North Carolina jurisdiction, but will record depreciation over the remaining useful lives of the assets. In accordance with a regulatory order, PEC ceased to amortize Clean Smokestacks Act compliance costs, but will record depreciation over the useful lives of the assets.

Taxes Other Than on Income

Taxes other than on income was $218 million for 2010, which represents an $8 million increase compared to 2009. This increase was primarily due to an increase in gross receipts taxes due to higher operating revenues. Taxes other than on income was $210 million for 2009, which represents a $12 million increase compared to 2008. The increase was primarily due to an increase in gross receipts taxes due to higher operating revenues and higher property tax rates. Gross receipts taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Other

Other operating expense was an expense of $8 million in 2010 and income of $5 million in 2008. The $8 million expense in 2010 was primarily due to the $7 million impairment of certain miscellaneous investments. The $5 million income in 2008 was primarily due to gain on land sales. Management does not consider impairments to be representative of PEC’s fundamental core earnings. Therefore, the impacts of impairments are excluded in computing PEC’s Ongoing Earnings.

Total Other Income, Net

Total other income, net was $67 million for 2010, which represents a $47 million increase compared to 2009. This increase was primarily due to favorable AFUDC equity of $31 million resulting from increased construction project costs and a $16 million cumulative prior period adjustment charge recorded in 2009 related to certain employee life insurance benefits. The prior period adjustment is not material to 2009 or previously issued financial statements. Management determined that the adjustment should be an exclusion from PEC’s 2009 Ongoing Earnings.

Total other income, net was $20 million for 2009, which represents a $23 million decrease compared to 2008. This decrease was primarily due to the previously discussed $16 million cumulative prior period adjustment related to certain employee life insurance benefits as well as lower interest income resulting from lower average eligible deferred fuel balances.

Total Interest Charges, Net

Total interest charges, net was $186 million, $195 million and $207 million for 2010, 2009 and 2008, respectively. The $9 million decrease in 2010 compared to 2009 was primarily due to $7 million favorable AFUDC debt related to increased construction project costs. The $12 million decrease in 2009 compared to 2008 was primarily due to lower interest rates on variable rate debt, partially offset by higher interest as a result of higher average debt outstanding.

Income Tax Expense

Income tax expense was $350 million, $277 million and $298 million in 2010, 2009 and 2008, respectively. The $73 million increase in 2010 compared to 2009 was primarily due to the $64 million impact of higher pre-tax income and the $12 million impact of the change in the tax treatment of the Medicare Part D subsidy resulting from federal health care reform enacted earlier in 2010 (See Note 16). Management does not consider the change in the tax treatment of the Medicare Part D subsidy to be representative of PEC’s fundamental core earnings, and therefore, the amount is excluded in computing PEC’s Ongoing Earnings. The $21 million income tax expense decrease in 2009 compared to 2008 was primarily due to the impact of lower pre-tax income and the $5 million favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from nonqualified nuclear decommissioning trusts (NDTs) to qualified NDTs.

PROGRESS ENERGY FLORIDA

PEF contributed net income available to parent totaling $451 million, $460 million and $383 million in 2010, 2009 and 2008, respectively. The decrease in net income available to parent for 2010 as compared to 2009 was primarily due to unfavorable AFUDC equity and higher O&M expenses, partially offset by the favorable impact of weather and higher clause-recoverable regulatory returns. The increase in net income available to parent for 2009 compared to 2008 was primarily due to higher clause-recoverable regulatory returns, the favorable impact of interim and limited base rate relief and the favorable impact of weather, partially offset by the unfavorable impact of retail customer growth and usage, higher base depreciation and amortization expense, and higher O&M.

PEF contributed Ongoing Earnings of $462 million, $460 million and $383 million in 2010, 2009 and 2008, respectively. The 2010 Ongoing Earnings adjustments to net income available to parent were due to PEF recording a $10 million charge for the change in the tax treatment of the Medicare part D subsidy and a $1 million impairment of other assets, net of tax. Management does not consider these charges to be representative of PEF’s fundamental core earnings and excluded these charges in computing PEF’s Ongoing Earnings. There were no Ongoing Earnings adjustments in 2009 or 2008.

REVENUES

The revenue tables that follow present the total amount and percentage change of total operating revenues and its components. “Base Revenues” is a non-GAAP measure and is defined as operating revenues excluding clause-recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues. We and PEF consider Base Revenues a useful measure to evaluate PEF’s electric operations because fuel and other pass-through revenues primarily represent the recovery of fuel, applicable portions of purchased power and other pass-through

expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. Clause-recoverable regulatory returns include the revenues associated with the return on asset component of nuclear cost-recovery and ECRC revenues. We and PEF have included the reconciliation and analysis that follows as a complement to the financial information we provide in accordance with GAAP.

A reconciliation of Base Revenues to GAAP operating revenues, including the percentage change by customer class and by year follows:


(in millions) Customer Class		2010	% Change		2009	% Change		2008
Residential	$	1,045	10.5	$	946	5.9	$	893
Commercial		359	5.6		340	3.7		328
Industrial		75	4.2		72	(5.3)		76
Governmental		92	5.7		87	6.1		82
Unbilled		17	-		9	-		(1)
Total retail base revenues		1,588	9.2		1,454	5.5		1,378
Wholesale base revenues		160	(22.7)		207	5.1		197
Total Base Revenues		1,748	5.2		1,661	5.5		1,575
Clause-recoverable regulatory returns		173	98.9		87	690.9		11
Miscellaneous		216	14.3		189	6.2		178
Fuel and other pass-through revenues		3,117	-		3,314	-		2,967
Total operating revenues	$	5,254	0.1	$	5,251	11.0	$	4,731

PEF’s total Base Revenues were $1.748 billion and $1.661 billion for 2010 and 2009, respectively. The $87 million increase in Base Revenues was due primarily to the $88 million favorable impact of weather and the $50 million impact of increased retail base rates associated with the repowered Bartow Plant, partially offset by $47 million lower wholesale base revenues and the $5 million unfavorable impact of net retail customer growth and usage. The favorable impact of weather was driven by 89 percent higher heating-degree days than 2009. Additionally, heating-degree days were 124 percent higher than normal. The lower wholesale base revenues were primarily due to an amended contract with a major customer. The unfavorable impact of net retail customer growth and usage was driven by a decrease in the average usage per retail customer, partially offset by a net 4,000 increase in the average number of customers for 2010 compared to 2009. See “Seasonality and the Impact of Weather” in Item 1, “Business,” for a summary of degree days and weather estimation.

PEF’s clause-recoverable regulatory returns increased $86 million in 2010 primarily due to higher returns on ECRC assets due to placing approximately $1 billion of Clean Air Interstate Rule (CAIR) projects into service in late 2009 and May 2010.

PEF’s miscellaneous revenues increased $27 million in 2010 primarily due to $20 million higher transmission revenues driven by favorable weather and $8 million higher right-of-use revenues related to the use of easements and land.

PEF’s total Base Revenues were $1.661 billion and $1.575 billion for 2009 and 2008, respectively. The $86 million increase in Base Revenues was due primarily to the $79 million favorable impact of interim and limited base rate relief and the $36 million favorable impact of weather, partially offset by the $41 million unfavorable impact of retail customer growth and usage. The interim and limited base rate relief was approved by the FPSC effective July 1, 2009. Of the $79 million interim and limited base rate relief, $7 million related to interim rate relief, which was in effect for only 2009, and $72 million related to limited rate relief, which continued in accordance with the base rate proceeding with an annual revenue requirement of $132 million. The favorable impact of weather was primarily driven by 14 percent higher heating-degree days and 6 percent higher cooling-degree days than 2008. Heating-degree days were 4 percent lower than normal in 2009 and 16 percent lower than normal in 2008. In addition to lower average usage per customer, PEF’s average number of customers for 2009, compared to 2008, decreased a net 8,000 customers.

PEF’s clause-recoverable regulatory returns increased $76 million in 2009 primarily due to higher revenues related to nuclear cost recovery and ECRC assets of $61 million and $15 million, respectively. As a result of an FPSC regulatory order effective in January 2009, PEF is allowed to earn returns on certain costs related to nuclear construction.

PEF’s electric energy sales in kWh and the percentage change by customer class and by year were as follows:


(in millions of kWh)
Customer Class	2010		% Change			2009		% Change			2008
Residential		20,524		5.8			19,399		0.4			19,328
Commercial		11,896		0.1			11,884		(2.1	)		12,139
Industrial		3,219		(2.0	)		3,285		(13.2	)		3,786
Governmental		3,286		0.9			3,256		(1.4	)		3,302
Unbilled		458		-			131		-			(99	)
Total retail kWh sales		39,383		3.8			37,955		(1.3	)		38,456
Wholesale		3,857		0.6			3,835		(43.1	)		6,734
Total kWh sales		43,240		3.5			41,790		(7.5	)		45,190

The increase in retail kWh sales in 2010 was primarily due to favorable weather as previously discussed.

Wholesale kWh sales have increased in 2010 primarily due to favorable weather, which resulted in increased deliveries under a certain capacity contract that has high demand and low energy charges. Despite the increase in sales, wholesale base revenues have decreased primarily due to a contract amendment as previously discussed.

Wholesale base revenues increased in 2009, despite decreased wholesale kWh sales in 2009, primarily due to committed capacity revenues. The wholesale kWh sales decreased primarily due to market conditions in which wholesale customers fulfilled a portion of their system requirements from other sources. Many of the new and amended capacity contracts entered into in 2008 expired by the end of 2009.

Retail base revenues increased in 2009, despite a decrease in kWh sales for the same period, primarily due to the impact of interim and limited base rate relief approved by the FPSC in 2009.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses totaled $2.591 billion in 2010, which represents a $163 million decrease compared to 2009. This decrease was primarily due to lower deferred fuel expense of $520 million resulting from lower fuel rates, which assumed the CR3 outage was completed in 2009, partially offset by increased current year fuel and purchased power costs of $189 million and an increase in the recovery of deferred capacity costs of $167 million. The increased current year fuel and purchased power costs were primarily driven by higher system requirements resulting from favorable weather and CR3 replacement power costs net of insurance recovery. The increase in the recovery of deferred capacity costs was primarily due to increased rates and higher system requirements due to favorable weather. See “Electric Utility Regulated Statistics - PEF” in Item 1, “Business,” for a summary of average fuel costs.

Fuel and purchased power expenses totaled $2.754 billion in 2009, which represents a $126 million increase compared to 2008. This increase was primarily due to higher deferred fuel expense of $467 million driven by the implementation of new fuel rates, partially offset by $164 million lower interchange costs, a decrease in the recovery

of deferred capacity costs of $91 million and decreased 2009 fuel costs of $70 million, all resulting from lower system requirements.

Operation and Maintenance

O&M expense was $912 million in 2010, which represents a $73 million increase compared to 2009. O&M expense increased primarily due to the $34 million prior-year pension deferral in accordance with an FPSC order; $22 million higher employee benefits expense driven by revised actuarial estimates; $18 million higher Energy Conservation Cost Recovery Clause (ECCR) costs driven by higher deferred expenses due to higher rates, increased energy sales and increased customer usage of load management programs and home improvement incentives; the $11 million prior-year impact of a change in vacation benefits policy; and the $2 million impairment of other assets. These increases are partially offset by $22 million favorable ECRC costs due to lower NOx allowances used resulting from a scrubber placed in service in December 2009. The ECCR and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. Management does not consider impairments to be representative of PEF’s fundamental core earnings. Therefore, the impacts of impairments are excluded in computing PEF’s Ongoing Earnings. In aggregate, O&M expenses primarily recoverable through base rates increased $80 million compared to the same period in 2009.

O&M expense was $839 million in 2009, which represents a $26 million increase compared to 2008. The increase was primarily due to $63 million higher ECRC and ECCR costs primarily due to an increase in current year rates for recovery of emission allowances, higher pension costs of $24 million and higher nuclear plant outage and maintenance costs of $14 million, partially offset by lower storm cost recovery of $66 million due to the surcharge that ended in July 2008 and the impact of a change in our vacation benefits policy of $11 million. The ECRC and ECCR expenses and replenishment of storm damage reserve are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. Pension costs were higher due to a $20 million pension credit in 2008. Substantially all of 2009’s pension expense was deferred in accordance with an FPSC order. In aggregate, O&M expenses recoverable through base rates increased $25 million compared to the same period in 2008.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $426 million for 2010, which represents a $76 million decrease compared to 2009. Depreciation, amortization and accretion expense decreased primarily due to a reduction in the cost of removal component of amortization expense of $60 million in accordance with the base rate settlement agreement (See Note 7C), the lower depreciation rate impact of $43 million and other adjustments required in the base rate settlement agreement of $13 million, partially offset by the $46 million impact of depreciable asset base increases. The lower depreciation rate resulted from a depreciation study in conjunction with the 2009 base rate case. In accordance with PEF’s base rate settlement agreement, PEF will have the discretion to reduce the cost of removal component of amortization expense in 2011 and 2012, subject to limitations (See Note 7C).

Depreciation, amortization and accretion expense was $502 million for 2009, which represents an increase of $196 million compared to 2008, primarily due to higher nuclear cost-recovery amortization of $155 million. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates and the ECRC increased $31 million compared to 2008, primarily due to depreciable asset base increases.

Taxes Other Than on Income

Taxes other than on income was $362 million for 2010, which represents a $15 million increase compared to 2009. This increase was primarily due to higher property taxes of $14 million resulting primarily from placing the repowered Bartow Plant in service in June 2009. Taxes other than on income was $347 million for 2009, which represents an increase of $38 million compared to 2008, primarily due to an increase in gross receipts and franchise taxes due to higher operating revenues. Gross receipts and franchise taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Other

Other operating expense was an expense of $4 million and $7 million in 2010 and 2009, respectively, and income of $5 million in 2008. The $7 million expense in 2009 was primarily due to regulatory disallowance of fuel costs. The $5 million income in 2008 was primarily due to gain on land sales.

Total Other Income, Net

Total other income, net was $28 million for 2010, which represents a $72 million decrease compared to 2009. This decrease was primarily due to $63 million unfavorable AFUDC equity related to lower eligible construction project costs, primarily due to placing the repowered Bartow Plant and CAIR projects into service in mid- and late 2009, respectively.

Total other income, net was $100 million for 2009, which represents a $6 million increase compared to 2008. This increase was primarily due to the $16 million of investment gains on certain employee benefit trusts resulting from improved market conditions, partially offset by $5 million lower interest income resulting from lower short-term investment balances and $4 million unfavorable AFUDC equity related to lower eligible construction project costs, primarily due to placing the repowered Bartow Plant into service in 2009.

Total Interest Charges, Net

Total interest charges, net was $258 million for 2010, which represents a $27 million increase compared to 2009. This increase was primarily due to $14 million unfavorable AFUDC debt related to costs associated with eligible construction projects as discussed above and $16 million higher interest driven by higher average long-term debt outstanding.

Total interest charges, net was $231 million in 2009, which represents an increase of $23 million compared to 2008. The increase in interest charges was primarily due to higher interest as a result of higher average debt outstanding.

Income Tax Expense

Income tax expense was $276 million, $209 million and $181 million in 2010, 2009 and 2008, respectively. The $67 million income tax expense increase in 2010 compared to 2009 was primarily due to the $24 million impact of the unfavorable AFUDC equity discussed above, the $23 million impact of higher pre-tax income and the $10 million impact of the change in the tax treatment of the Medicare Part D subsidy resulting from federal health care reform enacted earlier in 2010 (See Note 16). AFUDC equity is excluded from the calculation of income tax expense. As previously discussed, management does not consider the change in the tax treatment of the Medicare Part D subsidy to be representative of PEF’s fundamental core earnings. Accordingly, the impact of the change in the tax treatment of the Medicare Part D subsidy is excluded in computing PEF’s Ongoing Earnings.

The $28 million income tax expense increase in 2009 compared to 2008 was primarily due to the $40 million impact of higher pre-tax income compared to the prior year, partially offset by the $11 million impact of the favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from the nonqualified NDT fund to the qualified NDT fund.

CORPORATE AND OTHER

The Corporate and Other segment primarily includes the operations of the Parent, PESC and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. A discussion of the items excluded from Corporate and Other’s Ongoing Earnings is included in the detailed discussion and analysis below. Management believes the excluded items are not representative of our fundamental core earnings. The following table reconciles Corporate and Other’s Ongoing Earnings to GAAP net income attributable to controlling interests:


(in millions)	2010			Change			2009			Change			2008
Other interest expense	$	(298	)	$	(52	)	$	(246	)	$	(31	)	$	(215	)
Other income tax benefit		116			19			97			6			91
Other expense		(9	)		(4	)		(5	)		9			(14	)
Ongoing Earnings		(191	)		(37	)		(154	)		(16	)		(138	)
CVO mark-to-market		-			(19	)		19			19			-
Impairment, net of tax		-			2			(2	)		(2	)		-
Valuation allowance and related net operating loss carry forward		-			-			-			3			(3	)
Discontinued operations attributable to controlling interests, net of tax		(4	)		75			(79	)		(136	)		57
Net loss attributable to controlling interests	$	(195	)	$	21		$	(216	)		(132	)	$	(84	)

OTHER INTEREST EXPENSE

Other interest expense was $298 million, $246 million and $215 million for 2010, 2009 and 2008, respectively. The $52 million increase for 2010 compared to 2009 and the $31 million increase for 2009 compared to 2008 were primarily due to higher average debt outstanding at the Parent.

OTHER INCOME TAX BENEFIT

Other income tax benefit was $116 million, $97 million and $91 million for 2010, 2009 and 2008, respectively. The $19 million increase for 2010 compared to 2009 was primarily due to the favorable tax impact of higher pre-tax loss. The $6 million increase for 2009 compared to 2008 was primarily due to the favorable tax impact of higher pre-tax loss, partially offset by the unfavorable impact at the Corporate level resulting from the deductions taken by the Utilities related to NDT funds (See “Progress Energy Carolinas – Income Tax Expense” and “Progress Energy Florida – Income Tax Expense”).

OTHER EXPENSE

Other expense was $9 million, $5 million and $14 million for 2010, 2009 and 2008, respectively. The $9 million change for 2009 compared to 2008 was primarily due to investment gains on certain employee benefit trusts resulting from improved financial market conditions in 2009.

ONGOING EARNINGS ADJUSTMENTS

CVO Mark-to-Market

Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress) in 2000. Each CVO represents the right of the holder to receive contingency payments based on the performance of four synthetic fuels facilities purchased by subsidiaries of Florida Progress in October 1999. The payments are based on the net after-tax cash flows the facilities generate (See Note 15). The CVOs had a fair value of $15 million at December 31, 2010 and 2009 and $34 million at December 31, 2008. Progress Energy recorded unrealized gains of $19 million in 2009 to record the change in fair value of the CVOs, which had average unit prices of $0.16 at December 31, 2010 and 2009 and $0.35 at December 31, 2008. The unrealized gain/loss recognized due to changes in fair value is recorded in other, net on the Consolidated

Statements of Income. Because Progress Energy is unable to predict the changes in the fair value of the CVOs, management does not consider this adjustment to be representative of our fundamental core earnings.

Impairment, Net of Tax

We recorded a $3 million impairment of investments in 2009. The impairment was recorded in other, net on the Consolidated Statements of Income. Management does not consider impairments to be representative of our fundamental core earnings.

Valuation Allowance and Related Net Operating Loss Carry Forward

We previously recorded a deferred tax asset for a state net operating loss carry forward upon the sale of our nonregulated generating facilities and energy marketing and trading operations. In 2008, we recorded an additional $6 million deferred tax asset related to the state net operating loss carry forward due to a change in estimate based on 2007 tax return filings. We also evaluated the total state net operating loss carry forward and recorded a partial valuation allowance of $9 million, which more than offset the change in estimate. Management does not consider net valuation allowances to be representative of our fundamental core earnings.

Discontinued Operations Attributable to Controlling Interests, Net of Tax

We completed our business strategy of divesting of nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. See Note 3 for additional information related to discontinued operations. We recognized $4 million and $79 million of loss from discontinued operations attributable to controlling interests, net of tax, for 2010 and 2009, respectively and $57 million of income from discontinued operations attributable to controlling interests, net of tax for 2008. Management does not consider operating results of discontinued operations to be representative of our fundamental core earnings.

In 2009, we recognized $79 million of expense from discontinued operations attributable to controlling interests, net of tax, which was primarily due to a jury delivering a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates previously engaged in coal-based solid synthetic fuels operations (See Note 22D). As a result, we recorded an after-tax charge of $74 million to discontinued operations, which was net of a previously recorded indemnification liability.

In 2008, we recognized $57 million of income from discontinued operations attributable to controlling interests, net of tax, which was comprised primarily of $49 million after-tax gains on sales of our coal terminals and docks in West Virginia and Kentucky and our remaining coal mining businesses.

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We prepared our Consolidated Financial Statements in accordance with GAAP. In doing so, we made certain estimates that were critical in nature to the results of operations. The following discusses those significant accounting policies and estimates that may have a material impact on our financial results and are subject to the greatest amount of subjectivity. We have discussed the development and selection of these critical accounting policies and estimates with the Audit and Corporate Performance Committee (Audit Committee) of our board of directors.

IMPACT OF UTILITY REGULATION

Our regulated utilities segments are subject to regulation that sets the prices (rates) we are permitted to charge customers based on the costs that regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by a nonregulated company. The application of GAAP for regulated operations to this ratemaking process results in deferral of expense recognition and the recording of regulatory assets based on anticipated future cash inflows. As a result of the different ratemaking processes in each state in which we operate, a significant amount of regulatory assets has been recorded. We continually review these regulatory assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Additionally, the state regulatory agencies’ ratemaking processes often provide flexibility in the manner and timing of the depreciation of property, nuclear decommissioning costs and amortization of the regulatory assets.

Our conclusion that we and the Utilities meet the criteria to apply GAAP for regulated operations is a material assumption in the presentation and evaluation of our and the Utilities’ financial position and results of operations. The Utilities’ ability to continue to meet the criteria for application of GAAP for regulated operations could be affected in the future by actions of our regulators, competitive forces and restructuring in the electric utility industry. State regulators may not allow the Utilities to increase future retail rates required to recover their operating costs or provide an adequate return on investment, or in the manner requested. State regulators may also seek to reduce or freeze retail rates. Such events occurring over a sustained period could result in the Utilities no longer meeting the criteria for the continued application of GAAP for regulated operations. In the event that GAAP for regulated operations no longer applies to one or both of the Utilities, we are subject to the risk that regulatory assets and liabilities would be eliminated and utility plant assets may be impaired, unless an appropriate recovery mechanism was provided. Additionally, our financial condition, cash flows and results of operations may be adversely impacted. See Note 7 for additional information related to the impact of utility regulation on our operations.

We evaluate the carrying value of long-lived assets and intangible assets with definite lives for impairment whenever impairment indicators exist. If an impairment indicator exists, the asset group held and used is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows or if the asset group is to be disposed of, an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. Our exposure to potential impairment losses for utility plant, net is mitigated by the fact that our regulated ratemaking process generally allows for recovery of our investment in utility plant plus an allowed return on the investment, as long as the costs are prudently incurred. The carrying values of our total utility plant, net at December 31 were as follows:


(in millions)	2010		2009
Progress Energy	$	21,240	$	19,733
PEC		10,961		9,886
PEF		10,189		9,733

As discussed in Note 13, our financial assets and liabilities are primarily comprised of derivative financial instruments and marketable debt and equity securities held in our nuclear decommissioning trusts. Substantially all unrealized gains and losses on derivatives and all unrealized gains and losses on nuclear decommissioning trust investments are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Therefore, the

impact of fair value measurements from recurring financial assets and liabilities on our or the Utilities’ earnings is not significant.

ASSET RETIREMENT OBLIGATIONS

Asset Retirement Obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets. The present values of retirement costs for which we have a legal obligation are recorded as liabilities with an equivalent amount added to the asset cost and depreciated over the useful life of the associated asset. The liability is then accreted over time by applying an interest method of allocation to the liability.

AROs have no impact on the income of the Utilities as the effects are offset by the establishment of regulatory assets and regulatory liabilities in order to reflect the ratemaking treatment of the related costs.

Progress Energy’s, PEC’s and PEF’s total AROs at December 31, 2010, were $1.200 billion, $849 million, and $351 million, respectively. We calculated the present value of our AROs based on estimates which are dependent on subjective factors such as management’s estimated retirement costs, the timing of future cash flows and the selection of appropriate discount and cost escalation rates. These underlying assumptions and estimates are made as of a point in time and are subject to change. These changes could materially affect the AROs, although changes in such estimates should not affect earnings, because these costs are expected to be recovered through rates.

Nuclear decommissioning AROs represent 95 percent, 97 percent, and 90 percent, respectively, of Progress Energy’s, PEC’s and PEF’s total AROs at December 31, 2010. To determine nuclear decommissioning AROs, we utilize periodic site-specific cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for our nuclear plants. Our regulators require updated cost estimates for nuclear decommissioning every five years. These cost studies are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. Changes in PEC’s and PEF’s nuclear decommissioning site-specific cost estimates or the use of alternative cost escalation or discount rates could be material to the nuclear decommissioning liabilities recognized.

PEC obtained updated cost studies for its nuclear plants in 2009, using 2009 cost factors, which PEC filed with the NCUC in 2010. If the site-specific cost estimates increased by 10 percent, PEC’s AROs would have increased by $77 million. If the inflation adjustment increased 25 basis points, PEC’s AROs would have increased by $169 million. Similarly, an increase in the discount rate of 25 basis points would have decreased PEC’s AROs by $56 million.

PEF obtained an updated cost study for its nuclear plant in 2008, using 2008 cost factors, which PEF filed with the FPSC in 2009 as part of PEF’s base rate filing. As discussed in Note 4C, the FPSC deferred review of PEF’s nuclear decommissioning study from the rate case to be addressed in 2010 in order for FPSC staff to assess PEF’s study in combination with other utilities anticipated to submit nuclear decommissioning studies in 2010. PEF was not required to prepare a new site-specific nuclear decommissioning study in 2010; however, PEF was required to update the 2008 study with the most currently available escalation rates in 2010, which was filed with the FPSC in December 2010. If the site-specific cost estimates increased by 10 percent, PEF’s AROs would have increased by $32 million. If the inflation adjustment increased 25 basis points, PEF’s AROs would have increased by $25 million. Similarly, an increase in the discount rate of 25 basis points would have decreased PEF’s AROs by $21 million.

GOODWILL

As discussed in Note 8, goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility reporting units and our goodwill impairment tests are performed at the utility reporting unit level. The carrying amounts of goodwill at December 31, 2010 and 2009, for the PEC and PEF reporting units were $1.922 billion and $1.733 billion, respectively.

As discussed in Note 1D, in October 2010 we prospectively changed our annual goodwill testing date from April 1 to October 31 to better align our impairment testing procedures with the completion of our annual financial and strategic planning process. As a result, during 2010, we tested our goodwill for impairment as of October 31, 2010 and April 1, 2010, and concluded there was no impairment of the carrying value of the goodwill. If the estimated fair values of PEC and PEF on those dates had been lower by 10 percent, there still would be no impact on the reported

value of their goodwill. In addition, based on the results of impairment tests performed in April 2009 and April 2008, we concluded there was no impairment of the carrying value of the goodwill in the prior periods presented in the consolidated financial statements. This change in accounting principle did not accelerate, delay, avoid, or cause a goodwill impairment charge.

We calculate the fair value of our utility reporting units by considering various factors, including valuation studies based primarily on income and market approaches. More emphasis is applied to the income approach as substantially all of the Utilities’ cash flows are from rate-regulated operations. In such environments, revenue requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, the Utilities operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions.

The income approach uses discounted cash flow analyses to determine the fair value of the utility reporting units. The estimated future cash flows from operations are based on the Utilities’ business plans, which reflect management’s assumptions related to customer usage based on internal data and economic data obtained from third-party sources. The business plans assume the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, the timing of anticipated significant future capital investments, the anticipated earnings and returns related to such capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also determines the appropriate discount rate for the utility reporting units based on the weighted average cost of capital for each utility, which takes into account both the cost of equity and pre-tax cost of debt. As each utility reporting unit has a different risk profile based on the nature of its operations, the discount rate for each reporting unit may differ.

The market approach uses implied market multiples derived from comparable peer utilities and market transactions to estimate the fair value of the utility reporting units. Peer utilities are evaluated based on percentage of revenues generated by regulated utility operations; percentage of revenues generated by electric operations; generation mix, including coal, gas, nuclear and other resources; market capitalization as of the valuation date; and geographic location. Comparable market transactions are evaluated based on the availability of financial transaction data and the nature and geographic location of the businesses or assets acquired, including whether the target company had a significant electric component. The selection of comparable peer utilities and market transactions, as well as the appropriate multiples from within a reasonable range, is a matter of professional judgment.

The calculations in both the income and market approaches are highly dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates from a marketplace participant’s perspective, and the selection of peer utilities and marketplace transactions for comparative valuation purposes. These underlying assumptions and estimates are made as of a point in time. If these assumptions change or should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, the fair value of the utility reporting units could be significantly different in future periods, which could result in a future impairment charge to goodwill.

As an overall test of the reasonableness of the estimated fair values of the utility reporting units, we compared their combined fair value estimate to Progress Energy’s market capitalization as of October 31, 2010 and April 1, 2010. The analyses confirmed that the fair values were reasonably representative of market views when applying a reasonable control premium to the market capitalization.

We monitor for events or circumstances, including financial market conditions and economic factors, that may indicate an interim goodwill impairment test is necessary. We would perform an interim impairment test should any events occur or circumstances change that would more likely than not reduce the fair value of a utility reporting unit below its carrying value. As a result of the Merger Agreement discussed within MD&A – “Introduction – Merger” and in Note 25, we considered whether an interim goodwill impairment test was necessary. Based upon reasonable allocations of the Merger consideration to PEC and PEF, we concluded their fair values exceeded their carrying values, and no interim impairment test was necessary.

UNBILLED REVENUE

As discussed in Note 1, we recognize electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utilities base revenues, primarily related to retail base revenues, earned when service has been delivered but not billed by the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for the electric utility revenues associated with unbilled sales is recognized. Unbilled retail revenues are estimated by applying a weighted average revenue/kWh for all customer classes to the number of estimated kWh delivered but not billed. The calculation of unbilled revenue is affected by factors that include fluctuations in energy demand for the unbilled period, seasonality, weather, customer usage patterns, price in effect for each customer class and estimated transmission and distribution line losses.

Amounts recorded as receivables on the Balance Sheets at December 31 related to unbilled revenues were as follows:

(in millions)	2010		2009
Progress Energy	$	223	$	193
PEC		136		125
PEF		87		68

INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. As discussed in Note 14, deferred income tax assets and liabilities represent the future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. 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 availability of tax-planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized.

The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material. In accordance with GAAP, the uncertainty and judgment involved in the determination and filing of income taxes are accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. A two-step process is required: recognition of the tax benefit based on a “more-likely-than-not” threshold, and measurement of the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with the taxing authority.

PENSION COSTS

As discussed in Note 16A, we maintain qualified noncontributory defined benefit retirement (pension) plans. We also have supplementary defined benefit pension plans that provide benefits to higher-level employees. Our reported costs are dependent on numerous factors resulting from actual plan experience and assumptions of future experience. For example, such costs are impacted by employee demographics, changes made to plan provisions, actual plan asset returns and key actuarial assumptions, such as expected long-term rates of return on plan assets and discount rates used in determining benefit obligations and annual costs.

Due to a decrease in the market interest rates for high-quality (AAA/AA) debt securities, which are used as the benchmark for setting the discount rate to calculate the present value of future benefit payments, we decreased the discount rate to 5.65% at December 31, 2010, from 6.00% at December 31, 2009, which will increase 2011 pension costs, all other factors remaining constant. Our discount rates are selected based on a plan-by-plan study, which matches our projected benefit payments to a high-quality corporate yield curve. Consistent with general market conditions, our plan assets performed well in 2010 with returns of approximately 13%. That positive asset performance will result in decreased pension costs in 2011, all other factors remaining constant. In addition,

contributions to pension plan assets in late 2010 and in 2011 will result in decreased pension costs in 2011 due to increased asset balances and resulting expected earnings on those assets, all other factors remaining constant. Evaluations of the effects of these and other factors on our 2011 pension costs have not been completed, but we estimate that the total cost recognized for pensions in 2011 will be $70 million to $80 million, compared with $88 million recognized in 2010.

We have pension plan assets with a fair value of approximately $1.9 billion at December 31, 2010. Our expected rate of return on pension plan assets is 8.75%. The expected rate of return used in pension cost recognition is a long-term rate of return; therefore, we do not adjust that rate of return frequently. In 2009, we lowered the expected rate of return from the previously used 9.00%, due primarily to the uncertainties resulting from the severe capital market deterioration in 2008. A 25 basis point change in the expected rate of return for 2010 would have changed 2010 pension costs by approximately $4 million. For 2011, we have assumed an expected rate of return of 8.50%, which was reflected in the estimates of total pension costs discussed within this section.

Another factor affecting our pension costs, and sensitivity of the costs to plan asset performance, is the method selected to determine the market-related value of assets, i.e., the asset value to which the 8.75% expected long-term rate of return is applied. Entities may use either fair value or an averaging method that recognizes changes in fair value over a period not to exceed five years, with the method selected applied on a consistent basis from year to year. We have historically used a five-year averaging method. When we acquired Florida Progress in 2000, we retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets. Changes in plan asset performance are reflected in pension costs sooner under the fair value method than the five-year averaging method, and, therefore, pension costs tend to be more volatile using the fair value method. Approximately 50 percent of our pension plan assets are subject to each of the two methods.

Since PEC and PEF participate in our pension plans, the general discussion above applies to PEC and PEF. PEC and PEF have not completed evaluating their 2011 pension costs. PEC estimates that the total cost recognized for pensions in 2011 will be $20 million to $25 million, compared with $28 million recognized in 2010. A 25 basis point change in the expected rate of return for 2010 would have changed PEC’s 2010 pension costs by approximately $2 million. PEF estimates that the total cost recognized for pensions in 2011 will be $35 million to $40 million, compared with $44 million recognized in 2010. A 25 basis point change in the expected rate of return for 2010 would have changed PEF’s 2010 pension costs by approximately $2 million.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Our significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations, including expenditures for environmental compliance. We typically rely upon our operating cash flow, substantially all of which is generated by the Utilities, commercial paper and credit facilities, and our ability to access the long-term debt and equity capital markets for sources of liquidity. As discussed in “Future Liquidity and Capital Resources” below, synthetic fuels tax credits will provide an additional source of liquidity as those credits are realized.

The majority of our operating costs are related to the Utilities. Most of these costs are recovered from ratepayers in accordance with various rate plans. We are allowed to recover certain fuel, purchased power and other costs incurred by PEC and PEF through their respective recovery clauses. The types of costs recovered through clauses vary by jurisdiction. Fuel price volatility and plant performance can lead to over- or under-recovery of fuel costs, as changes in fuel expense are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility and plant performance can be both a source of and a use of liquidity resources, depending on what phase of the cycle of price volatility we are experiencing and/or how our plants are performing. Changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows, but not materially affect net income.

As a registered holding company, our establishment of intercompany extensions of credit is subject to regulation by the Federal Energy Regulatory Commission (FERC). Our subsidiaries participate in internal money pools, administered by PESC, to more effectively utilize cash resources and reduce external short-term borrowings. The utility money pool allows the Utilities to lend to and borrow from each other. A non-utility money pool allows our nonregulated operations to lend to and borrow from each other. The Parent can lend money to the utility and non-utility money pools but cannot borrow funds.

The Parent is a holding company with $4.7 billion of senior unsecured debt following its issuance of $500 million of senior unsecured debt on January 21, 2011. As a holding company, the Parent has no revenue-generating operations of its own. The primary cash needs at the Parent level are our common stock dividend, interest and principal payments on the Parent’s senior unsecured debt and potentially funding the Utilities’ capital expenditures through equity contributions. The Parent’s ability to meet these needs is typically funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; repayment of funds due to the Parent by its subsidiaries; the Parent’s credit facility; and/or the Parent’s ability to access the short-term and long-term debt and equity capital markets. In recent years, rather than paying dividends to the Parent, the Utilities, in certain cases, have retained their free cash flow to fund their capital expenditures. During 2010, PEC paid dividends of $100 million and PEF paid dividends of $50 million to the Parent. PEC and PEF expect to pay dividends to the Parent in 2011. There are a number of factors that impact the Utilities’ decision or ability to pay dividends to the Parent or to seek equity contributions from the Parent, including capital expenditure decisions and the timing of recovery of fuel and other pass-through costs. Therefore, we cannot predict the level of dividends or equity contributions between the Utilities and the Parent from year to year. The Parent could change its existing common stock dividend policy based upon these and other business factors.

Cash from operations, commercial paper issuance, borrowings under our credit facilities and/or long-term debt financings are expected to fund capital expenditures, long-term debt maturities and common stock dividends for 2011. We do not expect to realize a material amount of proceeds from the sale of equity in 2011 (See “Financing Activities”).

We have 24 financial institutions that support our combined $2.0 billion revolving credit facilities for the Parent, PEC and PEF, thereby limiting our dependence on any one institution. The credit facilities serve as back-ups to our commercial paper programs. To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At December 31, 2010, the Parent had no outstanding borrowings under its credit facility, no outstanding commercial paper and had issued $31 million of letters of credit, which were supported by the revolving credit facility. At December 31, 2010, PEC and PEF had no outstanding

borrowings under their respective credit facilities and no outstanding commercial paper. Based on these outstanding amounts at December 31, 2010, there was a combined $1.969 billion available for additional borrowings.

At December 31, 2010, PEC and PEF had limited counterparty mark-to-market exposure for financial commodity hedges (primarily gas and oil hedges) due to spreading our concentration risk over a number of counterparties. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. At December 31, 2010, the majority of the Utilities’ open financial commodity hedges were in net mark-to-market liability positions. See Note 17A for additional information with regard to our commodity derivatives.

At December 31, 2010, we had limited mark-to-market exposure to certain financial institutions under pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions for the Parent, PEC and PEF. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. At December 31, 2010, the sums of the Parent’s, PEC’s and PEF’s open pay-fixed forward starting swaps were each in a net mark-to-market liability position. See Note 17B for additional information with regard to our interest rate derivatives.

On July 21, 2010, the Wall Street Reform and Consumer Protection Act (H.R. 4173) was signed into law. Among other things, the law includes provisions related to the swaps and over-the-counter derivatives markets. Under the law, we expect to be exempt from mandatory clearing and exchange trading requirements for our commodity and interest rate hedges because we are an end user of these products. Capital and margin requirements for these hedges are expected to be determined as more detailed rules and regulations are published during 2011. At this time, we do not expect the law to have a material impact on our financial condition. However, we cannot determine the impact until the final regulations are issued.

Our pension and nuclear decommissioning trust funds are managed by a number of financial institutions, and the assets being managed are diversified in order to limit concentration risk in any one institution or business sector.

We believe our internal and external liquidity resources will be sufficient to fund our current business plans. We will continue to monitor the credit markets to maintain an appropriate level of liquidity. Our ability to access the capital markets on favorable terms may be negatively impacted by credit rating actions. Risk factors associated with the capital markets and credit ratings are discussed below and in Item 1A, “Risk Factors.”

The following discussion of our liquidity and capital resources is on a consolidated basis.

HISTORICAL FOR 2010 AS COMPARED TO 2009 AND 2009 AS COMPARED TO 2008

CASH FLOWS FROM OPERATIONS

Net cash provided by operations is the primary source used to meet operating requirements and a portion of capital expenditures. The Utilities produced substantially all of our consolidated cash from operations for the years ended December 31, 2010, 2009 and 2008. Net cash provided by operating activities for the three years ended December 31, 2010, 2009 and 2008, was $2.537 billion, $2.271 billion and $1.218 billion, respectively.

Net cash provided by operating activities increased $266 million for 2010, when compared to 2009. The increase was primarily due to the $203 million favorable impact of weather, partially offset by $78 million higher nuclear plant outage and maintenance costs included in O&M, both as previously discussed; $197 million lower cash used for inventory, primarily due to higher coal consumption in 2010 as a result of favorable weather that was fulfilled through the 2010 usage of inventory from year-end 2009; $154 million payment in 2009 due to a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates previously engaged in coal-based solid synthetic fuels operations (See Note 22D); $56 million net cash receipts for income taxes in 2010 compared to $87 million net cash payments for income taxes in 2009; and $121 million lower cash used for pension and other benefits, primarily due to a reduction of contributions made in 2010. These amounts were partially offset by a $2 million under-recovery of fuel in 2010 compared to a $290 million over-recovery of fuel in 2009 due to higher fuel costs and lower fuel rates in 2010 and $23 million of net payments of cash collateral to counterparties on derivative contracts in 2010 compared to $200 million net refunds of cash collateral in 2009.

Net cash provided by operating activities for 2009 increased when compared with 2008. The $1.053 billion increase in operating cash flow was primarily due to a $290 million over-recovery of fuel in 2009 compared to a $333 under-recovery of fuel in 2008 due to higher fuel rates in 2009 and $340 million of cash collateral paid to counterparties on derivative contracts in 2008 compared to $200 million net refunds of cash collateral in 2009. These impacts were partially offset by $221 million of pension and other benefits contributions made in 2009.

The Utilities file annual requests with their respective state commissions seeking rate increases or decreases for fuel cost under- or over-recovery.

INVESTING ACTIVITIES

Net cash used by investing activities for the three years ended December 31, 2010, 2009 and 2008, was $2.400 billion, $2.532 billion and $2.541 billion, respectively.

Net cash used by investing activities decreased by $132 million for 2010, when compared to 2009. This decrease was primarily due to a $74 million decrease in gross property additions, primarily due to lower spending for environmental compliance and nuclear projects at PEF, partially offset by PEC’s increased capital expenditures at the Wayne County, New Hanover County and Harris generating facilities; and a $62 million increase in cash provided by other investing activities primarily due to the receipt of Nuclear Electric Insurance Limited (NEIL) insurance proceeds for repairs due to the CR3 extended outage (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”).

Excluding proceeds from sales of discontinued operations and other assets, net of cash divested of $1 million in 2009 and $72 million in 2008, which are presented in other investing activities on the Consolidated Statements of Cash Flows, cash used in investing activities decreased by $80 million. The decrease in 2009 was primarily due to a $24 million decrease in gross property additions at the Utilities, primarily due to lower spending for environmental compliance projects and the completion of PEF’s Bartow Plant repowering project in 2009; a $22 million decrease in nuclear fuel additions; and a $20 million decrease in net purchases of available-for-sale securities and other investments. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

During 2008, proceeds from sales of discontinued operations and other assets primarily included proceeds of $63 million from the sale of our coal terminals and docks and our remaining coal mining businesses (See Notes 3A and 3B).

FINANCING ACTIVITIES

Net cash (used) provided by financing activities for the three years ended December 31, 2010, 2009 and 2008, was $(251) million, $806 million and $1.248 billion, respectively. See Note 11 for details of debt and credit facilities.

Net cash used by financing activities increased by $1.057 billion for 2010 when compared to 2009. The increase was primarily due to the $1.687 billion reduction in proceeds from long-term debt issuances, net primarily due to the Parent’s combined $1.700 billion issuances and PEC’s $600 million issuance in 2009 compared to PEF’s $600 million issuance of long-term debt in 2010; partially offset by the Parent’s payments of $629 million on short-term debt with original maturities greater than 90 days in 2009.

Net cash provided by financing activities decreased by $442 million for 2009 when compared to 2008. The decrease is primarily due to a $1.082 billion increase in net payments on short-term debt with original maturities greater than 90 days, primarily driven by the Parent’s repayment of prior-year borrowings under its revolving credit agreements (RCAs) and an $877 million net decrease in short-term indebtedness, primarily driven by commercial paper repayments; partially offset by a $491 million increase in proceeds from the issuance of common stock, primarily related to the Parent’s January 2009 common stock offering; a $481 million increase in net proceeds from long-term debt issuances due to the Parent’s combined $1.700 billion issuances and PEC’s $600 million issuance in 2009 compared to PEF’s $1.500 billion issuance and PEC’s $325 million issuance in 2008; and a $477 million decrease in payments at maturity of long-term debt.

Our Our financing activities are described below.

2011

·	On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due 2021. We expect to use the net proceeds, along with available cash on hand, to retire at maturity the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011.

2010

·	On January 15, 2010, the Parent paid at maturity $100 million of its Series A Floating Rate Notes with a portion of the proceeds from the $950 million of Senior Notes issued in November 2009.

On March 25, 2010, PEF issued $250 million of 4.55% First Mortgage Bonds due 2020 and $350 million of 5.65% First Mortgage Bonds due 2040. Proceeds were used to repay the outstanding balance of PEF’s notes payable to affiliated companies, to repay the maturity of PEF’s $300 million 4.50% First Mortgage Bonds due June 1, 2010, and for general corporate purposes.

·	On October 15, 2010, the Parent ratably reduced the size of its $1.130 billion credit facility to $500 million with the existing group of 15 financial institutions (See “Credit Facilities and Registration Statements”).

Progress Energy issued approximately 12.2 million shares of common stock resulting in approximately $434 million in proceeds from the Progress Energy Investor Plus Plan (IPP) and its employee benefit and equity incentive plans. Included in these amounts were approximately 11.2 million shares for proceeds of approximately $431 million issued for the IPP. For 2010, the dividends paid on common stock were approximately $718 million.

2009

On January 12, 2009, the Parent issued 14.4 million shares of common stock at a public offering price of $37.50 per share. Net proceeds from this offering were approximately $523 million. On February 3, 2009, the Parent used $100 million of the proceeds to reduce its $600 million RCA balance outstanding at December 31, 2008, and the remainder was used for general corporate purposes.

On January 15, 2009, PEC issued $600 million of First Mortgage Bonds, 5.30% Series due 2019. A portion of the proceeds was used to repay the maturity of PEC’s $400 million 5.95% Senior Notes, due March 1, 2009. The remaining proceeds were used to repay PEC’s outstanding short-term debt and for general corporate purposes.

On March 19, 2009, the Parent issued an aggregate $750 million of Senior Notes consisting of $300 million of 6.05% Senior Notes due 2014 and $450 million of 7.05% Senior Notes due 2019. A portion of the proceeds was used to fund PEF’s capital expenditures through an equity contribution with the remaining proceeds used for general corporate purposes.

On June 18, 2009, PEC entered into a Seventy-seventh Supplemental Indenture to its Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, in connection with certain amendments to the mortgage. The amendments are set forth in the Seventy-seventh Supplemental Indenture and include an amendment to extend the maturity date of the mortgage by 100 years. The maturity date of the mortgage is now May 1, 2140.

On November 19, 2009, the Parent issued an aggregate $950 million of Senior Notes consisting of $350 million of 4.875% Senior Notes due 2019 and $600 million of 6.00% Senior Notes due 2039. The proceeds were used to retire at maturity the $100 million outstanding Series A Floating Rate Notes due January 15, 2010, to repay outstanding commercial paper balances, to pre-fund a portion of the $700 million aggregate principal amount due upon maturity of our 7.10% Senior Notes due March 1, 2011, and for general corporate purposes.

·	During 2009, we repaid the November 2008 $600 million borrowing under our RCA.

Progress Energy issued approximately 3.1 million shares of common stock resulting in approximately $100 million in proceeds from its IPP and its employee benefit and equity incentive plans. Included in these amounts were approximately 2.5 million shares for proceeds of approximately $100 million issued for the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)) and the IPP. For 2009, the dividends paid on common stock were approximately $693 million.

2008

·	On February 1, 2008, PEF paid at maturity $80 million of its 6.875% First Mortgage Bonds with available cash on hand and commercial paper borrowings.

On March 12, 2008, PEC and PEF amended their RCAs with a syndication of financial institutions to extend the termination date by one year. The extensions were effective for both utilities on March 28, 2008. PEC’s RCA was extended to June 28, 2011, and PEF’s RCA was extended to March 28, 2011. These credit facilities were terminated on October 15, 2010 (See “Credit Facilities and Registration Statements”).

On March 13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due 2038. The proceeds were used to repay the maturity of PEC’s $300 million 6.65% Medium-Term Notes, Series D, due April 1, 2008, and the remainder was placed in temporary investments for general corporate use as needed.

·	On April 14, 2008, the Parent amended its RCA with a syndication of financial institutions to extend the termination date by one year. The extension was effective on May 2, 2008. The RCA is now scheduled to expire on May 3, 2012 (See “Credit Facilities and Registration Statements”).

·	On May 27, 2008, Progress Capital Holdings, Inc., one of our wholly owned subsidiaries, paid at maturity its remaining outstanding debt of $45 million of 6.46% Medium-Term Notes with available cash on hand.

On June 18, 2008, PEF issued $500 million of First Mortgage Bonds, 5.65% Series due 2018 and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038. A portion of the proceeds was used to repay PEF’s utility money pool borrowings, and the remaining proceeds were placed in temporary investments for general corporate use as needed. On August 14, 2008, PEF redeemed the entire outstanding $450 million principal amount of its Series A Floating Rate Notes due November 14, 2008, at 100 percent of par plus accrued interest. The redemption was funded with a portion of the proceeds from the June 18, 2008 debt issuance.

·	On November 3, 2008, the Parent borrowed $600 million under its RCA to reduce rollover risk in the commercial paper markets. The borrowing was repaid during 2009.

On November 18, 2008, the Parent, as a well-known seasoned issuer, PEC and PEF 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 (See “Credit Facilities and Registration Statements”).

Progress Energy issued approximately 3.7 million shares of common stock resulting in approximately $132 million in proceeds from its IPP and its employee benefit and equity incentive plans. Included in these amounts were approximately 3.1 million shares for proceeds of approximately $131 million issued for the 401(k) and the IPP. For 2008, the dividends paid on common stock were approximately $642 million.

SHORT-TERM DEBT

At December 31, 2010, and at the end of each month during 2010, Progress Energy had no outstanding short-term debt.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” for a discussion of the factors that may impact any such forward-looking statements made herein.

The Utilities produce substantially all of our consolidated cash from operations. We anticipate that the Utilities will continue to produce substantially all of the consolidated cash flows from operations over the next several years. Our discontinued synthetic fuels operations historically produced significant net earnings from the generation of tax credits (See “Other Matters – Synthetic Fuels Tax Credits”). A portion of these tax credits has yet to be realized in cash due to the difference in timing of when tax credits are recognized for financial reporting purposes and realized for tax purposes. At December 31, 2010, we have carried forward $836 million of deferred tax credits. Realization of these tax credits is dependent upon our future taxable income, which is expected to be generated primarily by the Utilities.

We expect to be able to meet our future liquidity needs through cash from operations, availability under our credit facilities and issuances of commercial paper and long-term debt, which are dependent on our ability to successfully access capital markets.

Credit rating downgrades could negatively impact our ability to access the capital markets and respond to major events such as hurricanes. Our cost of capital could also be higher, which could ultimately increase prices for our customers. It is important for us to maintain our credit ratings and have access to the capital markets in order to reliably serve customers, invest in capital improvements and prepare for our customer’s future energy needs (See Item 1A, “Risk Factors”).

We typically issue commercial paper to meet short-term liquidity needs. If liquidity conditions deteriorate and negatively impact the commercial paper market, we will need to evaluate other, potentially more expensive, options for meeting our short-term liquidity needs, which may include borrowing under our RCAs, issuing short-term notes and/or issuing long-term debt.

On October 15, 2010, PEC and PEF entered into new three-year RCAs. The Parent’s RCA will expire in May 2012, with the exception of approximately $22 million that will expire in May 2011 (See “Credit Facilities and Registration Statements”). In the event we enter into a new credit facility for the Parent, we cannot predict the terms, prices, duration or participants in such facility.

Progress Energy and its subsidiaries have approximately $12.642 billion in outstanding long-term debt, including the $505 million current portion at December 31, 2010. Currently, approximately $860 million of the Utilities’ debt obligations, approximately $620 million at PEC and approximately $240 million at PEF, are tax-exempt auction rate securities insured by bond insurance. These tax-exempt bonds have experienced and continue to experience failed auctions. Assuming the failed auctions persist, future interest rate resets on our tax-exempt auction rate bond portfolio will be dependent on the volatility experienced in the indices that dictate our interest rate resets and/or rating agency actions that may lower our tax-exempt bond ratings. In the event of a two notch downgrade of PEC’s and/or PEF’s senior secured debt rating by S&P, the ratings of such utility’s tax-exempt bonds would be below A-, most likely resulting in higher future interest rate resets. In the event of a two notch downgrade by Moody’s, PEC’s tax-exempt bonds will continue to be rated at or above A3 while PEF’s would be below A3, most likely resulting in higher future interest rate resets for PEF’s tax-exempt bonds. We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations under our defined benefit pension plans. Although a number of factors impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the obligations under our defined benefit pension plans. We expect to make contributions of $300 million to $400 million directly to pension plan assets in 2011 (See Note 16).

As discussed in “Liquidity and Capital Resources,” “Capital Expenditures,” and in “Other Matters – Environmental Matters,” over the long term, compliance with environmental regulations and meeting the anticipated load growth at the Utilities as described under “Other Matters – Energy Demand” will require the Utilities to make significant capital investments. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation. As discussed in “Other Matters – Nuclear – Potential New Construction,” PEF will postpone major capital expenditures for the Levy project until after the NRC issues the COL, which is expected to be in 2013 if the current licensing schedule remains on track.

Certain of our hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. Substantially all derivative commodity instrument positions are subject to retail regulatory treatment. After settlement of the derivatives and consumption of the fuel, any realized gains or losses are passed through the fuel cost-recovery clause. Changes in natural gas prices and settlements of financial hedge agreements since December 31, 2009, have impacted the amount of collateral posted with counterparties. At December 31, 2010, we had posted approximately $164 million of cash collateral compared to $146 million of cash collateral posted at December 31, 2009. The majority of our financial hedge agreements will settle in 2011 and 2012. Additional commodity market price decreases could result in significant increases in the derivative collateral that we are required to post with counterparties. We continually monitor our derivative positions in relation to market price activity. As discussed in Note 17C, credit rating downgrades could also require us to post additional cash collateral for commodity hedges in a liability position as certain derivative instruments require us to post collateral on liability positions based on our credit ratings.

The amount and timing of future sales of debt securities will depend on market conditions, operating cash flow and our specific liquidity needs. We may from time to time sell securities beyond the amount immediately needed to meet our capital or liquidity requirements in order to prefund our expected maturity schedule, to allow for the early redemption of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other corporate purposes.

At December 31, 2010, the current portion of our long-term debt was $505 million, including $300 million at PEF. We expect to fund the Parent’s $700 million of Senior Notes due March 1, 2011 with a combination of available cash on hand and net proceeds of $495 million from the Parent’s issuance of $500 million of 4.40% Senior Notes on January 21, 2011. Accordingly, we classified $495 million of the Parent’s $700 million Senior Notes due March 1, 2011 as long-term debt at December 31, 2010. We expect to fund PEF’s $300 million current portion of long-term debt with a combination of cash from operations, commercial paper borrowings and/or long-term debt.

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, including nuclear cost recovery, as discussed in Note 7 and “Other Matters – Regulatory Environment,” and recovery of environmental costs, as discussed in Note 21 and in “Other Matters – Environmental Matters,” may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Energy legislation enacted in recent years may impact our liquidity over the long term, including, among others, provisions regarding cost recovery, mandated renewable portfolio standards, DSM and EE.

Regulatory developments expected to have a material impact on our liquidity are discussed below.

PEC Cost-Recovery Clause

On June 23, 2010, the SCPSC approved PEC’s request for a decrease in the fuel rate charged to its South Carolina ratepayers. The $17 million decrease, effective July 1, 2010, is driven by declining fuel prices.

On November 17, 2010, the NCUC approved PEC’s request for a decrease in the fuel rate charged to its North Carolina ratepayers. The $170 million decrease, effective December 1, 2010, is also driven by declining fuel prices.

Also on November 17, 2010, the NCUC approved PEC’s request for an increase in the DSM and EE rate charges to its North Carolina ratepayers. The $31 million increase was effective December 1, 2010.

PEC Other Matters

The NCUC has issued Certificates of Public Convenience and Necessity allowing PEC to proceed with plans to construct an approximately 600-MW generating facility at its Richmond County generation site projected to be in service by June 2011; an approximately 950-MW generating facility at a site in Wayne County, N.C., projected to be in service by January 2013; and an approximately 620-MW generating facility at a site in New Hanover County, N.C., projected to be in service by December 2013.

PEF Base Rates

PEF Fuel Cost Recovery

On November 1, 2010, PEF filed a request with the FPSC to seek approval to decrease the total fuel cost-recovery by $205 million. This decrease is due to a decrease for the projected recovery through the Capacity Cost-Recovery Clause (CCRC) and for the projected recovery of fuel costs. The decrease in the CCRC is primarily due to the refund of a prior period over-recovery as a result of higher than expected sales in 2010 and lower anticipated costs associated with PEF’s proposed Levy Units 1 and 2 Nuclear Power Plants (Levy) in 2011 (See “Other Matters – Nuclear – Potential New Construction”). The decrease in the projected recovery of fuel costs is due to lower expected 2011 fuel costs, partially offset by an under-recovery of 2010 fuel costs. On November 2, 2010 and November 30, 2010, the FPSC approved PEF’s CCRC residential rate and fuel rate, respectively.

PEF Nuclear Cost Recovery

PEF is allowed to recover prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balances on an annual basis through the CCRC. Such amounts will not be included in PEF’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility.

In 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million through the CCRC, which primarily consisted of preconstruction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to help mitigate the initial price impact on its customers, PEF proposed and the FPSC approved collecting certain costs over a five-year period, with associated carrying costs on the unrecovered balance. In adopting PEF’s proposed rate management plan for 2010, the FPSC permitted PEF to annually reconsider changes to the recovery of deferred amounts to afford greater flexibility to manage future rate impacts. The rate management plan included the 2009 reclassification to the nuclear cost-recovery clause regulatory asset of $198 million of capacity revenues and the accelerated amortization of $76 million of preconstruction costs. The cumulative amount of $274 million was recorded as a nuclear cost-recovery regulatory asset at December 31, 2009, and is projected to be recovered by 2014.

On October 26, 2010, the FPSC approved PEF’s annual nuclear cost-recovery filing with the FPSC to recover $164 million, which includes recovery of preconstruction, carrying and CCRC-recoverable O&M costs incurred or anticipated to be incurred during 2011, recovery of $60 million of the 2009 deferral in 2011, as well as the estimated true-up of 2010 costs associated with the Levy and CR3 uprate projects beginning with the first January 2011 billing cycle. Additionally, the FPSC approved the prudence of the 2009 costs associated with the Levy project. The final order was issued on February 2, 2011.

CR3 Outage

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL (See Note 4D). NEIL has confirmed that the CR3 delamination event is a covered accident. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs.

The following table summarizes the CR3 replacement power and repair costs and recovery through December 31, 2010:

(in millions)	Replacement power costs			Repair costs
Spent to date	$	288		$	150
NEIL proceeds received		(117	)		(64	)
Insurance receivable at December 31, 2010		(54	)		(47	)
Balance for recovery	$	117		$	39

PEF considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. PEF accrued $171 million of replacement power cost reimbursements after the deductible period, which reduced the portion of the deferred fuel regulatory asset related to the extended CR3 outage to $117 million at December 31, 2010. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material.

We cannot predict the outcome of this matter.

PEF Demand-Side Management Cost Recovery

On December 30, 2009, the FPSC ordered PEF and other Florida utilities to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. As subsequently revised by the FPSC, PEF’s aggregate conservation goals over the next 10 years were: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). On March 30, 2010, PEF filed a petition for approval of its proposed DSM plan and to authorize cost recovery through the ECCR. On September 14, 2010, the FPSC held an agenda conference to approve PEF’s petition for the DSM plan. The FPSC ruled that while PEF’s proposed DSM plan met the cumulative, 10-year DSM goals set by the FPSC, the plan did not meet the annual DSM goals. On October 4, 2010, the FPSC denied PEF’s petition for the DSM plan, approved PEF’s solar pilot programs, and required PEF to file a revised proposed DSM plan that meets the annual goals set by the FPSC. PEF filed a revised proposed DSM plan on November 29, 2010, which would result in 1,540 GWh of energy savings from 2011-2019, seven times more than PEF’s historic

goals. An agenda conference has been scheduled by the FPSC for April 5, 2011. We cannot predict the outcome of this matter.

PEF Other Matters

On November 1, 2010, the FPSC approved PEF’s request to decrease the ECRC by $37 million, effective January 1, 2011. The decrease in the ECRC is primarily due to the 2010 base rate decision, which reduced the clean air project depreciation and return rates, and the refund of a prior period over-recovery as a result of higher than expected sales in 2010.

CAPITAL EXPENDITURES

We expect to make significant capital investments to meet anticipated load growth and environmental standards. We are currently constructing new generating facilities in the Carolinas and potentially will construct new baseload generating facilities in the Carolinas and Florida that will be placed in service toward the middle of the next decade.

Total cash from operations and proceeds from long-term debt and equity issuances provided the funding for our capital expenditures, including environmental compliance and other utility property additions, nuclear fuel expenditures and non-utility property additions, during 2010.

As shown in the table that follows, we expect the majority of our capital expenditures to be incurred at our regulated operations. We expect to fund our capital requirements primarily through a combination of cash from operations and long-term debt financings. In addition, we have $2.0 billion in credit facilities that support the issuance of commercial paper. Access to the commercial paper market provides additional liquidity to help meet our working capital requirements. AFUDC – borrowed funds represents the debt costs of capital funds necessary to finance the construction of new regulated plant assets.

	Actual			Forecasted
(in millions)	2010			2011			2012			2013
Regulated capital expenditures	$	2,105		$	1,965		$	1,820		$	1,775
Nuclear fuel expenditures		221			205			225			240
AFUDC – borrowed funds		(30	)		(30	)		(30	)		(20	)
Other capital expenditures		10			30			30			30
Total before potential nuclear construction		2,306			2,170			2,045			2,025
Potential nuclear construction(a)		104			50-100			50-100			200-300
Total	$	2,410		$	2,220-2,270		$	2,095-2,145		$	2,225-2,325

(a)

Expenditures for potential nuclear construction are net of AFUDC – borrowed funds.

Regulated capital expenditures for 2011, 2012 and 2013 in the previous table include approximately $30 million, $15 million and $25 million, respectively, for environmental compliance capital expenditures. Forecasted environmental compliance capital expenditures for 2011, 2012 and 2013 include $20 million, $15 million and $25 million, respectively, at PEC and $10 million at PEF for 2011. See “Other Matters – Environmental Matters” for further discussion of our environmental compliance costs and related recovery of costs.

Potential nuclear construction expenditures, which are primarily for PEF’s Levy, include development, engineering, licensing, land acquisition and equipment. Forecasted potential nuclear construction expenditures are dependent upon, and may vary significantly based upon, the decision to build, regulatory approval schedules, timing and escalation of project costs, and the percentages of joint ownership. Because of announced schedule shifts, we negotiated an amendment to the Levy EPC agreement (See discussion under “Other Matters – Nuclear – Potential New Construction”). The forecasted capital expenditures presented in the previous table reflect the announced schedule shift. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact

associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items and PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. Potential nuclear construction expenditures are subject to cost-recovery provisions in the Utilities' respective jurisdictions.

All projected capital and investment expenditures are subject to periodic review and revision and may vary significantly depending on a number of factors including, but not limited to, industry restructuring, regulatory constraints, market volatility and economic trends.

CREDIT FACILITIES AND REGISTRATION STATEMENTS

At December 31, 2010 and 2009, we had committed lines of credit used to support our commercial paper borrowings. At December 31, 2010 and 2009, we had no outstanding borrowings under our credit facilities. We are required to pay fees to maintain our credit facilities.

The following tables summarize our RCAs and available capacity at December 31:


(in millions)		Total		Outstanding		Reserved(a)		Available
2010
Parent	Five-year (expiring 5/3/12)(b)	$	500	$	-	$	31	$	469
PEC	Three-year (expiring 10/15/13)		750		-		-		750
PEF	Three-year (expiring 10/15/13)		750		-		-		750
Total credit facilities		$	2,000	$	-	$	31	$	1,969

2009
Parent	Five-year (expiring 5/3/12)	$	1,130	$	-	$	177	$	953
PEC	Five-year (expiring 6/28/11)		450		-		-		450
PEF	Five-year (expiring 3/28/11)		450		-		-		450
Total credit facilities		$	2,030	$	-	$	177	$	1,853

(a)

To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At December 31, 2010 and 2009, the Parent had $31 million and $37 million, respectively, of letters of credit issued, which were supported by the RCA. Additionally, on December 31, 2009, the Parent had $140 million of outstanding commercial paper supported by the RCA.

(b)

Approximately $22 million of the $500 million will expire May 3, 2011.

All of the revolving credit facilities were arranged through a syndication of financial institutions. See Note 11 for additional discussion of our credit facilities.

The RCAs provide liquidity support for issuances of commercial paper and other short-term obligations. We expect to continue to use commercial paper issuances as a source of liquidity as long as we maintain our current short-term ratings. Fees and interest rates under our RCAs are based upon the respective credit ratings of the Parent’s, PEC’s and PEF’s long-term unsecured senior noncredit-enhanced debt.

All of the credit facilities include defined maximum total debt-to-total capital ratio (leverage) covenants, which we were in compliance with at December 31, 2010. We are currently in compliance and expect to continue to be in compliance with these covenants. See Note 11 for a discussion of the credit facilities’ financial covenants. At December 31, 2010, the calculated ratios for the Progress Registrants, pursuant to the terms of the agreements, are as disclosed in Note 11.

The Parent, as a well-known seasoned issuer, has on file with the SEC a shelf registration statement under which it may issue an unlimited number or amount of various securities, including senior debt securities, junior subordinated debentures, common stock, preferred stock, stock purchase contracts, stock purchase units, and trust preferred securities and guarantees. Both PEC and PEF have on file with the SEC shelf registration statements under which

they may issue an unlimited number or amount of various long-term debt securities and preferred stock. The Parent’s, PEC’s and PEF’s shelf registration statements filed with the SEC expire on November 18, 2011.

Both PEC and PEF can issue first mortgage bonds under their respective first mortgage bond indentures based on property additions, retirements of first mortgage bonds and the deposit of cash, provided that adjusted net earnings are at least twice the annual interest requirement for bonds currently outstanding and to be outstanding. At December 31, 2010, PEC and PEF could issue up to approximately $6.8 billion and $2.7 billion of first mortgage bonds, respectively, based on property additions and retirements of previously issued first mortgage bonds. At December 31, 2010, PEC’s and PEF’s ratios of adjusted net earnings to annual interest requirement on outstanding first mortgage bonds were 5.6 times and 3.2 times, respectively.

CAPITALIZATION RATIOS

The following table shows each component of capitalization as a percentage of total capitalization at December 31, 2010 and 2009. In addition to total equity and preferred stock, total capitalization includes the following in total debt: long-term debt, net, long-term debt, affiliate, current portion of long-term debt, short-term debt and capital lease obligations.


	2010			2009
Total equity		43.6	%		42.3	%
Preferred stock		0.4	%		0.4	%
Total debt		56.0	%		57.3	%

CREDIT RATING MATTERS

Our credit ratings reflect the current views of the rating agencies, and no assurances can be given that our ratings will continue for any given period of time. However, we monitor our financial condition as well as market conditions that could ultimately affect our credit ratings.

As discussed in Note 17C, credit rating downgrades could also require us to post additional cash collateral for commodity hedges in a liability position as certain derivative instruments require us to post collateral on liability positions based on our credit ratings.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

Our off-balance sheet arrangements and contractual obligations are described below.

GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include standby letters of credit, surety bonds, performance obligations for trading operations and guarantees of certain subsidiary credit obligations. At December 31, 2010, we have issued $488 million of guarantees for future financial or performance assurance, including $12 million at PEC. Included in this amount is $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries issued by the Parent (See Note 23). We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

At December 31, 2010, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations as discussed in Note 22C.

MARKET RISK AND DERIVATIVES

Under our risk management policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 17 and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

We are party to numerous contracts and arrangements obligating us to make cash payments in future years. These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels and other financial commitments. The commitment amounts presented in the following table are estimates and therefore will likely differ from actual purchase amounts. Further disclosure regarding our contractual obligations is included in the respective notes to the Consolidated Financial Statements. We take into consideration the future commitments when assessing our liquidity and future financing needs.

The following table reflects Progress Energy’s contractual cash obligations and other commercial commitments at December 31, 2010, in the respective periods in which they are due:


(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (See Note 11)(a)	$	12,699	$	1,000	$	1,780	$	1,300	$	8,619
Interest payments on long-term debt(b)		10,034		691		1,234		1,079		7,030
Capital lease obligations (See Note 22B)(c)		457		34		75		65		283
Operating leases (See Note 22B)(c)		1,415		37		154		182		1,042
Fuel and purchased power (See Note 22A)(d)		21,745		2,882		5,247		3,436		10,180
Other purchase obligations (See Note 22A)(e)		2,046		629		490		216		711
Minimum pension funding requirements(f)		568		126		267		153		22
Other postretirement benefits(g)		489		41		89		96		263
Uncertain tax positions(h)		-		-		-		-		-
Other commitments(i)		91		13		26		26		26
Total	$	49,544	$	5,453	$	9,362	$	6,553	$	28,176

(a)

Our maturing debt obligations are generally expected to be repaid with cash from operations or refinanced with new debt issuances in the capital markets.

(b)

Interest payments on long-term debt are based on the interest rate effective at December 31, 2010.

(c)

Amounts include certain related executory cost commitments.

(d)

Essentially all fuel and certain purchased power costs incurred by the Utilities are eligible for recovery through cost-recovery clauses in accordance with state and federal regulations and therefore do not require separate liquidity support. Amounts exclude precedent and conditional contracts of $3.213 billion, including $2.042 billion for PEC and $1.171 billion for PEF and an approximately $400 million Levy nuclear fuel fabrication contract. (See Note 22A and the other purchase obligations discussion following in (e)).

(e)

Amounts exclude an EPC agreement that PEF entered into in December 2008 for two nuclear units planned for construction at Levy. As disclosed in “Other Matters – Nuclear – Potential New Construction,” the EPC agreement includes provisions for termination. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. We executed an amendment to the EPC agreement in 2010 due to the schedule shifts that will postpone major construction activities on the project until after the NRC issues the combined license (COL), which is expected to be in 2013, if the licensing schedule remains on track. Prior to the amendment, estimated payments and associated escalations were $8.608 billion for the multi-year contract and did not assume any joint ownership. Because we have executed an amendment to the EPC agreement and anticipate negotiating additional amendments upon receipt of the COL, we cannot currently predict the timing of when those obligations will be satisfied or the magnitude of any change. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items, which have total remaining estimated payments and associated escalations of approximately $1.250 billion included in the previously discussed $8.608 billion. PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. In its April 30, 2010 nuclear cost-recovery filing, PEF included for rate-making purposes a point estimate of potential Levy disposition fees and charges of $50 million, subject to true-up. However, the amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed. We cannot predict the outcome of this matter.

(f)

Represents the projected minimum required contributions to the qualified pension trusts for a total of 10 years. These amounts are subject to change significantly based on factors such as pension asset earnings and market interest rates.

(g)

Represents projected benefit payments for a total of 10 years related to our postretirement health and life plans and are subject to change based on factors such as experienced claims and general health care cost trends.

(h)

Uncertain tax positions of $176 million are not reflected in this table as we cannot predict when open income tax years will close with completed examinations. It is reasonably possible that the total amounts of unrecognized tax benefits will decrease by up to approximately $60 million during the 12-month period ending December 31, 2011, due to expected settlements.

(i)

By NCUC order, in 2008, PEC began transitioning North Carolina jurisdictional amounts currently retained internally to its external decommissioning funds. The transition of the original $131 million must be complete by December 31, 2017, and at least 10 percent must be transitioned each year.

OTHER MATTERS

REGULATORY ENVIRONMENT

The Utilities’ operations in North Carolina, South Carolina and Florida are regulated by the NCUC, the SCPSC and the FPSC, respectively. The Utilities are also subject to regulation by the FERC, the NRC and other federal and state agencies common to the utility business. As a result of regulation, many of the fundamental business decisions, as well as the rate of return the Utilities are permitted the opportunity to earn, are subject to the approval of one or more of these governmental agencies.

To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give retail ratepayers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. We cannot anticipate if any of these states will move to increase retail competition in the electric industry.

Current retail rate matters affected by state regulatory authorities are discussed in Notes 7B and 7C. This discussion identifies specific retail rate matters, the status of the issues and the associated effects on our consolidated financial statements.

On April 28, 2010, we accepted a grant from the United States Department of Energy (DOE) for $200 million in federal matching infrastructure funds. In addition to providing the Utilities real-time information about the state of their electric grids, the smart grid transition will enable customers to better understand and manage their energy use, and will provide for more efficient integration of renewable energy resources. Supplementing the DOE grant, the Utilities will invest more than $300 million in smart grid projects, which include enhancements to distribution equipment, installation of 160,000 additional smart meters and additional public infrastructure for plug-in electric vehicles. Projects funded by the grant must be completed by April 2013.

Through December 31, 2010, we have incurred $107 million of allowable, 50 percent reimbursable, smart grid project costs, and have submitted to the DOE requests for reimbursement of $47 million, of which we have received $34 million reimbursement.

Concerns about climate change and oil price volatility have led to proposed and enacted legislation at the federal and state levels to increase renewable energy and reduce greenhouse gas (GHG) emissions.

The North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS) requires PEC to file an annual compliance report with the NCUC demonstrating the actions it has taken to comply with the NC REPS requirement. The rules measure compliance with the NC REPS requirement via renewable energy certificates earned after January 1, 2008. North Carolina electric power suppliers with a renewable energy compliance obligation, including PEC, are participating in the renewable energy certificate tracking system, which came online July 1, 2010. North Carolina law mandates that utilities achieve a targeted amount of energy from specified renewable energy resources or implementation of energy-efficiency measures beginning with a 3 percent requirement in 2012 escalating to 12.5 percent in 2021. PEC expects to be in compliance with this requirement.

In 2007, the governor of Florida issued executive orders to address reduction of GHG emissions. The executive orders include adoption of a maximum allowable emissions level of GHGs for Florida utilities, which will require, at a minimum, the following three reduction milestones: by 2017, emissions not greater than Year 2000 utility sector emissions; by 2025, emissions not greater than Year 1990 utility sector emissions; and by 2050, emissions not greater than 20 percent of Year 1990 utility sector emissions. The executive orders also requested that the FPSC initiate a rulemaking that would (1) require Florida utilities to produce at least 20 percent of their electricity from renewable sources; (2) reduce the cost of connecting solar and other renewable energy technologies to Florida’s power grid by adopting uniform statewide interconnection standards for all utilities; and (3) authorize a uniform, statewide method to enable residential and commercial customers who generate electricity from onsite renewable technologies of up to 1 MW in capacity to offset their consumption over a billing period by allowing their electric meters to turn backward when they generate electricity (net metering).

In response to the executive orders, Florida energy law enacted in 2008 includes provisions that required the FPSC to develop a renewable portfolio standard that the FPSC would present to the legislature for ratification and also

includes provisions that direct the Florida Department of Environmental Protection (FDEP) to develop rules establishing a cap-and-trade program to regulate GHG emissions that the FDEP would present to the legislature no earlier than January 2010 for ratification. To date, the Florida legislature has not ratified or enacted any renewable portfolio standard or cap-and-trade rules or programs. Until these agency actions are finalized, we cannot predict the outcome of this matter.

Our balanced solution, as described in “Energy Demand,” includes greater investment in energy efficiency, renewable energy and a state-of-the-art power system and demonstrates our commitment to environmental responsibility.

ENERGY DEMAND

Implementing state and federal energy policies, promoting environmental stewardship and providing reliable electricity to meet the anticipated long-term growth within the Utilities’ service territories will require a balanced approach. The three main elements of this balanced solution are: (1) expanding our DSM and EE programs; (2) investing in the development of alternative energy resources for the future; and (3) operating a state-of-the-art power system.

We are continuing the expansion and enhancement of our DSM and EE programs because energy efficiency is one of the most effective ways to reduce energy costs, offset the need for new power plants and protect the environment. DSM programs include programs and initiatives that shift the timing of electricity use from peak to nonpeak periods, such as load management, electricity system and operating controls, direct load control, interruptible load, and electric system equipment and operating controls. Our previously discussed smart grid projects will aid in these initiatives. EE programs include any equipment, physical or program change that results in less energy used to perform the same function. We provide our residential customers with home energy audits and offer EE programs that provide incentives for customers to implement measures that reduce energy use. For business customers, we also provide energy audits and other tools, including an interactive Internet website with online calculators, programs and efficiency tips, to help them reduce their energy use.

We are actively engaged in a variety of alternative energy projects to pursue the generation of electricity from swine waste and other plant or animal sources, biomass, solar, hydrogen and landfill-gas technologies. Among our projects, we have executed contracts to purchase approximately 300 MW of electricity generated from biomass. This number includes 93 MW of biomass toward compliance with NC REPS. The majority of these projects should be online within the next five years. In addition, we have executed purchased power agreements for approximately 7 MW of electricity generated from solar photovoltaic generation as part of the NC REPS. More than half of these projects are online and the remainder should be online by the end of 2011. Additionally, customers across our service territory have connected approximately 4 MW of solar photovoltaic energy systems to our grid. In June 2009, we expanded our solar energy strategy to include a range of new solar incentives and programs, which are expected to significantly increase our use of solar energy over the next decade.

We are pursuing numerous options to create a state-of-the-art power system, including investments in smart grid technology and advanced environmental controls on our coal-fired plants. In the coming years, we will continue to invest in existing nuclear plants and evaluate plans for building or co-owning new generating plants. Due to the anticipated long-term growth in our service territories, retirement of existing coal generation and potential changes in environmental regulations, we are constructing new natural gas-fueled generating facilities in the Carolinas and we estimate that we will require new generating facilities in both Florida and the Carolinas in the first half of the next decade. In addition to nuclear generation, we are evaluating natural gas-fired plants, renewable generation resources, energy-efficiency initiatives and economic purchased power to meet this increased need. At this time, no definitive decisions have been made to construct or when to construct our proposed new nuclear plants (See “Nuclear – Potential New Construction”) or to acquire new generation from another utility’s regional nuclear project. In the near term, we will focus our efforts on modernizing the power system and pursuing all elements of a balanced portfolio while looking to new nuclear capacity as a critical part of the long-term mix.

In 2009, PEC announced a coal-to-gas modernization strategy whereby the 11 remaining coal-fired generating facilities in North Carolina that do not have scrubbers would be retired prior to the end of their useful lives and their approximately 1,500 MW of generating capacity replaced with new natural gas-fueled facilities. The original

strategy called for the retirement of the coal-fired units by the end of 2017; however, we currently expect the plants will be retired no later than the end of 2014. PEC has received approval from the NCUC for construction of an approximately 950-MW natural gas-fueled generating facility at a site in Wayne County, N.C., to be placed in service in January 2013. PEC has also received approval from the NCUC to construct an approximately 620-MW natural gas-fueled generating facility at a site in New Hanover County, N.C., to replace the existing coal-fired generation at this site. The facility is projected to be placed in service in December 2013. After 2014, PEC will continue to operate its Roxboro, Mayo and Asheville coal-fired plants in North Carolina, which have state-of-the-art emission controls. Emissions of NOx, sulfur dioxide (SO2), mercury and other pollutants have been reduced significantly at these sites.

In recent years, the federal government has authorized loan guarantee programs for innovative energy projects as well as newly constructed nuclear facilities. PEF decided not to pursue the loan guarantee program for the Levy project. However, this decision does not preclude PEF from revisiting the program at a later date if there are changes to the program. We cannot predict if PEF will pursue this program further.

NUCLEAR

Nuclear generating units are regulated by the NRC. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. Our nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.

In September 2009, CR3 began an outage for normal refueling and maintenance, as well as its uprate project to increase its generating capacity and to replace two steam generators. During preparations to replace the steam generators, we discovered a delamination within the concrete of the outer wall of the containment structure, which has resulted in an extension of the outage. After a comprehensive analysis, we have determined that the concrete delamination at CR3 was caused by redistribution of stresses on the containment wall that occurred when we created an opening to accommodate the replacement of the unit’s steam generators. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. Nuclear safety remains our top priority, and our plans and actions will continue to reflect that commitment. A number of factors affect the return to service date, including regulatory reviews by the NRC and other agencies, emergent work, final engineering designs, testing, weather and other developments (See Note 7C).

PEC’s nuclear units have operating licenses granted by the NRC that have been extended to 2030 and 2046. The NRC operating license held by PEF for CR3 currently expires in December 2016. On March 9, 2009, the NRC docketed, or accepted for review, PEF’s application for a 20-year renewal on the operating license for CR3, which would extend the operating license through 2036, if approved. Docketing the application does not preclude additional requests for information as the review proceeds, nor does it indicate whether the NRC will renew the license. The license renewal application for CR3 is currently under review by the NRC with a decision expected in 2011.

POTENTIAL NEW CONSTRUCTION

While we have not made a final determination on nuclear construction, we continue to take steps to keep open the option of building a plant or plants. During 2008, PEC and PEF filed COL applications to potentially construct new nuclear plants in North Carolina and Florida (See Item 1A, “Risk Factors”). The NRC estimates that it will take approximately three to four years to review and process the COL applications. We have focused on the potential nuclear plant construction in Florida given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce GHG emissions as well as existing state legislative policy that is supportive of nuclear projects.

In 2006, we announced that PEF selected Levy to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application submission. In 2007, PEF completed the purchase of approximately 5,000 acres for Levy and associated transmission needs. On July 30, 2008, PEF filed its COL application with the NRC for two reactors. PEF also completed and submitted a

Limited Work Authorization request for Levy concurrent with the COL application. The FPSC issued the final order granting PEF’s petition for the Determination of Need for Levy on August 12, 2008. On October 6, 2008, the NRC docketed the Levy nuclear project application. On February 24, 2009, PEF received the NRC’s schedule for review and approval of the COL.

PEF’s initial schedule anticipated performing certain site work pursuant to the Limited Work Authorization prior to COL receipt. However, in 2009, the NRC Staff determined that certain schedule-critical work that PEF had proposed to perform within the scope of the Limited Work Authorization will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work will be shifted until after COL issuance. This factor alone resulted in a minimum 20-month schedule shift later than the originally anticipated timeframe. Since then, regulatory and economic conditions have changed, resulting in additional schedule shifts. These conditions include the permitting and licensing process, national and state economic conditions, recent FPSC DSM goals and the resulting impact on ratepayers, and other FPSC decisions. Uncertainty regarding PEF’s access to capital on reasonable terms, PEF’s ability to secure joint owners and increasing uncertainty surrounding carbon regulation and its costs could be other factors to affect the Levy schedule.

PEF signed the EPC agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two Westinghouse AP1000 nuclear units to be constructed at Levy. More than half of the approximate $7.650 billion contract price is fixed or firm with agreed upon escalation factors. The EPC agreement includes various incentives, warranties, performance guarantees, liquidated damage provisions and parent guarantees designed to incent the contractor to perform efficiently. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. We executed an amendment to the EPC agreement in 2010 due to the schedule shifts previously discussed. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items and PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. In its April 30, 2010 nuclear cost-recovery filing, PEF included for rate-making purposes a point estimate of potential Levy disposition fees and charges of $50 million, subject to true-up. However, the amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed. We cannot predict the outcome of this matter.

The total escalated cost for the two generating units was estimated in PEF’s petition for the Determination of Need for Levy to be approximately $14 billion. This total cost estimate included land, plant components, financing costs, construction, labor, regulatory fees and the initial core for the two units. An additional $3 billion was estimated for the necessary transmission equipment and approximately 200 miles of transmission lines associated with the project. PEF’s 2010 nuclear cost-recovery filing included an updated analysis that demonstrated continued feasibility of the Levy project with PEF’s current estimated range of total escalated cost, including transmission, of $17.2 billion to $22.5 billion. The filed estimated cost range primarily reflects cost escalation resulting from the schedule shifts. Many factors will affect the total cost of the project and once PEF receives the COL, it will further refine the project timeline and budget. As previously discussed, we continue to evaluate the Levy project on an ongoing basis.

In 2006, we announced that PEC selected a site at Harris to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. On February 19, 2008, PEC filed its COL application with the NRC for two additional reactors at Harris. On April 17, 2008, the NRC docketed the Harris application. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, a new plant would not be online until the middle of the next decade (See “Energy Demand” above).

SPENT NUCLEAR FUEL MATTERS

The Nuclear Waste Policy Act of 1982 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. We will continue to maximize the use of spent fuel storage capability within our own facilities for as long as feasible.

With certain modifications and additional approvals by the NRC, including the installation and/or expansion of on-site dry cask storage facilities at Robinson, Brunswick and CR3, the Utilities’ spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on their respective systems through the expiration of the operating licenses, including any license renewals, for their nuclear generating units. Harris has sufficient storage capacity through the expiration of its renewed operating licenses.

See Note 22D for discussion of the status of the Utilities’ contracts with the DOE for spent nuclear fuel storage.

ENVIRONMENTAL MATTERS

HAZARDOUS AND SOLID WASTE MANAGEMENT

We accrue costs to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates could change and additional losses, which could be material, may be incurred in the future.

In 2009, the EPA evaluated information about ash impoundment dams nationwide and developed a listing of 44 utility ash impoundment dams considered to have “high hazard potential,” including two of PEC’s ash impoundment dams. A “high hazard potential” rating is not related to the stability of those ash ponds but to the potential for harm should the impoundment dam fail. All of the dams at PEC’s coal ash ponds have been subject to periodic third-party inspection for many years in accordance with prior applicable requirements. The EPA rated the 44 “high hazard potential” impoundments, as well as other impoundments, from “unsatisfactory” to “satisfactory” based on their structural integrity and associated documentation.

Only dams rated as “unsatisfactory” would be considered to pose an immediate safety threat. None of the facilities received an “unsatisfactory” rating from the EPA. In total, six of PEC’s ash pond dams, including one “high hazard

potential” impoundment, were rated as “poor” based on the contract inspector’s desire to see additional documentation and evaluations of vegetation management and minor erosion control. Inspectors applied the same criteria to both active and inactive ash ponds, despite the fact that most of the inactive ash impoundments no longer hold water and do not pose a risk of breaching and spilling. PEC has completed several of the EPA’s recommendations for the active ponds and other recommended actions are under way. Following evaluations and inspections, engineers have determined that one ash pond dam requires modifications to comply with current standards for an extra margin of safety for slope stability. Design and permitting efforts for that work have been initiated. PEC is working with the North Carolina Dam Safety program to evaluate the remaining recommendations. We do not expect mitigation of these issues to have a material impact on our results of operations.

As of January 1, 2010, dams at utility fossil-fired power plants in North Carolina, including dams for ash ponds, are subject to the North Carolina Dam Safety Act’s applicable provisions, including state inspection. Those provisions are under the purview of the North Carolina Division of Land Resources. The division has completed its initial inspections of all of PEC’s dams. No significant issues were found.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities’ coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. On June 21, 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residue management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residuals that are recycled. A final rule is expected in late 2011 or 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

AIR QUALITY AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which likely would result in increased capital expenditures and O&M expenses. Additionally, Congress may be considering legislation that would require reductions in air emissions of NOx, SO2, carbon dioxide (CO2) and mercury. Some proposals establish nationwide caps and emission rates over an extended period of time. This national multipollutant approach to air pollution control could involve significant capital costs that could be material to our financial position or results of operations. Control equipment installed pursuant to the provisions of CAIR, Clean Air Visibility Rule (CAVR) and mercury regulations, which are discussed below, may address some of the issues outlined previously. PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, CAVR and mercury regulation (see discussion of the court decisions that impacted the CAIR, the delisting determination and the Clean Air Mercury Rule [CAMR] below). The CAVR requires the installation of best available retrofit technology (BART) on certain units. However, the outcome of these matters cannot be predicted.

Clean Smokestacks Act

In 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,000 MW of coal-fired generation capacity in North Carolina affected by the Clean Smokestacks Act. PEC’s environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions have been placed in service. PEC plans to retire by the end of 2014, its remaining coal-fired generating facilities in North Carolina totaling 1,500 MW that do not have scrubbers and replace the generation capacity with new natural gas-fueled generating facilities, which should enable the utility to comply with the final Clean Smokestacks Act SO2

emissions target that begins in 2013. We are continuing to evaluate various design, technology, generation and fuel options that could change expenditures required to maintain compliance with the Clean Smokestacks Act limits subsequent to 2013.

O&M expense increases with the operation of pollution control equipment due to the cost of reagents, additional personnel and general maintenance associated with the pollution control equipment. PEC is allowed to recover the cost of reagents and certain other costs under its fuel clause; the North Carolina retail portion of all other O&M expense is currently recoverable through base rates. In 2009, the SCPSC issued an order allowing PEC to begin deferring as a regulatory asset the depreciation expense that PEC incurs on its environmental compliance control facilities as well as the incremental O&M expenses that PEC incurs in connection with its environmental compliance control facilities.

Clean Air Interstate Rule

The CAIR, issued by the EPA, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2. States were required to adopt rules implementing the CAIR, and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR.

The air quality controls installed to comply with NOx requirements under certain sections of the Clean Air Act (CAA) and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEC and PEF met the 2009 phase I requirements for NOx and the 2010 phase I requirements of CAIR for NOx and SO2 with a combination of emission reductions resulting from in-service emission control equipment and emission allowances. PEF’s Crystal River Unit No. 4 (CR4) SO2 and NOx emission control equipment was placed in service in May 2010 and PEF’s Crystal River Unit No. 5 (CR5) SO2 and NOx emission control equipment was placed in service in 2009.

In 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court’s prior opinion. On August 2, 2010, the EPA published the proposed Transport Rule, which is the regulatory program that will replace the CAIR when finalized. The proposed Transport Rule contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets. The EPA plans to finalize the Transport Rule in the spring of 2011. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are well positioned to comply with the Transport Rule. The outcome of the EPA’s rulemaking cannot be predicted. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, the current implementation of the CAIR continues to fulfill BART for NOx and SO2 for BART-affected units under the CAVR. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO2 emissions reductions in addition to particulate matter emissions reductions for BART-eligible units.

Under an agreement with the Florida Department of Environmental Protection (FDEP), PEF will retire Crystal River Units No. 1 and No. 2 coal-fired steam units (CR1 and CR2) and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As required, PEF has advised the FDEP of developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date as discussed in “Other Matters – Nuclear – Potential New Construction.” We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

Clean Air Mercury Rule

rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of these decisions. The outcome of this matter cannot be predicted.

Clean Air Visibility Rule

The EPA’s rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in certain specially protected areas, including national parks and wilderness areas, designated as Class I areas. To help restore visibility in those areas, states must require the identified facilities to install BART to control their emissions. PEC’s BART-eligible units are Asheville Units No. 1 and No. 2, Roxboro Units No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Units No. 1 and No. 2, CR1 and CR2. The reductions associated with BART begin in 2013. As discussed in Note 7B, Sutton Unit No. 3 is one of the coal-fired generating units that PEC plans to replace with combined cycle natural gas-fueled electric generation. As discussed previously, PEF and the FDEP announced an agreement under which PEF will retire CR1 and CR2 as coal-fired units.

The CAVR included the EPA’s determination that compliance with the NOx and SO2 requirements of the CAIR could be used by states as a BART substitute to fulfill BART obligations, but the states could require the installation of additional air quality controls if they did not achieve reasonable progress in improving visibility. The D.C. Court of Appeals’ decision remanding the CAIR maintained its implementation such that CAIR satisfies BART for NOx and SO2. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. The FDEP finalized a Regional Haze implementation rule that goes beyond BART by requiring sources significantly impacting visibility in Class I areas to install additional controls by December 31, 2017. However, in the spring of 2010 the EPA indicated that the Reasonable Further Progress portion of the Regional Haze implementation rule is not approvable. In August 2010, the FDEP amended the rule by removing the Reasonable Further Progress provision, including the December 31, 2017, deadline for installation of additional controls, and instead will rely on current federal programs to achieve improvement in visibility. The outcome of these matters cannot be predicted.

Compliance Strategy

Both PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, the CAVR, mercury regulation and related air quality regulations. The air quality controls installed to comply with NOx requirements under certain sections of the CAA and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, resulted in a reduction of the costs to meet PEC’s CAIR requirements.

PEC’s environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions have been placed in service. PEF’s environmental compliance projects have also been placed in service.

The FPSC approved PEF’s petition to develop and implement an Integrated Clean Air Compliance Plan to comply with the CAIR, CAMR and CAVR and for recovery of prudently incurred costs necessary to achieve this strategy through the ECRC (see discussion previously regarding the vacating of the CAMR and remanding of the CAIR and its potential impact on CAVR). PEF’s April 1, 2010 filing with the FPSC for true-up of final 2009 environmental costs included a review of the Integrated Clean Air Compliance Plan, which reconfirmed the efficacy of the recommended plan and included an estimated total project cost of approximately $1.1 billion to be spent through 2016, to plan, design, build and install pollution control equipment at the Anclote Plant, CR4 and CR5. The majority of the $1.1 billion estimated total project cost related to CR4 and CR5 projects, which have been placed in service. Additional costs may be incurred if pollution controls are required in order to comply with the requirements of the CAVR, as discussed previously, or to meet compliance requirements of the final Transport Rule. Subsequent rule interpretations, increases in the underlying material, labor and equipment costs, equipment availability, or the unexpected acceleration of compliance dates, among other things, could result in significant increases in our estimated costs to comply and acceleration of some projects. The outcome of this matter cannot be predicted.

Environmental Compliance Cost Estimates

Risk factors regarding environmental compliance cost estimates are discussed in Item 1A, “Risk Factors.” Costs to comply with environmental laws and regulations are eligible for regulatory recovery through either base rates or cost-recovery clauses. The outcome of future petitions for recovery cannot be predicted. Our estimates of capital expenditures to comply with environmental laws and regulations are subject to periodic review and revision and may vary significantly. PEC is continuing to evaluate various design, technology and new generation options that could change expenditures required to maintain compliance with the Clean Smokestacks Act limits subsequent to 2013. Additional compliance plans for PEC and PEF to meet the requirements of the Transport Rule will be determined upon finalization of the rule. As a result of the decision remanding the CAIR, compliance plans and costs to meet the requirements of the CAVR are being reassessed and we cannot predict the impact that the EPA’s further proceedings will have on our compliance with the CAVR requirements. Compliance plans to meet the requirements of a revised or new implementing rule for mercury will be determined upon finalization of the rule. Compliance plans to meet the requirements of a revised or new implementing rule under Section 316(b) of the Clean Water Act (Section 316(b)), as discussed below, will be determined upon finalization of the rule. The timing and extent of the costs for future projects will depend upon final compliance strategies. However, we believe that future costs to comply with new or subsequent rule interpretations could be significant.

North Carolina Attorney General Petition under Section 126 of the Clean Air Act

In 2004, the North Carolina attorney general filed a petition with the EPA, under Section 126 of the CAA, asking the federal government to force fossil fuel-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina’s ability to meet National Ambient Air Quality Standards (NAAQS) for ozone and particulate matter. In 2006, the EPA issued a final response denying the petition, and the North Carolina attorney general filed a petition in the D.C. Court of Appeals seeking a review of the agency’s denial. In 2009, the D.C. Court of Appeals remanded the EPA’s denial to the agency for reconsideration. The outcome of the remand proceeding cannot be predicted.

National Ambient Air Quality Standards

Environmental groups and 13 states filed a joint petition with the D.C. Court of Appeals arguing that the EPA's particulate matter rule does not adequately restrict levels of particulate matter, especially with respect to the annual and secondary standards. In 2009, the D.C. Court of Appeals remanded the annual and secondary standards to the EPA for further review and consideration. The outcome of this matter cannot be predicted.

In 2008, the EPA revised the 8-hour primary and secondary standards for the NAAQS for ground-level ozone. Additional nonattainment areas may be designated in PEC’s and PEF’s service territories as a result of these revised standards. A number of states, environmental groups and industry associations filed petitions against the revised NAAQS in the D.C. Court of Appeals. The EPA requested the D.C. Court of Appeals to suspend proceedings in the case while the EPA evaluates whether to maintain, modify or otherwise reconsider the revised NAAQS. In 2009, the EPA announced that it was reconsidering the level of the ozone NAAQS and it will stay plans to designate nonattainment areas until after the reconsideration has been completed.

On January 7, 2010, the EPA announced a proposed revision to the primary ozone NAAQS. In addition, the EPA proposed a cumulative seasonal secondary standard. The EPA plans to finalize the revisions by July 29, 2011, and to designate nonattainment areas by August 2012. The proposed revisions are significantly more stringent than the current NAAQS. Should additional nonattainment areas be designated in our service territories, we may be required to install additional emission controls at some of our facilities. The outcome of this matter cannot be predicted.

On January 25, 2010, the EPA announced a revision to the primary NAAQS for nitrogen dioxide. Historically, the standard for nitrogen dioxide has been an annual average. The EPA has retained the annual standard and added a new 1-hour NAAQS. In conjunction with proposing changes to the standard, the EPA is also requiring an increase in the coverage of the monitoring network, particularly near roadways where the highest concentrations are expected to occur due to traffic emissions. The EPA plans to designate nonattainment areas by January 2012. Currently, there are no monitors reporting violation of the new standard in PEC’s or PEF’s service territories, but the expanded

monitoring network will provide additional data, which could result in additional nonattainment areas. The outcome of this matter cannot be predicted.

On June 22, 2010, the EPA published the final new 1-hour NAAQS for SO2, which sets the limit at 75 parts per billion. The primary NAAQS on a 24-hour average basis and annual average will be eliminated under the new rule. The new 1-hour standard is a significant increase in the stringency of the standard and increases the risk of nonattainment, especially near uncontrolled coal-fired facilities. In addition, for the first time the EPA plans to use air quality modeling along with monitoring data in determining whether areas are attaining the new standard, which is likely to expand the number of nonattainment areas. Should additional nonattainment areas be designated in our service territories, we may be required to install additional emission controls at some of our facilities. The outcome of this matter cannot be predicted.

Water Quality

1. General

As a result of the operation of certain pollution control equipment required to comply with the air quality issues outlined previously, new sources of wastewater discharge will be generated at certain affected facilities. Integration of these new wastewater discharges into the existing wastewater treatment processes is currently ongoing and will result in permitting, construction and treatment requirements imposed on the Utilities now and into the future. The future costs of complying with these requirements could be material to our or the Utilities’ results of operations or financial position.

On September 15, 2009, the EPA concluded after a multi-year study of power plant wastewater discharges that current regulations have not kept pace with changes in the electric power industry since the regulations were issued in 1982, including addressing impacts to wastewater discharge from operation of air pollution control equipment. As a result, the EPA has announced that it plans to revise the regulations that govern wastewater discharge, which may result in operational changes and additional compliance costs in the future. The outcome of this matter cannot be predicted.

2. Section 316(b) of the Clean Water Act

Section 316(b) requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. The EPA promulgated a rule implementing Section 316(b) in respect to existing power plants in July 2004.

A number of states, environmental groups and others sought judicial review of the July 2004 rule. In 2007, the U.S. Court of Appeals for the Second Circuit issued an opinion and order remanding provisions of the rule to the EPA, and the EPA suspended the rule pending further rulemaking, with the exception of the requirement that permitted facilities must meet any requirements under Section 316(b) as determined by the permitting authorities on a case-by-case, best professional judgment basis. Following appeal, in 2009, the U.S. Supreme Court issued an opinion holding that the EPA, in selecting the “best technology” pursuant to Section 316(b), does have the authority to reject technology when its costs are “wholly disproportionate” to the benefits expected. Also, the U.S. Supreme Court held that EPA’s site-specific variance procedure (contained in the July 2004 rule) was permissible in that the procedure required testing to determine whether costs would be “significantly greater than” the benefits before a variance would be considered. As a result of these developments, our plans and associated estimated costs to comply with Section 316(b) will need to be reassessed and determined in accordance with any revised or new implementing rule after it is established by the EPA. Costs of compliance with a revised or new implementing rule are expected to be higher, and could be significantly higher, than estimated costs under the July 2004 rule. Our cost estimates to comply with the July 2004 rule were $60 million to $90 million, including $5 million to $10 million at PEC and $55 million to $80 million at PEF. In December 2010, consent decrees were entered in two pending federal actions brought by environmental groups against the EPA requiring the EPA to issue proposed 316(b) rules by March 14, 2011, and to issue a final decision by July 27, 2012. The outcome of this matter cannot be predicted.

OTHER ENVIRONMENTAL MATTERS

Climate Change

Growing state, federal and international attention to global climate change may result in the regulation of CO2 and other GHGs. In addition, the Obama administration has begun the process of regulating GHG emissions through use of the CAA. In 2007, the U.S. Supreme Court ruled that the EPA has the authority under the CAA to regulate CO2 emissions from new automobiles. In 2009, the EPA announced that six GHGs (CO2, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) pose a threat to public health and welfare under the CAA. A number of parties have filed petitions for review of this finding in the D.C. Court of Appeals. On December 23, 2010, the EPA announced a schedule for development of a new source performance standard for new and existing fossil fuel-fired electric utility units. Under the schedule, the EPA will propose the standard by July 2011 and issue the final rule by May 2012. The full impact of regulation under GHG initiatives and any final legislation, if enacted, cannot be determined at this time; however, we anticipate that it could result in significant cost increases over time for which the Utilities would seek corresponding rate recovery. We are preparing for a carbon-constrained future and are actively engaged in helping shape effective policies to address the issue.

The state of Florida’s 2008 comprehensive energy legislation included a directive that the FDEP develop rules to establish a cap-and-trade program to regulate GHG emissions that would be presented to the legislature. The FDEP has studied GHG policy options and the potential economic impacts, but it has not developed a regulation for the consideration of the legislature. While state-level study groups have been active in all three of our jurisdictions, we continue to believe that this issue requires a national policy framework – one that provides certainty and consistency. Our balanced solution as discussed in “Other Matters – Energy Demand” is a comprehensive plan to meet the anticipated demand in the Utilities’ service territories and provides a solid basis for slowing and reducing CO2 emissions by focusing on energy efficiency, alternative energy and a state-of-the-art power system.

There are ongoing efforts to reach a new international climate change treaty to succeed the Kyoto Protocol. The Kyoto Protocol was originally adopted by the United Nations to address global climate change by reducing emissions of CO2 and other GHGs. Although the treaty went into effect in 2005, the United States has not adopted it. In 2009, the United Nations Framework Convention on Climate Change convened the 15th Conference of the Parties to conduct further negotiations on GHG emissions reductions. At the conclusion of the conference, a number of the parties, including the United States, entered into a nonbinding accord calling upon the parties to submit emission reduction targets for 2020 to the United Nations Framework Convention on Climate Change Secretariat by the end of January 2010. On January 28, 2010, President Obama submitted a proposal to reduce the U.S. GHG emissions in the range of 17 percent below 2005 levels by 2020, subject to future congressional action.

Reductions in CO2 emissions to the levels specified by the Kyoto Protocol, potential new international treaties or federal or state proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from ratepayers. The cost impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time.

In 2009, the EPA issued the final GHG emissions reporting rule, which establishes a national protocol for the reporting of annual GHG emissions. Facilities that emit greater than 25,000 metric tons per year of GHGs must report emissions by March 31 of each year beginning in 2011 for year 2010 emissions. Because the rule builds on current emission-reporting requirements, compliance with the requirements is not expected to have a material impact on the Utilities.

On April 1, 2010, the EPA and the National Highway Transportation Safety Administration jointly announced the first regulation of GHG emissions from new vehicles. The EPA is regulating mobile source GHG emissions under Section 202 of the CAA, which according to the EPA also results in stationary sources, such as coal-fired power plants, being subject to regulation of GHG emissions under the CAA. On March 29, 2010, the EPA issued an interpretation that stationary source GHG emissions will be subject to regulation under the CAA beginning in January 2011. On May 13, 2010, the EPA issued the final “tailoring rule,” which establishes the thresholds for applicability of the Prevention of Significant Deterioration program permitting requirements for GHG emissions from stationary sources such as power plants and manufacturing facilities. Prevention of significant deterioration is a

construction air pollution permitting program designed to ensure air quality does not degrade beyond the NAAQS levels or beyond specified incremental amounts above a prescribed baseline level. The tailoring rule initially raises the permitting applicability threshold for GHG emissions to 75,000 tons per year, and it requires that the permitting requirements for GHG emissions from stationary sources begin on January 2, 2011. These developments require PEC and PEF to address GHG emissions in new air quality permits beginning in 2011. The impact of these developments cannot be predicted.

SYNTHETIC FUELS TAX CREDITS

Historically, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Internal Revenue Code (the Code) (Section 29) and as redesignated effective 2006 as Section 45K of the Code (Section 45K) as discussed below. The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. Qualifying synthetic fuels facilities entitled their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The synthetic fuels tax credit program expired at the end of 2007, and the synthetic fuels businesses were abandoned and reclassified to discontinued operations.

The amount of Section 29 tax credits that we were allowed to claim in any calendar year through December 31, 2005, was limited by the amount of our regular federal income tax liability. Section 29 tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. Legislation enacted in 2005 redesignated Section 29 tax credits generated after January 1, 2006, as general business credits under Section 45K of the Code. The redesignation of Section 29 tax credits generated after January 1, 2006, as a Section 45K general business credit removed the regular federal income tax liability limit on synthetic fuels production and subjects the credits to a one-year carry back period and a 20-year carry forward period.

Total Section 29/45K credits generated under the synthetic fuels tax credit program (including those generated by Florida Progress prior to our acquisition) were $1.891 billion, $1.055 billion of which has been used through December 31, 2010, to offset regular federal income tax liability and $836 million is being carried forward as deferred tax credits that do not expire.

See Note 22D and Item 1A, “Risk Factors,” for additional discussion related to our previous synthetic fuels operations.

LEGAL

We are subject to federal, state and local legislation and court orders. The specific issues, the status of the issues, accruals associated with issue resolutions and our associated exposures are discussed in detail in Note 22D.

NEW ACCOUNTING STANDARDS

See Note 2 for a discussion of the impact of new accounting standards.

PEC

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s MD&A insofar as they relate to PEC: “Results of Operations,” “Application of Critical Accounting Policies and Estimates,” “Liquidity and Capital Resources” and “Other Matters.”

The following MD&A and the information incorporated herein by reference 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 “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” for a discussion of the factors that may impact any such forward-looking statements made herein.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

PEC has primarily used a combination of debt securities, commercial paper and its revolving credit agreement for liquidity needs in excess of cash provided by operations. PEC also participates in the utility money pool, which allows PEC and PEF to lend and borrow to and from each other.

See discussion of credit ratings in Progress Energy “Credit Rating Matters.”

PEC expects to have sufficient resources to meet its future obligations through a combination of cash from operations, availability under its credit facility, money pool borrowings, issuances of commercial paper and long-term debt and/or contributions of equity from the Parent.

CASH FLOW DISCUSSION

HISTORICAL FOR 2010 AS COMPARED TO 2009 AND 2009 AS COMPARED TO 2008

Cash Flows from Operations

Net cash provided by operating activities increased $235 million for 2010, when compared to 2009. The increase was primarily due to the $115 million favorable impact of weather partially offset by $78 million higher nuclear plant outage and maintenance costs included in O&M, both as previously discussed; $141 million lower cash used for inventory, primarily due to higher coal consumption as a result of favorable weather in 2010 that was fulfilled through the 2010 usage of inventory from year-end 2009; $86 million lower cash used for pension and other benefits primarily due to a reduction of contributions made in 2010; and $37 million lower cash paid for income taxes. These amounts were partially offset by a $108 million decrease in the over-recovery of fuel as a result of higher fuel costs in 2010.

Net cash provided by operating activities increased $222 million in 2009, when compared to 2008. The increase in operating cash flow was primarily due to a $187 million over-recovery of fuel in 2009 compared to a $71 million under-recovery of fuel in 2008 due to higher fuel rates in 2009, $67 million in lower net income tax payments and a $63 million decrease in inventory purchases primarily driven by lower coal prices in 2009. These impacts were partially offset by $163 million of pension and other benefits contributions made in 2009.

Investing Activities

Net cash used by investing activities increased $67 million in 2010, when compared with 2009. The increase was primarily due to a $359 million increase in gross property additions and a $61 million increase in nuclear fuel additions, partially offset by a $351 million decrease in advances to affiliated companies. The increase in property additions is primarily due to increased capital expenditures at the Wayne County, New Hanover County and Harris generating facilities. The increase in nuclear fuel additions was primarily due to the three nuclear refueling and maintenance outages in 2010, compared to two in 2009.

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Net cash used by investing activities increased $121 million in 2009, when compared with 2008. The increase was primarily due to a $94 million increase in advances to affiliated companies and a $79 million increase in gross property additions, partially offset by a $57 million decrease in nuclear fuel additions. Property additions are primarily for normal construction activity and ongoing capital expenditures related to environmental compliance programs.

Financing Activities

Net cash used by financing activities decreased $10 million for 2010 when compared to 2009. The decrease in net cash used by financing activities was primarily due to the $400 million payment at maturity of long-term debt in 2009, the $110 million net repayment of commercial paper in 2009 and a $100 million reduction in dividends paid to the Parent in 2010 compared to 2009. These impacts were partially offset by $595 million of proceeds from the issuance of long-term debt, net in 2009.

Net cash used by financing activities increased $77 million for 2009 when compared to 2008. The increase in net cash used by financing activities was primarily due to the $200 million in dividends paid to the Parent in 2009, the $110 million net repayment of commercial paper in 2009, the $110 million issuance of commercial paper in 2008, and the $100 million increase in the payment at maturity of long-term debt in 2009 compared to 2008. These impacts were partially offset by a $273 million increase in the proceeds from the issuance of long-term debt, net in 2009 compared to 2008, as well as the $154 million repayment of advances from affiliates in 2008.

On October 15, 2010, PEC entered into a new $750 million, three-year RCA with a syndication of 22 financial institutions. The RCA is used to provide liquidity support for PEC’s issuances of commercial paper and other short-term obligations, and for general corporate purposes. The RCA will expire on October 15, 2013. The $450 million RCA was terminated effective October 15, 2010 (See “Credit Facilities and Registration Statements”).

On March 12, 2008, PEC amended its RCA with a syndication of financial institutions to extend the termination date by one year to June 28, 2011. This RCA was terminated on October 15, 2010 (See “Credit Facilities and Registration Statements”).

On November 18, 2008, PEC; the Parent, as a well-known seasoned issuer; and PEF 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 (See “Credit Facilities and Registration Statements”).

SHORT-TERM DEBT

At December 31, 2010, PEC had no outstanding short-term debt. At the end of each month during 2010, PEC had a maximum short-term debt balance of $12 million and an average short-term debt balance of $2 million at a weighted average interest rate of 0.32 percent. PEC’s short-term debt during 2010 consisted solely of money pool borrowings.

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FUTURE LIQUIDITY AND CAPITAL RESOURCES

PEC’s estimated capital requirements for 2011, 2012 and 2013 are approximately $1.5 billion, $1.3 billion and $1.2 billion, respectively, and primarily reflect construction expenditures to support customer growth, add regulated generation and upgrade existing facilities as discussed in Progress Energy “Capital Expenditures.”

PEC expects to fund its capital requirements primarily through a combination of cash from operations, issuance of long-term debt and/or contributions of equity from the Parent. In addition, PEC has a $750 million credit facility that supports the issuance of commercial paper. Access to the commercial paper market and the utility money pool provide additional liquidity to help meet PEC’s working capital requirements.

Over the long term, meeting the anticipated load growth will require a balanced approach, including energy conservation and efficiency programs, development and deployment of new energy technologies, and new generation, transmission and distribution facilities, including new generating facilities in the Carolinas currently under construction and the potential for additional new baseload generating facilities toward the middle of the next decade. This approach will require PEC to make significant capital investments. See Progress Energy “Introduction – Strategy” for additional information. PEC may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.

PEC has on file with the SEC a shelf registration statement under which it may issue an unlimited number or amount of various long-term debt securities and preferred stock. The shelf registration statement expires on November 18, 2011 (See “Credit Facilities and Registration Statements”).

CAPITALIZATION RATIOS

The following table shows each component of capitalization as a percentage of total capitalization at December 31, 2010 and 2009. In addition to total equity and preferred stock, total capitalization includes the following in total debt: long-term debt, net, current portion of long-term debt and capital lease obligations.


	2010			2009
Total equity		57.9	%		55.2	%
Preferred stock		0.7	%		0.7	%
Total debt		41.4	%		44.1	%

See the discussion of PEC’s future liquidity and capital resources, including financial market impacts, under Progress Energy and see Note 11 for further information regarding PEC’s debt and credit facility.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

See discussion under Progress Energy and Notes 22A, 22B and 22C for information on PEC’s off-balance sheet arrangements and contractual obligations at December 31, 2010.

GUARANTEES

See discussion under Progress Energy and Note 22C for a discussion of PEC’s guarantees.

MARKET RISK AND DERIVATIVES

Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 17 and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

PEC is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. In most cases, these contracts contain provisions for price adjustments, minimum purchase

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levels and other financial commitments. The commitment amounts presented in the following table are estimates and therefore will likely differ from actual purchase amounts. Further disclosure regarding PEC’s contractual obligations is included in the respective notes to the PEC Consolidated Financial Statements. PEC takes into consideration the future commitments when assessing its liquidity and future financing needs.

The following table reflects PEC’s contractual cash obligations and other commercial commitments at December 31, 2010, in the respective periods in which they are due:

(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (See Note 11)(a)	$	3,699	$	-	$	905	$	700	$	2,094
Interest payments on long-term debt(b)		1,844		179		328		246		1,091
Capital lease obligations (See Note 22B)		20		2		12		-		6
Operating leases (See Note 22B)(c)		780		23		71		96		590
Fuel and purchased power (See Note 22A)(d)		8,842		1,367		2,485		1,799		3,191
Other purchase obligations (See Note 22A)		1,172		489		314		66		303
Minimum pension funding requirements(e)		303		79		149		72		3
Other postretirement benefits(f)		238		19		42		47		130
Uncertain tax positions(g)		-		-		-		-		-
Other commitments(h)		91		13		26		26		26
Total	$	16,989	$	2,171	$	4,332	$	3,052	$	7,434

(a)

PEC’s maturing debt obligations are generally expected to be repaid with cash from operations or refinanced with new debt issuances in the capital markets.

(b)

Interest payments on long-term debt are based on the interest rate effective at December 31, 2010.

(c)

Amounts include certain related executory cost commitments.

(d)

Essentially all of PEC’s fuel and certain purchased power costs are eligible for recovery through cost-recovery clauses in accordance with state and federal regulations and therefore do not require separate liquidity support. Amounts exclude precedent and conditional contracts of $2.042 billion (See Note 22A).

(e)

Represents the projected minimum required contributions to the qualified pension trust for a total of 10 years. These amounts are subject to change significantly based on factors such as pension asset earnings and market interest rates.

(f)

Represents projected benefit payments for a total of 10 years related to PEC’s postretirement health and life plans and are subject to change based on factors such as experienced claims and general health care cost trends.

(g)

Uncertain tax positions of $74 million are not reflected in this table as PEC cannot predict when open income tax years will be closed with completed examinations. It is reasonably possible that the total amounts of PEC’s unrecognized tax benefits will decrease by up to approximately $10 million during the 12-month period ending December 31, 2011, due to expected settlements.

(h)

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PEF

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s MD&A insofar as they relate to PEF: “Results of Operations,” “Application of Critical Accounting Policies and Estimates,” “Liquidity and Capital Resources” and “Other Matters.”

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

PEF has primarily used a combination of debt securities, equity contributions from the Parent, commercial paper and its revolving credit agreement for liquidity needs in excess of cash provided by operations. PEF also participates in the utility money pool, which allows PEC and PEF to lend and borrow to and from each other.

See discussion of credit ratings in Progress Energy “Credit Rating Matters.”

PEF expects to have sufficient resources to meet its future obligations through a combination of cash from operations, availability under its credit facility, money pool borrowings, issuances of commercial paper and long-term debt and/or contributions of equity from the Parent.

CASH FLOW DISCUSSION

HISTORICAL FOR 2010 AS COMPARED TO 2009 AND 2009 AS COMPARED TO 2008

Cash Flows from Operations

Net cash provided by operating activities increased $67 million for 2010, when compared to 2009. The increase was primarily due to the $88 million favorable impact of weather as previously discussed; $98 million net cash receipts from income taxes in 2010 compared to $184 million of net cash payments for income taxes in 2009; and $56 million lower cash used for inventory, primarily due to higher coal consumption in 2010 as a result of favorable weather that was fulfilled through 2010 usage of inventory from year-end 2009. These amounts were partially offset by an $81 million under-recovery of fuel in 2010 compared to a $103 million over-recovery of fuel in 2009 driven by lower fuel rates in 2010 and $6 million of net payments of cash collateral to counterparties on derivative contracts in 2010 compared to $190 million net refunds of cash collateral in 2009.

Net cash provided by operating activities increased $1.086 billion in 2009, when compared with 2008. The increase in operating cash flow was primarily due to a $103 million over-recovery of fuel in 2009 compared to a $262 million under-recovery of fuel in 2008 due to higher fuel rates in 2009; a $323 million payment made in 2008 to counterparties for collateral associated with derivative contracts and $190 million net refunds of cash collateral in 2009. The change in derivative collateral assets was primarily driven by the relative fair values of our commodity derivative instruments (See Note 17A).

Investing Activities

Net cash used by investing activities decreased $541 million in 2010, when compared with 2009. The decrease in cash used by investing activities was primarily due to a $435 million decrease in gross property additions and a $67 million increase in cash provided by other investing activities. The decrease in property additions was driven by decreases in environmental compliance spending and expenditures for nuclear projects. The increase in cash provided by other investing activities is driven by the receipt of $64 million of NEIL insurance proceeds for repairs due to the CR3 extended outage.

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Net cash used by investing activities increased $89 million in 2009, when compared with 2008. The increase in cash used by investing activities was primarily due to a $149 million decrease in settlements of advances to affiliates and a $35 million increase in nuclear fuel additions, partially offset by a $103 million decrease in gross property additions. The decrease in property additions was driven by decreases in environmental compliance spending and completion of the Bartow Plant repowering project, partially offset by an increase in expenditures for nuclear projects.

Financing Activities

Net cash provided by financing activities decreased $374 million for 2010 when compared to 2009. The decrease in cash provided by financing activities was primarily due to a $620 million contribution from the Parent in 2009, a $361 million decrease in advances from affiliates and a $300 million retirement at maturity of long-term debt in 2010. The decreases are partially offset by $591 million of proceeds from the issuance of long-term debt in 2010 and $371 million repayment of commercial paper in 2009.

Net cash provided by financing activities decreased $995 million for 2009 when compared to 2008. The decrease in cash provided by financing activities was primarily due to PEF’s $1.475 billion in net proceeds from issuance of long-term debt in 2008, outstanding commercial paper issuances of $371 million in 2008, and repayment of commercial paper outstanding of $371 million in 2009, partially offset by receipts of $620 million in contributions from the Parent in 2009 and $532 million of long-term debt retirements in 2008.

On October 15, 2010, PEF entered into a new $750 million, three-year RCA with a syndication of 22 financial institutions. The RCA is used to provide liquidity support for PEF’s issuances of commercial paper and other short-term obligations, and for general corporate purposes. The RCA will expire on October 15, 2013. The $450 million RCA was terminated effective October 15, 2010 (See “Credit Facilities and Registration Statements”).

In 2009, PEF did not issue or retire long-term debt.

On February 1, 2008, PEF paid at maturity $80 million of its 6.875% First Mortgage Bonds with available cash on hand and commercial paper borrowings.

On March 12, 2008, PEF amended its RCA with a syndication of financial institutions to extend the termination date by one year to March 28, 2011. This RCA was terminated on October 15, 2010 (See “Credit Facilities and Registration Statements”).

On June 18, 2008, PEF issued $500 million of First Mortgage Bonds, 5.65% Series due 2018 and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038. A portion of the proceeds was used to repay PEF’s utility money pool borrowings and the remaining proceeds were placed in temporary investments for general corporate use as needed. On August 14, 2008, PEF redeemed the entire outstanding $450 million principal amount of its Series A Floating Rate Notes due November 14, 2008, at 100 percent of par plus accrued interest. The redemption was funded with a portion of the proceeds from the June 18, 2008 debt issuance.

On November 18, 2008, PEF; the Parent, as a well-known seasoned issuer; and PEC 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 (See “Credit Facilities and Registration Statements”).

SHORT-TERM DEBT

At December 31, 2010, PEF had outstanding short-term debt consisting of money pool borrowings totaling $9 million at an interest rate of 0.37 percent. At the end of each month during 2010, PEF had a maximum short-term

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debt balance of $259 million and an average short-term debt balance of $46 million at a weighted average interest rate of 0.29 percent. PEF’s short-term debt during 2010 consisted solely of money pool borrowings.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

PEF’s estimated capital requirements for 2011, 2012 and 2013 are approximately $720 million to $765 million, $785 million to $830 million, and $1.0 billion to $1.1 billion, respectively, and primarily reflect construction expenditures to support customer growth, add regulated generation and upgrade existing facilities as discussed in Progress Energy “Capital Expenditures.” PEF’s estimated capital requirements include potential nuclear construction expenditures for Levy. Forecasted potential nuclear construction expenditures are dependent upon, and may vary significantly based upon, the decision to build, regulatory approval schedules, timing and escalation of project costs, and the percentages of joint ownership. Because of announced schedule shifts, we negotiated an amendment to the Levy EPC agreement (See discussion under “Other Matters – Nuclear – Potential New Construction”). The forecasted capital expenditures reflect the announced schedule shift. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items and PEF has been in suspension negotiations with the selected equipment vendors, which PEF anticipates concluding by the end of the first quarter of 2011. Potential nuclear construction expenditures are subject to cost-recovery provisions.

PEF expects to fund its capital requirements primarily through a combination of cash from operations, issuance of long-term debt and/or contributions of equity from the Parent. In addition, PEF has a $750 million credit facility that supports the issuance of commercial paper. Access to the commercial paper market and the utility money pool provide additional liquidity to help meet PEF’s working capital requirements.

At December 31, 2010, the current portion of PEF’s long-term debt was $300 million, which we expect to fund with a combination of cash from operations, commercial paper borrowings and/or long-term debt.

Over the long term, meeting the anticipated load growth will require a balanced approach, including energy conservation and efficiency programs, development and deployment of new energy technologies, and new generation, transmission and distribution facilities, potentially including new baseload generating facilities in Florida toward the middle of the next decade. This approach will require PEF to make significant capital investments. PEF may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.

PEF has on file with the SEC a shelf registration statement under which it may issue an unlimited number or amount of various long-term debt securities and preferred stock. The shelf registration statement expires on November 18, 2011 (See “Credit Facilities and Registration Statements”).

CAPITALIZATION RATIOS

The following table shows each component of capitalization as a percentage of total capitalization at December 31, 2010 and 2009. In addition to total common stock equity and preferred stock, total capitalization includes the following in total debt: long-term debt, net, current portion of long-term debt, notes payable to affiliate companies and capital lease obligations.


	2010			2009
Total common stock equity		50.9	%		49.1	%
Preferred stock		0.3	%		0.4	%
Total debt		48.8	%		50.5	%

See the discussion of PEF’s future liquidity and capital resources, including financial market impacts, under Progress Energy and see Note 11 for further information regarding PEF’s debt and credit facility.

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OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

See discussion under Progress Energy and Notes 22A, 22B and 22C for information on PEF’s off-balance sheet arrangements and contractual obligations at December 31, 2010.

MARKET RISK AND DERIVATIVES

Under its risk management policy, PEF may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 17 and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

This information called for by Item 7 is omitted for PEF pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various risks related to changes in market conditions. Market risk represents the potential loss arising from adverse changes in market rates and prices. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk to the extent that the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties (See Note 17). Both PEC and PEF also have limited counterparty exposure for commodity hedges (primarily gas and oil hedges) by spreading concentration risk over a number of counterparties.

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.

Certain market risks are inherent in our financial instruments, which arise from transactions entered into in the normal course of business. Our primary exposures are changes in interest rates with respect to our long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to our NDT funds, changes in the market value of CVOs and changes in energy-related commodity prices.

These financial instruments are held for purposes other than trading. The risks discussed below do not include the price risks associated with nonfinancial instrument transactions and positions associated with our operations, such as purchase and sales commitments and inventory.

PROGRESS ENERGY

INTEREST RATE RISK

As part of our debt portfolio management and daily cash management, we have variable rate long-term debt and may have commercial paper and/or loans outstanding under our RCA facilities, which are also exposed to floating interest rates. Approximately 7 percent and 9 percent of consolidated debt had variable rates at December 31, 2010 and 2009, respectively.

Based on our variable rate long-term debt balances at December 31, 2010, a 100 basis point change in interest rates would result in an annual pre-tax interest expense change of approximately $9 million. We had no outstanding short-term debt at December 31, 2010.

From time to time, we use interest rate derivative instruments to adjust the mix between fixed and floating rate debt in our debt portfolio, to mitigate our exposure to interest rate fluctuations associated with certain debt instruments and to hedge interest rates with regard to future fixed-rate debt issuances.

The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates.

We use a number of models and methods to determine interest rate risk exposure and fair value of derivative positions. For reporting purposes, fair values and exposures of derivative positions are determined as of the end of the reporting period using the Bloomberg Financial Markets system.

In accordance with GAAP, interest rate derivatives that qualify as hedges are separated into one of two categories: cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest rate changes.

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The following tables provide information, at December 31, 2010 and 2009, about our interest rate risk-sensitive instruments. The tables present principal cash flows and weighted-average interest rates by expected maturity dates for the fixed and variable rate long-term debt and Parent-obligated mandatorily redeemable preferred securities of trust. The tables also include estimates of the fair value of our interest rate risk-sensitive instruments based on quoted market prices for these or similar issues. For interest rate forward contracts, the tables present notional amounts and weighted-average interest rates by contractual mandatory termination dates for 2011 to 2015 and thereafter and the related fair value. Notional amounts are used to calculate the settlement amounts under the interest rate forward contracts. See Note 17 for more information on interest rate derivatives.

December 31, 2010																						Fair Value
																						December 31,
(dollars in millions)	2011			2012			2013			2014			2015			Thereafter			Total			2010
Fixed-rate long-term debt	$	1,000		$	950		$	830		$	300		$	1,000		$	7,449		$	11,529		$	12,826
Average interest rate		6.96	%		6.67	%		4.96	%		6.05	%		5.18	%		6.18	%		6.11	%
Variable-rate long-term debt		-			-			-			-			-		$	861		$	861		$	861
Average interest rate		-			-			-			-			-			0.53	%		0.53	%
Debt to affiliated trust(a)		-			-			-			-			-		$	309		$	309		$	315
Interest rate		-			-			-			-			-			7.10	%		7.10	%
Interest rate forward contracts(b)	$	550		$	400		$	100			-			-			-		$	1,050		$	(35	)
Average pay rate		4.19	%		4.23	%		4.37	%		-			-			-			4.22	%
Average receive rate	(c)			(c)			(c)				-			-			-		(c)

(a)

Florida Progress Funding Corporation - Junior Subordinated Deferrable Interest Notes.

(b)

Notional amount of 10-year forward starting swaps are categorized by mandatory cash settlement date.

(c)

Rate is 3-month London Inter Bank Offered Rate (LIBOR), which was 0.30% at December 31, 2010.

During January 2011, Progress Energy terminated $300 million notional of forward starting swaps in conjunction with the issuance of $500 million of 4.40% Senior Notes.

At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million notional at PEC and $200 million notional at PEF.

December 31, 2009																						Fair Value
																						December 31,
(dollars in millions)	2010			2011			2012			2013			2014			Thereafter			Total			2009
Fixed-rate long-term debt	$	306		$	1,000		$	950		$	825		$	300		$	7,864		$	11,245		$	12,126
Average interest rate		4.53	%		6.96	%		6.67	%		4.96	%		6.05	%		6.13	%		6.12	%
Variable-rate long-term debt	$	100			-			-			-			-		$	861		$	961		$	961
Average interest rate		0.73	%		-			-			-			-			0.45	%		0.48	%
Debt to affiliated trust(a)		-			-			-			-			-		$	309		$	309		$	315
Interest rate		-			-			-			-			-			7.10	%		7.10	%
Interest rate forward contracts(b)	$	75		$	150		$	100			-			-			-		$	325		$	19
Average pay rate		3.48	%		4.03	%		4.07	%		-			-			-			3.91	%
Average receive rate	(c)			(c)			(c)				-			-			-		(c)

(a)

Florida Progress Funding Corporation - Junior Subordinated Deferrable Interest Notes.

(b)

Notional amount of 10-year forward starting swaps are categorized by mandatory cash settlement date.

(c)

Rate is 3-month LIBOR, which was 0.25% at December 31, 2009.

At December 31, 2009, Progress Energy had $325 million notional of open forward starting swaps, including $100 million notional at PEC and $75 million notional at PEF.

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MARKETABLE SECURITIES PRICE RISK

The Utilities maintain trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning their nuclear plants. These funds are primarily invested in stocks, bonds and cash equivalents, which are exposed to price fluctuations in equity markets and to changes in interest rates. At December 31, 2010 and December 31, 2009, the fair value of these funds was $1.571 billion and $1.367 billion, respectively, including $1.017 billion and $871 million, respectively, for PEC and $554 million and $496 million, respectively, for PEF. We actively monitor our portfolio by benchmarking the performance of our investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings. See Note 13 for further information on the trust fund securities.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At December 31, 2010 and December 31, 2009, the fair value of CVOs was $15 million. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analyses performed on the CVOs uses quoted prices obtained from brokers or quote services to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. A hypothetical 10 percent increase in the December 31, 2010 market price would result in a $2 million increase in the fair value of the CVOs and a corresponding increase in the CVO liability.

COMMODITY PRICE RISK

We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of our ownership of energy-related assets. Our exposure to these fluctuations is significantly limited by the cost-based regulation of the Utilities. Each state commission allows electric utilities to recover certain of these costs through various cost-recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, most of our long-term power sales contracts shift substantially all fuel price risk to the purchaser.

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. At December 31, 2010, substantially all derivative commodity instrument positions were subject to retail regulatory treatment.

See Note 17 for additional information with regard to our commodity contracts and use of economic and cash flow derivative financial instruments.

PEC

PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC’s primary exposures are changes in interest rates with respect to long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to its NDT funds and changes in energy-related commodity prices.

The information required by this item is incorporated herein by reference to Progress Energy’s Quantitative and Qualitative Disclosures About Market Risk insofar as it relates to PEC.

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INTEREST RATE RISK

The following tables provide information at December 31, 2010 and 2009, about PEC’s interest rate risk-sensitive instruments:

December 31, 2010																					Fair Value
																					December 31,
(dollars in millions)	2011			2012			2013			2014		2015			Thereafter			Total			2010
Fixed-rate long-term debt	$	-		$	500		$	405		$	-	$	700		$	1,474		$	3,079		$	3,413
Average interest rate		-			6.50	%		5.14	%				5.21	%		5.91	%		5.75	%
Variable-rate long-term debt		-			-			-			-		-		$	620		$	620		$	620
Average interest rate		-			-			-			-		-			0.54	%		0.54	%
Interest rate forward contracts(a)	$	100		$	200		$	50			-		-			-		$	350		$	(8	)
Average pay rate		4.31	%		4.27	%		4.43	%		-		-			-			4.30	%
Average receive rate	(b)			(b)			(b)				-		-			-		(b)

(a)

Notional amount of 10-year forward starting swaps are categorized by mandatory cash settlement date.

(b)

Rate is 3-month LIBOR, which was 0.30% at December 31, 2010.

At December 31, 2010, PEC had $350 million notional of open forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

December 31, 2009																				Fair Value
																				December 31,
(dollars in millions)	2010			2011		2012			2013			2014		Thereafter			Total			2009
Fixed-rate long-term debt	$	6		$	-	$	500		$	400		$	-	$	2,189		$	3,095		$	3,352
Average interest rate		6.30	%		-		6.50	%		5.13	%		-		5.69	%		5.75	%
Variable-rate long-term debt		-			-		-			-			-	$	620		$	620		$	620
Average interest rate		-			-		-			-			-		0.45	%		0.45	%
Interest rate forward contracts(a)		-			-	$	100			-			-		-		$	100		$	8
Average pay rate		-			-		4.07	%		-			-		-			4.07	%
Average receive rate		-			-	(b)				-			-		-		(b)

(a)

Notional amount of 10-year forward starting swaps are categorized by mandatory cash settlement date.

(b)

Rate is 3-month LIBOR, which was 0.25% at December 31, 2009.

At December 31, 2009, PEC had $100 million notional of open forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

COMMODITY PRICE RISK

PEC is exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. PEC’s exposure to these fluctuations is significantly limited by the cost-based regulation. Each state commission allows electric utilities to recover certain of these costs through various cost-recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. See “Commodity Price Risk” discussion under Progress Energy mentioned previously and Note 17 for additional information with regard to PEC’s commodity contracts and use of derivative financial instruments.

111

PEF

PEF has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEF’s primary exposures are changes in interest rates with respect to long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to its NDT funds, and changes in energy-related commodity prices.

The information required by this item is incorporated herein by reference by Progress Energy’s Quantitative and Qualitative Disclosures About Market Risk insofar as it relates to PEF.

INTEREST RATE RISK

The following tables provide information at December 31, 2010 and 2009, about PEF’s interest rate risk-sensitive instruments:

December 31, 2010																				Fair Value
																				December 31,
(dollars in millions)	2011			2012		2013			2014		2015			Thereafter			Total			2010
Fixed-rate long-term debt	$	300		$	-	$	425		$	-	$	300		$	3,225		$	4,250		$	4,730
Average interest rate		6.65	%		-		4.80	%		-		5.10	%		5.99	%		5.85	%
Variable-rate long-term debt		-			-		-			-		-		$	241		$	241		$	241
Average interest rate		-			-		-			-		-			0.52	%		0.52	%
Interest rate forward contracts(a)	$	150			-	$	50			-		-			-		$	200		$	(7	)
Average pay rate		4.18	%		-		4.30	%		-		-			-			4.21	%
Average receive rate	(b)				-	(b)				-		-			-		(b)

(a)

Notional amount of 10-year forward starting swaps are categorized by mandatory cash settlement date.

(b)

Rate is 3-month LIBOR, which was 0.30% at December 31, 2010.

At December 31, 2010, PEF had $200 million notional of open forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

December 31, 2009																				Fair Value
																				December 31,
(dollars in millions)	2010			2011			2012		2013			2014		Thereafter			Total			2009
Fixed-rate long-term debt	$	300		$	300		$	-	$	425		$	-	$	2,925		$	3,950		$	4,252
Average interest rate		4.50	%		6.65	%		-		4.80	%		-		6.06	%		5.85	%
Variable-rate long-term debt		-			-			-		-			-	$	241		$	241		$	241
Average interest rate		-			-			-		-			-		0.47	%		0.47	%
Interest rate forward contracts(a)	$	75			-			-		-			-		-		$	75		$	5
Average pay rate		3.48	%		-			-		-			-		-			3.48	%
Average receive rate	(b)				-			-		-			-		-		(b)

(a)

Notional amount of 10-year forward starting swaps are categorized by mandatory cash settlement date.

(b)

Rate is 3-month LIBOR, which was 0.25% at December 31, 2009.

At December 31, 2009, PEF had $75 million notional of open forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

COMMODITY PRICE RISK

PEF is exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. PEF’s

112

exposure to these fluctuations is significantly limited by its cost-based regulation. The FPSC allows PEF to recover certain fuel and purchased power costs to the extent the FPSC determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. See “Commodity Price Risk” discussion under Progress Energy mentioned previously and Note 17 for additional information with regard to PEF’s commodity contracts and use of derivative financial instruments.

113

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements, supplementary data and financial statement schedules are included herein:


Progress Energy, Inc. (Progress Energy)	Page
Report of Independent Registered Public Accounting Firm	116
Consolidated Statements of Income for the Years Ended December 31, 2010, 2009 and 2008	117
Consolidated Balance Sheets at December 31, 2010 and 2009	118
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	119
Consolidated Statements of Changes in Total Equity for the Years Ended December 31, 2010, 2009 and 2008	120
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008	121

Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
Report of Independent Registered Public Accounting Firm	122
Consolidated Statements of Income for the Years Ended December 31, 2010, 2009 and 2008	123
Consolidated Balance Sheets at December 31, 2010 and 2009	124
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	125
Consolidated Statements of Changes in Total Equity for the Years Ended December 31, 2010, 2009 and 2008	126
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008	126

Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
Report of Independent Registered Public Accounting Firm	127
Statements of Income for the Years Ended December 31, 2010, 2009 and 2008	128
Balance Sheets at December 31, 2010 and 2009	129
Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	130
Statements of Changes in Common Stock Equity for the Years Ended December 31, 2010, 2009 and 2008	131
Statements of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008	131

Combined Notes to the Financial Statements for Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a Progress Energy Florida, Inc.

Note 1 – Organization and Summary of Significant Accounting Policies	132
Note 2 – New Accounting Standards	139
Note 3 – Divestitures	139
Note 4 – Property, Plant and Equipment	140
Note 5 – Receivables	146
Note 6 – Inventory	147
Note 7 – Regulatory Matters	147
Note 8 – Goodwill	155
Note 9 – Equity	155
Note 10 – Preferred Stock of Subsidiaries	159
Note 11 – Debt and Credit Facilities	160
Note 12 – Investments	164
Note 13 – Fair Value Disclosures	164
Note 14 – Income Taxes	175
Note 15 – Contingent Value Obligations	182
Note 16 – Benefit Plans	183

114

Note 17 – Risk Management Activities and Derivatives Transactions	198
Note 18 – Related Party Transactions	205
Note 19 – Financial Information by Business Segment	206
Note 20 – Other Income and Other Expense	208
Note 21 – Environmental Matters	209
Note 22 – Commitments and Contingencies	213
Note 23 – Condensed Consolidating Statements	222
Note 24 – Quarterly Financial Data (Unaudited)	231
Note 25 – Subsequent Event – Merger Agreement	233

Each of the preceding combined notes to the financial statements of the Progress Registrants are applicable to Progress Energy, Inc. but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF.

Registrant	Applicable Notes
PEC	1, 2, 4 through 7, 9 through 14, 16 through 18, 20 through 22, 24 and 25
PEF	1, 2, 4 through 7, 9 through 14, 16 through 18, 20 through 22, 24 and 25

115

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.:

We have audited the accompanying consolidated balance sheets of Progress Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, changes in total equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Progress Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2011, expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2011

116

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
(in millions except per share data)
Years ended December 31	2010			2009			2008
Operating revenues	$	10,190		$	9,885		$	9,167
Operating expenses
Fuel used in electric generation		3,300			3,752			3,021
Purchased power		1,279			911			1,299
Operation and maintenance		2,027			1,894			1,820
Depreciation, amortization and accretion		920			986			839
Taxes other than on income		580			557			508
Other		30			13			(3	)
Total operating expenses		8,136			8,113			7,484
Operating income		2,054			1,772			1,683
Other income (expense)
Interest income		7			14			24
Allowance for equity funds used during construction		92			124			122
Other, net		-			6			(17	)
Total other income, net		99			144			129
Interest charges
Interest charges		779			718			679
Allowance for borrowed funds used during construction		(32	)		(39	)		(40	)
Total interest charges, net		747			679			639
Income from continuing operations before income tax		1,406			1,237			1,173
Income tax expense		539			397			395
Income from continuing operations		867			840			778
Discontinued operations, net of tax		(4	)		(79	)		58
Net income		863			761			836
Net income attributable to noncontrolling interests, net of tax		(7	)		(4	)		(6	)
Net income attributable to controlling interests	$	856		$	757		$	830
Average common shares outstanding – basic		291			279			262
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	2.96		$	2.99		$	2.95
Discontinued operations attributable to controlling interests, net of tax		(0.01	)		(0.28	)		0.22
Net income attributable to controlling interests	$	2.95		$	2.71		$	3.17
Dividends declared per common share	$	2.480		$	2.480		$	2.465
Amounts attributable to controlling interests
Income from continuing operations, net of tax	$	860		$	836		$	773
Discontinued operations, net of tax		(4	)		(79	)		57
Net income attributable to controlling interests	$	856		$	757		$	830

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

117

PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(in millions)	December 31, 2010			December 31, 2009
ASSETS
Utility plant
Utility plant in service	$	29,708		$	28,353
Accumulated depreciation		(11,567	)		(11,176	)
Utility plant in service, net		18,141			17,177
Other utility plant, net		220			212
Construction work in progress		2,205			1,790
Nuclear fuel, net of amortization		674			554
Total utility plant, net		21,240			19,733
Current assets
Cash and cash equivalents		611			725
Receivables, net		1,033			800
Inventory		1,226			1,325
Regulatory assets		176			142
Derivative collateral posted		164			146
Income taxes receivable		52			145
Prepayments and other current assets		214			248
Total current assets		3,476			3,531
Deferred debits and other assets
Regulatory assets		2,374			2,179
Nuclear decommissioning trust funds		1,571			1,367
Miscellaneous other property and investments		413			438
Goodwill		3,655			3,655
Other assets and deferred debits		325			333
Total deferred debits and other assets		8,338			7,972
Total assets	$	33,054		$	31,236
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 293 million and 281 million shares issued and outstanding, respectively	$	7,343		$	6,873
Unearned ESOP shares (0 and 1 million shares, respectively)		-			(12	)
Accumulated other comprehensive loss		(125	)		(87	)
Retained earnings		2,805			2,675
Total common stock equity		10,023			9,449
Noncontrolling interests		4			6
Total equity		10,027			9,455
Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			272
Long-term debt, net		11,864			11,779
Total capitalization		22,257			21,599
Current liabilities
Current portion of long-term debt		505			406
Short-term debt		-			140
Accounts payable		994			835
Interest accrued		216			206
Dividends declared		184			175
Customer deposits		324			300
Derivative liabilities		259			190
Accrued compensation and other benefits		175			167
Other current liabilities		298			239
Total current liabilities		2,955			2,658
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,696			1,196
Accumulated deferred investment tax credits		110			117
Regulatory liabilities		2,635			2,510
Asset retirement obligations		1,200			1,170
Accrued pension and other benefits		1,514			1,339
Derivative liabilities		278			240
Other liabilities and deferred credits		409			407
Total deferred credits and other liabilities		7,842			6,979
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	33,054		$	31,236

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

118

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2010			2009			2008
Operating activities
Net income	$	863		$	761		$	836
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		1,083			1,135			957
Deferred income taxes and investment tax credits, net		478			220			411
Deferred fuel (credit) cost		(2	)		290			(333	)
Allowance for equity funds used during construction		(92	)		(124	)		(122	)
Loss (gain) on sales of assets		9			2			(75	)
Pension, postretirement and other employee benefits		198			135			71
Other adjustments to net income		40			134			64
Cash (used) provided by changes in operating assets and liabilities
Receivables		(200	)		26			233
Inventory		98			(99	)		(237	)
Derivative collateral posted		(23	)		200			(340	)
Other assets		(1	)		14			(37	)
Income taxes, net		90			(14	)		(169	)
Accounts payable		125			(26	)		77
Accrued pension and other benefits		(164	)		(285	)		(39	)
Other liabilities		35			(98	)		(79	)
Net cash provided by operating activities		2,537			2,271			1,218
Investing activities
Gross property additions		(2,221	)		(2,295	)		(2,333	)
Nuclear fuel additions		(221	)		(200	)		(222	)
Purchases of available-for-sale securities and other investments		(7,009	)		(2,350	)		(1,590	)
Proceeds from available-for-sale securities and other investments		6,990			2,314			1,534
Other investing activities		61			(1	)		70
Net cash used by investing activities		(2,400	)		(2,532	)		(2,541	)
Financing activities
Issuance of common stock, net		434			623			132
Dividends paid on common stock		(717	)		(693	)		(642	)
Payments of short-term debt with original maturities greater than 90 days		-			(629	)		(176	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		-			-			629
Net (decrease) increase in short-term debt		(140	)		(381	)		496
Proceeds from issuance of long-term debt, net		591			2,278			1,797
Retirement of long-term debt		(400	)		(400	)		(877	)
Cash distributions to noncontrolling interests		(6	)		(6	)		(85	)
Other financing activities		(13	)		14			(26	)
Net cash (used) provided by financing activities		(251	)		806			1,248
Net (decrease) increase in cash and cash equivalents		(114	)		545			(75	)
Cash and cash equivalents at beginning of year		725			180			255
Cash and cash equivalents at end of year	$	611		$	725		$	180
Supplemental disclosures
Cash paid for interest, net of amount capitalized	$	709		$	701		$	612
Cash (received) paid for income taxes		(56	)		87			152
Significant noncash transactions
Accrued property additions		313			252			334
Asset retirement obligation additions and estimate revisions		(36	)		(384	)		14

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

119

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES in TOTAL EQUITY
	Common Stock							Accumulated
	Outstanding				Unearned			Other
					ESOP			Comprehensive			Retained			Noncontrolling			Total
(in millions except per share data)	Shares		Amount		Shares			(Loss) Income			Earnings			Interests			Equity

Balance, December 31, 2007		260	$	6,028	$	(37	)	$	(34	)	$	2,438		$	84		$	8,479
Net income				-		-			-			830			6			836
Other comprehensive loss				-		-			(82	)		-			-			(82	)
Issuance of shares		4		132		-			-			-			-			132
Allocation of ESOP shares				13		12			-			-			-			25
Stock-based compensation expense				33		-			-			-			-			33
Dividends ($2.465 per share)				-		-			-			(646	)		-			(646	)
Distributions to noncontrolling interests				-		-			-			-			(85	)		(85	)
Contributions from noncontrolling interests				-		-			-			-			2			2
Other				-		-			-			-			(1	)		(1	)

Balance, December 31, 2008		264		6,206		(25	)		(116	)		2,622			6			8,693
Net income(a)				-		-			-			757			-			757
Other comprehensive income				-		-			29			-			-			29
Issuance of shares		17		623		-			-			-			-			623
Allocation of ESOP shares				8		13			-			-			-			21
Stock-based compensation expense				36		-			-			-			-			36
Dividends ($2.480 per share)				-		-			-			(704	)		-			(704	)
Distributions to noncontrolling interests				-		-			-			-			(1	)		(1	)
Other				-		-			-			-			1			1

Balance, December 31, 2009		281		6,873		(12	)		(87	)		2,675			6			9,455
Cumulative effect of change in accounting principle (Note 2)				-		-			-			-			(2	)		(2	)
Net income(a)				-		-			-			856			3			859
Other comprehensive loss				-		-			(38	)		-			-			(38	)
Issuance of shares		12		434		-			-			-			-			434
Allocation of ESOP shares				9		12			-			-			-			21
Stock-based compensation expense				27		-			-			-			-			27
Dividends ($2.480 per share)				-		-			-			(726	)		-			(726	)
Distributions to noncontrolling interests				-		-			-			-			(2	)		(2	)
Other				-		-			-			-			(1	)		(1	)
Balance, December 31, 2010		293	$	7,343	$	-		$	(125	)	$	2,805		$	4		$	10,027

(a)

For the year ended December 31, 2010, consolidated net income of $863 million includes $4 million attributable to preferred shareholders of subsidiaries, which is not a component of total equity and is excluded from the table above. For the year ended December 31, 2009, consolidated net income of $761 million includes $4 million attributable to preferred shareholders of subsidiaries, which is not a component of total equity and is excluded from the table above.

See Notes to Progress Energy, Inc. Consolidated Financial Statements

120

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31,	2010			2009			2008
Net income	$	863		$	761		$	836
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $4, $4 and $2)		6			6			3
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $2, $3 and $1)		3			4			1
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $22, $(10) and $24)		(34	)		16			(37	)
Net unrecognized items for pension and other postretirement benefits (net of tax benefit (expense) of $8, $(1) and $29)		(13	)		2			(49	)
Other (net of tax benefit of $-, $- and $1)		-			1			-
Other comprehensive (loss) income		(38	)		29			(82	)
Comprehensive income		825			790			754
Comprehensive income attributable to noncontrolling interests, net of tax		(7	)		(4	)		(6	)
Comprehensive income attributable to controlling interests	$	818		$	786		$	748

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

121

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.:

We have audited the accompanying consolidated balance sheets of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and subsidiaries (“PEC”) as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, changes in total equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. PEC 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 PEC'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, such consolidated financial statements present fairly, in all material respects, the financial position of Progress Energy Carolinas, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2011

122

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of INCOME
(in millions)
Years ended December 31	2010			2009			2008
Operating revenues	$	4,922		$	4,627		$	4,429
Operating expenses
Fuel used in electric generation		1,686			1,680			1,346
Purchased power		302			229			346
Operation and maintenance		1,158			1,072			1,030
Depreciation, amortization and accretion		479			470			518
Taxes other than on income		218			210			198
Other		8			-			(5	)
Total operating expenses		3,851			3,661			3,433
Operating income		1,071			966			996
Other income (expense)
Interest income		3			5			12
Allowance for equity funds used during construction		64			33			27
Other, net		-			(18	)		4
Total other income, net		67			20			43
Interest charges
Interest charges		205			207			219
Allowance for borrowed funds used during construction		(19	)		(12	)		(12	)
Total interest charges, net		186			195			207
Income before income tax		952			791			832
Income tax expense		350			277			298
Net income		602			514			534
Net loss attributable to noncontrolling interests, net of tax		1			2			-
Net income attributable to controlling interests		603			516			534
Preferred stock dividend requirement		(3	)		(3	)		(3	)
Net income available to parent	$	600		$	513		$	531

See Notes to Progress Energy Carolinas, Inc. Consolidated Financial Statements.

123

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED BALANCE SHEETS
(in millions)	December 31, 2010			December 31, 2009
ASSETS
Utility plant
Utility plant in service	$	16,388		$	15,732
Accumulated depreciation		(7,324	)		(7,121	)
Utility plant in service, net		9,064			8,611
Other utility plant, net		184			177
Construction work in progress		1,233			702
Nuclear fuel, net of amortization		480			396
Total utility plant, net		10,961			9,886
Current assets
Cash and cash equivalents		230			35
Receivables, net		519			442
Receivables from affiliated companies		44			33
Notes receivable from affiliated companies		2			204
Inventory		590			677
Deferred fuel cost		71			88
Income taxes receivable		90			38
Prepayments and other current assets		110			61
Total current assets		1,656			1,578
Deferred debits and other assets
Regulatory assets		987			873
Nuclear decommissioning trust funds		1,017			871
Miscellaneous other property and investments		183			199
Other assets and deferred debits		95			95
Total deferred debits and other assets		2,282			2,038
Total assets	$	14,899		$	13,502
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,130		$	2,108
Unearned ESOP shares		-			(12	)
Accumulated other comprehensive loss		(33	)		(27	)
Retained earnings		3,083			2,588
Total common stock equity		5,180			4,657
Noncontrolling interests		-			3
Total equity		5,180			4,660
Preferred stock		59			59
Long-term debt, net		3,693			3,703
Total capitalization		8,932			8,422
Current liabilities
Current portion of long-term debt		-			6
Accounts payable		534			355
Payables to affiliated companies		109			72
Interest accrued		74			70
Customer deposits		106			95
Derivative liabilities		53			29
Accrued compensation and other benefits		99			86
Other current liabilities		81			50
Total current liabilities		1,056			763
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,608			1,258
Accumulated deferred investment tax credits		104			110
Regulatory liabilities		1,461			1,293
Asset retirement obligations		849			801
Accrued pension and other benefits		723			708
Other liabilities and deferred credits		166			147
Total deferred credits and other liabilities		4,911			4,317
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	14,899		$	13,502

See Notes to Progress Energy Carolinas, Inc. Consolidated Financial Statements.

124

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2010			2009			2008
Operating activities
Net income	$	602		$	514		$	534
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		602			585			616
Deferred income taxes and investment tax credits, net		285			64			204
Deferred fuel cost (credit)		79			187			(71	)
Allowance for equity funds used during construction		(64	)		(33	)		(27	)
Pension, postretirement and other employee benefits		78			65			25
Other adjustments to net income		4			67			20
Cash (used) provided by changes in operating assets and liabilities
Receivables		(76	)		42			(61	)
Receivables from affiliated companies		(11	)		(4	)		13
Inventory		85			(56	)		(119	)
Other assets		(24	)		28			11
Income taxes, net		(54	)		50			(116	)
Accounts payable		51			(18	)		42
Payables to affiliated companies		37			(10	)		11
Accrued pension and other benefits		(95	)		(181	)		(31	)
Other liabilities		19			(17	)		10
Net cash provided by operating activities		1,518			1,283			1,061
Investing activities
Gross property additions		(1,198	)		(839	)		(760	)
Nuclear fuel additions		(183	)		(122	)		(179	)
Purchases of available-for-sale securities and other investments		(489	)		(696	)		(682	)
Proceeds from available-for-sale securities and other investments		437			642			626
Changes in advances to affiliated companies		202			(149	)		(55	)
Other investing activities		1			1			8
Net cash used by investing activities		(1,230	)		(1,163	)		(1,042	)
Financing activities
Dividends paid on preferred stock		(3	)		(3	)		(3	)
Dividends paid to parent		(100	)		(200	)		-
Net (decrease) increase in short-term debt		-			(110	)		110
Proceeds from issuance of long-term debt, net		-			595			322
Retirement of long-term debt		-			(400	)		(300	)
Changes in advances from affiliated companies		-			-			(154	)
Contributions from parent		14			15			15
Other financing activities		(4	)		-			(16	)
Net cash used by financing activities		(93	)		(103	)		(26	)
Net increase (decrease) in cash and cash equivalents		195			17			(7	)
Cash and cash equivalents at beginning of year		35			18			25
Cash and cash equivalents at end of year	$	230		$	35		$	18
Supplemental disclosures
Cash paid for interest, net of amount capitalized	$	166		$	171		$	193
Cash paid for income taxes, net		108			144			211
Significant noncash transactions
Accrued property additions		198			91			99
Asset retirement obligation additions and estimate revisions		1			(386	)		(3	)

See Notes to Progress Energy Carolinas, Inc. Consolidated Financial Statements.

125

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of CHANGES in TOTAL EQUITY
	Common Stock				Unearned			Accumulated
	Outstanding				ESOP			Other
					Common			Comprehensive			Retained			Noncontrolling			Total
(in millions)	Shares		Amount		Stock			(Loss) Income			Earnings			Interests			Equity
Balance, December 31, 2007		160	$	2,054	$	(37	)	$	(10	)	$	1,745		$	4		$	3,756
Net income				-		-			-			534			-			534
Other comprehensive loss				-		-			(25	)		-			-			(25	)
Allocation of ESOP shares				16		12			-			-			-			28
Stock-based compensation expense				13		-			-			-			-			13
Preferred stock dividends at stated rates				-		-			-			(3	)		-			(3	)
Tax benefit dividend				-		-			-			2			-			2
Balance, December 31, 2008		160		2,083		(25	)		(35	)		2,278			4			4,305
Net income				-		-			-			516			(2	)		514
Other comprehensive income				-		-			8			-			-			8
Allocation of ESOP shares				10		13			-			-			-			23
Stock-based compensation expense				15		-			-			-			-			15
Dividends paid to parent				-		-			-			(200	)		-			(200	)
Preferred stock dividends at stated rates				-		-			-			(3	)		-			(3	)
Tax dividend				-		-			-			(3	)		-			(3	)
Other				-		-			-			-			1			1
Balance, December 31, 2009		160		2,108		(12	)		(27	)		2,588			3			4,660
Cumulative effect of change in accounting principle (Note 2)															(2	)		(2	)
Net income				-		-			-			603			(1	)		602
Other comprehensive loss				-		-			(6	)		-			-			(6	)
Allocation of ESOP shares				10		12			-			-			-			22
Stock-based compensation expense				12		-			-			-			-			12
Dividends paid to parent				-		-			-			(100	)		-			(100	)
Preferred stock dividends at stated rates				-		-			-			(3	)		-			(3	)
Tax dividend				-		-			-			(5	)		-			(5	)
Balance, December 31, 2010		160	$	2,130	$	-		$	(33	)	$	3,083		$	-		$	5,180

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31,	2010			2009		2008
Net income	$	602		$	514	$	534
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $3, $2 and $1)		4			3		1
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $6, $(3) and $17)		(10	)		5		(26	)
Other comprehensive (loss) income		(6	)		8		(25	)
Comprehensive income		596			522		509
Comprehensive loss attributable to noncontrolling interests, net of tax		1			2		-
Comprehensive income attributable to controlling interests	$	597		$	524	$	509

See Notes to Progress Energy Carolinas, Inc. Consolidated Financial Statements.

126

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.:

We have audited the accompanying balance sheets of Florida Power Corporation d/b/a Progress Energy Florida, Inc. (“PEF”) as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. PEF 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 PEF'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, such financial statements present fairly, in all material respects, the financial position of PEF as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, 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 financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2011

127

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of INCOME
(in millions)
Years ended December 31	2010			2009			2008
Operating revenues	$	5,254		$	5,251		$	4,731
Operating expenses
Fuel used in electric generation		1,614			2,072			1,675
Purchased power		977			682			953
Operation and maintenance		912			839			813
Depreciation, amortization and accretion		426			502			306
Taxes other than on income		362			347			309
Other		4			7			(5	)
Total operating expenses		4,295			4,449			4,051
Operating income		959			802			680
Other income (expense)
Interest income		1			4			9
Allowance for equity funds used during construction		28			91			95
Other, net		(1	)		5			(10	)
Total other income, net		28			100			94
Interest charges
Interest charges		271			258			236
Allowance for borrowed funds used during construction		(13	)		(27	)		(28	)
Total interest charges, net		258			231			208
Income before income tax		729			671			566
Income tax expense		276			209			181
Net income		453			462			385
Preferred stock dividend requirement		(2	)		(2	)		(2	)
Net income available to parent	$	451		$	460		$	383

See Notes to Progress Energy Florida, Inc. Financial Statements.

128

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
BALANCE SHEETS
(in millions)	December 31, 2010			December 31, 2009
ASSETS
Utility plant
Utility plant in service	$	13,155		$	12,438
Accumulated depreciation		(4,168	)		(3,987	)
Utility plant in service, net		8,987			8,451
Held for future use		36			36
Construction work in progress		972			1,088
Nuclear fuel, net of amortization		194			158
Total utility plant, net		10,189			9,733
Current assets
Cash and cash equivalents		249			17
Receivables, net		496			356
Receivables from affiliated companies		11			8
Inventory		636			648
Regulatory assets		105			54
Derivative collateral posted		140			139
Deferred tax assets		77			115
Prepayments and other current assets		29			80
Total current assets		1,743			1,417
Deferred debits and other assets
Regulatory assets		1,387			1,307
Nuclear decommissioning trust funds		554			496
Miscellaneous other property and investments		43			42
Other assets and deferred debits		140			105
Total deferred debits and other assets		2,124			1,950
Total assets	$	14,056		$	13,100
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,750		$	1,744
Accumulated other comprehensive (loss) income		(4	)		3
Retained earnings		3,144			2,743
Total common stock equity		4,890			4,490
Preferred stock		34			34
Long-term debt, net		4,182			3,883
Total capitalization		9,106			8,407
Current liabilities
Current portion of long-term debt		300			300
Notes payable to affiliated companies		9			221
Accounts payable		439			451
Payables to affiliated companies		60			62
Interest accrued		83			72
Customer deposits		218			205
Derivative liabilities		188			161
Accrued compensation and other benefits		47			53
Other current liabilities		121			89
Total current liabilities		1,465			1,614
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,065			767
Regulatory liabilities		1,084			1,103
Asset retirement obligations		351			369
Accrued pension and other benefits		522			395
Capital lease obligations		199			208
Derivative liabilities		190			174
Other liabilities and deferred credits		74			63
Total deferred credits and other liabilities		3,485			3,079
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	14,056		$	13,100

See Notes to Progress Energy Florida, Inc. Financial Statements.

129

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2010			2009			2008
Operating activities
Net income	$	453		$	462		$	385
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		446			527			320
Deferred income taxes and investment tax credits, net		324			64			130
Deferred fuel (credit) cost		(81	)		103			(262	)
Allowance for equity funds used during construction		(28	)		(91	)		(95	)
Pension, postretirement and other employee benefits		79			28			8
Other adjustments to net income		44			88			32
Cash (used) provided by changes in operating assets and liabilities
Receivables		(110	)		(15	)		(26	)
Receivables from affiliated companies		(3	)		7			(7	)
Inventory		13			(43	)		(122	)
Derivative collateral posted		(6	)		190			(323	)
Other assets		(17	)		15			(23	)
Income taxes, net		50			(75	)		-
Accounts payable		79			(11	)		48
Payables to affiliated companies		(2	)		7			(32	)
Accrued pension and other benefits		(61	)		(83	)		(24	)
Other liabilities		24			(36	)		42
Net cash provided by operating activities		1,204			1,137			51
Investing activities
Gross property additions		(1,014	)		(1,449	)		(1,552	)
Nuclear fuel additions		(38	)		(78	)		(43	)
Purchases of available-for-sale securities and other investments		(6,386	)		(1,540	)		(782	)
Proceeds from available-for-sale securities and other investments		6,390			1,545			784
Changes in advances to affiliated companies		-			-			149
Proceeds from sales of assets to affiliated companies		-			-			12
Other investing activities		61			(6	)		(7	)
Net cash used by investing activities		(987	)		(1,528	)		(1,439	)
Financing activities
Dividends paid on preferred stock		(2	)		(2	)		(2	)
Dividends paid to parent		(50	)		-			-
Net (decrease) increase in short-term debt		-			(371	)		371
Proceeds from issuance of long-term debt, net		591			-			1,475
Retirement of long-term debt		(300	)		-			(532	)
Changes in advances from affiliated companies		(212	)		149			72
Contributions from parent		-			620			-
Other financing activities		(12	)		(7	)		-
Net cash provided by financing activities		15			389			1,384
Net increase (decrease) in cash and cash equivalents		232			(2	)		(4	)
Cash and cash equivalents at beginning of year		17			19			23
Cash and cash equivalents at end of year	$	249		$	17		$	19
Supplemental disclosures
Cash paid for interest, net of amount capitalized	$	241		$	228		$	205
Cash (received) paid for income taxes		(98	)		184			52
Significant noncash transactions
Accrued property additions		111			156			231

See Notes to Progress Energy Florida, Inc. Financial Statements.

130

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of CHANGES in COMMON STOCK EQUITY
	Common Stock				Accumulated						Total
	Outstanding				Other						Common
					Comprehensive			Retained			Stock
(in millions except per share data)	Shares		Amount		(Loss) Income			Earnings			Equity
Balance, December 31, 2007		100	$	1,109	$	(8	)	$	1,901		$	3,002
Net income				-		-			385			385
Other comprehensive income				-		7			-			7
Stock-based compensation expense				7		-			-			7
Preferred stock dividends at stated rates				-		-			(2	)		(2	)
Balance, December 31, 2008		100		1,116		(1	)		2,284			3,399
Net income				-		-			462			462
Other comprehensive income				-		4			-			4
Stock-based compensation expense				8		-			-			8
Contributions from parent				620		-			-			620
Preferred stock dividends at stated rates				-		-			(2	)		(2	)
Tax dividend				-		-			(1	)		(1	)
Balance, December 31, 2009		100		1,744		3			2,743			4,490
Net income				-		-			453			453
Other comprehensive loss				-		(7	)		-			(7	)
Stock-based compensation expense				6		-			-			6
Dividends paid to parent				-		-			(50	)		(50	)
Preferred stock dividends at stated rates				-		-			(2	)		(2	)
Balance, December 31, 2010		100	$	1,750	$	(4	)	$	3,144		$	4,890

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31,	2010			2009		2008
Net income	$	453		$	462	$	385
Other comprehensive (loss) income
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $4, $(2) and $(5))		(7	)		4		7
Other comprehensive (loss) income		(7	)		4		7
Comprehensive income	$	446		$	466	$	392

See Notes to Progress Energy Florida, Inc. Financial Statements.

131

PROGRESS ENERGY, INC.

CAROLINA POWER & LIGHT COMPANY d/b/a/ PROGRESS ENERGY CAROLINAS, INC.

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.

COMBINED NOTES TO FINANCIAL STATEMENTS

In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to the Combined Notes. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.	ORGANIZATION

PROGRESS ENERGY

The Parent is a public utility holding company headquartered in Raleigh, N.C. As such, we are subject to regulation by the Federal Energy Regulatory Commission (FERC).

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 19 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.

PEF

PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC.

B.	BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), including GAAP for regulated operations. The financial statements include the activities of the Parent and our majority-owned and controlled subsidiaries. The Utilities are subsidiaries of Progress Energy, and as such their financial condition and results of operations and cash flows are also consolidated, along with our nonregulated subsidiaries, in our consolidated financial statements. Significant intercompany balances and transactions have been eliminated in consolidation.

Noncontrolling interests in subsidiaries along with the income or loss attributed to these interests are included in noncontrolling interests in both the Consolidated Balance Sheets and in the Consolidated Statements of Income. The results of operations for noncontrolling interests are reported on a net of tax basis if the underlying subsidiary is structured as a taxable entity.

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Unconsolidated investments in companies over which we do not have control, but have the ability to exercise influence over operating and financial policies, are accounted for under the equity method of accounting. These investments are primarily in limited liability corporations and limited liability partnerships, and the earnings from these investments are recorded on a pre-tax basis. Other investments are stated principally at cost. These equity and cost method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. See Note 12 for more information about our investments.

Our presentation of operating, investing and financing cash flows combines the respective cash flows from our continuing and discontinued operations as permitted under GAAP.

These combined notes accompany and form an integral part of Progress Energy’s and PEC’s consolidated financial statements and PEF’s financial statements.

Certain amounts for 2009 and 2008 have been reclassified to conform to the 2010 presentation.

C.	CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE’s variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity.

In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance that made significant changes to the model for determining who should consolidate a VIE and addressed how often this assessment should be performed. The guidance was effective for us on January 1, 2010 (See Note 2). As a result of the adoption, we and PEC deconsolidated two entities that qualify for low-income housing tax credits under Section 42 of the Internal Revenue Code (the Code) and recognized a $(2) million cumulative effect of change in accounting principle in 2010.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the managing member, and primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary for this VIE during 2008 through 2010. No financial or other support has been provided to the VIE during the periods presented.

The following table sets forth the carrying amount and classification of our investment in the partnership as reflected in the Consolidated Balance Sheets at December 31:


(in millions)	2010		2009
Miscellaneous other property and investments	$	12	$	17
Other assets and deferred debits		1		1
Accounts payable		5		4

The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC and there are no other arrangements that could expose us to losses.

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million

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mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $2 million annually in 2008, 2009 and 2010. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

See discussion of PEC’s variable interests in VIEs within the Progress Energy section.

PEF

PEF has no significant variable interests in VIEs.

D.	SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES AND ASSUMPTIONS

In preparing consolidated financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.

REVENUE RECOGNITION

We recognize revenue when it is realized or realizable and earned when all of the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; our price to the buyer is fixed or determinable; and collectability is reasonably assured. We recognize electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utility base revenues earned when service has been delivered but not billed by the end of the accounting period. Customer prepayments are recorded as deferred revenue and recognized as revenues as the services are provided.

FUEL COST DEFERRALS

Fuel expense includes fuel costs and other recoveries that are deferred through fuel clauses established by the Utilities’ regulators. These clauses allow the Utilities to recover fuel costs, fuel-related costs and portions of purchased power costs through surcharges on customer rates. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers.

EXCISE TAXES

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.

The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of income for the years ended December 31 were as follows:


(in millions)	2010		2009		2008
Progress Energy	$	345	$	333	$	295
PEC		119		108		102
PEF		226		225		193

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RELATED PARTY TRANSACTIONS

Our subsidiaries provide and receive services, at cost, to and from the Parent and its subsidiaries, in accordance with FERC regulations. The costs of the services are billed on a direct-charge basis, whenever possible, and on allocation factors for general costs that cannot be directly attributed. In the subsidiaries’ financial statements, billings from affiliates are capitalized or expensed depending on the nature of the services rendered.

UTILITY PLANT

Utility plant in service is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs of units of property as well as indirect construction costs. Certain costs are capitalized in accordance with regulatory treatment. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property (including planned major maintenance activities), and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred, with the exception of nuclear outages at PEF. Pursuant to a regulatory order, PEF accrues for nuclear outage costs in advance of scheduled outages, which generally occur every two years. Maintenance activities under long-term service agreements with third parties are capitalized or expensed as appropriate as if the Utilities had performed the activities. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal or disposal costs that do not represent asset retirement obligations (AROs) are charged to a regulatory liability.

Allowance for funds used during construction (AFUDC) represents the estimated costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform system of accounts, AFUDC is charged to the cost of the plant. The equity funds portion of AFUDC is credited to other income, and the borrowed funds portion is credited to interest charges.

Nuclear fuel is classified as a fixed asset and included in the utility plant section of the Consolidated Balance Sheets. Nuclear fuel in the front-end fuel processing phase is considered work in progress and not amortized until placed in service.

DEPRECIATION AND AMORTIZATION – UTILITY PLANT

Substantially all depreciation of utility plant other than nuclear fuel is computed on the straight-line method based on the estimated remaining useful life of the property, adjusted for estimated salvage (See Note 4A). Pursuant to their rate-setting authority, the NCUC, SCPSC and FPSC can also grant approval to accelerate or reduce depreciation and amortization rates of utility assets (See Note 7).

Amortization of nuclear fuel costs is computed primarily on the units-of-production method. In the Utilities’ retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC, the SCPSC and the FPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdictions, the provisions for nuclear decommissioning costs are approved by the FERC.

FEDERAL GRANT

The American Recovery and Reinvestment Act, signed into law in February 2009, contains provisions promoting energy efficiency (EE) and renewable energy. On April 28, 2010, we accepted a grant from the United States Department of Energy (DOE) for $200 million in federal matching infrastructure funds in support of our smart grid initiatives. PEC and PEF each will receive up to $100 million over a three-year period as project work progresses. The DOE will provide reimbursement for 50 percent of allowable project costs, as incurred, up to the DOE’s maximum obligation of $200 million. Projects funded by the grant must be completed by April 2013.

In accounting for the federal grant, we have elected to reduce the cost basis of select smart grid projects. As the select capital projects are placed into service, this will reduce depreciation expense over the life of the assets. Reimbursements by the DOE are deferred as a short-term or long-term liability on the Consolidated Balance Sheets based on their expected date of application to the select projects.

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ASSET RETIREMENT OBLIGATIONS

AROs are legal obligations associated with the retirement of certain tangible long-lived assets. The present values of retirement costs for which we have a legal obligation are recorded as liabilities with an equivalent amount added to the asset cost and depreciated over the useful life of the associated asset. The liability is then accreted over time by applying an interest method of allocation to the liability. Accretion expense is included in depreciation, amortization and accretion in the Consolidated Statements of Income. AROs have no impact on the income of the Utilities as the effects are offset by the establishment of regulatory assets and regulatory liabilities in order to reflect the ratemaking treatment of the related costs.

CASH AND CASH EQUIVALENTS

We consider cash and cash equivalents to include unrestricted cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

RECEIVABLES, NET

We record accounts receivable at net realizable value. This value includes an allowance for estimated uncollectible accounts to reflect any loss anticipated on the accounts receivable balances. The allowance for uncollectible accounts reflects our estimate of probable losses inherent in the accounts receivable, unbilled revenue, and other receivables balances. We calculate this allowance based on our history of write-offs, level of past due accounts, prior rate of recovery experience and relationships with and economic status of our customers.

INVENTORY

We account for inventory, including emission allowances, using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. Materials and supplies are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Materials reserves are established for excess and obsolete inventory.

REGULATORY ASSETS AND LIABILITIES

The Utilities’ operations are subject to GAAP for regulated operations, which allows a regulated company to record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, the Utilities record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 7A). The regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process.

NUCLEAR COST DEFERRALS

PEF accounts for costs incurred in connection with the proposed nuclear expansion in Florida in accordance with FPSC regulations, which establish an alternative cost-recovery mechanism. PEF is allowed to accelerate the recovery of prudently incurred siting, preconstruction costs, AFUDC and incremental operation and maintenance expenses resulting from the siting, licensing, design and construction of a nuclear plant through PEF’s capacity cost-recovery clause. Nuclear costs are deemed to be recovered up to the amount of the FPSC-approved projections, and the deferral of unrecovered nuclear costs accrues a carrying charge equal to PEF’s approved AFUDC rate. Unrecovered nuclear costs eligible for accelerated recovery are deferred and recorded as regulatory assets in the Consolidated Balance Sheets and are amortized in the period the costs are collected from customers.

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GOODWILL AND INTANGIBLE ASSETS

Goodwill is subject to at least an annual assessment for impairment by applying a two-step, fair value-based test. This assessment could result in periodic impairment charges. Intangible assets are amortized based on the economic benefit of their respective lives.

CHANGE IN ACCOUNTING POLICY REGARDING ANNUAL GOODWILL TESTING DATE

We perform our goodwill impairment tests for the PEC and PEF reporting units at least annually, and more often if events or changes in circumstances indicate it is more likely than not that their carrying values exceed their fair values. Since the adoption of Accounting Standards Codification (ASC) 350, Intangibles – Goodwill and Other, through April 1, 2010, we performed the annual impairment testing of goodwill using April 1 as the testing date. Our annual financial and strategic planning process, including the preparation of long-term cash flow projections, concludes in the fourth quarter of each year. Effective in October 2010, we changed our annual goodwill impairment testing date from April 1 to October 31 to better align our impairment testing procedures with the completion of our financial and strategic planning process. We believe the change is preferable since these long-term cash flow projections are a key component in performing our annual impairment tests of goodwill. During 2010, we tested our goodwill for impairment as of October 31, 2010 and April 1, 2010, and concluded there was no impairment of the carrying value of the goodwill. This change did not accelerate, delay, avoid, or cause a goodwill impairment charge. As it was impracticable to objectively determine operating and valuation estimates for periods prior to October 31, 2010, we have prospectively applied the change in the annual impairment testing date from October 31, 2010.

UNAMORTIZED DEBT PREMIUMS, DISCOUNTS AND EXPENSES

Long-term debt premiums, discounts and issuance expenses are amortized over the terms of the debt issues. Any expenses or call premiums associated with the reacquisition of debt obligations by the Utilities are amortized over the applicable lives using the straight-line method consistent with ratemaking treatment (See Note 7A).

INCOME TAXES

We and our affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to PEC and PEF in accordance with the Intercompany Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provides an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the carryover of uncompensated tax benefits, which primarily relate to deferred synthetic fuels tax credits. Income taxes are provided for as if PEC and PEF filed separate returns.

Deferred income taxes have been provided for temporary differences. These occur when the book and tax carrying amounts of assets and liabilities differ. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. Credits for the production and sale of synthetic fuels are deferred credits to the extent they cannot be or have not been utilized in the annual consolidated federal income tax returns, and are included in income tax expense (benefit) of discontinued operations in the Consolidated Statements of Income. We accrue for uncertain tax positions when it is determined that it is more likely than not that the benefit will not be sustained on audit by the taxing authority, including resolutions of any related appeals or litigation processes, based solely on the technical merits of the associated tax position. If the recognition threshold is met, the tax benefit recognized is measured at the largest amount of the tax benefit that, in our judgment, is greater than 50 percent likely to be realized. Interest expense on tax deficiencies and uncertain tax positions is included in net interest charges, and tax penalties are included in other, net in the Consolidated Statements of Income.

DERIVATIVES

GAAP requires that an entity recognize all derivatives as assets or liabilities on the balance sheet and measure those instruments at fair value, unless the derivatives meet the GAAP criteria for normal purchases or normal sales and are designated as such. We generally designate derivative instruments as normal purchases or normal sales whenever the criteria are met. If normal purchase or normal sale criteria are not met, we will generally designate the derivative instruments as cash flow or fair value hedges if the related hedge criteria are met. We have elected not to offset fair

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value amounts recognized for derivative instruments and related collateral assets and liabilities with the same counterparty under a master netting agreement. Certain economic derivative instruments receive regulatory accounting treatment, under which unrealized gains and losses are recorded as regulatory liabilities and assets, respectively, until the contracts are settled. Cash flows from derivative instruments are generally included in cash provided by operating activities on the Statements of Cash Flows. See Note 17 for additional information regarding risk management activities and derivative transactions.

LOSS CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

We accrue for loss contingencies, such as unfavorable results of litigation, when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. With the exception of legal fees that are incremental direct costs of an environmental remediation effort, we do not accrue an estimate of legal fees when a contingent loss is initially recorded, but rather when the legal services are actually provided.

As discussed in Note 21, we accrue environmental remediation liabilities when the criteria for loss contingencies have been met. We record accruals for probable and estimable costs, including legal fees, related to environmental sites on an undiscounted basis. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Certain environmental expenses receive regulatory accounting treatment, under which the expenses are recorded as regulatory assets. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable or on actual receipt of recovery. Environmental expenditures that have future economic benefits are capitalized in accordance with our asset capitalization policy.

IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS

We review the recoverability of long-lived tangible and intangible assets whenever impairment indicators exist. Examples of these indicators include current period losses, combined with a history of losses or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an impairment indicator exists for assets to be held and used, then the asset group is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows or the asset group is to be disposed of, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group.

We review our equity investments to evaluate whether or not a decline in fair value below the carrying value is an other-than-temporary decline. We consider various factors, such as the investee’s cash position, earnings and revenue outlook, liquidity and management’s ability to raise capital in determining whether the decline is other-than-temporary. If we determine that an other-than-temporary decline in value exists, the investments are written down to fair value with a new cost basis established.

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2.	NEW ACCOUNTING STANDARDS

A.	CONSOLIDATIONS

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities.” Subsequently, the FASB issued Accounting Standards Update (ASU) 2009-17, “Consolidations (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which codified SFAS No. 167 in the ASC. This guidance made significant changes to the model for determining who should consolidate a VIE, addressed how often this assessment should be performed, required all existing arrangements with VIEs to be evaluated, and was adopted through a cumulative effect of change in accounting principle adjustment. This guidance was effective for us on January 1, 2010. See Note 1C for information regarding our implementation of ASU 2009-17 and its impact on our and the Utilities’ financial position and results of operations.

B.	FAIR VALUE MEASUREMENT AND DISCLOSURES

In January 2010, the FASB issued ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” which amends ASC 820 to clarify certain existing disclosure requirements and to require a number of additional disclosures, including amounts and reasons for significant transfers between the three levels of the fair value hierarchy, and presentation of certain information in the reconciliation of recurring Level 3 measurements on a gross basis. ASU 2010-06 was effective for us on January 1, 2010, with certain disclosures effective January 1, 2011. The adoption of ASU 2010-06 resulted in additional disclosure but did not have an impact on our or the Utilities’ financial position or results of operations.

3.	DIVESTITURES

We have completed our business strategy of divesting nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. Included in discontinued operations, net of tax are amounts related to adjustments of our prior sales of diversified businesses. These adjustments are generally due to guarantees and indemnifications provided for certain legal, tax and environmental matters. See Note 22C for further discussion of our guarantees. The ultimate resolution of these matters could result in additional adjustments in future periods. The information below presents the impacts of the divestitures on net income attributable to controlling interests.

A.	TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

Prior to 2008, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 (Section 29) of the Code and as redesignated effective 2006 as Section 45K of the Code (Section 45K and, collectively, Section 29/45K). The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. As a result of the expiration of the tax credit program, all of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007. The accompanying consolidated statements of income reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky for $71 million in gross cash proceeds. Proceeds from the sale were used for general corporate purposes. During the year ended December 31, 2008, we recorded an after-tax gain of $42 million on the sale of these assets. The accompanying consolidated financial statements reflect the operations as discontinued operations.

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates. As a result, during the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations.

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Results of coal terminals and docks and synthetic fuels businesses discontinued operations for the years ended December 31 were as follows:

(in millions)	2010			2009			2008
Revenues	$	-		$	-		$	17
(Loss) earnings before income taxes and noncontrolling interest	$	(11	)	$	(125	)	$	8
Income tax benefit, including tax credits		5			47			12
Earnings attributable to noncontrolling interests		-			-			(1	)
Net (loss) earnings from discontinued operations attributable to controlling interests		(6	)		(78	)		19
Gain on disposal of discontinued operations, net of income tax expense of $7		-			-			42
(Loss) earnings from discontinued operations attributable to controlling interests	$	(6	)	$	(78	)	$	61

B.	COAL MINING BUSINESSES

On March 7, 2008, we sold the remaining operations of subsidiaries engaged in the coal mining business for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. As a result of the sale, during the year ended December 31, 2008, we recorded an after-tax gain of $7 million on the sale of these assets. During the years ended December 31, 2010 and 2009, gains and losses related to post-closing adjustments and pre-divestiture contingencies were not material to our results of operations.

The accompanying consolidated financial statements reflect the coal mining businesses as discontinued operations. Results of discontinued operations for the coal mining businesses for the year ended December 31, 2008 were as follows:


(in millions)	2008
Revenues	$	2
Loss before income taxes	$	(13	)
Income tax benefit		4
Net loss from discontinued operations		(9	)
Gain on disposal of discontinued operations, net of income tax expense of $2		7
Loss from discontinued operations attributable to controlling interests	$	(2	)

C.	OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations are amounts related to adjustments of our prior sales of other diversified businesses. During the years ended December 31, 2010, 2009 and 2008, gains and losses related to post-closing adjustments and pre-divestiture contingencies of other diversified businesses were not material to our results of operations.

4.	PROPERTY, PLANT AND EQUIPMENT

A.	UTILITY PLANT

The balances of electric utility plant in service at December 31 are listed below, with a range of depreciable lives (in years) for each:

	Depreciable		Progress Energy				PEC				PEF
(in millions)	Lives		2010		2009		2010		2009		2010		2009
Production plant		3-41	$	16,042	$	15,477	$	9,354	$	9,014	$	6,523	$	6,280
Transmission plant		7-75		3,530		3,273		1,626		1,535		1,904		1,738
Distribution plant		13-67		8,715		8,376		4,687		4,499		4,028		3,877
General plant and other		5-35		1,421		1,227		721		684		700		543
Utility plant in service			$	29,708	$	28,353	$	16,388	$	15,732	$	13,155	$	12,438

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Generally, electric utility plant at PEC and PEF, other than nuclear fuel, is pledged as collateral for the first mortgage bonds of PEC and PEF, respectively (See Note 11).

As discussed in Note 7B, PEC intends to retire no later than December 31, 2014, all of its coal-fired generating facilities in North Carolina that do not have scrubbers. These facilities total approximately 1,500 megawatts (MW) at four sites. During the fourth quarter of 2010, Progress Energy and PEC reclassified, for all periods, the net carrying value of the four facilities from utility plant in service, net, to other utility plant, net, on the consolidated balance sheets, in accordance with ASC 980-360, Regulated Operations – Property, Plant and Equipment. At December 31, 2010 and 2009, the net carrying value of the four facilities included in other utility plant, net, totaled $172 million and $165 million, respectively. Consistent with current ratemaking treatment, PEC expects to include the four facilities’ remaining net carrying value in rate base after retirement.

AFUDC represents the estimated costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the cost of the plant for certain projects in accordance with the regulatory provisions for each jurisdiction. The equity funds portion of AFUDC is credited to other income, and the borrowed funds portion is credited to interest charges. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the rates charged to customers by the Utilities over the service life of the property. The composite AFUDC rate for PEC’s electric utility plant was 9.2% in 2010, 2009 and 2008. The composite AFUDC rate for PEF’s electric utility plant was 7.4%, effective beginning April 1, 2010, based on its authorized return on equity (ROE) approved in the base rate case (See Note 7C). Prior to April 1, 2010, the composite AFUDC rate for PEF’s electric utility plant was 8.8%.

Our depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.0%, 2.4% and 2.3% in 2010, 2009 and 2008, respectively. The depreciation provisions related to utility plant were $635 million, $626 million and $578 million in 2010, 2009 and 2008, respectively. In addition to utility plant depreciation provisions, depreciation, amortization and accretion expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 4C), regulatory approved expenses (See Notes 7 and 21) and Clean Smokestacks Act amortization.

PEC’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.1% for 2010, 2009 and 2008. The depreciation provisions related to utility plant were $338 million, $328 million and $310 million in 2010, 2009 and 2008, respectively. In addition to utility plant depreciation provisions, depreciation, amortization and accretion expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 4C), regulatory approved expenses (See Note 7B) and Clean Smokestacks Act amortization.

PEF’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 1.9% in 2010, and 2.7% in 2009 and 2008. The depreciation provisions related to utility plant were $297 million, $299 million and $268 million in 2010, 2009 and 2008, respectively. In addition to utility plant depreciation provisions, depreciation, amortization and accretion expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 4C) and regulatory approved expenses (See Note 7C).

During 2010, PEF updated the depreciation rates which were approved by the FPSC in the 2009 base rate case. The rate change was effective January, 1, 2010, and resulted in a decrease in depreciation expense of $43 million for 2010. Additionally, in December 2010, PEF filed the FPSC approved depreciation rates with the FERC for use in its formula transmission rate for its Open Access Transmission Tariff (OATT). The FERC filing requested depreciation rates be applied retroactively to January 1, 2010 whereby if approved, the depreciation rate changes will result in a reduction to the depreciation expense charged to PEF’s OATT customers, beginning June 1, 2011.

Nuclear fuel, net of amortization at December 31, 2010 and 2009, was $674 million and $554 million, respectively, for Progress Energy, $480 million and $396 million, respectively, for PEC and $194 million and $158 million, respectively, for PEF. The amount not yet in service at December 31, 2010 and 2009, was $367 million and $308 million, respectively, for Progress Energy, $199 million and $175 million, respectively, for PEC and $168 million and $133 million, respectively, for PEF. Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE) and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities, was $132 million, $159 million and $145 million for

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the years ended December 31, 2010, 2009 and 2008, respectively. This amortization expense is included in fuel used in electric generation in the Consolidated Statements of Income. PEC’s amortization of nuclear fuel costs for the years ended December 31, 2010, 2009 and 2008 was $132 million, $134 million and $115 million, respectively. PEF’s amortization of nuclear fuel costs for the years ended December 31, 2009 and 2008 was $25 million and $30 million, respectively. PEF did not have any amortization of nuclear fuel costs for the year ended December 31, 2010, due to the Crystal River Unit No. 3 (CR3) outage (See Note 7C).

PEF’s construction work in progress related to certain nuclear projects has received regulatory treatment. At December 31, 2010, PEF had $519 million of accelerated recovery of construction work in process, of which $237 million was a component of a nuclear cost-recovery clause regulatory asset. At December 31, 2009, PEF had $451 million of accelerated recovery of construction work in process, of which $274 million was a component of nuclear cost-recovery clause regulatory asset and $22 million was a component of a deferred fuel regulatory asset. See Note 7C for further discussion of PEF’s nuclear cost recovery.

B.	JOINT OWNERSHIP OF GENERATING FACILITIES

PEC and PEF hold ownership interests in certain jointly owned generating facilities. Each is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to the additional costs. Each of the Utilities' share of operating costs of the jointly owned generating facilities is included within the corresponding line in the Statements of Income. The co-owner of Intercession City Unit P11 has exclusive rights to the output of the unit during the months of June through September. PEF has that right for the remainder of the year.

PEC’s and PEF’s ownership interests in the jointly owned generating facilities are listed below with related information at December 31:

		Company							Construction
(in millions)		Ownership			Plant		Accumulated		Work in
Subsidiary	Facility	Interest			Investment		Depreciation		Progress
2010
PEC	Mayo		83.83	%	$	798	$	294	$	8
PEC	Harris		83.83	%		3,255		1,604		16
PEC	Brunswick		81.67	%		1,702		939		38
PEC	Roxboro Unit 4		87.06	%		706		457		22
PEF	Crystal River Unit 3		91.78	%		901		497		648
PEF	Intercession City Unit P11		66.67	%		23		11		-

2009
PEC	Mayo		83.83	%	$	785	$	282	$	8
PEC	Harris		83.83	%		3,207		1,651		28
PEC	Brunswick		81.67	%		1,681		981		74
PEC	Roxboro Unit 4		87.06	%		686		449		15
PEF	Crystal River Unit 3		91.78	%		900		472		510
PEF	Intercession City Unit P11		66.67	%		23		10		-

In the tables above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Shearon Harris Nuclear Plant (Harris), which are not applicable to the joint owner’s ownership interest in Harris.

In the tables above, construction work in process for Crystal River Unit 3 is not reduced by the accelerated recovery of qualifying project costs under the FPSC nuclear cost-recovery rule (see Note 7C).

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C.	ASSET RETIREMENT OBLIGATIONS

At December 31, 2010 and 2009, our asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant, net of accumulated depreciation totaled $90 million and $132 million, respectively. PEC had immaterial asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant at December 31, 2010. Primarily due to the impact of updated cost estimates, as discussed below, at December 31, 2009, PEC had no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant. Primarily due to the impact of updated escalation factors, as discussed below, at December 31, 2010, PEF had no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant. At December 31 2009, PEF’s asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $18 million. At December 31, 2010 and 2009, additional PEF-related asset retirement costs, net of accumulated depreciation, of $90 million and $114 million, respectively, were recorded at Progress Energy as purchase accounting adjustments recognized when we purchased Florida Progress Corporation (Florida Progress) in 2000.

The fair value of funds set aside in the Utilities’ nuclear decommissioning trust (NDT) funds for the nuclear decommissioning liability totaled $1.571 billion and $1.367 billion at December 31, 2010 and 2009, respectively (See Notes 12 and 13). The fair value of funds set aside in the NDT funds for the nuclear decommissioning liability totaled $1.017 billion and $871 million at December 31, 2010 and 2009, respectively, for PEC and $554 million and $496 million, respectively, for PEF (See Notes 12 and 13). Net NDT unrealized gains are included in regulatory liabilities (See Note 7A).

Progress Energy’s and PEC’s nuclear decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million each in 2010, 2009 and 2008. As discussed below, PEF has suspended its accrual for nuclear decommissioning. Management believes that nuclear decommissioning costs that have been and will be recovered through rates by PEC and PEF will be sufficient to provide for the costs of decommissioning.

Expenses recognized for the disposal or removal of utility assets that do not meet the definition of AROs, which are included in depreciation, amortization and accretion expense, were $87 million, $141 million and $133 million in 2010, 2009 and 2008, respectively. PEC’s related expenses were $122 million, $106 million and $100 million in 2010, 2009 and 2008, respectively. Due to a $60 million cost of removal credit as allowed by the settlement agreement approved by the FPSC (See Note 7C), PEF had income of $35 million in 2010. PEF’s related expenses were $35 million and $33 million in 2009 and 2008, respectively.

The Utilities recognize removal, nonirradiated decommissioning and dismantlement of fossil generation plant costs in regulatory liabilities on the Consolidated Balance Sheets (See Note 7A). At December 31, such costs consisted of:

	Progress Energy				PEC				PEF
(in millions)	2010		2009		2010		2009		2010		2009
Removal costs	$	1,503	$	1,536	$	1,000	$	944	$	503	$	592
Nonirradiated decommissioning costs		233		211		172		150		61		61
Dismantlement costs		121		119		-		-		121		119
Non-ARO cost of removal	$	1,857	$	1,866	$	1,172	$	1,094	$	685	$	772

The NCUC requires that PEC update its cost estimate for nuclear decommissioning every five years. PEC received a new site-specific estimate of decommissioning costs for Robinson Nuclear Plant (Robinson) Unit No. 2, Brunswick Nuclear Plant (Brunswick) Units No. 1 and No. 2, and Harris, in December 2009, which was filed with the NCUC on March 16, 2010. PEC’s estimate is based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring after operating license expiration. These decommissioning cost estimates also include interim spent fuel storage costs associated with maintaining spent nuclear fuel on site until such time that it can be transferred to a DOE facility (See Note 22D). These estimates, in 2009 dollars, were $687 million for Unit No. 2 at Robinson, $591 million for Brunswick Unit No. 1, $585 million for Brunswick Unit No. 2 and $1.126 billion for Harris. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion

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attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in Brunswick and Harris. See Note 7D for information about the NRC operating licenses held by PEC. Based on updated cost estimates, in 2009 PEC reduced its asset retirement cost net of accumulated depreciation and its ARO liability by approximately $27 million and $390 million, respectively, resulting in no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant at December 31, 2009.

The FPSC requires that PEF update its cost estimate for nuclear decommissioning every five years. PEF received a new site-specific estimate of decommissioning costs for CR3 in October 2008, which PEF filed with the FPSC in 2009 as part of PEF’s base rate filing (See Note 7C). However, the FPSC deferred review of PEF’s nuclear decommissioning study from the rate case to be addressed in 2010 in order for FPSC staff to assess PEF’s study in combination with other utilities anticipated to submit nuclear decommissioning studies in 2010. PEF was not required to prepare a new site-specific nuclear decommissioning study in 2010; however, PEF was required to update the 2008 study with the most currently available escalation rates in 2010, which was filed with the FPSC in December 2010. PEF’s estimate is based on prompt dismantlement decommissioning and includes interim spent fuel storage costs associated with maintaining spent nuclear fuel on site until such time that it can be transferred to a DOE facility (See Note 22D). The estimate, in 2008 dollars, is $751 million and is subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimate excludes the portion attributable to other co-owners of CR3. See Note 7D for information about the NRC operating license held by PEF for CR3. Based on the 2008 estimate, assumed operating license renewal and updated escalation factors in 2010, PEF decreased its asset retirement cost to zero and its ARO liability by approximately $37 million in 2010. Retail accruals on PEF’s reserves for nuclear decommissioning were previously suspended under the terms of previous base rate settlement agreements. PEF expects to continue this suspension based on its 2010 nuclear decommissioning filing. In addition, the wholesale accrual on PEF’s reserves for nuclear decommissioning was suspended retroactive to January 2006, following a FERC accounting order issued in November 2006.

The FPSC requires that PEF update its cost estimate for fossil plant dismantlement every four years. PEF received an updated fossil dismantlement study estimate in 2008, which PEF filed with the FPSC in 2009 as part of PEF’s base rate filing. As a result of the base rate case, the FPSC approved an annual fossil dismantlement accrual of $4 million. PEF’s reserve for fossil plant dismantlement was approximately $144 million and $143 million at December 31, 2010 and 2009, including amounts in the ARO liability for asbestos abatement, discussed below.

PEC and PEF have recognized ARO liabilities related to asbestos abatement costs. The ARO liabilities related to asbestos abatement costs were $26 million and $27 million at December 31, 2010 and 2009, respectively, at PEC and $27 million at December 31, 2010 and 2009 at PEF.

Additionally, PEC and PEF have recognized ARO liabilities related to landfill capping costs. The ARO liabilities related to landfill capping costs were immaterial at December 31, 2010 and 2009, at PEC and $6 million at December 31, 2010 and 2009, at PEF.

We have identified but not recognized AROs related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by us. These easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the specified purpose. The ARO is not estimable for such easements, as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO would be recorded at that time.

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The following table presents the changes to the AROs during the years ended December 31. Revisions to prior estimates of the PEC and PEF regulated ARO are primarily related to the updated cost estimates for nuclear decommissioning and asbestos described above.


(in millions)	Progress Energy			PEC			PEF
Asset retirement obligations at January 1, 2009	$	1,471		$	1,122		$	349
Accretion expense		83			65			18
Revisions to prior estimates		(384	)		(386	)		2
Asset retirement obligations at December 31, 2009		1,170			801			369
Additions		4			4			-
Accretion expense		65			46			19
Revisions to prior estimates		(39	)		(2	)		(37	)
Asset retirement obligations at December 31, 2010	$	1,200		$	849		$	351

INSURANCE

The Utilities are members of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members’ nuclear generating facilities. Under the primary program, each company is insured for $500 million at each of its respective nuclear plants. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $1.750 billion on each nuclear plant.

Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL. Both PEC and PEF are insured under this program, following a 12-week deductible period, for 52 weeks in the amounts ranging from $3.5 million to $4.5 million per week. Additional weeks of coverage ranging from 71 weeks to 110 weeks are provided at 80 percent of the above weekly amounts. For the current policy period, the companies are subject to retrospective premium assessments of up to approximately $28 million with respect to the primary coverage, $41 million with respect to the decontamination, decommissioning and excess property coverage, and $25 million for the incremental replacement power costs coverage, in the event covered losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant, before any proceeds can be used for decommissioning, plant repair or restoration. Each company is responsible to the extent losses may exceed limits of the coverage described above. At December 31, 2010, PEF has an outstanding claim with NEIL (See Notes 5 and 7C).

Both of the Utilities are insured against public liability for a nuclear incident up to $12.595 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed for a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from each insured nuclear incident exceed the primary level of coverage provided by American Nuclear Insurers, each company would be subject to pro rata assessments of up to $117.5 million for each reactor owned for each incident. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $17.5 million per reactor owned per incident. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before August 29, 2013.

Under the NEIL policies, if there were multiple terrorism losses within one year, NEIL would make available one industry aggregate limit of $3.240 billion for noncertified acts, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.

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The Utilities self-insure their transmission and distribution lines against loss due to storm damage and other natural disasters. PEF maintains a storm damage reserve and has a regulatory mechanism to recover the costs of named storms on an expedited basis (See Note 7C).

For loss or damage to non-nuclear properties, excluding self-insured transmission and distribution lines, the Utilities are insured under an all-risk property insurance program with a total limit of $600 million per loss. The basic deductible is $2.5 million per loss, and there is no outage or replacement power coverage under this program.

5.	RECEIVABLES

Income taxes receivable and interest income receivables are not included in receivables. These amounts are included in prepayments and other current assets or shown separately on the Consolidated Balance Sheets. At December 31 receivables were comprised of:


	Progress Energy						PEC						PEF
(in millions)	2010			2009			2010			2009			2010			2009
Trade accounts receivable	$	651		$	581		$	346		$	291		$	303		$	288
Unbilled accounts receivable		223			193			136			125			87			68
Other receivables		75			44			47			34			12			10
NEIL receivable (See Notes 4 and 7)		119			-			-			-			119			-
Allowance for doubtful receivables		(35	)		(18	)		(10	)		(8	)		(25	)		(10	)
Total receivables, net	$	1,033		$	800		$	519		$	442		$	496		$	356

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INVENTORY

At December 31 inventory was comprised of:


	Progress Energy				PEC				PEF
(in millions)	2010		2009		2010		2009		2010		2009
Fuel for production	$	542	$	667	$	192	$	304	$	350	$	363
Materials and supplies		676		639		395		366		281		273
Emission allowances		8		18		3		6		5		12
Other		-		1		-		1		-		-
Total inventory	$	1,226	$	1,325	$	590	$	677	$	636	$	648

Materials and supplies amounts above exclude long-term combustion turbine inventory amounts included in other assets and deferred debits on the Consolidated Balance Sheets for Progress Energy of $24 million at December 31, 2009, which was transferred to PEC in 2010 and is included in construction work in progress on the Consolidated Balance Sheets for Progress Energy and PEC at December 31, 2010.

Emission allowances above exclude long-term emission allowances included in other assets and deferred debits on the Consolidated Balance Sheets for Progress Energy, PEC and PEF of $33 million, $5 million and $28 million, respectively, at December 31, 2010. Long-term emission allowances for Progress Energy, PEC and PEF were $39 million, $8 million and $31 million, respectively, at December 31, 2009.

7.	REGULATORY MATTERS

A.	REGULATORY ASSETS AND LIABILITIES

As regulated entities, the Utilities are subject to the provisions of GAAP for regulated operations. Accordingly, the Utilities record certain assets and liabilities resulting from the effects of the ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utilities’ ability to continue to meet the criteria for application of GAAP for regulated operations could be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that GAAP for regulated operations no longer applies to a separable portion of our operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism was provided. Additionally, such an event would require the Utilities to determine if any impairment to other assets, including utility plant, exists and write down impaired assets to their fair values.

Except for portions of deferred fuel costs and loss on reacquired debt, all regulatory assets earn a return or the cash has not yet been expended, in which case the assets are offset by liabilities that do not incur a carrying cost. We expect to fully recover our regulatory assets and refund our regulatory liabilities through customer rates under current regulatory practice.

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At December 31 the balances of regulatory assets (liabilities) were as follows:

PROGRESS ENERGY
(in millions)	2010			2009
Deferred fuel costs – current (Notes 7B and 7C)	$	169		$	105
Nuclear deferral (Notes 7C)		7			37
Total current regulatory assets		176			142
Deferred fuel cost – long-term		-			62
Nuclear deferral (Note 7C)(a)		178			239
Deferred impact of ARO (Note 4C)(b)		122			99
Income taxes recoverable through future rates(c)		302			264
Loss on reacquired debt(d)		31			35
Postretirement benefits (Note 16)(e)		1,105			945
Derivative mark-to-market adjustment (Note 17A)(f)		505			436
DSM / Energy-efficiency deferral (Note 7B)(g)		57			19
Other		74			80
Total long-term regulatory assets		2,374			2,179
Environmental (Note 7C)		(45	)		(24	)
Deferred energy conservation cost and other current regulatory liabilities		(14	)		(3	)
Total current regulatory liabilities		(59	)		(27	)
Non-ARO cost of removal (Note 4C)(b)		(1,857	)		(1,866	)
Deferred impact of ARO (Note 4C)(b)		(143	)		(150	)
Net nuclear decommissioning trust unrealized gains (Note 4C)(h)		(421	)		(295	)
Storm reserve (Note 7C)(i)		(136	)		(136	)
Other		(78	)		(63	)
Total long-term regulatory liabilities		(2,635	)		(2,510	)
Net regulatory liabilities	$	(144	)	$	(216	)

PEC
(in millions)	2010			2009
Deferred fuel costs – current (Notes 7B)	$	71		$	88
Deferred fuel cost – long-term		-			62
Deferred impact of ARO (Note 4C)(b)		112			92
Income taxes recoverable through future rates(c)		103			76
Loss on reacquired debt(d)		13			15
Postretirement benefits (Note 16)(e)		545			483
Derivative mark-to-market adjustment (Note 17A)(f)		121			88
DSM / Energy-efficiency deferral (Note 7B)(g)		57			19
Other		36			38
Total long-term regulatory assets		987			873
Non-ARO cost of removal (Note 4C)(b)		(1,172	)		(1,094	)
Net nuclear decommissioning trust unrealized gains (Note 4C)(h)		(267	)		(181	)
Other		(22	)		(18	)
Total long-term regulatory liabilities		(1,461	)		(1,293	)
Net regulatory liabilities	$	(403	)	$	(332	)

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PEF
(in millions)	2010			2009
Deferred fuel costs – current (Note 7C)	$	98		$	17
Nuclear deferral (Notes 7C)		7			37
Total current regulatory assets		105			54
Nuclear deferral (Note 7C)(a)		178			239
Income taxes recoverable through future rates(c)		199			188
Loss on reacquired debt(d)		18			20
Postretirement benefits (Note 16)(e)		560			462
Derivative mark-to-market adjustment (Note 17A)(f)		384			348
Other		48			50
Total long-term regulatory assets		1,387			1,307
Environmental (Note 7C)		(45	)		(24	)
Deferred energy conservation cost and other current regulatory liabilities		(14	)		(3	)
Total current regulatory liabilities		(59	)		(27	)
Non-ARO cost of removal (Note 4C)(b)		(685	)		(772	)
Deferred impact of ARO (Note 4C)(b)		(47	)		(30	)
Net nuclear decommissioning trust unrealized gains (Note 4C)(h)		(154	)		(114	)
Derivative mark-to-market adjustment (Note 17A)(f)		(13	)		(20	)
Storm reserve (Note 7C)(i)		(136	)		(136	)
Other		(49	)		(31	)
Total long-term regulatory liabilities		(1,084	)		(1,103	)
Net regulatory assets	$	349		$	231

The recovery and amortization periods for these regulatory assets and (liabilities) at December 31, 2010, are as follows:
(a)	Recorded and recovered or amortized as approved by the appropriate state utility commission over a period not exceeding five years.
(b)	Asset retirement and removal liabilities are recorded over the related property lives, which may range up to 65 years, and will be settled and adjusted following completion of the related activities.
(c)	Income taxes recoverable through future rates are recovered over the related property lives, which may range up to 65 years.
(d)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 30 years.
(e)	Recovered and amortized over the remaining service period of employees. In accordance with a 2009 FPSC order, PEF's 2009 deferred pension expense of $34 million will be amortized to the extent that annual pension expense is less than the $27 million allowance provided for in base rates (See Note 16).
(f)	Related to derivative unrealized gains and losses that are recorded as a regulatory liability or asset, respectively, until the contracts are settled. After contract settlement and consumption of the related fuel, the realized gains or losses are passed through the fuel cost-recovery clause.
(g)	Recorded and recovered or amortized as approved by the appropriate state utility commission over a period not exceeding 10 years.
(h)	Related to unrealized gains and losses on NDT funds that are recorded as a regulatory asset or liability, respectively, until the funds are used to decommission a nuclear plant.
(i)	Utilized as storm restoration expenses are incurred.

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B.	PEC RETAIL RATE MATTERS

BASE RATES

PEC’s base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC. In PEC’s most recent rate cases in 1988, the NCUC and the SCPSC each authorized a ROE of 12.75 percent.

COST RECOVERY FILINGS

On November 17, 2010, the NCUC approved three separate PEC cost-recovery filings, all of which were effective December 1, 2010. The NCUC approved PEC’s request for a $170 million decrease in the fuel rate charged to its North Carolina ratepayers, driven by declining fuel prices, which reduced residential electric bills by $5.60 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. The NCUC approved PEC’s request for a $31 million increase in the demand-side management (DSM) and EE rate charged to its North Carolina ratepayers, which increased the residential electric bills by $1.56 per 1,000 kWh for DSM and EE cost recovery. The NCUC approved PEC’s request for a $2 million decrease for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), which decreased the residential electric bills by $0.07 per 1,000 kWh. The net impact of the three filings results in an average reduction in residential electric bills of 3.9 percent. At December 31, 2010, PEC’s North Carolina deferred fuel and DSM / EE balances were $56 million and $49 million, respectively.

On June 23, 2010, the SCPSC approved PEC’s request for a $17 million decrease in the fuel rate charged to its South Carolina ratepayers, driven by declining fuel prices. The decrease was effective July 1, 2010, and decreased residential electric bills by $2.73 per 1,000 kWh for fuel cost recovery. PEC also filed with the SCPSC for an increase in the DSM and EE rate effective July 1, 2010, which was approved on a provisional basis on June 30, 2010, pending review by the South Carolina Office of Regulatory Staff. The net impact of the two filings resulted in an average reduction in residential electric bills of 1.7 percent. We cannot predict the outcome of this matter. At December 31, 2010, PEC’s South Carolina deferred fuel and DSM / EE balances were $15 million and $8 million, respectively.

OTHER MATTERS

On October 13, 2008, the NCUC issued a Certificate of Public Convenience and Necessity allowing PEC to proceed with plans to construct an approximately 600-MW combined cycle dual fuel-capable generating facility at its Richmond County generation site to provide additional generating and transmission capacity to meet the growing energy demands of southern and eastern North Carolina. PEC projects that the generating facility and related transmission will be in service by June 2011.

On October 22, 2009, the NCUC issued its order granting PEC a Certificate of Public Convenience and Necessity to construct an approximately 950-MW combined cycle natural gas-fueled electric generating facility at a site in Wayne County, N.C. PEC projects that the generating facility will be in service by January 2013.

On December 1, 2009, PEC filed with the NCUC a plan to retire no later than December 31, 2017, all of its coal-fired generating facilities in North Carolina that do not have scrubbers. These facilities total approximately 1,500 MW at four sites. On September 13, 2010, PEC filed its 15-year Integrated Resource Plan with the NCUC and SCPSC, which further accelerated the expected retirement schedule of the four coal-fired generating facilities to no later than December 31, 2014. The net carrying value of the four facilities at December 31, 2010, of $172 million is included in other utility plant, net on the Consolidated Balance Sheets. Consistent with ratemaking treatment, PEC will continue to depreciate these plants using the current depreciation lives and rates on file with the NCUC and the SCPSC until PEC completes and files a new depreciation study. The final recovery periods may change in connection with the regulators’ determination of the rate recovery of the remaining net carrying value.

On June 9, 2010, the NCUC issued its order granting PEC a Certificate of Public Convenience and Necessity to construct an approximately 620-MW combined cycle natural gas-fueled electric generating facility at a site in New Hanover County, N.C., to replace the existing coal-fired generation at this site. PEC projects that the generating facility will be in service in December 2013.

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The NCUC and the SCPSC approved proposals to accelerate cost recovery of PEC’s nuclear generating assets beginning January 1, 2000, through 2009. The North Carolina aggregate minimum and maximum amounts of cost recovery were $415 million and $585 million, respectively, with flexibility in the amount of annual depreciation recorded, from none to $150 million per year. Accelerated cost recovery of these assets resulted in additional depreciation expense of $52 million for the year ended December 31, 2008. PEC reached the minimum amount of $415 million of cost recovery by December 31, 2008, and no additional depreciation expense from accelerated cost recovery was subsequently recorded. As a result of the SCPSC’s approval of a 2008 PEC petition, PEC will not be required to recognize the remaining $38 million of accelerated depreciation required to reach the minimum $115 million of cost recovery for the South Carolina jurisdiction, but will record depreciation over the useful lives of the assets. No additional depreciation expense from accelerated cost recovery for the South Carolina jurisdiction was recorded in 2008 or subsequent to the approval.

C.	PEF RETAIL RATE MATTERS

BASE RATES

On June 1, 2010, the FPSC approved a settlement agreement between PEF and the interveners, with the exception of the Florida Association for Fairness in Ratemaking, to the 2009 rate case. As part of the settlement, PEF withdrew its motion for reconsideration of the rate case order. Among other provisions, under the terms of the settlement agreement, PEF will maintain base rates at current levels through the last billing cycle of 2012. The settlement agreement also provides that PEF will have the discretion to reduce amortization expense (cost of removal component) by up to $150 million in 2010, up to $250 million in 2011, and up to any remaining balance in the cost of removal reserve in 2012 until the earlier of (a) PEF’s applicable cost of removal reserve reaches zero, or (b) the expiration of the settlement agreement at the end of 2012. In the event PEF reduces amortization expense by less than the annual amounts for 2010 or 2011, PEF may carry forward (i.e., increase the annual cap by) any unused cost of removal reserve amounts in subsequent years during the term of the agreement. The balance of the cost of removal reserve is impacted by accruals in accordance with PEF’s latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreement. For the year ended December 31, 2010, PEF recognized a $60 million reduction in amortization expense pursuant to the settlement agreement. PEF’s applicable cost of removal reserve of $461 million is recorded as a regulatory liability on its December 31, 2010 Balance Sheet. The settlement agreement also provides PEF with the opportunity to earn a ROE of up to 11.5 percent and provides that if PEF’s actual retail base rate earnings fall below a 9.5 percent ROE on an adjusted or pro forma basis, as reported on a historical 12-month basis during the term of the agreement, PEF may seek general, limited or interim base rate relief, or any combination thereof. Prior to requesting any such relief, PEF must have reflected on its referenced surveillance report associated amortization expense reductions of at least $150 million. The settlement agreement does not preclude PEF from requesting the FPSC to approve the recovery of costs (a) that are of a type which traditionally and historically would be, have been or are presently recovered through cost-recovery clauses or surcharges; or (b) that are incremental costs not currently recovered in base rates, which the legislature or FPSC determines are clause recoverable; or (c) which are recoverable through base rates under the nuclear cost-recovery legislation or the FPSC’s nuclear cost-recovery rule. PEF also may, at its discretion, accelerate in whole or in part the amortization of certain regulatory assets over the term of the settlement agreement. Finally, PEF will be allowed to recover the costs of named storms on an expedited basis after depletion of the storm damage reserve. Specifically, 60 days following the filing of a cost-recovery petition with the FPSC and based on a 12-month recovery period, PEF can begin recovery, subject to refund, through a surcharge of up to $4.00 per 1,000 kWh on monthly residential customer bills for storm costs. In the event the storm costs exceed that level, any excess additional costs will be deferred and recovered in a subsequent year or years as determined by the FPSC. Additionally, the order approving the settlement agreement allows PEF to use the surcharge to replenish the storm damage reserve to $136 million, the level as of June 1, 2010, after storm costs are fully recovered. At December 31, 2010, PEF’s storm damage reserve was $136 million, the amount permitted by the settlement agreement.

On September 14, 2010, the FPSC approved a reduction to PEF’s AFUDC rate, from 8.848 percent to 7.44 percent. This new rate is based on PEF’s updated authorized ROE and all adjustments approved on January 11, 2010, in PEF’s base rate case and will be used for all purposes except for nuclear recoveries with original need petitions submitted on or before December 31, 2010, as permitted by FPSC regulations.

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FUEL COST RECOVERY

On November 1, 2010, PEF filed a request with the FPSC to seek approval to decrease the total fuel-cost recovery by $205 million, reducing the residential rate by $6.64 per 1,000 kWh, or 5.2 percent effective January 1, 2011. This decrease is due to decreases of $5.14 per 1,000 kWh for the projected recovery through the Capacity Cost-Recovery Clause (CCRC) and of $1.50 per 1,000 kWh for the projected recovery of fuel costs. The decrease in the CCRC is primarily due to the refund of a prior period over-recovery as a result of higher than expected sales in 2010 and lower anticipated costs associated with PEF’s proposed Levy Units No. 1 and No. 2 Nuclear Power Plants (Levy) in 2011 (See “Levy Nuclear”). The decrease in the projected recovery of fuel costs is due to an expectation of lower 2011 fuel costs and the continued recovery of incremental CR3 replacement power costs through insurance, partially offset by an under-recovery of 2010 fuel costs. On November 2, 2010 and November 30, 2010, the FPSC approved PEF’s CCRC residential rate and fuel rate, respectively. Within the fuel clause, PEF received approval to collect, subject to refund, replacement power costs related to the CR3 nuclear plant outage (See “CR3 Outage”). At December 31, 2010, PEF’s under-recovered deferred fuel balance was $98 million.

On October 25, 2010, the FPSC approved PEF’s motion to establish a separate spin-off docket related to the outage and replacement fuel and power costs associated with the CR3 extended outage (See “CR3 Outage”). This docket will allow the FPSC to evaluate PEF’s actions concerning the concrete delamination and review PEF’s resulting costs associated with the CR3 extended outage. PEF intends to file a petition within 60 days following CR3’s return to service; however, the FPSC has not yet established a case schedule. A hearing is expected later in 2011. We cannot predict the outcome of this matter.

NUCLEAR COST RECOVERY

Levy Nuclear

In 2008, the FPSC granted PEF’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. Levy is needed to maintain electric system reliability and integrity, provide fuel and generating diversity, and allow PEF to continue to provide adequate electricity to its customers at a reasonable cost. The proposed Levy units will be advanced passive light water nuclear reactors, each with a generating capacity of approximately 1,100 MW. The petition included projections that Levy Unit No. 1 would be placed in service by June 2016 and Levy Unit No. 2 by June 2017. The filed, nonbinding project cost estimate for Levy Units No. 1 and No. 2 was approximately $14 billion for generating facilities and approximately $3 billion for associated transmission facilities.

In PEF’s 2010 nuclear cost-recovery filing (See “Cost Recovery”), PEF identified a schedule shift in the Levy project that resulted from the NRC’s 2009 determination that certain schedule-critical work that PEF had proposed to perform within the scope of its Limited Work Authorization request submitted with the combined license (COL) application will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work anticipated in the initial schedule cannot begin until the COL is issued, resulting in a project shift of at least 20 months. Since then, regulatory and economic conditions identified in the 2010 nuclear cost-recovery filing have changed such that major construction activities on the Levy project are being postponed until after the NRC issues the COL, expected in 2013 if the current licensing schedule remains on track. Taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification, we consider Levy to be PEF’s preferred baseload generation option. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility, including comparison to other generation options; DSM and EE programs; and availability and terms of capital financing.

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Crystal River Unit No. 3 Nuclear Plant Uprate

In 2007, the FPSC issued an order approving PEF’s Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3’s gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. PEF will apply for the required license amendment for the third-stage design modification.

Cost Recovery

In 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million through the CCRC, which primarily consisted of preconstruction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to help mitigate the initial price impact on its customers, as part of its filing, PEF proposed collecting certain costs over a five-year period, with associated carrying costs on the unrecovered balance. The FPSC approved the alternate proposal allowing PEF to recover revenue requirements associated with the nuclear cost-recovery clause through the CCRC beginning with the first billing cycle of January 2010. The remainder, with minor adjustments, will also be recovered through the CCRC. In adopting PEF’s proposed rate management plan for 2010, the FPSC permitted PEF to annually reconsider changes to the recovery of deferred amounts to afford greater flexibility to manage future rate impacts. The rate management plan included the 2009 reclassification to the nuclear cost-recovery clause regulatory asset of $198 million of capacity revenues and the accelerated amortization of $76 million of preconstruction costs. The cumulative amount of $274 million was recorded as a nuclear cost-recovery regulatory asset at December 31, 2009, and is projected to be recovered by 2014. At December 31, 2010, PEF’s nuclear cost-recovery regulatory asset was $7 million and $178 milliion, classified as current and noncurrent, respectively.

On October 26, 2010, the FPSC approved PEF’s annual nuclear cost-recovery filing to recover $164 million, which includes recovery of preconstruction, carrying and CCRC-recoverable operations and maintenance (O&M) costs incurred or anticipated to be incurred during 2011, recovery of $60 million of the 2009 deferral in 2011, as well as the estimated true-up of 2010 costs associated with the Levy and CR3 uprate projects. This resulted in a decrease in the nuclear cost-recovery charge of $1.46 per 1,000 kWh for residential customers, beginning with the first January 2011 billing cycle. The FPSC determined the costs associated with Levy were prudent and deferred a determination concerning the prudence of the 2009 CR3 uprate costs until the 2011 nuclear cost-recovery proceeding. The final order was issued on February 2, 2011.

CR3 OUTAGE

In September 2009, CR3 began an outage for normal refueling and maintenance as well as its uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination within the concrete of the outer wall of the containment structure, which has resulted in an extension of the outage. After a comprehensive analysis, we have determined that the concrete delamination at CR3 was caused by redistribution of stresses on the containment wall that occurred when we created an opening to accommodate the replacement of the unit’s steam generators. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. A number of factors affect the return to service date, including regulatory reviews by the NRC and other agencies, emergent work, final engineering designs, testing, weather and other developments.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL as discussed in Note 4D. PEF also maintains insurance coverage through an accidental property damage program, which provides insurance coverage with a $10 million deductible per claim. PEF notified NEIL of the claim related to the CR3 delamination event on October 15, 2009. NEIL has confirmed that the CR3 delamination event is a covered accident. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs.

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The following table summarizes the CR3 replacement power and repair costs and recovery through December 31, 2010:

(in millions)	Replacement power costs			Repair costs
Spent to date	$	288		$	150
NEIL proceeds received		(117	)		(64	)
Insurance receivable at December 31, 2010		(54	)		(47	)
Balance for recovery	$	117		$	39

We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT COST RECOVERY

On December 30, 2009, the FPSC ordered PEF and other Florida utilities to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. As subsequently revised by the FPSC, PEF’s aggregate conservation goals over the next 10 years were: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). On March 30, 2010, PEF filed a petition for approval of its proposed DSM plan and to authorize cost recovery through the Energy Conservation Cost Recovery Clause (ECCR). On September 14, 2010, the FPSC held an agenda conference to approve PEF’s petition for the DSM plan. The FPSC ruled that while PEF’s proposed DSM plan met the cumulative, 10-year DSM goals set by the FPSC, the plan did not meet the annual DSM goals. On October 4, 2010, the FPSC denied PEF’s petition for the DSM plan, approved PEF’s solar pilot programs, and required PEF to file a revised proposed DSM plan that meets the annual goals set by the FPSC. PEF filed a revised proposed DSM plan on November 29, 2010. An agenda conference has been scheduled by the FPSC for April 5, 2011. We cannot predict the outcome of this matter.

On November 1, 2010, the FPSC approved PEF’s request to increase the ECCR residential rate by $0.29 per 1,000 kWh, or 0.2 percent of the total residential rate, effective January 1, 2011. The increase in the ECCR is primarily due to an increase in conservation program costs, including the costs associated with PEF’s solar pilot, partially offset by a refund of a prior period over-recovery as a result of higher than expected sales in 2010.

OTHER MATTERS

On November 1, 2010, the FPSC approved PEF’s request to decrease the Environmental Cost Recovery Clause (ECRC) by $37 million, reducing the residential rate by $1.02 per 1,000 kWh, or 0.8 percent, effective January 1, 2011. The decrease in the ECRC is primarily due to the 2010 base rate decision, which reduced the clean air project depreciation and return rates, and the refund of a prior period over-recovery as a result of higher than expected sales in 2010. At December 31, 2010, PEF’s over-recovered deferred ECRC was $45 million.

On March 20, 2009, PEF filed a petition with the FPSC for expedited approval of the deferral of $53 million in 2009 pension expense. PEF requested that the deferral of pension expense continue until the recovery of these costs is provided for in FPSC-approved base rates. On June 16, 2009, the FPSC approved the deferral of the retail portion of actual 2009 pension expense. As a result of the order, PEF deferred pension expense of $34 million for the year ended December 31, 2009. PEF will not earn a carrying charge on the deferred pension regulatory asset. The deferral of pension expense did not result in a change in PEF’s 2009 retail rates or prices. In accordance with the order, subsequent to 2009 PEF will amortize the deferred pension regulatory asset to the extent that annual pension expense is less than the $27 million allowance provided for in the base rates established in the 2010 base rate proceeding. In the event such amortization is insufficient to fully amortize the regulatory asset, PEF can seek

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recovery of the remaining unamortized amount in a base rate proceeding no earlier than 2015. As of December 31, 2010, PEF has not recorded any amortization related to the deferred pension regulatory asset.

D.	NUCLEAR LICENSE RENEWALS

PEC’s nuclear units are currently operating under licenses that expire between 2030 and 2046. The NRC operating license held by PEF for CR3 currently expires in December 2016. On December 18, 2008, PEF filed an application for a 20-year renewal from the NRC on the operating license for CR3, which would extend the operating license through 2036, if approved. PEF anticipates a decision from the NRC in 2011.

GOODWILL

Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility reporting units and our goodwill impairment tests are performed at the utility reporting unit level. At December 31, 2010 and 2009, our carrying amount of goodwill was $3.655 billion, with $1.922 billion assigned to PEC and $1.733 billion assigned to PEF. The amounts assigned to PEC and PEF are recorded in our Corporate and Other business segment. As discussed in Note 1D, during 2010 we changed the annual testing date for our annual goodwill impairment tests from April 1 to October 31 of each year. As a result, we performed goodwill impairment tests as of April 1, 2010 and October 31, 2010, and concluded there was no impairment of the carrying value of the goodwill.

EQUITY

A.	COMMON STOCK

PROGRESS ENERGY

At December 31, 2010 and December 31, 2009, we had 500 million shares of common stock authorized under our charter, of which 293 million and 281 million shares were outstanding, respectively. We periodically issue shares of common stock through the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)), the Progress Energy Investor Plus Plan (IPP) and other benefit plans.

There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2010, there were no significant restrictions on the use of retained earnings (See Note 11B and Note 25).

The following table presents information for our common stock issuances for the years ended December 31:


	2010				2009				2008
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		12.2	$	434		17.5	$	623		3.7	$	132
Issuances under an underwritten public offering(a)		-		-		14.4		523		-		-
Issuances through 401(k) and/or IPP		11.2		431		2.5		100		3.1		131

(a)

The shares issued under an underwritten public offering were issued on January 12, 2009, at a public offering price of $37.50.

PEC

At December 31, 2010 and December 31, 2009, PEC was authorized to issue up to 200 million shares of common stock. All shares issued and outstanding are held by Progress Energy. There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2010, there were

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no significant restrictions on the use of retained earnings. See Note 11B for additional dividend restrictions related to PEC.

PEF

At December 31, 2010 and December 31, 2009, PEF was authorized to issue up to 60 million shares of common stock. All PEF common shares issued and outstanding are indirectly held by Progress Energy. There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2010, there were no significant restrictions on the use of retained earnings. See Note 11B for additional dividend restrictions related to PEF.

B.	STOCK-BASED COMPENSATION

EMPLOYEE STOCK OWNERSHIP PLAN

We sponsor the 401(k) for which substantially all full-time nonbargaining unit employees and certain part-time nonbargaining unit employees within participating subsidiaries are eligible. The 401(k), which has a matching feature, encourages systematic savings by employees and provides a method of acquiring Progress Energy common stock and other diverse investments. The 401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire Progress Energy common stock to satisfy 401(k) common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the 401(k). Common stock acquired with the proceeds of an ESOP loan was held by the 401(k) Trustee in a suspense account. The common stock was released from the suspense account and made available for allocation to participants as the ESOP loan was repaid. Such allocations are used to partially meet common stock needs related to matching and incentive contributions and/or reinvested dividends. All or a portion of the dividends paid on ESOP suspense shares and on ESOP shares allocated to participants may be used to repay ESOP acquisition loans. Dividends that are used to repay such loans, paid directly to participants or reinvested by participants, are deductible for income tax purposes. At December 31, 2010, no ESOP suspense shares were outstanding and the ESOP acquisition loan was repaid.

There were 0.5 million ESOP suspense shares at December 31, 2009 with a fair value of $22 million. ESOP shares allocated to plan participants totaled 13.4 million and 13.0 million at December 31, 2010 and 2009, respectively. Our matching compensation cost under the 401(k) is determined based on matching percentages as defined in the plan. Through December 31, 2010, such compensation cost was allocated to participants’ accounts in the form of Progress Energy common stock, with the number of shares determined by dividing compensation cost by the common stock market value at the time of allocation. In 2010, we met common stock share needs with open market purchases and with shares released from the ESOP suspense account. Matching costs met with shares released from the suspense account totaled approximately $12 million, $12 million and $8 million for the years ended December 31, 2010, 2009 and 2008, respectively. At December 31, 2009, we had a long-term note receivable from the 401(k) Trustee related to the purchase of common stock from us in 1989. The balance of the note receivable from the 401(k) Trustee was included in the determination of unearned ESOP common stock, which reduces common stock equity.

We also sponsor the Savings Plan for Employees of Florida Progress Corporation, which is an ESOP plan that covers bargaining unit employees of PEF.

Total matching cost for both plans was approximately $43 million, $41 million and $38 million for the years ended December 31, 2010, 2009 and 2008, respectively.

PEC

PEC’s matching costs met with shares released from the ESOP suspense account totaled approximately $8 million, $8 million and $6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Total matching cost was approximately $23 million, $22 million and $21 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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PEF

PEF’s matching costs met with shares released from the ESOP suspense account totaled approximately $3 million, $4 million and $2 million for the years ended December 31, 2010, 2009 and 2008, respectively. Total matching cost for both plans was approximately $14 million, $12 million and $11 million for the years ended December 31, 2010, 2009 and 2008, respectively.

OTHER STOCK-BASED COMPENSATION PLANS

We have additional compensation plans for our officers and key employees that are stock-based in whole or in part. Our long-term compensation program currently includes two types of equity-based incentives: performance shares under the Performance Share Sub-Plan (PSSP) and restricted stock programs. The compensation program was established pursuant to our 1997 Equity Incentive Plan (EIP) and was continued under our 2002 and 2007 EIPs, as amended and restated from time to time. As authorized by the EIPs, we may grant up to 20 million shares of Progress Energy common stock through our long-term compensation program.

In 2008, shares issued under the PSSP used only one performance measure. In 2009, the PSSP was redesigned. For 2009 and 2010, shares issued under the revised plan use total shareholder return and earnings growth as two equally weighted performance measures. The outcome of the performance measures can result in an increase or decrease from the target number of performance shares granted. We distribute common stock shares to participants equivalent to the number of performance shares that ultimately vest. Through December 31, 2010, we issued new shares of common stock to satisfy the requirements of the PSSP program. Also, the fair value of the stock-settled award is generally established at the grant date based on the fair value of common stock on that date, with subsequent adjustments made to reflect the status of the performance measure. Compensation expense for all awards is reduced by estimated forfeitures. At December 31, 2010, there were an immaterial number of stock-settled performance target shares outstanding. The final number of shares issued will be dependent upon the outcome of the performance measures discussed above.

Beginning in 2007, we began issuing restricted stock units (RSUs) rather than the previously issued restricted stock awards for our officers, vice presidents, managers and key employees. RSUs awarded to eligible employees are generally subject to either three- or five-year cliff vesting or three- or five-year graded vesting. Through December 31, 2010, we issued new shares of common stock to satisfy the requirements of the RSU program. Compensation expense, based on the fair value of common stock at the grant date, is recognized over the applicable vesting period, with corresponding increases in common stock equity. RSUs are included as shares outstanding in the basic earnings per share calculation and are converted to shares upon vesting. At December 31, 2010, there were an immaterial number of RSUs outstanding.

The total fair value of RSUs vested during the years ended December 31, 2010, 2009 and 2008, was $24 million, $16 million and $9 million, respectively. No cash was expended to purchase stock to satisfy RSU plan obligations in 2010, 2009 and 2008. The RSUs vested during 2010 had a weighted-average grant date fair value of $43.58.

Our Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $27 million for the year ended December 31, 2010, with a recognized tax benefit of $11 million. The total expense recognized on our Consolidated Statements of Income for other stock-based compensation plans was $37 million, with a recognized tax benefit of $14 million, and $34 million, with a recognized tax benefit of $13 million, for the years ended December 31, 2009 and 2008, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

At December 31, 2010, unrecognized compensation cost related to nonvested other stock-based compensation plan awards totaled $25 million, which is expected to be recognized over a weighted-average period of 1.6 years.

PEC

PEC’s Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $16 million for the year ended December 31, 2010, with a recognized tax benefit of $6 million. The total expense recognized on PEC’s Consolidated Statements of Income for other stock-based compensation plans was $22 million, with a recognized tax benefit of $9 million, and $20 million, with a recognized tax benefit of $8

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million, for the years ended December 31, 2009 and 2008, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

PEF

PEF’s Statements of Income included total recognized expense for other stock-based compensation plans of $11 million for the year ended December 31, 2010, with a recognized tax benefit of $4 million. The total expense recognized on PEF’s Statements of Income for other stock-based compensation plans was $14 million, with a recognized tax benefit of $5 million, and $14 million, with a recognized tax benefit of $5 million, for the years ended December 31, 2009 and 2008, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

C.	EARNINGS PER COMMON SHARE

Basic earnings per common share are based on the weighted-average number of common shares outstanding, which includes the effects of unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents. Diluted earnings per share include the effects of the nonvested portion of performance share awards and the effect of stock options outstanding.

A reconciliation of the weighted-average number of common shares outstanding for the years ended December 31 for basic and dilutive purposes follows:

(in millions)	2010		2009		2008
Weighted-average common shares – basic		290.7		279.4		261.6
Net effect of dilutive stock-based compensation plans		0.1		0.1		0.1
Weighted-average shares – fully diluted		290.8		279.5		261.7

There were no adjustments to net income or to income from continuing operations attributable to controlling interests between the calculations of basic and fully diluted earnings per common share. There were 0.8 million, 1.5 million and 1.6 million stock options outstanding at December 31, 2010, 2009 and 2008, respectively, which were not included in the weighted-average number of shares for computing the fully diluted earnings per share because they were antidilutive.

D.	ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME

Components of accumulated other comprehensive (loss) income, net of tax, at December 31 were as follows:


	Progress Energy						PEC						PEF
(in millions)	2010			2009			2010			2009			2010			2009
Cash flow hedges	$	(63	)	$	(35	)	$	(33	)	$	(27	)	$	(4	)	$	3
Pension and other postretirement benefits		(62	)		(52	)		-			-			-			-
Total accumulated other comprehensive (loss) income	$	(125	)	$	(87	)	$	(33	)	$	(27	)	$	(4	)	$	3

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10.	PREFERRED STOCK OF SUBSIDIARIES

All of our preferred stock was issued by the Utilities. The preferred stock is considered temporary equity due to certain provisions that could require us to redeem the preferred stock for cash. In the event dividends payable on PEC or PEF preferred stock are in default for an amount equivalent to or exceeding four quarterly dividend payments, the holders of the preferred stock are entitled to elect a majority of PEC or PEF’s respective board of directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities’ respective board of directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share plus any accumulated unpaid dividends except for PEF’s 4.75%, $100 par value class, which does not have a liquidation preference. Each holder of PEC’s preferred stock is entitled to one vote. The holders of PEF’s preferred stock have no right to vote except for certain circumstances involving dividends payable on preferred stock that are in default or certain matters affecting the rights and preferences of the preferred stock.

At December 31, 2010 and 2009, preferred stock outstanding consisted of the following:

	Shares
(dollars in millions, except share and per share data)	Authorized		Outstanding		Redemption Price		Total

PEC
Cumulative, no par value $5 Preferred Stock		300,000		236,997	$	110.00	$	24
Cumulative, no par value Serial Preferred Stock		20,000,000
$4.20 Serial Preferred				100,000		102.00		10
$5.44 Serial Preferred				249,850		101.00		25
Cumulative, no par value Preferred Stock A		5,000,000		-		-		-
No par value Preference Stock		10,000,000		-		-		-
Total PEC								59

PEF
Cumulative, $100 par value Preferred Stock		4,000,000
4.00% $100 par value Preferred				39,980		104.25		4
4.40% $100 par value Preferred				75,000		102.00		8
4.58% $100 par value Preferred				99,990		101.00		10
4.60% $100 par value Preferred				39,997		103.25		4
4.75% $100 par value Preferred				80,000		102.00		8
Cumulative, no par value Preferred Stock		5,000,000		-		-		-
$100 par value Preference Stock		1,000,000		-		-		-
Total PEF								34
Total preferred stock of subsidiaries							$	93

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11.	DEBT AND CREDIT FACILITIES

A.	DEBT AND CREDIT FACILITIES

At December 31 our long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2010):

(in millions)			2010			2009
Parent
Senior unsecured notes, maturing 2011-2039	6.64	%	$	4,200		$	4,300
Unamortized premium and discount, net				(6	)		(7	)
Current portion of long-term debt				(205	)		(100	)
Long-term debt, net				3,989			4,193

PEC
First mortgage bonds, maturing 2011-2038	5.60	%		2,525			2,525
Pollution control obligations, maturing 2017-2024	0.89	%		669			669
Senior unsecured notes, maturing 2012	6.50	%		500			500
Miscellaneous notes	6.00	%		5			21
Unamortized premium and discount, net				(6	)		(6	)
Current portion of long-term debt				-			(6	)
Long-term debt, net				3,693			3,703

PEF
First mortgage bonds, maturing 2011-2040	5.82	%		4,100			3,800
Pollution control obligations, maturing 2018-2027	0.52	%		241			241
Medium-term notes, maturing 2028	6.75	%		150			150
Unamortized premium and discount, net				(9	)		(8	)
Current portion of long-term debt				(300	)		(300	)
Long-term debt, net				4,182			3,883
Progress Energy consolidated long-term debt, net			$	11,864		$	11,779

Florida Progress Funding Corporation (See Note 23)
Debt to affiliated trust, maturing 2039	7.10	%	$	309		$	309
Unamortized premium and discount, net				(36	)		(37	)
Long-term debt, affiliate			$	273		$	272

On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due 2021. We expect to use net proceeds of $495 million, along with available cash on hand, to retire at maturity the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011. Accordingly, we classified $495 million of the Parent’s $700 million 7.10% Senior Notes due March 1, 2011 as long-term debt at December 31, 2010.

On January 15, 2010, the Parent paid at maturity $100 million of its Series A Floating Rate Notes with a portion of the proceeds from the $950 million of Senior Notes issued in November 2009.

At December 31, 2010 and 2009, we had committed lines of credit used to support our commercial paper and other short-term borrowings. At December 31, 2010 and December 31, 2009, we had no outstanding borrowings under our revolving credit agreements (RCAs). We are required to pay fees to maintain our credit facilities.

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The following tables summarize our RCAs and available capacity at December 31:


(in millions)		Total		Outstanding		Reserved(a)		Available
2010
Parent	Five-year (expiring 5/3/12)(b)	$	500	$	-	$	31	$	469
PEC	Three-year (expiring 10/15/13)		750		-		-		750
PEF	Three-year (expiring 10/15/13)		750		-		-		750
Total credit facilities		$	2,000	$	-	$	31	$	1,969

2009
Parent	Five-year (expiring 5/3/12)	$	1,130	$	-	$	177	$	953
PEC	Five-year (expiring 6/28/11)		450		-		-		450
PEF	Five-year (expiring 3/28/11)		450		-		-		450
Total credit facilities		$	2,030	$	-	$	177	$	1,853

(a)

(b)

Approximately $22 million of the $500 million will expire May 3, 2011.

On October 15, 2010, PEC and PEF each entered into new $750 million, three-year RCAs with a syndication of 22 financial institutions. The RCAs are used to provide liquidity support for PEC’s and PEF’s issuances of commercial paper and other short-term obligations, and for general corporate purposes. The RCAs will expire on October 15, 2013. The new $750 million RCAs replaced PEC’s and PEF’s $450 million RCAs, which were set to expire on June 28, 2011 and March 28, 2011, respectively. Both $450 million RCAs were terminated effective October 15, 2010. Fees and interest rates under the new RCAs are to be determined based upon the respective credit ratings of PEC’s and PEF’s long-term unsecured senior noncredit-enhanced debt, as rated by Moody’s Investor Services, Inc. (Moody’s) and Standard and Poor’s Rating Services (S&P). The RCAs do not include material adverse change representations for borrowings or financial covenants for interest coverage. See “Covenants and Default Provisions” for additional provisions related to the RCAs.

Also on October 15, 2010, the Parent ratably reduced the size of its $1.130 billion credit facility to $500 million with the existing group of 15 financial institutions. As a result of the changes made on October 15, 2010, our combined credit commitments total $2.000 billion, supported by 24 financial institutions.

The following table summarizes short-term debt comprised of outstanding commercial paper, and related weighted-average interest rates at December 31:


(in millions)	2010				2009
Parent	-	%	$	-	0.49	%	$	140
PEC	-			-	-			-
PEF	-			-	-			-
Total	-	%	$	-	0.49	%	$	140

Long-term debt maturities during the next five years are as follows:


(in millions)	Progress Energy Consolidated		PEC		PEF
2011	$	1,000	$	-	$	300
2012		950		500		-
2013		830		405		425
2014		300		-		-
2015		1,000		700		300

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B.	COVENANTS AND DEFAULT PROVISIONS

FINANCIAL COVENANTS

The Parent’s, PEC’s and PEF’s credit lines contain various terms and conditions that could affect the ability to borrow under these facilities. All of the credit facilities include a defined maximum total debt to total capital ratio (leverage). At December 31, 2010, the maximum and calculated ratios for the Progress Registrants, pursuant to the terms of the agreements, were as follows:

Company	Maximum Ratio			Actual Ratio(a)
Parent		68	%		56	%
PEC		65	%		42	%
PEF		65	%		49	%

(a)

Indebtedness as defined by the credit agreement includes certain letters of credit and guarantees not recorded on the Consolidated Balance Sheets.

CROSS-DEFAULT PROVISIONS

Each of these credit agreements contains cross-default provisions for defaults of indebtedness in excess of the following thresholds: $50 million for the Parent and $35 million each for PEC and PEF. Under these provisions, if the applicable borrower or certain subsidiaries of the borrower fail to pay various debt obligations in excess of their respective cross-default threshold, the lenders of that credit facility could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility. The Parent’s cross-default provision can be triggered by the Parent and its significant subsidiaries, as defined in the credit agreement. PEC’s and PEF’s cross-default provisions can be triggered only by defaults of indebtedness by PEC and its subsidiaries and PEF, respectively, not by each other or by other affiliates of PEC and PEF.

Additionally, certain of the Parent’s long-term debt indentures contain cross-default provisions for defaults of indebtedness in excess of amounts ranging from $25 million to $50 million; these provisions apply only to other obligations of the Parent, primarily commercial paper issued by the Parent, not its subsidiaries. In the event that these indenture cross-default provisions are triggered, the debt holders could accelerate payment of long-term debt. Following payment of the Parent’s $700 million March 1, 2011 maturity, $4.000 billion in long-term debt could be subject to acceleration provisions. Certain agreements underlying our indebtedness also limit our ability to incur additional liens or engage in certain types of sale and leaseback transactions.

OTHER RESTRICTIONS

Neither the Parent’s Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends, so long as no shares of preferred stock are outstanding. At December 31, 2010, the Parent had no shares of preferred stock outstanding. See Note 25 for information regarding restrictions on dividends relative to the Progress Energy and Duke Energy Agreement and Plan of Merger.

Certain documents restrict the payment of dividends by the Parent’s subsidiaries as outlined below.

PEC

PEC’s mortgage indenture provides that as long as any first mortgage bonds are outstanding, cash dividends and distributions on its common stock and purchases of its common stock are restricted to aggregate net income available for PEC since December 31, 1948, plus $3 million, less the amount of all preferred stock dividends and distributions, and all common stock purchases, since December 31, 1948. At December 31, 2010, none of PEC’s cash dividends or distributions on common stock was restricted.

In addition, PEC’s Articles of Incorporation provide that so long as any shares of preferred stock are outstanding, the aggregate amount of cash dividends or distributions on common stock since December 31, 1945, including the amount then proposed to be expended, shall be limited to 75 percent of the aggregate net income available for common stock if common stock equity falls below 25 percent of total capitalization, and to 50 percent if common

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stock equity falls below 20 percent. PEC’s Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75 percent of the current year’s net income available for dividends if common stock equity falls below 25 percent of total capitalization, and to 50 percent if common stock equity falls below 20 percent. At December 31, 2010, PEC’s common stock equity was approximately 58.0 percent of total capitalization. At December 31, 2010, none of PEC’s cash dividends or distributions on common stock was restricted.

PEF

PEF’s mortgage indenture provides that as long as any first mortgage bonds are outstanding, it will not pay any cash dividends upon its common stock, or make any other distribution to the stockholders, except a payment or distribution out of net income of PEF subsequent to December 31, 1943. At December 31, 2010, none of PEF’s cash dividends or distributions on common stock was restricted.

In addition, PEF’s Articles of Incorporation provide that so long as any shares of preferred stock are outstanding, no cash dividends or distributions on common stock shall be paid, if the aggregate amount thereof since April 30, 1944, including the amount then proposed to be expended, plus all other charges to retained earnings since April 30, 1944, exceeds all credits to retained earnings since April 30, 1944, plus all amounts credited to capital surplus after April 30, 1944, arising from the donation to PEF of cash or securities or transfers of amounts from retained earnings to capital surplus. PEF’s Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75 percent of the current year’s net income available for dividends if common stock equity falls below 25 percent of total capitalization, and to 50 percent if common stock equity falls below 20 percent. On December 31, 2010, PEF’s common stock equity was approximately 53.7 percent of total capitalization. At December 31, 2010, none of PEF’s cash dividends or distributions on common stock was restricted.

C.	COLLATERALIZED OBLIGATIONS

PEC’s and PEF’s first mortgage bonds are collateralized by 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. Each mortgage also constitutes a lien on subsequently acquired property. At December 31, 2010, PEC and PEF had a total of $3.194 billion and $4.341 billion, respectively, of first mortgage bonds outstanding, including those related to pollution control obligations. Each mortgage allows the issuance of additional mortgage bonds upon the satisfaction of certain conditions.

D.	GUARANTEES OF SUBSIDIARY DEBT

See Note 18 on related party transactions for a discussion of obligations guaranteed or secured by affiliates.

E.	HEDGING ACTIVITIES

We use interest rate derivatives to adjust the fixed and variable rate components of our debt portfolio and to hedge cash flow risk related to commercial paper and fixed-rate debt to be issued in the future. See Note 17 for a discussion of risk management activities and derivative transactions.

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12.	INVESTMENTS

A.	INVESTMENTS

At December 31, 2010 and 2009, we had investments in various debt and equity securities, cost investments, company-owned life insurance and investments held in trust funds as follows:


	Progress Energy				PEC				PEF
(in millions)	2010		2009		2010		2009		2010		2009
Nuclear decommissioning trust (See Notes 4C and 13)	$	1,571	$	1,367	$	1,017	$	871	$	554	$	496
Equity method investments(a)		16		18		3		5		2		2
Cost investments(b)		5		5		4		4		-		-
Company-owned life insurance(c)		46		45		37		35		-		-
Benefit investment trusts(d)		175		191		97		90		37		35
Total	$	1,813	$	1,626	$	1,158	$	1,005	$	593	$	533

(a)

Investments in unconsolidated companies are accounted for using the equity method of accounting (See Note 1) and are included in miscellaneous other property and investments in the Consolidated Balance Sheets. These investments are primarily in limited liability corporations and limited partnerships, and the earnings from these investments are recorded on a pre-tax basis.

(b)

Investments stated principally at cost are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

(c)

Investments in company-owned life insurance approximate fair value due to the nature of the investments and are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

(d)

Benefit investment trusts are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2010 and 2009, $166 million and $152 million, respectively, of investments in company-owned life insurance were held in Progress Energy’s trusts. Substantially all of PEC’s and PEF’s benefit investment trusts are invested in company-owned life insurance.

B.	IMPAIRMENT OF INVESTMENTS

We evaluate declines in value of investments under the criteria of GAAP. Declines in fair value to below the cost basis judged to be other than temporary on available-for-sale securities are included in long-term regulatory assets or liabilities on the Consolidated Balance Sheets for securities held in our nuclear decommissioning trust funds and in operation and maintenance expense and other, net on the Consolidated Statements of Income for securities in our benefit investment trusts, other available-for-sale securities and equity and cost method investments. See Note 13 for additional information. There were no material other-than-temporary impairments in 2010, 2009 or 2008.

13.	FAIR VALUE DISCLOSURES

A.	DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $12.642 billion and $12.457 billion at December 31, 2010 and 2009, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $14.0 billion and $13.4 billion at December 31, 2010 and 2009, respectively.

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INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities’ nuclear plants (See Note 4C). NDT funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, we hold other debt investments classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.

The following table summarizes our available-for-sale securities at December 31:


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
2010
Common stock equity	$	1,021	$	13	$	408
Preferred stock and other equity		28		-		11
Corporate debt		90		-		6
U.S. state and municipal debt		132		4		3
U.S. and foreign government debt		264		2		10
Money market funds and other		52		-		1
Total	$	1,587	$	19	$	439

2009
Common stock equity	$	839	$	22	$	301
Preferred stock and other equity		16		-		5
Corporate debt		71		1		5
U.S. state and municipal debt		118		2		3
U.S. and foreign government debt		197		1		8
Money market funds and other		161		-		-
Total	$	1,402	$	26	$	322

The NDT funds and other available-for-sale debt investments held in certain benefit trusts are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and unrealized gains for 2010 and 2009 relate to the NDT funds. There were no material unrealized losses and unrealized gains for the other available-for-sale debt securities held in benefit trusts at December 31, 2010 and 2009.

The aggregate fair value of investments that related to the December 31, 2010 and 2009 unrealized losses was $195 million and $209 million, respectively.

At December 31, 2010, the fair value of our available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	27
Due after one through five years		223
Due after five through 10 years		126
Due after 10 years		117
Total	$	493

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The following table presents selected information about our sales of available-for-sale securities for the years ended December 31. Realized gains and losses were determined on a specific identification basis.


(in millions)	2010		2009		2008
Proceeds	$	6,747	$	2,207	$	1,316
Realized gains		21		26		29
Realized losses		27		87		86

Proceeds were primarily related to NDT funds. Losses for investments in the benefit investment trusts were not material. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At December 31, 2010 and 2009, our other securities had no investments in a continuous loss position for greater than 12 months.

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $3.693 billion and $3.709 billion at December 31, 2010 and 2009, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.0 billion at December 31, 2010 and 2009.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC’s nuclear plants (See Note 4C). NDT funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes PEC’s available-for-sale securities at December 31:


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
2010
Common stock equity	$	652	$	10	$	256
Preferred stock and other equity		14		-		6
Corporate debt		72		-		5
U.S. state and municipal debt		51		1		1
U.S. and foreign government debt		199		1		9
Money market funds and other		42		-		1
Total	$	1,030	$	12	$	278

2009
Common stock equity	$	545	$	19	$	186
Preferred stock and other equity		10		-		3
Corporate debt		67		1		4
U.S. state and municipal debt		37		-		1
U.S. and foreign government debt		177		1		8
Money market funds and other		35		-		-
Total	$	871	$	21	$	202

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds

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based on the original cost of the trust investments. All of the unrealized losses and gains for 2010 and 2009 relate to the NDT funds.

The aggregate fair value of investments that related to the December 31, 2010 and 2009 unrealized losses was $104 million and $121 million, respectively.

At December 31, 2010, the fair value of PEC’s available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	14
Due after one through five years		138
Due after five through 10 years		85
Due after 10 years		92
Total	$	329

The following table presents selected information about PEC’s sales of available-for-sale securities for the years ended December 31. Realized gains and losses were determined on a specific identification basis.


(in millions)	2010		2009		2008
Proceeds	$	419	$	622	$	587
Realized gains		10		9		12
Realized losses		19		36		48

PEC’s proceeds were primarily related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At December 31, 2010 and 2009, PEC did not have any other securities.

PEF

DEBT

The carrying amount of PEF’s long-term debt, including current maturities, was $4.482 billion and $4.183 billion at December 31, 2010 and 2009, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $5.0 billion and $4.5 billion at December 31, 2010 and 2009, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF’s nuclear plant (See Note 4C). The NDT funds are presented on the Balance Sheets at fair value.

The following table summarizes PEF’s available-for-sale securities at December 31:


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
2010
Common stock equity	$	369	$	3	$	152
Preferred stock and other equity		14		-		5
Corporate debt		14		-		1
U.S. state and municipal debt		81		3		2
U.S. and foreign government debt		62		1		1
Money market funds and other		10		-		-
Total	$	550	$	7	$	161

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(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
2009
Common stock equity	$	294	$	3	$	115
Preferred stock and other equity		6		-		2
Corporate debt		4		-		1
U.S. state and municipal debt		80		2		2
U.S. and foreign government debt		13		-		-
Money market funds and other		99		-		-
Total	$	496	$	5	$	120

The aggregate fair value of investments that related to the December 31, 2010 and 2009 unrealized losses was $87 million and $56 million, respectively.

At December 31, 2010, the fair value of PEF’s available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	6
Due after one through five years		85
Due after five through 10 years		41
Due after 10 years		25
Total	$	157

The following table presents selected information about PEF’s sales of available-for-sale securities for the years ended December 31. Realized gains and losses were determined on a specific identification basis.


(in millions)	2010		2009		2008
Proceeds	$	6,170	$	1,471	$	610
Realized gains		10		14		16
Realized losses		8		50		36

PEF’s proceeds were related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At December 31, 2010 and 2009, PEF did not have any other securities.

B.	FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest

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priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets.

Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available.

Certain assets and liabilities, including long-lived assets, were measured at fair value on a nonrecurring basis. There were no significant fair value measurement losses recognized for such assets and liabilities in the periods reported. These fair value measurements fall within Level 3 of the hierarchy discussed above.

The following tables set forth, by level within the fair value hierarchy, our and the Utilities’ financial assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2010 and 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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PROGRESS ENERGY
(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,021	$	-	$	-	$	1,021
Preferred stock and other equity		22		6		-		28
Corporate debt		-		86		-		86
U.S. state and municipal debt		-		132		-		132
U.S. and foreign government debt		79		182		-		261
Money market funds and other		1		42		-		43
Total nuclear decommissioning trust funds		1,123		448		-		1,571
Derivatives
Commodity forward contracts		-		15		-		15
Interest rate contracts		-		4		-		4
Other marketable securities
Corporate debt		-		4		-		4
U.S. and foreign government debt		-		3		-		3
Money market funds and other		18		-		-		18
Total assets	$	1,141	$	474	$	-	$	1,615

Liabilities
Derivatives
Commodity forward contracts	$	-	$	458	$	36	$	494
Interest rate contracts		-		39		-		39
Contingent value obligations derivatives		-		15		-		15
Total liabilities	$	-	$	512	$	36	$	548

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(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Nuclear decommissioning trust funds
Common stock equity	$	839	$	-	$	-	$	839
Preferred stock and other equity		16		-		-		16
Corporate debt		-		71		-		71
U.S. state and municipal debt		-		117		-		117
U.S. and foreign government debt		62		128		-		190
Money market funds and other		1		133		-		134
Total nuclear decommissioning trust funds		918		449		-		1,367
Derivatives
Commodity forward contracts		-		20		-		20
Interest rate contracts		-		19		-		19
Other marketable securities
U.S. state and municipal debt		-		1		-		1
U.S. and foreign government debt		-		7		-		7
Money market funds and other		16		27		-		43
Total assets	$	934	$	523	$	-	$	1,457

Liabilities
Derivatives
Commodity forward contracts	$	-	$	386	$	39	$	425
Contingent value obligations derivatives		-		15		-		15
Total liabilities	$	-	$	401	$	39	$	440

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PEC
(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	652	$	-	$	-	$	652
Preferred stock and other equity		14		-		-		14
Corporate debt		-		72		-		72
U.S. state and municipal debt		-		51		-		51
U.S. and foreign government debt		76		123		-		199
Money market funds and other		1		28		-		29
Total nuclear decommissioning trust funds		743		274		-		1,017
Derivatives
Commodity forward contracts		-		2		-		2
Interest rate contracts		-		3		-		3
Other marketable securities		4		-		-		4
Total assets	$	747	$	279	$	-	$	1,026

Liabilities
Derivatives
Commodity forward contracts	$	-	$	87	$	36	$	123
Interest rate contracts		-		11		-		11
Total liabilities	$	-	$	98	$	36	$	134


(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Nuclear decommissioning trust funds
Common stock equity	$	545	$	-	$	-	$	545
Preferred stock and other equity		10		-		-		10
Corporate debt		-		67		-		67
U.S. state and municipal debt		-		37		-		37
U.S. and foreign government debt		52		125		-		177
Money market funds and other		1		34		-		35
Total nuclear decommissioning trust funds		608		263		-		871
Derivatives
Interest rate contracts		-		8		-		8
Other marketable securities		1		-		-		1
Total assets	$	609	$	271	$	-	$	880

Liabilities
Derivatives
Commodity forward contracts	$	-	$	63	$	27	$	90

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PEF
(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	369	$	-	$	-	$	369
Preferred stock and other equity		8		6		-		14
Corporate debt		-		14		-		14
U.S. state and municipal debt		-		81		-		81
U.S. and foreign government debt		3		59		-		62
Money market funds and other		-		14		-		14
Total nuclear decommissioning trust funds		380		174		-		554
Derivatives
Commodity forward contracts		-		13		-		13
Other marketable securities		1		-		-		1
Total assets	$	381	$	187	$	-	$	568

Liabilities
Derivatives
Commodity forward contracts	$	-	$	371	$	-	$	371
Interest rate contracts		-		7		-		7
Total liabilities	$	-	$	378	$	-	$	378


(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Nuclear decommissioning trust funds
Common stock equity	$	294	$	-	$	-	$	294
Preferred stock and other equity		6		-		-		6
Corporate debt		-		4		-		4
U.S. state and municipal debt		-		80		-		80
U.S. and foreign government debt		10		3		-		13
Money market funds and other		-		99		-		99
Total nuclear decommissioning trust funds		310		186		-		496
Derivatives
Commodity forward contracts		-		20		-		20
Interest rate contracts		-		5		-		5
Other marketable securities		1		-		-		1
Total assets	$	311	$	211	$	-	$	522

Liabilities
Derivatives
Commodity forward contracts	$	-	$	323	$	12	$	335

The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities’ credit risk on our liabilities.

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract,

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or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 17 for discussion of risk management activities and derivative transactions.

NDT funds reflect the assets of the Utilities’ nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2.

Other marketable securities primarily represent available-for-sale debt securities used to fund certain employee benefit costs.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress, as discussed in Note 15. The CVOs are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

Transfers in (out) of Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher level for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. There were no significant transfers in (out) of Levels 1 or 2 during the period other than those reflected in the Level 3 reconciliations. Transfers into and out of each level are measured at the end of the reporting period.

A reconciliation of changes in the fair value of our and the Utilities’ commodity derivatives, net classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:

PROGRESS ENERGY
(in millions)	2010			2009			2008
Derivatives, net at beginning of period	$	39		$	41		$	(26	)
Total losses (gains), realized and unrealized deferred as regulatory assets and liabilities, net		44			13			102
Transfers (out) in of Level 3, net		(47	)		(15	)		(35	)
Derivatives, net at end of period	$	36		$	39		$	41

PEC
(in millions)		2010			2009			2009
Derivatives, net at beginning of period	$	27		$	22		$	(6	)
Total losses (gains), realized and unrealized deferred as regulatory assets and liabilities, net		27			7			32
Transfers (out) in of Level 3, net		(18	)		(2	)		(4	)
Derivatives, net at end of period	$	36		$	27		$	22

PEF
(in millions)		2010			2009			2008
Derivatives, net at beginning of period	$	12		$	19		$	(20	)
Total losses (gains), realized and unrealized deferred as regulatory assets and liabilities, net		17			6			70
Transfers (out) in of Level 3, net		(29	)		(13	)		(31	)
Derivatives, net at end of period	$	-		$	12		$	19

Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. There were no Level 3 purchases, sales, issuances or settlements during the period.

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14.	INCOME TAXES

We provide deferred income taxes for temporary differences between book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. To the extent that the establishment of deferred income taxes is different from the recovery of taxes by the Utilities through the ratemaking process, the differences are deferred pursuant to GAAP for regulated operations. A regulatory asset or liability has been recognized for the impact of tax expenses or benefits that are recovered or refunded in different periods by the Utilities pursuant to rate orders. We accrue for uncertain tax positions when it is determined that it is more likely than not that the benefit will not be sustained on audit by the taxing authority based solely on the technical merits of the associated tax position. If the recognition threshold is met, the tax benefit recognized is measured at the largest amount that, in our judgment, is greater than 50 percent likely to be realized.

PROGRESS ENERGY

Accumulated deferred income tax assets (liabilities) at December 31 were:

(in millions)	2010			2009
Deferred income tax assets
ARO liability	$	107		$	127
Derivative instruments		204			159
Income taxes refundable through future rates		271			225
Pension and other postretirement benefits		447			508
Other		394			374
Tax credit carry forwards		839			712
Net operating loss carry forwards		105			66
Valuation allowance		(60	)		(55	)
Total deferred income tax assets		2,307			2,116
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(2,439	)		(1,889	)
Income taxes recoverable through future rates		(875	)		(782	)
Other		(386	)		(338	)
Total deferred income tax liabilities		(3,700	)		(3,009	)
Total net deferred income tax liabilities	$	(1,393	)	$	(893	)

The above amounts were classified on the Consolidated Balance Sheets as follows:

(in millions)	2010			2009
Current deferred income tax assets, included in prepayments and other current assets	$	156		$	168
Noncurrent deferred income tax assets, included in other assets and deferred debits		34			37
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,583	)		(1,098	)
Total net deferred income tax liabilities	$	(1,393	)	$	(893	)

At December 31, 2010, we had the following tax credit and net operating loss carry forwards:

·	$836 million of federal alternative minimum tax credits that do not expire.

·	$5 million of state income tax credits that will expire during 2013.

·	$105 million of gross federal net operating loss carry forwards that will expire during 2030.

·	$1.6 billion of gross state net operating loss carry forwards that will expire during the period 2011 through 2030.

Valuation allowances have been established due to the uncertainty of realizing certain future state tax benefits. We had a net increase of $5 million in our valuation allowances during 2010.

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We believe it is more likely than not that the results of future operations will generate sufficient taxable income to allow for the utilization of the remaining deferred tax assets.

Certain substantial changes in ownership of Progress Energy, including the proposed merger between Progress Energy and Duke Energy (See Note 25), can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards.

Reconciliations of our effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:

	2010			2009			2008
Effective income tax rate		38.3	%		32.1	%		33.7	%
State income taxes, net of federal benefit		(4.3	)		(3.7	)		(3.8	)
Investment tax credit amortization		0.5			0.8			1.0
Employee stock ownership plan dividends		0.9			1.0			1.0
Domestic manufacturing deduction		-			0.8			0.3
AFUDC equity		1.4			2.2			2.5
Other differences, net		(1.8	)		1.8			0.3
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Income tax expense applicable to continuing operations for the years ended December 31 was comprised of:


(in millions)	2010			2009			2008
Current
Federal	$	(46	)	$	227		$	38
State		(13	)		41			12
Total current income tax expense (benefit)		(59	)		268			50
Deferred
Federal		542			114			305
State		100			25			49
Total deferred income tax expense		642			139			354
Investment tax credit		(7	)		(10	)		(12	)
Net operating loss carry forward		(37	)		-			(6	)
Beginning-of-the-year valuation allowance change		-			-			9
Total income tax expense	$	539		$	397		$	395

We previously recorded a deferred income tax asset for a state net operating loss carry forward upon the sale of our nonregulated generating facilities and energy marketing and trading operations. During 2008, we recorded an additional deferred income tax asset of $6 million related to the state net operating loss carry forward due to a change in estimate based on 2007 tax return filings. During 2008 we also evaluated this state net operating loss carry forward and recorded a partial valuation allowance of $9 million.

Total income tax expense applicable to continuing operations excluded the following:

·	Taxes related to discontinued operations recorded net of tax for 2010, 2009 and 2008, which are presented separately in Notes 3A through 3C.

·	Taxes related to other comprehensive income recorded net of tax for 2010, 2009 and 2008, which are presented separately in the Consolidated Statements of Comprehensive Income.

An immaterial amount of current tax benefit, which was recorded in common stock during 2010, related to excess tax deductions resulting from vesting of restricted stock awards, vesting of RSUs, vesting of stock-settled PSSP awards and exercises of nonqualified stock options pursuant to the terms of our EIP. No net current tax benefit was recorded in common stock during 2009 and 2008.

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At December 31, 2010, 2009, and 2008, our liability for unrecognized tax benefits was $176 million, $160 million, and $104 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $8 million, $9 million, and $8 million, respectively, at December 31, 2010, 2009, and 2008. The following table presents the changes to unrecognized tax benefits during the years ended December 31:


(in millions)	2010			2009			2008
Unrecognized tax benefits at beginning of period	$	160		$	104		$	93
Gross amounts of increases as a result of tax positions taken in a prior period		10			11			17
Gross amounts of decreases as a result of tax positions taken in a prior period		(4	)		(3	)		(11	)
Gross amounts of increases as a result of tax positions taken in the current period		14			52			8
Gross amounts of decreases as a result of tax positions taken in the current period		(4	)		(4	)		(2	)
Amounts of net increases relating to settlements with taxing authorities		-			-			1
Reduction as a result of a lapse of the applicable statute of limitations		-			-			(2	)
Unrecognized tax benefits at end of period	$	176		$	160		$	104

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Generally our open federal tax years are from 2004 forward, and our open state tax years in our major jurisdictions are from 2003 or 2004 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. We cannot predict when the review will be completed. Although the timing for completion of the IRS review is uncertain, it is reasonably possible that unrecognized tax benefits will decrease by up to approximately $60 million during the 12-month period ending December 31, 2011, due to expected settlements. Any potential decrease will not have a material impact on our results of operations.

We include interest expense related to unrecognized tax benefits in net interest charges and we include penalties in other, net on the Consolidated Statements of Income. During 2010, 2009, and 2008, the net interest expense related to unrecognized tax benefits was $9 million, $9 million, and $4 million, respectively, of which a respective $5 million, $5 million, and $1 million expense component was deferred as a regulatory asset by PEF, which is amortized as a charge to interest expense over a three-year period or less. During 2008, PEF charged the unamortized balance of the regulatory asset to interest expense. During 2010 and 2009, there were no penalties related to unrecognized tax benefits. During 2008, less than $1 million was recorded for penalties related to unrecognized tax benefits. At December 31, 2010, 2009, and 2008, we had accrued $45 million, $36 million, and $27 million, respectively, for interest and penalties, which are included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets.

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PEC

Accumulated deferred income tax assets (liabilities) at December 31 were:

(in millions)	2010			2009
Deferred income tax assets
ARO liability	$	103		$	111
Income taxes refundable through future rates		142			106
Pension and other postretirement benefits		180			254
Other		207			186
Total deferred income tax assets		632			657
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(1,552	)		(1,307	)
Deferred fuel recovery		(29	)		(60	)
Income taxes recoverable through future rates		(421	)		(377	)
Investments		(104	)		(71	)
Other		(6	)		(8	)
Total deferred income tax liabilities		(2,112	)		(1,823	)
Total net deferred income tax liabilities	$	(1,480	)	$	(1,166	)

The above amounts were classified on the Consolidated Balance Sheets as follows:


(in millions)	2010			2009
Current deferred income tax assets, included in prepayments and other current assets	$	65		$	42
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,545	)		(1,208	)
Total net deferred income tax liabilities	$	(1,480	)	$	(1,166	)

Reconciliations of PEC’s effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:


	2010			2009			2008
Effective income tax rate		36.8	%		35.0	%		35.8	%
State income taxes, net of federal benefit		(3.2	)		(2.8	)		(2.7	)
Investment tax credit amortization		0.6			0.7			0.7
Domestic manufacturing deduction		0.4			0.9			0.5
Other differences, net		0.4			1.2			0.7
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Income tax expense for the years ended December 31 was comprised of:


(in millions)	2010			2009			2008
Current
Federal	$	73		$	192		$	87
State		(8	)		21			7
Total current income tax expense		65			213			94
Deferred
Federal		238			57			181
State		53			13			29
Total deferred income tax expense		291			70			210
Investment tax credit		(6	)		(6	)		(6	)
Total income tax expense	$	350		$	277		$	298

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Total income tax expense excluded taxes related to other comprehensive income recorded net of tax for 2010, 2009 and 2008, which are presented separately in the Consolidated Statements of Comprehensive Income.

PEC and each of its wholly owned subsidiaries have entered into the Tax Agreement with the Parent (See Note 1D). PEC’s intercompany tax receivable was approximately $78 million and $38 million at December 31, 2010 and 2009, respectively.

At December 31, 2010, 2009, and 2008, PEC’s liability for unrecognized tax benefits was $74 million, $59 million, and $38 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $4 million, $5 million, and $5 million, respectively, at December 31, 2010, 2009, and 2008. The following table presents the changes to unrecognized tax benefits during the years ended December 31, 2010, 2009, and 2008:

(in millions)	2010			2009			2008
Unrecognized tax benefits at beginning of period	$	59		$	38		$	41
Gross amounts of increases as a result of tax positions taken in a prior period		8			6			5
Gross amounts of decreases as a result of tax positions taken in a prior period		(2	)		(2	)		(10	)
Gross amounts of increases as a result of tax positions taken in the current period		10			17			4
Gross amounts of decreases as a result of tax positions taken in the current period		(1	)		-			(1	)
Amounts of net increases relating to settlements with taxing authorities		-			-			1
Reduction as a result of a lapse of the applicable statute of limitations		-			-			(2	)
Unrecognized tax benefits at end of period	$	74		$	59		$	38

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. Generally PEC’s open federal tax years are from 2004 forward, and PEC’s open state tax years in our major jurisdictions are from 2003 or 2004 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEC cannot predict when the review will be completed. Although the timing for completion of the IRS review is uncertain, it is reasonably possible that unrecognized tax benefits will decrease by up to approximately $10 million during the 12-month period ending December 31, 2011, due to expected settlements. Any potential decrease will not have a material impact on PEC’s results of operations.

PEC includes interest expense related to unrecognized tax benefits in net interest charges and we include penalties in other, net on the Consolidated Statements of Income. During 2010 and 2009, the interest expense recorded related to unrecognized tax benefits was $4 million and $3 million, respectively. During 2008, the interest benefit recorded related to unrecognized tax benefits was $1 million. During 2010, 2009, and 2008, there were no penalties related to unrecognized tax benefits. At December 31, 2010, 2009, and 2008, we had accrued $14 million, $10 million, and $7 million, respectively, for interest and penalties, which are included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets.

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PEF

Accumulated deferred income tax assets (liabilities) at December 31 were:


(in millions)	2010			2009
Deferred income tax assets
Derivative instruments	$	145		$	125
Income taxes refundable through future rates		93			73
Pension and other postretirement benefits		170			163
Reserve for storm damage		52			52
Unbilled revenue		61			48
Other		82			89
Tax credit carry forwards		3			-
Net operating loss carry forwards		9			-
Total deferred income tax assets		615			550
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(874	)		(568	)
Deferred fuel recovery		(65	)		(14	)
Deferred nuclear cost recovery		(94	)		(107	)
Income taxes recoverable through future rates		(454	)		(406	)
Investments		(60	)		(44	)
Other		(18	)		(26	)
Total deferred income tax liabilities		(1,565	)		(1,165	)
Total net deferred income tax liabilities	$	(950	)	$	(615	)

The above amounts were classified on the Balance Sheets as follows:


(in millions)	2010				2009
Current deferred income tax assets, included in deferred tax assets		$	77			$	115
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities			(1,027	)			(730	)
Total net deferred income tax liabilities		$	(950	)		$	(615	)

At December 31, 2010, PEF had the following tax credit and net operating loss carry forwards:

·	$5 million of state income tax credits that will expire during 2013.

·	$22 million of gross federal net operating loss carry forwards that will expire during 2030.

·	$46 million of gross state net operating loss carry forwards that will expire during 2030.

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Reconciliations of PEF’s effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:


	2010			2009			2008
Effective income tax rate		37.9	%		31.1	%		32.0	%
State income taxes, net of federal benefit		(3.2	)		(3.0	)		(3.1	)
Investment tax credit amortization		0.2			0.7			1.1
Domestic manufacturing deduction		-			0.8			0.2
AFUDC equity		0.8			3.4			5.4
Other differences, net		(0.7	)		2.0			(0.6	)
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Income tax expense for the years ended December 31 was comprised of:


(in millions)	2010			2009			2008
Current
Federal	$	(44	)	$	125		$	39
State		(4	)		20			12
Total current income tax expense (benefit)		(48	)		145			51
Deferred
Federal		293			57			121
State		41			11			15
Total deferred income tax expense		334			68			136
Investment tax credit		(1	)		(4	)		(6	)
Net operating loss carry forward		(9	)		-			-
Total income tax expense	$	276		$	209		$	181

Total income tax expense excluded the following:

·	Taxes related to other comprehensive income recorded net of tax for 2010, 2009 and 2008, which are presented separately in the Statements of Comprehensive Income.

PEF has entered into the Tax Agreement with the Parent (See Note 1D). PEF’s intercompany tax receivable was approximately $71 million and $122 million at December 31, 2010 and 2009, respectively.

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At December 31, 2010, 2009, and 2008, PEF’s liability for unrecognized tax benefits was $99 million, $98 million, and $62 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $2 million, $3 million, and $2 million, respectively, at December 31, 2010, 2009, and 2008. The following table presents the changes to unrecognized tax benefits during the years ended December 31, 2010, 2009, and 2008:


(in millions)	2010			2009			2008
Unrecognized tax benefits at beginning of period	$	98		$	62		$	55
Gross amounts of increases as a result of tax positions taken in a prior period		2			5			6
Gross amounts of decreases as a result of tax positions taken in a prior period		(1	)		(1	)		(1	)
Gross amounts of increases as a result of tax positions taken in the current period		3			35			3
Gross amounts of decreases as a result of tax positions taken in the current period		(3	)		(3	)		(1	)
Amounts of net increases (decreases) relating to settlements with taxing authorities		-			-			-
Reduction as a result of a lapse of the applicable statute of limitations		-			-			-
Unrecognized tax benefits at end of period	$	99		$	98		$	62

We file consolidated federal and state income tax returns that include PEF. Generally PEF’s open federal tax years are from 2004 forward, and PEF’s open state tax years are from 2003 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEF cannot predict when the review will be completed. Although the timing for completion of the IRS review is uncertain, it is reasonably possible that unrecognized tax benefits will decrease by up to approximately $50 million during the 12-month period ending December 31, 2011, due to expected settlements. Any potential decrease will not have a material impact on our results of operations.

Pursuant to a regulatory order, PEF records interest expense related to unrecognized tax benefits as a regulatory asset, which is amortized over a three-year period or less, with the amortization included in net interest charges on the Statements of Income. During 2008, PEF charged the unamortized balance of the regulatory asset to interest expense on the Statements of Income. Penalties are included in other, net on the Statements of Income. During 2010, 2009, and 2008, interest expense recorded as a regulatory asset was $5 million, $5 million, and $1 million, respectively, and there were no penalties recorded related to unrecognized tax benefits. At December 31, 2010, 2009, and 2008, PEF had accrued $29 million, $24 million, and $19 million, respectively, for interest and penalties, which are included in interest accrued and other assets and deferred debits on the Consolidated Balance Sheets.

15.	CONTINGENT VALUE OBLIGATIONS

In connection with the acquisition of Florida Progress during 2000, the Parent issued 98.6 million CVOs. Each CVO represents the right of the holder to receive contingent payments based on the performance of four coal-based solid synthetic fuels limited liability companies, three of which were wholly owned (Earthco), purchased by subsidiaries of Florida Progress in October 1999. All of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007 (See Note 3A). The payments are based on the net after-tax cash flows the facilities generated. We make deposits into a CVO trust for estimated contingent payments due to CVO holders based on the results of operations and the utilization of tax credits. The balance of the CVO trust at December 31, 2010 and 2009 was $11 million and is included in other assets and deferred debits on the Consolidated Balance Sheets. Future payments from the trust to CVO holders will not be made until certain conditions are satisfied and will include principal and interest earned during the investment period net of expenses deducted. Interest earned on the payments held in trust for 2010 and 2009 was insignificant.

The CVOs are derivatives and are recorded at fair value. The unrealized loss/gain recognized due to changes in fair value is recorded in other, net on the Consolidated Statements of Income (See Note 20). At December 31, 2010 and

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2009, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $15 million.

16.	BENEFIT PLANS

A.	POSTRETIREMENT BENEFITS

We have noncontributory defined benefit retirement plans that provide pension benefits for substantially all full-time employees. We also have supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, we provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. We use a measurement date of December 31 for our pension and OPEB plans.

COSTS OF BENEFIT PLANS

Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

To determine the market-related value of assets, we use a five-year averaging method for a portion of the pension assets and fair value for the remaining portion. We have historically used the five-year averaging method. When we acquired Florida Progress in 2000, we retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets.

The tables below provide the components of the net periodic benefit cost for the years ended December 31. A portion of net periodic benefit cost is capitalized as part of construction work in progress.

PROGRESS ENERGY
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009			2008
Service cost	$	48		$	42		$	46		$	16		$	7		$	8
Interest cost		140			138			128			45			31			34
Expected return on plan assets		(157	)		(133	)		(170	)		(4	)		(4	)		(6	)
Amortization of actuarial loss(a)		51			54			8			13			1			1
Other amortization, net (a)		6			6			2			5			5			5
Net periodic cost before deferral(b)	$	88		$	107		$	14		$	75		$	40		$	42

(a)

Adjusted to reflect PEF’s rate treatment (See Note 16B).

(b)

PEF received permission from the FPSC to defer the retail portion of certain 2009 pension expense. The FPSC order did not change the total net periodic pension cost, but deferred a portion of the costs to be recovered in future periods. During 2009, PEF deferred $34 million of net periodic pension costs as a regulatory asset. See Note 7C.

PEC
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009			2008
Service cost	$	19		$	18		$	23		$	5		$	5		$	5
Interest cost		64			64			58			20			16			17
Expected return on plan assets		(77	)		(67	)		(66	)		(2	)		(2	)		(4	)
Amortization of actuarial loss		16			11			6			4			-			-
Other amortization, net		6			6			2			1			1			1
Net periodic cost	$	28		$	32		$	23		$	28		$	20		$	19

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PEF
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009			2008
Service cost	$	22		$	19		$	17		$	10		$	2		$	2
Interest cost		59			56			53			22			13			14
Expected return on plan assets		(68	)		(56	)		(90	)		(2	)		(1	)		(1	)
Amortization of actuarial loss		31			38			1			9			-			1
Other amortization, net		-			-			(1	)		4			3			3
Net periodic cost before deferral(a)	$	44		$	57		$	(20	)	$	43		$	17		$	19

(a)

The following tables provide a summary of amounts recognized in other comprehensive income and other comprehensive income reclassification adjustments for amounts included in net income for 2010, 2009 and 2008. The tables also include comparable items that affected regulatory assets of PEC and PEF. For PEC and PEF, amounts that would otherwise be recorded in other comprehensive income are recorded as adjustments to regulatory assets consistent with the recovery of the related costs through the ratemaking process.

PROGRESS ENERGY
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009		2008
Other comprehensive income (loss)
Recognized for the year
Net actuarial (loss) gain	$	(11	)	$	(1	)	$	(64	)	$	(10	)	$	4	$	(8	)
Other, net		-			-			(6	)		-			-		-
Reclassification adjustments
Net actuarial loss		4			5			1			-			1		-
Other, net		-			-			1			-			1		-
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain		(65	)		10			(735	)		(164	)		64		(73	)
Other, net		-			(3	)		(36	)		-			-		-
Amortized to income(a)
Net actuarial loss		47			49			7			13			-		1
Other, net		6			6			1			5			4		5

(a)	These amounts were amortized as a component of net periodic cost, as reflected in the previous net periodic cost table. Refer to that table for information regarding the deferral of a portion of net periodic pension cost.

PEC
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009		2008
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain	$	(24	)	$	(14	)	$	(308	)	$	(64	)	$	38	$	(66	)
Other, net		-			(2	)		(31	)		-			-		-
Amortized to income
Net actuarial loss		16			11			6			4			-		-
Other, net		6			6			2			1			1		1

184

PEF
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009		2008
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain	$	(41	)	$	24		$	(427	)	$	(100	)	$	26	$	(6	)
Other, net		-			(1	)		(5	)		-			-		-
Amortized to income(a)
Net actuarial loss		31			38			1			9			-		1
Other, net		-			-			(1	)		4			3		3

(a)	These amounts were amortized as a component of net periodic cost, as reflected in the previous net periodic cost table. Refer to that table for information regarding the deferral of a portion of net periodic pension cost.

The following weighted-average actuarial assumptions were used by Progress Energy in the calculation of its net periodic cost:


	Pension Benefits									OPEB
	2010			2009			2008			2010			2009			2008
Discount rate		6.00	%		6.30	%		6.20	%		6.05	%		6.20	%		6.20	%
Rate of increase in future compensation
Bargaining		4.50	%		4.25	%		4.25	%		-			-			-
Supplementary plans		5.25	%		5.25	%		5.25	%		-			-			-
Expected long-term rate of return on plan assets		8.75	%		8.75	%		9.00	%		6.60	%		6.80	%		8.10	%

The weighted-average actuarial assumptions used by PEC and PEF were not materially different from the assumptions above, as applicable, except that the expected long-term rate of return on OPEB plan assets was 5.00% for PEF for all years presented and for PEC was 8.75%, 8.75% and 9.00% for 2010, 2009 and 2008, respectively.

The expected long-term rates of return on plan assets were determined by considering long-term projected returns based on the plans’ target asset allocations. Specifically, return rates were developed for each major asset class and weighted based on the target asset allocations. The projected returns were benchmarked against historical returns for reasonableness. We decreased our expected long-term rate of return on pension assets by 0.25% in 2009, primarily due to the uncertainties resulting from the severe capital market deterioration in 2008. See the “Assets of Benefit Plans” section below for additional information regarding our investment policies and strategies.

BENEFIT OBLIGATIONS AND ACCRUED COSTS

GAAP requires us to recognize in our statement of financial condition the funded status of our pension and other postretirement benefit plans, measured as the difference between the fair value of the plan assets and the benefit obligation as of the end of the fiscal year.

185

Reconciliations of the changes in the Progress Registrants’ benefit obligations and the funded status as of December 31, 2010 and 2009 are presented in the tables below, with each table followed by related supplementary information.

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Projected benefit obligation at January 1	$	2,422		$	2,234		$	543		$	608
Service cost		48			42			16			7
Interest cost		140			138			45			31
Settlements		-			(9	)		-			-
Benefit payments		(129	)		(124	)		(44	)		(40	)
Plan amendment		1			3			-			-
Actuarial loss (gain)		127			138			173			(63	)
Obligation at December 31		2,609			2,422			733			543
Fair value of plan assets at December 31		1,891			1,673			33			55
Funded status	$	(718	)	$	(749	)	$	(700	)	$	(488	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $2.609 billion and $2.422 billion at December 31, 2010 and 2009, respectively. Those plans had accumulated benefit obligations totaling $2.563 billion and $2.378 billion at December 31, 2010 and 2009, respectively, and plan assets of $1.891 billion and $1.673 billion at December 31, 2010 and 2009, respectively.

The accrued benefit costs reflected in the Consolidated Balance Sheets at December 31 were as follows:

	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Current liabilities	$	(10	)	$	(9	)	$	(22	)	$	-
Noncurrent liabilities		(708	)		(740	)		(678	)		(488	)
Funded status	$	(718	)	$	(749	)	$	(700	)	$	(488	)

The following table provides a summary of amounts not yet recognized as a component of net periodic cost at December 31:

	Pension Benefits				OPEB
(in millions)	2010		2009		2010		2009
Recognized in accumulated other comprehensive loss
Net actuarial loss (gain)	$	90	$	83	$	5	$	(5	)
Other, net		9		10		1		-
Recognized in regulatory assets, net
Net actuarial loss		824		806		183		32
Other, net		55		59		9		14
Total not yet recognized as a component of net periodic cost(a)	$	978	$	958	$	198	$	41

(a)

All components are adjusted to reflect PEF's rate treatment (See Note 16B).

186

The following table presents the amounts we expect to recognize as components of net periodic cost in 2011:

(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss(a)	$	58	$	12
Amortization of other, net(a)		7		5

(a)

Adjusted to reflect PEF’s rate treatment (See Note 16B).

PEC
	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Projected benefit obligation at January 1	$	1,120		$	1,025		$	282		$	312
Service cost		19			18			5			5
Interest cost		64			64			20			16
Plan amendment		-			2			-			-
Benefit payments		(56	)		(50	)		(19	)		(17	)
Actuarial loss (gain)		41			61			64			(34	)
Obligation at December 31		1,188			1,120			352			282
Fair value of plan assets at December 31		884			749			-			21
Funded status	$	(304	)	$	(371	)	$	(352	)	$	(261	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $1.188 billion and $1.120 billion at December 31, 2010 and 2009, respectively. Those plans had accumulated benefit obligations totaling $1.184 billion and $1.116 billion at December 31, 2010 and 2009, respectively, and plan assets of $884 million and $749 million at December 31, 2010 and 2009, respectively.

The accrued benefit costs reflected on the Balance Sheets at December 31 were as follows:


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Current liabilities	$	(2	)	$	(2	)	$	(19	)	$	-
Noncurrent liabilities		(302	)		(369	)		(333	)		(261	)
Funded status	$	(304	)	$	(371	)	$	(352	)	$	(261	)

The table below provides a summary of amounts not yet recognized as a component of net periodic cost at December 31:


	Pension Benefits				OPEB
(in millions)	2010		2009		2010		2009
Recognized in regulatory assets
Net actuarial loss	$	418	$	410	$	76	$	16
Other, net		49		54		2		3
Total not yet recognized as a component of net periodic cost	$	467	$	464	$	78	$	19

187

The following table presents the amounts PEC expects to recognize as components of net periodic cost in 2011:

in millions)	Pension Benefits		OPEB
Amortization of actuarial loss	$	23	$	4
Amortization of other, net		6		1

PEF
	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Projected benefit obligation at January 1	$	992		$	914		$	219		$	248
Service cost		22			19			10			2
Interest cost		59			56			22			13
Plan amendment		1			-			-			-
Benefit payments		(58	)		(58	)		(23	)		(20	)
Actuarial loss (gain)		71			61			98			(24	)
Obligation at December 31		1,087			992			326			219
Fair value of plan assets at December 31		871			794			33			32
Funded status	$	(216	)	$	(198	)	$	(293	)	$	(187	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $1.087 billion and $992 million at December 31, 2010 and 2009, respectively. Those plans had accumulated benefit obligations totaling $1.049 billion and $957 million at December 31, 2010 and 2009, respectively, and plan assets of $871 million and $794 million at December 31, 2010 and 2009, respectively.

The accrued benefit costs reflected in the Balance Sheets at December 31 were as follows:

	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Current liabilities	$	(3	)	$	(3	)	$	-		$	-
Noncurrent liabilities		(213	)		(195	)		(293	)		(187	)
Funded status	$	(216	)	$	(198	)	$	(293	)	$	(187	)

The following table provides a summary of amounts not yet recognized as a component of net periodic cost at December 31.

	Pension Benefits				OPEB
(in millions)	2010		2009		2010		2009
Recognized in regulatory assets, net
Net actuarial loss	$	406	$	396	$	107	$	16
Other, net		6		5		7		11
Total not yet recognized as a component of net periodic cost	$	412	$	401	$	114	$	27

188

The following table presents the amounts PEF expects to recognize as components of net periodic cost in 2011:

(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss	$	31	$	7
Amortization of other, net		-		4

The following weighted-average actuarial assumptions were used in the calculation of our year-end obligations:

	Pension Benefits						OPEB
	2010			2009			2010			2009
Discount rate		5.65	%		6.00	%		5.75	%		6.05	%
Rate of increase in future compensation
Bargaining		4.50	%		4.50	%		-			-
Supplementary plans		5.25	%		5.25	%		-			-
Initial medical cost trend rate for pre-Medicare Act benefits		-			-			8.50	%		8.50	%
Initial medical cost trend rate for post-Medicare Act benefits		-			-			8.50	%		8.50	%
Ultimate medical cost trend rate		-			-			5.00	%		5.00	%
Year ultimate medical cost trend rate is achieved		-			-			2017			2016

The weighted-average actuarial assumptions for PEC and PEF were the same or were not significantly different from those indicated above, as applicable. The rates of increase in future compensation include the effects of cost of living adjustments and promotions.

Our primary defined benefit retirement plan for nonbargaining employees is a “cash balance” pension plan. Therefore, we use the traditional unit credit method for purposes of measuring the benefit obligation of this plan. Under the traditional unit credit method, no assumptions are included about future changes in compensation, and the accumulated benefit obligation and projected benefit obligation are the same.

MEDICAL COST TREND RATE SENSITIVITY

The medical cost trend rates were assumed to decrease gradually from the initial rates to the ultimate rates. The effects of a 1 percent change in the medical cost trend rate are shown below.

	Progress Energy			PEC			PEF
1 percent increase in medical cost trend rate
Effect on total of service and interest cost	$	3		$	1		$	2
Effect on postretirement benefit obligation		46			22			20
1 percent decrease in medical cost trend rate
Effect on total of service and interest cost		(2	)		(1	)		(1	)
Effect on postretirement benefit obligation		(31	)		(15	)		(14	)

ASSETS OF BENEFIT PLANS

In the plan asset reconciliation tables that follow, our, PEC’s and PEF’s employer contributions for 2010 include contributions directly to pension plan assets of $129 million, $95 million and $34 million, respectively, and for 2009 include contributions directly to pension plan assets of $222 million, $163 million and $58 million, respectively. Substantially all of the remaining employer contributions represent benefit payments made directly from the Progress Registrants’ assets. The OPEB benefit payments presented in the plan asset reconciliation tables that follow represent the cost after participant contributions. Participant contributions represent approximately 15 percent of gross benefit payments for Progress Energy, 21 percent for PEC and 10 percent for PEF. The OPEB benefit payments are also reduced by prescription drug-related federal subsidies received. In 2010, the subsidies totaled $3 million for us, $1 million for PEC and $2 million for PEF. In 2009, the subsidies totaled $3 million for us, $1 million for PEC and $1 million for PEF.

189

Reconciliations of the fair value of plan assets at December 31 follow:

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Fair value of plan assets January 1	$	1,673		$	1,285		$	55		$	52
Actual return on plan assets		208			279			2			9
Benefit payments, including settlements		(129	)		(133	)		(44	)		(40	)
Employer contributions		139			242			20			34
Fair value of plan assets at December 31	$	1,891		$	1,673		$	33		$	55

PEC
	Pension Benefits						OPEB
(in millions)		2010			2009			2010			2009
Fair value of plan assets January 1	$	749		$	521		$	21		$	22
Actual return on plan assets		94			113			2			5
Benefit payments		(56	)		(50	)		(19	)		(17	)
Employer contributions (reimbursements)		97			165			(4	)		11
Fair value of plan assets at December 31	$	884		$	749		$	-		$	21

PEF
	Pension Benefits						OPEB
(in millions)		2010			2009			2010			2009
Fair value of plan assets January 1	$	794		$	650		$	32		$	27
Actual return on plan assets		98			141			1			3
Benefit payments		(58	)		(58	)		(23	)		(20	)
Employer contributions		37			61			23			22
Fair value of plan assets at December 31	$	871		$	794		$	33		$	32

The Progress Registrants’ primary objectives when setting investment policies and strategies are to manage the assets of the pension plan to ensure that sufficient funds are available at all times to finance promised benefits and to invest the funds such that contributions are minimized, within acceptable risk limits. We periodically perform studies to analyze various aspects of our pension plans including asset allocations, expected portfolio return, pension contributions and net funded status. One of our key investment objectives is to achieve a rolling 10-year annual return of 6 percent over the rate of inflation. The current target pension asset allocations are 40 percent domestic equity, 20 percent international equity, 25 percent domestic fixed income, 10 percent private equity and timber and 5 percent hedge funds. Tactical shifts (plus or minus 5 percent) in asset allocation from the target allocations are made based on the near-term view of the risk and return tradeoffs of the asset classes. Domestic equity includes investments across large, medium and small capitalized domestic stocks, using investment managers with value, growth and core-based investment strategies. International equity includes investments in foreign stocks in both developed and emerging market countries, using a mix of value and growth based investment strategies. Domestic fixed income primarily includes domestic investment grade fixed income investments. A substantial portion of OPEB plan assets are managed with pension assets. The remaining OPEB plan assets, representing all PEF’s OPEB plan assets, are invested in domestic governmental securities.

190

PROGRESS ENERGY

The following table sets forth by level within the fair value hierarchy of our pension plan assets at December 31, 2010 and 2009. See Note 13 for detailed information regarding the fair value hierarchy.


		Pension Benefit Plan Assets
(in millions)	Level 1			Level 2			Level 3			Total
2010
Assets
Cash and cash equivalents		$	-		$	94		$	-	$	94
International equity securities			40			-			-		40
Domestic equity securities			286			-			-		286
Private equity securities			-			-			147		147
Corporate bonds			-			216			-		216
U.S. state and municipal debt			-			19			-		19
U.S. and foreign government debt			144			30			-		174
Commingled funds			-			847			-		847
Hedge funds			-			51			2		53
Timber investments			-			-			11		11
Interest rate swaps and other investments			-			4			-		4
Fair value of plan assets		$	470		$	1,261		$	160	$	1,891

		Pension Benefit Plan Assets
(in millions)	Level 1			Level 2			Level 3			Total
2009
Assets
Cash and cash equivalents		$	1		$	96		$	-	$	97
Domestic equity securities			263			1			-		264
Private equity securities			-			-			122		122
Corporate bonds			-			67			-		67
U.S. state and municipal debt			-			4			-		4
U.S. and foreign government debt			25			95			-		120
Mortgage backed securities			-			22			-		22
Commingled funds			-			888			-		888
Hedge funds			-			47			2		49
Timber investments			-			-			14		14
Interest rate swaps and other investments			-			56			-		56
Total assets		$	289		$	1,276		$	138	$	1,703
Liabilities
Foreign currency contracts			5			-			-		5
Interest rate swaps and other investments			-			25			-		25
Total liabilities			5			25			-		30
Fair value of plan assets		$	284		$	1,251		$	138	$	1,673

191

At December 31, 2010, our other postretirement benefit plan assets had a fair value of $33 million, which consisted of U.S. state and municipal assets classified as Level 2 in the fair value hierarchy as of December 31, 2010.

The following table sets forth the fair value hierarchy of our other postretirement plan assets at December 31, 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	Other Postretirement Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Cash and cash equivalents	$	-	$	1	$	-	$	1
Domestic equity securities		4		-		-		4
Corporate bonds		-		1		-		1
U.S. state and municipal debt		-		32		-		32
U.S. and foreign government debt		-		2		-		2
Commingled funds		-		13		-		13
Hedge funds		-		1		-		1
Interest rate swaps and other investments		-		1		-		1
Fair value of plan assets	$	4	$	51	$	-	$	55

A reconciliation of changes in the fair value of our pension plan assets classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:


(in millions)	Private Equity Securities				Hedge Funds			Timber Investments				Total
2010
Balance at January 1		$	122			$	2		$	14		$	138
Net realized and unrealized gains (losses)(a)			7				-			(2	)		5
Purchases, sales and distributions, net			18				-			(1	)		17
Balance at December 31		$	147			$	2		$	11		$	160

(in millions)	Private Equity Securities				Hedge Funds			Timber Investments				Total
2009
Balance at January 1		$	111			$	2		$	18		$	131
Net realized and unrealized (losses)(a)			(10	)			-			(4	)		(14	)
Purchases, sales and distributions, net			21				-			-			21
Balance at December 31		$	122			$	2		$	14		$	138

(a)

Substantially all amounts relate to investments held at December 31.

192

PEC

The following table sets forth by level within the fair value hierarchy of PEC’s pension plan assets at December 31, 2010 and 2009. See Note 13 for detailed information regarding the fair value hierarchy.


		Pension Benefit Plan Assets
(in millions)	Level 1			Level 2			Level 3			Total
2010
Assets
Cash and cash equivalents		$	-		$	44		$	-	$	44
International equity securities			19			-			-		19
Domestic equity securities			134			-			-		134
Private equity securities			-			-			69		69
Corporate bonds			-			101			-		101
U.S. state and municipal debt			-			9			-		9
U.S. and foreign government debt			67			14			-		81
Commingled funds			-			396			-		396
Hedge funds			-			24			1		25
Timber investments			-			-			5		5
Interest rate swaps and other investments			-			1			-		1
Fair value of plan assets		$	220		$	589		$	75	$	884


		Pension Benefit Plan Assets
(in millions)	Level 1			Level 2			Level 3			Total
2009
Assets
Cash and cash equivalents		$	-		$	43		$	-	$	43
Domestic equity securities			118			-			-		118
Private equity securities			-			-			55		55
Corporate bonds			-			30			-		30
U.S. state and municipal debt			-			2			-		2
U.S. and foreign government debt			11			43			-		54
Mortgage backed securities			-			10			-		10
Commingled funds			-			398			-		398
Hedge funds			-			21			1		22
Timber investments			-			-			6		6
Interest rate swaps and other investments			-			24			-		24
Total assets		$	129		$	571		$	62	$	762
Liabilities
Foreign currency contracts			2			-			-		2
Interest rate swaps and other investments			-			11			-		11
Total liabilities			2			11			-		13
Fair value of plan assets		$	127		$	560		$	62	$	749

193

The following table sets forth the fair value hierarchy of our other postretirement plan assets at December 31, 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	Other Postretirement Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Cash and cash equivalents	$	-	$	1	$	-	$	1
Domestic equity securities		4		-		-		4
Corporate bonds		-		1		-		1
U.S. and foreign government debt		-		2		-		2
Commingled funds		-		12		-		12
Hedge funds		-		1		-		1
Fair value of plan assets	$	4	$	17	$	-	$	21

A reconciliation of changes in the fair value of PEC’s pension plan assets classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:.


(in millions)	Private Equity Securities			Hedge Funds			Timber Investments				Total
2010
Balance at January 1		$	55		$	1		$	6			$	62
Net realized and unrealized gains (losses)(a)			4			-			(1	)			3
Purchases, sales and distributions, net			10			-			-				10
Balance at December 31		$	69		$	1		$	5			$	75


(in millions)	Private Equity Securities				Hedge Funds			Timber Investments				Total
2009
Balance at January 1		$	49			$	1		$	8			$	58
Net realized and unrealized (losses)(a)			(4	)			-			(2	)			(6	)
Purchases, sales and distributions, net			10				-			-				10
Balance at December 31		$	55			$	1		$	6			$	62

(a)

Substantially all amounts relate to investments held at December 31.

194

PEF

The following table sets forth by level within the fair value hierarchy of PEF’s pension assets at December 31, 2010 and 2009. See Note 13 for detailed information regarding the fair value hierarchy.


		Pension Benefit Plan Assets
(in millions)	Level 1			Level 2			Level 3			Total
2010
Assets
Cash and cash equivalents		$	-		$	43		$	-	$	43
International equity securities			18			-			-		18
Domestic equity securities			132			-			-		132
Private equity securities			-			-			68		68
Corporate bonds			-			99			-		99
U.S. state and municipal debt			-			9			-		9
U.S. and foreign government debt			66			14			-		80
Commingled funds			-			391			-		391
Hedge funds			-			23			1		24
Timber investments			-			-			5		5
Interest rate swaps and other investments			-			2			-		2
Fair value of plan assets		$	216		$	581		$	74	$	871


		Pension Benefit Plan Assets
(in millions)	Level 1			Level 2			Level 3			Total
2009
Assets
Cash and cash equivalents		$	-		$	46		$	-	$	46
Domestic equity securities			125			-			-		125
Private equity securities			-			-			58		58
Corporate bonds			-			32			-		32
U.S. state and municipal debt			-			2			-		2
U.S. and foreign government debt			12			45			-		57
Mortgage backed securities			-			10			-		10
Commingled funds			-			421			-		421
Hedge funds			-			22			1		23
Timber investments			-			-			7		7
Interest rate swaps and other investments			-			26			-		26
Total assets		$	137		$	604		$	66	$	807
Liabilities
Foreign currency contracts			2			-			-		2
Interest rate swaps and other investments			-			11			-		11
Total liabilities			2			11			-		13
Fair value of plan assets		$	135		$	593		$	66	$	794

PEF’s other postretirement benefit plan assets had a fair value of $33 million and $32 million, which consisted of U.S. state and municipal assets classified as Level 2 in the fair value hierarchy at December 31, 2010 and 2009, respectively.

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A reconciliation of changes in the fair value of PEF’s pension plan assets classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:


(in millions)	Private Equity Securities			Hedge Funds			Timber Investments				Total
2010
Balance at January 1		$	58		$	1		$	7			$	66
Net realized and unrealized (losses)(a)			3			-			(1	)			2
Purchases, sales and distributions, net			7			-			(1	)			6
Balance at December 31		$	68		$	1		$	5			$	74


(in millions)	Private Equity Securities				Hedge Funds			Timber Investments				Total
2009
Balance at January 1		$	53			$	1		$	9			$	63
Net realized and unrealized (losses)(a)			(5	)			-			(2	)			(7	)
Purchases, sales and distributions, net			10				-			-				10
Balance at December 31		$	58			$	1		$	7			$	66

(a)

Substantially all amounts relate to investments held at December 31.

For Progress Energy, PEC and PEF, the determination of the fair values of pension and postretirement plan assets incorporates various factors required under GAAP. The assets of the plan include exchange traded securities (classified within Level 1) and other marketable debt and equity securities, most of which are valued using Level 1 inputs for similar instruments, and are classified within Level 2 investments.

Most over-the-counter investments are valued using observable inputs for similar instruments or prices from similar transactions and are classified as Level 2. Over-the-counter investments where significant unobservable inputs are used, such as financial pricing models, are classified as Level 3 investments.

Investments in private equity are valued using observable inputs, when available, and also include comparable market transactions, income and cost basis valuation techniques. The market approach includes using comparable market transactions or values. The income approach generally consists of the net present value of estimated future cash flows, adjusted as appropriate for liquidity, credit, market and/or other risk factors. Private equity investments are classified as Level 3 investments.

Investments in commingled funds are not publically traded, but the underlying assets held in these funds are traded in active markets and the prices for these assets are readily observable. Holdings in commingled funds are classified as Level 2 investments.

Hedge funds are based primarily on the net asset values and other financial information provided by management of the private investment funds. Hedge funds are classified as Level 2 if the plan is able to redeem the investment with the investee at net asset value as of the measurement date, or at a later date within a reasonable period of time. Hedge funds are classified as Level 3 if the investment cannot be redeemed at net asset value or it cannot be determined when the fund will be redeemed.

Investments in timber are valued primarily on valuations prepared by independent property appraisers. These appraisals are based on cash flow analysis, current market capitalization rates, recent comparable sales transactions, actual sales negotiations and bona fide purchase offers. Inputs include the species, age, volume and condition of timber stands growing on the land; the location, productivity, capacity and accessibility of the timber tracts; current and expected log prices; and current local prices for comparable investments. Timber investments are classified as Level 3 investments.

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CONTRIBUTION AND BENEFIT PAYMENT EXPECTATIONS

In 2011, we expect to make contributions of $300 million-$400 million directly to pension plan assets and $1 million of discretionary contributions directly to the OPEB plan assets. The expected benefit payments for the pension benefit plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $168, $176, $178, $189, $193 and $1,016, respectively. The expected benefit payments for the OPEB plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $45, $48, $51, $53, $56 and $306, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from our assets. The benefit payment amounts reflect our net cost after any participant contributions and do not reflect reductions for expected prescription drug-related federal subsidies. The expected federal subsidies for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $4, $5, $5, $6, $6 and $43, respectively.

In 2011, PEC expects to make contributions of $200 million-$250 million directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $86, $90, $89, $95, $96 and $476, respectively. The expected benefit payments for the OPEB plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $20, $22, $24, $26, $27 and $152, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from PEC assets. The benefit payment amounts reflect the net cost to PEC after any participant contributions and do not reflect reductions for expected prescription drug-related federal subsidies. The expected federal subsidies for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $2, $2, $3, $3, $3 and $22, respectively.

In 2011, PEF expects to make contributions of $100 million-$150 million directly to pension plan assets and expects to make $1 million of discretionary contributions to OPEB plan assets. The expected benefit payments for the pension benefit plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $62, $65, $67, $69, $73 and $411, respectively. The expected benefit payments for the OPEB plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $22, $22, $23, $24, $25 and $132, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from PEF’s assets. The benefit payment amounts reflect the net cost to PEF after any participant contributions and do not reflect reductions for expected prescription drug-related federal subsidies. The expected federal subsidies for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $2, $2, $2, $3, $3 and $17, respectively.

The Patient Protection and Affordable Care Act (PPACA) and the related Health Care and Education Reconciliation Act, which made various amendments to the PPACA, were enacted in March 2010. The PPACA contains a provision that changes the tax treatment related to a federal subsidy available to sponsors of retiree health benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to the benefits under Medicare Part D. The subsidy is known as the Retiree Drug Subsidy. Employers are not currently taxed on the Retiree Drug Subsidy payments they receive. However, as a result of the PPACA as amended, Retiree Drug Subsidy payments will effectively become taxable in tax years beginning after December 31, 2012, by requiring the amount of the subsidy received to be offset against the employer's deduction for health care expenses. Under GAAP, changes in tax law are accounted for in the period of enactment. Accordingly, an additional tax expense of $22 million for us, including $12 million for PEC and $10 million for PEF has been recognized during the year ended December 31, 2010.

B.	FLORIDA PROGRESS ACQUISITION

During 2000, we completed our acquisition of Florida Progress. Florida Progress’ pension and OPEB liabilities, assets and net periodic costs are reflected in the above information as appropriate. Certain of Florida Progress’ nonbargaining unit benefit plans were merged with our benefit plans effective January 1, 2002.

PEF continues to recover qualified plan pension costs and OPEB costs in rates as if the acquisition had not occurred. The information presented in Note 16A is adjusted as appropriate to reflect PEF’s rate treatment.

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17.	RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations.

See Note 13B for information about the fair value of derivatives.

A.	COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value.

ECONOMIC DERIVATIVES

Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions.

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2011 and 2012. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled (See Note 7A). After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

Certain hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $164 million and $146 million on the Progress Energy Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. At December 31, 2010, Progress Energy had 259.9 million MMBtu notional of natural gas and 20.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $24 million and $7 million on the PEC Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. At December 31, 2010, PEC had 64.0 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases.

PEF’s cash collateral asset included in derivative collateral posted was $140 million and $139 million on the PEF Balance Sheets at December 31, 2010 and 2009, respectively. At December 31, 2010, PEF had 195.9 million MMBtu notional of natural gas and 20.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

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B.	INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates.

CASH FLOW HEDGES

At December 31, 2010, all open interest rate hedges will reach their mandatory termination dates within three years. At December 31, 2010, including amounts related to terminated hedges, we had $63 million of after-tax losses, including $33 million and $4 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income related to forward starting swaps. It is expected that in the next twelve months losses of $7 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $4 million at PEC. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in the timing of debt issuances at the Parent and the Utilities and changes in market value of currently open forward starting swaps.

At December 31, 2009, including amounts related to terminated hedges, we had $35 million of after-tax losses, including $27 million of after-tax losses at PEC and $3 million of after-tax gains at PEF, recorded in accumulated other comprehensive income related to forward starting swaps.

At December 31, 2008, including amounts related to terminated hedges, we had $56 million of after-tax losses, including $35 million of after-tax losses at PEC, recorded in accumulated other comprehensive income related to forward starting swaps.

At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. During January 2011, Progress Energy terminated $300 million notional of forward starting swaps in conjunction with the issuance of debt (See Note 11A).

At December 31, 2009, Progress Energy had $325 million notional of open forward starting swaps, including $100 million at PEC and $75 million at PEF.

FAIR VALUE HEDGES

For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At December 31, 2010 and 2009, neither we nor the Utilities had any outstanding positions in such contracts.

C.	CONTINGENT FEATURES

Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company’s credit rating with Moody’s, S&P and Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions.

In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody’s, S&P and Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions.

199

The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position at December 31, 2010, is $446 million, for which Progress Energy has posted collateral of $164 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at December 31, 2010, Progress Energy would have been required to post an additional $282 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position at December 31, 2010 is $118 million, for which PEC has posted collateral of $24 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at December 31, 2010, PEC would have been required to post an additional $94 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position at December 31, 2010 is $328 million, for which PEF has posted collateral of $140 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on December 31, 2010, PEF would have been required to post an additional $188 million of collateral with its counterparties.

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D.	DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

The following table presents the fair value of derivative instruments at December 31:

Instrument / Balance sheet location	2010					2009
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets	$	1				$	5
Other assets and deferred debits		3					14
Derivative liabilities, current				$	32				$	-
Derivative liabilities, long-term					7					-
Total derivatives designated as hedging instruments		4			39		19			-

Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		11					11
Other assets and deferred debits		4					9
Derivative liabilities, current					226					189
Derivative liabilities, long-term					268					236
CVOs(b)
Other liabilities and deferred credits					15					15
Fair value of derivatives not designated as hedging instruments		15			509		20			440
Fair value loss transition adjustment(c)
Derivative liabilities, current					1					1
Derivative liabilities, long-term					3					4
Total derivatives not designated as hedging instruments		15			513		20			445
Total derivatives	$	19		$	552	$	39		$	445

(a)

Substantially all of these contracts receive regulatory treatment.

(b)

The Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000 (See Note 15).

(c)

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the adoption of new accounting guidance for derivatives. The related liability is being amortized to earnings over the term of the related contracts.

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The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Income for the years ended December 31:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)								Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)									Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2010			2009		2008			2010			2009			2008			2010		2009			2008
Commodity cash flow derivatives	$	-		$	1	$	(2	)	$	-		$	-		$	-		$	-	$	-		$	-
Interest rate derivatives(c) (d)		(34	)		15		(35	)		(6	)		(6	)		(3	)		3		(3	)		1
Total	$	(34	)	$	16	$	(37	)	$	(6	)	$	(6	)	$	(3	)	$	3	$	(3	)	$	1

(a)

Effective portion.

(b)

Related to ineffective portion and amount excluded from effectiveness testing.

(c)

Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.

(d)

Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)									Unrealized Gain or (Loss)(b)
(in millions)		2010			2009			2008			2010			2009			2008
Commodity derivatives(a)		$	(324	)	$	(659	)	$	174		$	(398	)	$	(387	)	$	(653	)

(a)

After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

(b)

Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2010		2009		2008
Commodity derivatives(a)	$	-	$	1	$	(3	)
Fair value loss transition adjustment(a)		1		2	$	3
CVOs(a)		-		19		-
Total	$	1	$	22	$	-

(a)

Amounts recorded in the Consolidated Statements of Income are classified in other, net.

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PEC

The following table presents the fair value of derivative instruments at December 31:


Instrument / Balance sheet location	2010					2009
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Other assets and deferred debits	$	3				$	8
Derivative liabilities, current				$	7				$	-
Other liabilities and deferred credits					4					-
Total derivatives designated as hedging instruments		3			11		8			-

Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		1					-
Other assets and deferred debits		1					-
Derivative liabilities, current					45					28
Other liabilities and deferred credits					78					62
Fair value of derivatives not designated as hedging instruments		2			123		-			90
Fair value loss transition adjustment(b)
Derivative liabilities, current					1					1
Other liabilities and deferred credits					3					4
Total derivatives not designated as hedging instruments		2			127		-			95
Total derivatives	$	5		$	138	$	8		$	95

(a)

Substantially all of these contracts receive regulatory treatment.

(b)

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Income for the years ended December 31:


Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)								Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)									Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2010			2009		2008			2010			2009			2008			2010		2009			2008
Commodity cash flow derivatives	$	-		$	-	$	(1	)	$	-		$	-		$	-		$	-	$	-		$	-
Interest rate derivatives(c) (d)		(10	)		5		(25	)		(4	)		(3	)		(1	)		-		(2	)		-
Total	$	(10	)	$	5	$	(26	)	$	(4	)	$	(3	)	$	(1	)	$	-	$	(2	)	$	-

(a)

Effective portion.

(b)

Related to ineffective portion and amount excluded from effectiveness testing.

(c)

(d)

Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

203

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)									Unrealized Gain or (Loss)(b)
(in millions)		2010			2009			2008			2010			2009			2008
Commodity derivatives		$	(46	)	$	(76	)		2		$	(77	)	$	(68	)	$	(110	)

(a)

After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

(b)

Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2010		2009		2008
Commodity derivatives(a)	$	-	$	1	$	(3	)
Fair value loss transition adjustment(a)		1		2	$	3
Total	$	1	$	3	$	-

(a)

Amounts recorded in the Consolidated Statements of Income are classified in other, net.

PEF

The following table presents the fair value of derivative instruments at December 31:

Instrument / Balance sheet location	2010					2009
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets	$	-				$	5
Derivative liabilities, current				$	7				$	-
Total derivatives designated as hedging instruments		-			7		5			-

Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		10					11
Other assets and deferred debits		3					9
Derivative liabilities, current					181					161
Derivative liabilities, long-term					190					174
Total derivatives not designated as hedging instruments		13			371		20			335
Total derivatives	$	13		$	378	$	25		$	335

(a)

Substantially all of these contracts receive regulatory treatment.

204

The following tables present the effect of derivative instruments on the Statements of Comprehensive Income and the Statements of Income for the years ended December 31:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)								Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2010			2009		2008			2010		2009		2008		2010		2009		2008
Commodity cash flow derivatives	$	-		$	1	$	(1	)	$	-	$	-	$	-	$	-	$	-	$	-
Interest rate derivatives(c) (d)		(7	)		3		8			-		-		-		-		-		1
Total	$	(7	)	$	4	$	7		$	-	$	-	$	-	$	-	$	-	$	1

(a)

Effective portion.

(b)

Related to ineffective portion and amount excluded from effectiveness testing.

(c)

(d)

Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)								Unrealized Gain or (Loss)(b)
(in millions)	2010			2009			2008		2010			2009			2008
Commodity derivatives	$	(278	)	$	(583	)	$	172	$	(321	)	$	(319	)	$	(543	)

(a)

After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

(b)

Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.

18.	RELATED PARTY TRANSACTIONS

As a part of normal business, we enter into various agreements providing financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees may include performance obligations under power supply agreements, transmission agreements, gas agreements, fuel procurement agreements, trading operations and cash management. Our guarantees also include standby letters of credit and surety bonds. At December 31, 2010, the Parent had issued $473 million of guarantees for future financial or performance assurance on behalf of its subsidiaries. This includes $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries (See Note 23). We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included on the Consolidated Balance Sheets.

Our subsidiaries provide and receive services, at cost, to and from the Parent and its subsidiaries, in accordance with agreements approved by the SEC pursuant to Section 13(b) of the Public Utility Holding Company Act of 1935. The repeal of the Public Utility Holding Company Act of 1935 effective February 8, 2006, and subsequent regulation by the FERC did not change our current intercompany services. Services include purchasing, human resources, accounting, legal, transmission and delivery support, engineering materials, contract support, loaned employees payroll costs, construction management and other centralized administrative, management and support services. The costs of the services are billed on a direct-charge basis, whenever possible, and on allocation factors for general costs that cannot be directly attributed. Billings from affiliates are capitalized or expensed depending on the nature

205

of the services rendered. Amounts receivable from and/or payable to affiliated companies for these services are included in receivables from affiliated companies and payables to affiliated companies on the Balance Sheets.

PESC provides the majority of the affiliated goods and services under the approved agreements. Goods and services provided by PESC during 2010, 2009 and 2008 to PEC amounted to $176 million, $170 million and $194 million, respectively, and services provided to PEF were $156 million, $147 million and $160 million, respectively. During 2010, PESC transferred a $24 million combustion turbine to PEC at cost (See Note 6).

PEC and PEF also provide and receive goods and services at cost. Goods and services provided by PEC to PEF during 2010, 2009 and 2008 amounted to $43 million, $36 million and $44 million, respectively. Goods and services provided by PEF to PEC during 2010, 2009 and 2008 amounted to $18 million, $12 million and $12 million, respectively.

PEC and PEF participate in an internal money pool, operated by Progress Energy, to more effectively utilize cash resources and to reduce outside short-term borrowings. The money pool is also used to settle intercompany balances. The weighted-average interest rate for the money pool was 0.30%, 0.74% and 3.29% for the years ended December 31, 2010, 2009 and 2008, respectively. Amounts payable to the money pool are included in notes payable to affiliated companies on the Balance Sheets. PEC and PEF recorded insignificant interest expense related to the money pool for all the years presented.

PEC and its wholly owned subsidiaries and PEF have entered into the Tax Agreement with the Parent (See Note 14).

19.	FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and PESC and other miscellaneous nonregulated businesses that do not separately meet the quantitative thresholds for disclosure as separate reportable business segments.

Products and services are sold between the various reportable segments. All intersegment transactions are at cost.

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In the following tables, capital and investment expenditures include property additions, acquisitions of nuclear fuel and other capital investments.

(in millions)	PEC		PEF		Corporate and Other			Eliminations			Total
At and for the year ended December 31, 2010
Revenues
Unaffiliated	$	4,922	$	5,252	$	16		$	-		$	10,190
Intersegment		-		2		248			(250	)		-
Total revenues		4,922		5,254		264			(250	)		10,190
Depreciation, amortization and accretion		479		426		15			-			920
Interest income		3		1		31			(28	)		7
Total interest charges, net		186		258		331			(28	)		747
Income tax expense (benefit)(a)		342		267		(87	)		-			522
Ongoing Earnings (loss)		618		462		(191	)		-			889
Total assets		14,899		14,056		21,110			(17,011	)		33,054
Capital and investment expenditures		1,382		991		33			(24	)		2,382

At and for the year ended December 31, 2009
Revenues
Unaffiliated	$	4,627	$	5,249	$	9		$	-		$	9,885
Intersegment		-		2		234			(236	)		-
Total revenues		4,627		5,251		243			(236	)		9,885
Depreciation, amortization and accretion		470		502		14			-			986
Interest income		5		4		38			(33	)		14
Total interest charges, net		195		231		286			(33	)		679
Income tax expense (benefit)(a)		295		209		(88	)		-			416
Ongoing Earnings (loss)		540		460		(154	)		-			846
Total assets		13,502		13,100		20,538			(15,904	)		31,236
Capital and investment expenditures		962		1,532		21			(12	)		2,503

At and for the year ended December 31, 2008
Revenues
Unaffiliated	$	4,429	$	4,730	$	8		$	-		$	9,167
Intersegment		-		1		361			(362	)		-
Total revenues		4,429		4,731		369			(362	)		9,167
Depreciation, amortization and accretion		518		306		15			-			839
Interest income		12		9		38			(35	)		24
Total interest charges, net		207		208		259			(35	)		639
Income tax expense (benefit)(a)		298		181		(87	)		-			392
Ongoing Earnings (loss)		531		383		(138	)		-			776
Total assets		13,165		12,471		17,483			(13,246	)		29,873
Capital and investment expenditures		939		1,601		33			(13	)		2,560

(a)

Income tax expense (benefit) excludes the tax impact of Ongoing Earnings adjustments.

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Management uses the non-GAAP financial measure “Ongoing Earnings” as a performance measure to evaluate the results of our segments and operations. Ongoing Earnings is computed as GAAP net income attributable to controlling interests after excluding discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Management has identified the following Ongoing Earnings adjustments: CVO mark-to-market adjustments because we are unable to predict changes in their fair value and the impact from changes in the tax treatment of the Medicare Part D subsidy because GAAP requires that the impact of the tax law change be accounted for in the period of enactment rather than the affected tax year. Additionally, management has determined that impairments, charges (and subsequent adjustments, if any) recognized for the retirement of generating units prior to the end of their estimated useful lives, cumulative prior period adjustments, net valuation allowances and operating results of discontinued operations are not representative of our ongoing operations and should be excluded in computing Ongoing Earnings.

Reconciliations of consolidated Ongoing Earnings to net income attributable to controlling interests for the years ended December 31 follow:

(in millions)	2010			2009			2008
Ongoing Earnings	$	889		$	846		$	776
CVO mark-to-market (Note 15)		-			19			-
Impairment, net of tax benefit of $4 and $1		(6	)		(2	)		-
Plant retirement adjustment, net of tax benefit of $1 and $11		(1	)		(17	)		-
Change in tax treatment of the Medicare Part D subsidy (Note 16)		(22	)		-			-
Cumulative prior period adjustment related to certain employee life insurance benefits, net of tax benefit of $7		-			(10	)		-
Valuation allowance and related net operating loss carry forward		-			-			(3	)
Continuing income attributable to noncontrolling interests, net of tax		7			4			5
Income from continuing operations		867			840			778
Discontinued operations, net of tax		(4	)		(79	)		58
Net income attributable to noncontrolling interests, net of tax		(7	)		(4	)		(6	)
Net income attributable to controlling interests	$	856		$	757		$	830

20.	OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income; AFUDC equity, which represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets; and other, net. The components of other, net as shown on the accompanying Statements of Income are presented below. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities.

PROGRESS ENERGY
(in millions)	2010			2009			2008
Nonregulated energy and delivery services income, net	$	10		$	17		$	17
CVOs unrealized gain, net (Note 15)		-			19			-
Investment gains (losses), net		9			(9	)		(13	)
Donations		(23	)		(20	)		(25	)
Other, net		4			(1	)		4
Other, net	$	-		$	6		$	(17	)

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PEC
(in millions)	2010			2009			2008
Nonregulated energy and delivery services income, net	$	-		$	6		$	11
Investment gains (losses), net		2			(21	)		-
Donations		(9	)		(10	)		(14	)
Other, net		7			7			7
Other, net	$	-		$	(18	)	$	4

PEF
(in millions)	2010			2009			2008
Nonregulated energy and delivery services income, net	$	11		$	11		$	8
Donations		(13	)		(10	)		(11	)
Investment gains, net		4			7			(9	)
Other, net		(3	)		(3	)		2
Other, net	$	(1	)	$	5		$	(10	)

21.	ENVIRONMENTAL MATTERS

A.	HAZARDOUS AND SOLID WASTE

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the United States Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Note 7). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities’ coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. On June 21, 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in late 2011 or 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and

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additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M on the Income Statements to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:


PROGRESS ENERGY
(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2009	$	22		$	20		$	42
Amount accrued for environmental loss contingencies(a)		8			13			21
Expenditures for environmental loss contingencies(a)		(10	)		(18	)		(28	)
Balance, December 31, 2010(b)	$	20		$	15		$	35

Balance, December 31, 2008	$	31		$	22		$	53
Amount accrued for environmental loss contingencies(a)		3			13			16
Expenditures for environmental loss contingencies(a)		(12	)		(15	)		(27	)
Balance, December 31, 2009(b)	$	22		$	20		$	42

(a)	Amounts accrued and expenditures are for the years ended December 31. For the year ended December 31, 2008, we accrued $8 million for the remediation of MGP and other sites and $17 million for the remediation of distribution and substation transformers. For the year ended December 31, 2008, we spent $8 million for the remediation of MGP and other sites and $28 million for the remediation of distribution and substation transformers.
(b)	Expected to be paid out over one to 15 years.

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PEC
(in millions)	MGP and Other Sites
Balance, December 31, 2009	$	13
Amount accrued for environmental loss contingencies(a)		3
Expenditures for environmental loss contingencies(a)		(4	)
Balance, December 31, 2010(b)	$	12

Balance, December 31, 2008	$	16
Amount accrued for environmental loss contingencies(a)		3
Expenditures for environmental loss contingencies(a)		(6	)
Balance, December 31, 2009(b)	$	13

(a)	Amounts accrued and expenditures are for the years ended December 31. For the year ended December 31, 2008, PEC accrued and spent approximately $8 million.
(b)	Expected to be paid out over one to five years.

PEF
(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2009	$	9		$	20		$	29
Amount accrued for environmental loss contingencies(a)		5			13			18
Expenditures for environmental loss contingencies(a)		(6	)		(18	)		(24	)
Balance, December 31, 2010(b)	$	8		$	15		$	23

Balance, December 31, 2008	$	15		$	22		$	37
Amount accrued for environmental loss contingencies(a)		-			13			13
Expenditures for environmental loss contingencies(a)		(6	)		(15	)		(21	)
Balance, December 31, 2009(b)	$	9		$	20		$	29

(a)	Amounts accrued and expenditures are for the years ended December 31. For the year ended December 31, 2008, PEF accrued approximately $17 million and spent approximately $28 million, which primarily related to distribution and substation transformers.
(b)	Expected to be paid out over one to 15 years.

PROGRESS ENERGY

In addition to the Utilities’ sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 22C).

PEC

PEC has recorded a minimum estimated total remediation cost for all of its remaining MGP sites based upon its historical experience with remediation of several of its MGP sites. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. (Ward) site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At December 31, 2010 and December 31, 2009, PEC’s recorded liability for the site was approximately $5 million and $4 million, respectively. In 2008 and 2009, PEC filed civil actions against PRPs

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seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. On March 24, 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. The court also set a trial date for May 7, 2012. On June 15, 2010, the court entered a case management order and discovery is proceeding. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. In 2009, PEC and several of the other participating PRPs at the Ward site submitted a letter containing a good faith response to the EPA’s special notice letter. Another group of PRPs separately submitted a good faith response, which the EPA advised would be used to negotiate implementation of the required actions. The other PRPs’ good faith response was subsequently withdrawn. Discussions among representatives of certain PRPs, including PEC, and the EPA are ongoing. Although a loss is considered probable, an agreement among the PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.

PEF

The accruals for PEF’s MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed all distribution transformer sites and all substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M costs will not be recoverable through the ECRC. At December 31, 2010 and December 31, 2009, PEF has recorded a regulatory asset for the probable recovery of costs through the ECRC related to the sites included under the agreement with the FDEP.

B.	AIR AND WATER QUALITY

At December 31, 2010 and 2009, we were subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury regulation. PEC’s environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions have been placed in service. PEF’s CAIR projects have been placed in service.

In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court’s prior opinion. On August 2, 2010, the EPA published the proposed Transport Rule, which is the regulatory program that will replace the CAIR when finalized. The proposed Transport Rule contains new emissions trading programs for nitrogen oxides (NOx) and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets. The EPA plans to finalize the Transport Rule in the spring of 2011. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are well positioned to comply with the Transport Rule. The outcome of the EPA’s rulemaking cannot be predicted. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, the current implementation of the CAIR continues to fulfill best available retrofit technology (BART) for NOx and SO2

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for BART-affected units under the CAVR. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units.

In 2008, the D.C. Court of Appeals vacated the CAMR. As a result, the EPA subsequently announced that it will develop a maximum achievable control technology (MACT) standard. The United States District Court for the District of Columbia has issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. In addition, North Carolina adopted a state-specific requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of these decisions. The outcome of this matter cannot be predicted.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5). The CR4 project was placed in service in May 2010 and the CR5 project was placed in service in December 2009. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 7C, PEF identified in its 2010 nuclear cost-recovery filing regulatory and economic conditions causing schedule shifts such that major construction activities are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

The EPA is continuing to record allowance allocations under the CAIR NOx trading program, in some cases for years beyond the estimated 2011 finalization of the Transport Rule. The EPA’s continued recording of CAIR NOx allowance allocations does not guarantee that allowances will continue to be usable for compliance after a replacement rule is finalized or that they will continue to have value in the future. SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements. PEF’s CAIR expenses, including NOx allowance inventory expense, are recoverable through the ECRC. At December 31, 2010 and 2009, PEC had approximately $8 million and $13 million, respectively, in SO2 emission allowances and an immaterial amount of NOx emission allowances. At December 31, 2010 and 2009, PEF had approximately $5 million and $7 million, respectively, in SO2 emission allowances and approximately $28 million and $36 million, respectively, in NOx emission allowances.

22.	COMMITMENTS AND CONTINGENCIES

A.	PURCHASE OBLIGATIONS

In most cases, our purchase obligation contracts contain provisions for price adjustments, minimum purchase levels and other financial commitments. The commitment amounts presented below are estimates and therefore will likely differ from actual purchase amounts. At December 31, 2010, the following tables reflect contractual cash obligations and other commercial commitments in the respective periods in which they are due:

Progress Energy
(in millions)	2011		2012		2013		2014		2015		Thereafter		Total
Fuel(a)	$	2,407	$	2,365	$	1,985	$	1,441	$	1,224	$	6,719	$	16,141
Purchased power		475		457		440		382		389		3,461		5,604
Construction obligations(a)		507		230		122		51		55		14		979
Other purchase obligations		122		72		66		41		69		697		1,067
Total	$	3,511	$	3,124	$	2,613	$	1,915	$	1,737	$	10,891	$	23,791

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PEC
(in millions)	2011		2012		2013		2014		2015		Thereafter		Total
Fuel	$	1,269	$	1,202	$	1,130	$	846	$	816	$	2,764	$	8,027
Purchased power		98		80		73		68		69		427		815
Construction obligations		450		199		75		8		-		-		732
Other purchase obligations		39		25		15		19		39		303		440
Total	$	1,856	$	1,506	$	1,293	$	941	$	924	$	3,494	$	10,014

PEF
(in millions)	2011		2012		2013		2014		2015		Thereafter		Total
Fuel(a)	$	1,138	$	1,163	$	855	$	595	$	408	$	3,955	$	8,114
Purchased power		377		377		367		314		320		3,034		4,789
Construction obligations(a)		57		31		47		43		55		14		247
Other purchase obligations		59		39		48		22		30		394		592
Total	$	1,631	$	1,610	$	1,317	$	974	$	813	$	7,397	$	13,742

(a)

PEF signed an engineering, procurement and construction (EPC) agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two approximately 1,100-MW Westinghouse AP1000 nuclear units planned for construction at Levy. Due to uncertainty regarding the ultimate magnitude and timing of obligations under the EPC agreement and the Levy nuclear fabrication contract, the table includes only the obligations related to the selected components of long lead time equipment as discussed under “Fuel and Purchased Power” and "Construction Obligations.”

FUEL AND PURCHASED POWER

Through our subsidiaries, we have entered into various long-term contracts for coal, oil, gas and nuclear fuel as well as transportation agreements for the related fuel. Our purchases under these commitments were $2.890 billion, $2.921 billion and $3.078 billion for 2010, 2009 and 2008, respectively. PEC’s total purchases under these commitments for its generating plants were $1.489 billion, $1.527 billion and $1.446 billion in 2010, 2009 and 2008, respectively. PEF’s purchases totaled $1.401 billion, $1.394 billion and $1.632 billion in 2010, 2009 and 2008, respectively. Essentially all fuel and certain purchased power costs incurred by PEC and PEF are eligible for recovery through their respective cost-recovery clauses.

In December 2008, PEF entered into a nuclear fuel fabrication contract for the planned Levy nuclear units. The construction schedule and startup dates were subsequently revised. (See discussion following under “Construction Obligations.”) This approximately $400 million contract (for fuel plus related core components), which is excluded from the previous table, is for the period from 2019 through 2033, and contains exit provisions with termination fees that vary based on the circumstance.

Both PEC and PEF have ongoing purchased power contracts, including renewable energy contracts, with certain co-generators, primarily qualified facilities (QFs), with expiration dates ranging from 2011 to 2030. These purchased power contracts generally provide for capacity and energy payments or bundled capacity and energy payments.

PEC executed two long-term tolling agreements for the purchase of all of the power generated from Broad River LLC’s Broad River facility. One agreement provides for the purchase of approximately 500 MW of capacity through May 2021 with average minimum annual payments of approximately $24 million, primarily representing capital-related capacity costs. The second agreement provides for the additional purchase of approximately 335 MW of capacity through February 2022 with average annual payments of approximately $24 million representing capital-related capacity costs. Total purchases for both capacity and energy under the Broad River LLC’s Broad River facility agreements amounted to $115 million, $46 million and $44 million in 2010, 2009 and 2008, respectively.

In 2007, PEC executed long-term agreements for the purchase of power from Southern Power Company. The agreements provide for firm unit capacity and energy purchases of 305 MW (68 percent of net output) for 2010, 310 MW (30 percent of net output) for 2011 and 150 MW (33 percent of net output) annually thereafter through 2019. Estimated payments for capacity under the agreements are approximately $25 million for 2011 and $12 million

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annually thereafter through 2019. Total purchases for both capacity and energy under the agreements were $92 million in 2010.

PEC has various pay-for-performance contracts with QFs, including renewable energy, for approximately 31 MW of firm capacity expiring at various times through 2030. In most cases, these contracts account for 100 percent of the net generating capacity of each of the facilities. Payments for both capacity and energy are contingent upon the QFs’ ability to generate. Payments made under these contracts were $8 million, $24 million and $55 million in 2010, 2009 and 2008, respectively.

PEF has firm contracts for approximately 657 MW of purchased power with other utilities, including a contract with Southern Company for approximately 424 MW (25 percent of net output) of purchased power annually, which started in 2010 and extends into 2016. A contract with Southern Company for approximately 414 MW (12 percent of net output) of purchased power ended in 2010. Total purchases, for both energy and capacity, under agreements with other utilities amounted to $189 million, $149 million and $178 million for 2010, 2009 and 2008, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $64 million, $53 million, $46 million, $65 million and $65 million for 2011 through 2015, respectively, and $24 million payable thereafter.

PEF has ongoing purchased power contracts with certain QFs for 682 MW of firm capacity with expiration dates ranging from 2011 to 2025. Energy payments are based on the actual power taken under these contracts. Capacity payments are subject to the QFs meeting certain contract performance obligations. In most cases, these contracts account for 100 percent of the net generating capacity of each of the facilities. All ongoing commitments have been approved by the FPSC. Total capacity and energy payments made under these contracts amounted to $469 million, $435 million and $440 million for 2010, 2009 and 2008, respectively. Minimum expected future capacity payments under these contracts are $300 million, $313 million, $309 million, $238 million and $244 million for 2011 through 2015, respectively, and $3.006 billion payable thereafter. The FPSC allows the capacity payments to be recovered through a capacity cost-recovery clause, which is similar to, and works in conjunction with, energy payments recovered through the fuel cost-recovery clause.

In 2009, PEC executed a long-term coal transportation agreement by combining, amending and restating previous agreements with Norfolk Southern Railroad. This agreement will support PEC’s coal supply needs through June 2020. Expected future transportation payments under this agreement are $223 million, $235 million, $224 million, $213 million and $218 million for 2011 through 2015, respectively, with approximately $1.322 billion payable thereafter. Coal transportation expenses under these agreements were approximately $231 million and $283 million for 2010 and 2009, respectively. PEC’s state utility commissions allow fuel-related costs to be recovered through fuel cost-recovery clauses.

PEC has entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs. Certain agreements are for the period from May 2011 through May 2033. The estimated total cost to PEC associated with these agreements is approximately $2.042 billion, approximately $426 million of which will be classified as a capital lease. Due to the conditions of the capital lease agreement, the capital lease will not be recorded on PEC’s balance sheet until approximately 2012. The transactions are subject to several conditions precedent, including various state regulatory approvals, the completion and commencement of operation of necessary related interstate and intrastate natural gas pipeline system expansions and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEC’s fuel commitments or in PEC’s capital lease assets or obligations.

In April 2008, (and as amended in February 2009), PEF entered into a conditional contract with a pipeline entity for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with this agreement is estimated to be approximately $890 million. In addition to this contract, PEF has entered into additional gas transportation arrangements for the period from 2011 through 2036. The total current notional cost of these additional agreements is estimated to be approximately $281 million. All of these contracts are subject to conditions precedent, including the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEF’s fuel commitments.

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CONSTRUCTION OBLIGATIONS

We have purchase obligations related to various capital construction projects. Our total payments under these contracts were $703 million, $818 million and $1.018 billion for 2010, 2009 and 2008, respectively.

PEC has purchase obligations related to various capital projects including new generation and transmission obligations. Total payments under PEC’s construction-related contracts were $555 million, $199 million and $140 million for 2010, 2009 and 2008, respectively. Payments for 2010 primarily relate to construction of generating facilities at our sites in Richmond County, N.C., Wayne County, N.C., and New Hanover County, N.C., as discussed in Note 7B.

PEF made payments of $63 million, $243 million and $117 million for 2010, 2009 and 2008, respectively, toward long lead equipment and engineering related to the Levy EPC. Additionally, PEF has other construction obligations related to various capital projects including new generation, transmission and environmental compliance. Total payments under PEF’s other construction-related contracts were $84 million, $376 million and $761 million for 2010, 2009 and 2008, respectively.

The future construction obligations presented in the previous tables for Progress Energy and PEF exclude the EPC agreement. The EPC agreement includes provisions for termination. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. As discussed in Note 7C in PEF’s 2010 nuclear cost-recovery filing, PEF identified a schedule shift in the Levy project that resulted from the NRC’s 2009 determination that certain schedule-critical work that PEF had proposed to perform within the scope of its Limited Work Authorization request submitted with the combined license (COL) application will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work anticipated in the initial schedule cannot begin until the COL is issued, resulting in a project shift of at least 20 months. Since then, regulatory and economic conditions identified in the 2010 nuclear cost-recovery filing have changed such that major construction activities on the Levy project are being postponed until after the NRC issues the COL, expected in 2013 if the current licensing schedule remains on track. We executed an amendment to the EPC agreement in 2010 due to the schedule shifts. Prior to the amendment, estimated payments and associated escalations were $8.608 billion for the multi-year contract and did not assume any joint ownership. Because we have executed an amendment to the EPC agreement and anticipate negotiating additional amendments upon receipt of the COL, we cannot currently predict the timing of when those obligations will be satisfied or the magnitude of any change. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items, which have total remaining estimated payments and associated escalations of approximately $1.250 billion. PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. In its April 30, 2010 nuclear cost-recovery filing, PEF included for rate-making purposes a point estimate of potential Levy disposition fees and charges of $50 million, subject to true-up. However, the amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed. We cannot predict the outcome of this matter.

OTHER PURCHASE OBLIGATIONS

We have various other contractual obligations primarily related to PESC service contracts for operational services, PEC service agreements related to its Richmond County, N.C., Wayne County, N.C., and New Hanover County, N.C., generating facilities, and PEF service agreements related to the Hines Energy Complex and the Bartow Plant. Our payments under these agreements were $124 million, $56 million and $110 million for 2010, 2009 and 2008, respectively.

PEC has various other purchase obligations, including obligations for parts and equipment, limestone supply and fleet vehicles. Total purchases under these contracts were $55 million, $14 million and $18 million for 2010, 2009 and 2008, respectively.

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On October 1, 2010, PEC entered into long-term service agreements for its Richmond County, N.C., Wayne County, N.C., and New Hanover County, N.C., generating facilities, covering projected maintenance events for each facility through 2033, 2028 and 2029, respectively. The total cost to PEC associated with these agreements is estimated to be approximately $379 million over the term of the agreements. Expected future payments under these agreements are $6 million, $7 million, $11 million, $16 million and $36 million for 2011 through 2015, respectively, with approximately $303 million payable thereafter. Total purchases under these agreements were not material for 2010.

Among PEF’s other purchase obligations, PEF has long-term service agreements for the Hines Energy Complex and the Bartow Plant, emission obligations and fleet vehicles. Total payments under these contracts were $35 million, $22 million and $58 million for 2010, 2009 and 2008, respectively. Future obligations are primarily comprised of the long-term service agreements.

LEASES

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates. Some rental payments for transportation equipment include minimum rentals plus contingent rentals based on mileage. These contingent rentals are not significant. Our rent expense under operating leases totaled $39 million, $37 million and $38 million for 2010, 2009 and 2008, respectively. Our purchased power expense under agreements classified as operating leases was approximately $61 million, $11 million and $152 million in 2010, 2009 and 2008, respectively.

PEC’s rent expense under operating leases totaled $25 million, $26 million and $26 million during 2010, 2009 and 2008, respectively. These amounts include rent expense allocated from PESC to PEC of $5 million in 2010, 2009 and 2008. Purchased power expense under agreements classified as operating leases was approximately $38 million, $11 million and $9 million in 2010, 2009 and 2008, respectively.

PEF’s rent expense under operating leases totaled $14 million, $11 million and $11 million during 2010, 2009 and 2008, respectively. These amounts include rent expense allocated from PESC to PEF of $3 million in 2010, 2009 and 2008. Purchased power expense under agreements classified as operating leases was approximately $23 million and $142 million in 2010 and 2008, respectively. PEF had no purchased power expense under operating lease agreements for 2009.

Assets recorded under capital leases, including plant related to purchased power agreements, at December 31 consisted of:

	Progress Energy						PEC						PEF
(in millions)	2010			2009			2010			2009			2010			2009
Buildings	$	267		$	267		$	30		$	30		$	237		$	237
Less: Accumulated amortization		(46	)		(37	)		(17	)		(15	)		(29	)		(22	)
Total	$	221		$	230		$	13		$	15		$	208		$	215

Consistent with the ratemaking treatment for capital leases, capital lease expenses are charged to the same accounts that would be used if the leases were operating leases. Thus, our and the Utilities’ capital lease expense is generally included in O&M or purchased power expense. Our capital lease expense totaled $25 million, $26 million and $26 million for 2010, 2009 and 2008, respectively, which was primarily comprised of PEF’s capital lease expense of $23 million, $24 million and $24 million for 2010, 2009 and 2008, respectively.

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At December 31, 2010, minimum annual payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable operating and capital leases were:

	Progress Energy					PEC					PEF
(in millions)	Capital			Operating		Capital			Operating		Capital			Operating
2011	$	28		$	37	$	2		$	23	$	26		$	10
2012		28			55		2			22		26			30
2013		36			80		10			43		26			35
2014		26			78		-			42		26			34
2015		25			77		-			43		25			33
Thereafter		227			866		6			515		221			350
Minimum annual payments		370			1,193		20			688		350			492
Less amount representing imputed interest		(149	)				(7	)				(142	)
Total	$	221		$	1,193	$	13		$	688	$	208		$	492

In 2003, we entered into an operating lease for a building for which minimum annual rental payments are approximately $7 million. The lease term expires July 2035 and provides for no rental payments during the last 15 years of the lease, during which period $53 million of rental expense will be recorded in the Consolidated Statements of Income.

In 2008, PEC entered into a 336-MW (100 percent of net output) tolling purchased power agreement, which is classified as an operating lease. The agreement calls for an approximately $18 million initial minimum payment with minimum annual payments from 2013 through 2032 escalating at a rate of 2.5 percent, for a total of approximately $460 million.

In 2009, PEC entered into a 240-MW (100 percent of net output) tolling purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $10 million from July 2012 through September 2017, for a total of approximately $52 million.

In 2007, PEF entered into a 632-MW (100 percent of net output) tolling purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $28 million from June 2012 through May 2027, for a total of approximately $420 million.

In 2005, PEF entered into an agreement for a capital lease for a building completed during 2006. The lease term expires March 2047 and provides for minimum annual payments from 2007 through 2026 and no payments from 2027 through 2047. The minimum annual payments are approximately $5 million, for a total of approximately $103 million. During the last 20 years of the lease, approximately $51 million of rental expense will be recorded in the Statements of Income.

In 2006, PEF extended the terms of a 517-MW (100 percent of net output) tolling agreement for purchased power, which is classified as a capital lease of the related plant, for an additional 10 years. The agreement calls for minimum annual payments of approximately $21 million from April 2007 through April 2024, for a total of approximately $348 million.

The Utilities are lessors of electric poles, streetlights and other facilities. PEC’s minimum rentals receivable under noncancelable leases were $11 million for 2011 and none thereafter. PEC’s rents received are contingent upon usage and totaled $33 million, $34 million, $33 million for 2010, 2009 and 2008, respectively. PEF’s rents received are based on a fixed minimum rental where price varies by type of equipment or contingent usage and totaled $85 million, $84 million and $81 million for 2010, 2009 and 2008, respectively. PEF’s minimum rentals receivable under noncancelable leases are not material for 2011 and thereafter.

C.	GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At December 31,

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2010, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Balance Sheets.

At December 31, 2010, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At December 31, 2010, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $307 million, including $31 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. At December 31, 2010 and 2009, we had recorded liabilities related to guarantees and indemnifications to third parties of approximately $31 million and $34 million, respectively. These amounts included $6 million and $7 million for PEF at December 31, 2010 and 2009, respectively. During the year ended December 31, 2010, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 23).

D.	OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 21).

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts with the DOE under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities on or before January 31, 1998. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. The Utilities have asserted nearly $91 million in damages incurred between January 31, 1998, and December 31, 2005, the time period set by the court for damages in this case. The Utilities may file subsequent damage claims as they incur additional costs.

In 2008, the Utilities received a ruling from the United States Court of Federal Claims awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. A request for reconsideration filed by the United States Department of Justice resulted in an immaterial reduction of the award. Substantially all of the award relates to costs incurred by PEC. On August 15, 2008, the Department of Justice appealed the United States Court of Federal Claims ruling to the D.C. Court of Appeals. On July 21, 2009, the D.C. Court of Appeals vacated and remanded the calculation of damages back to the Trial Court but affirmed the portion of damages awarded that were directed to overhead costs and other indirect expenses. The Department of Justice requested a rehearing en banc but the D.C. Court of Appeals denied the motion on November 3, 2009. In the event that the Utilities recover damages in this matter, such recovery will primarily offset capital assets and therefore is not expected to have a material impact on the Utilities’ results of operations. However, the Utilities cannot predict the outcome of this matter.

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SYNTHETIC FUELS MATTERS

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000 (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco; certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the expiration of the Section 29 tax credit program on December 31, 2007, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

The jury awarded Global $78 million. On October 23, 2009, Global filed a motion to assess prejudgment interest on the award. On November 20, 2009, the court granted the motion and assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. In December 2009, we made a $154 million payment, which represents payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. On December 17, 2010, we filed our initial appellate brief. We cannot predict the outcome of this matter.

In a second suit filed in the Superior Court for Wake County, N.C., Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), the Progress Affiliates seek declaratory relief consistent with our interpretation of the Asset Purchase Agreement. Global was served with the North Carolina Global Case on April 17, 2003.

On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates’ declaratory judgment action. On August 7, 2003, the Wake County Superior Court denied Global’s motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court’s order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

NOTICE OF VIOLATION

On April 29, 2009, the EPA issued a notice of violation and opportunity to show cause with respect to a 16,000-gallon oil spill at one of PEC’s substations in 2007. The notice of violation did not include specified sanctions sought. Subsequently, the EPA notified PEC that the agency was seeking monetary sanctions that are de minimus to our and PEC’s results of operations or financial condition. PEC has entered into consent agreements with the EPA resolving all issues and requiring de minimus payment of penalties and performance.

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FLORIDA NUCLEAR COST RECOVERY

On February 8, 2010, a lawsuit was filed against PEF in state circuit court in Sumter County, Fla., alleging that the Florida nuclear cost-recovery statute (Section 366.93, Florida Statutes) violates the Florida Constitution, and seeking a refund of all monies collected by PEF pursuant to that statute with interest. The complaint also requests that the court grant class action status to the plaintiffs. On April 6, 2010, PEF filed a motion to dismiss the complaint. The trial judge issued an order on May 3, 2010, dismissing the complaint. The plaintiffs filed an amended complaint on June 1, 2010. PEF believes the lawsuit is without merit and filed a motion to dismiss the amended complaint on July 12, 2010. On October 1, 2010, the plaintiffs filed an appeal of the trial court’s order dismissing the complaint. Initial and reply briefs have been filed by the appellants and PEF. The appellants filed their response brief on January 25, 2011. We cannot predict the outcome of this matter.

OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, we have made accruals and disclosures to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on our consolidated results of operations or financial position.

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23.	CONDENSED CONSOLIDATING STATEMENTS

Presented below are the Condensed Consolidating Statements of Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In September 2005, we issued our guarantee of certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are in addition to the previously issued guarantees of our wholly owned subsidiary, Florida Progress.

The Trust, a finance subsidiary, was established in 1999 for the sole purpose of issuing $300 million of 7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A (Preferred Securities) and using the proceeds thereof to purchase from Funding Corp. $300 million of 7.10% Junior Subordinated Deferrable Interest Notes due 2039 (Subordinated Notes). The Trust has no other operations and its sole assets are the Subordinated Notes and Notes Guarantee (as discussed below). Funding Corp. is a wholly owned subsidiary of Florida Progress and was formed for the sole purpose of providing financing to Florida Progress and its subsidiaries. Funding Corp. does not engage in business activities other than such financing and has no independent operations. Since 1999, Florida Progress has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes. In addition, Florida Progress guaranteed the payment of all distributions related to the Preferred Securities required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (the Preferred Securities Guarantee). The two guarantees considered together constitute a full and unconditional guarantee by Florida Progress of the Trust’s obligations under the Preferred Securities. The Preferred Securities and the Preferred Securities Guarantee are listed on the New York Stock Exchange.

The Subordinated Notes may be redeemed at the option of Funding Corp. at par value plus accrued interest through the redemption date. The proceeds of any redemption of the Subordinated Notes will be used by the Trust to redeem proportional amounts of the Preferred Securities and common securities in accordance with their terms. Upon liquidation or dissolution of Funding Corp., holders of the Preferred Securities would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. The annual interest expense related to the Subordinated Notes is reflected in the Consolidated Statements of Income.

We have guaranteed the payment of all distributions related to the Trust's Preferred Securities. At December 31, 2010, the Trust had outstanding 12 million shares of the Preferred Securities with a liquidation value of $300 million. Our guarantees are joint and several, full and unconditional, and are in addition to the joint and several, full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances, and as disclosed in Note 11B, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a variable-interest entity of which we are not the primary beneficiary. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.

In these condensed consolidating statements, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the consolidated financial results of Florida Progress only, which is primarily comprised of its wholly owned subsidiary PEF. The Non-Guarantor Subsidiaries column includes the consolidated financial results of all non-guarantor subsidiaries, which is primarily comprised of our wholly owned subsidiary PEC. The Other column includes elimination entries for all intercompany transactions and other consolidation adjustments. Financial statements for PEC and PEF are separately presented elsewhere in this Form 10-K. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the subsidiary guarantor or other non-guarantor subsidiaries operated as independent entities.

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Condensed Consolidating Statement of Income
Year ended December 31, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	5,268		$	4,922		$	-		$	10,190
Affiliate revenues		-			-			248			(248	)		-
Total operating revenues		-			5,268			5,170			(248	)		10,190
Operating expenses
Fuel used in electric generation		-			1,614			1,686			-			3,300
Purchased power		-			977			302			-			1,279
Operation and maintenance		7			912			1,345			(237	)		2,027
Depreciation, amortization and accretion		-			426			494			-			920
Taxes other than on income		-			362			225			(7	)		580
Other		-			17			13			-			30
Total operating expenses		7			4,308			4,065			(244	)		8,136
Operating (loss) income		(7	)		960			1,105			(4	)		2,054
Other income (expense)
Interest income		7			2			5			(7	)		7
Allowance for equity funds used during construction		-			28			64			-			92
Other, net		(1	)		1			(3	)		3			-
Total other income, net		6			31			66			(4	)		99
Interest charges
Interest charges		282			293			211			(7	)		779
Allowance for borrowed funds used during construction		-			(13	)		(19	)		-			(32	)
Total interest charges, net		282			280			192			(7	)		747
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(283	)		711			979			(1	)		1,406
Income tax (benefit) expense		(111	)		267			378			5			539
Equity in earnings of consolidated subsidiaries		1,027			-			-			(1,027	)		-
Income from continuing operations		855			444			601			(1,033	)		867
Discontinued operations, net of tax		1			(1	)		(4	)		-			(4	)
Net income		856			443			597			(1,033	)		863
Net (income) loss attributable to noncontrolling interests, net of tax		-			(4	)		1			(4	)		(7	)
Net income attributable to controlling interests	$	856		$	439		$	598		$	(1,037	)	$	856

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Condensed Consolidating Statement of Income
Year ended December 31, 2009
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	5,259		$	4,626		$	-		$	9,885
Affiliate revenues		-			-			235			(235	)		-
Total operating revenues		-			5,259			4,861			(235	)		9,885
Operating expenses
Fuel used in electric generation		-			2,072			1,680			-			3,752
Purchased power		-			682			229			-			911
Operation and maintenance		8			839			1,269			(222	)		1,894
Depreciation, amortization and accretion		-			502			484			-			986
Taxes other than on income		-			347			216			(6	)		557
Other		-			13			-			-			13
Total operating expenses		8			4,455			3,878			(228	)		8,113
Operating (loss) income		(8	)		804			983			(7	)		1,772
Other income (expense)
Interest income		10			5			9			(10	)		14
Allowance for equity funds used during construction		-			91			33			-			124
Other, net		18			6			(22	)		4			6
Total other income, net		28			102			20			(6	)		144
Interest charges
Interest charges		233			280			215			(10	)		718
Allowance for borrowed funds used during construction		-			(27	)		(12	)		-			(39	)
Total interest charges, net		233			253			203			(10	)		679
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(213	)		653			800			(3	)		1,237
Income tax (benefit) expense		(93	)		200			286			4			397
Equity in earnings of consolidated subsidiaries		875			-			-			(875	)		-
Income from continuing operations		755			453			514			(882	)		840
Discontinued operations, net of tax		2			(43	)		(38	)		-			(79	)
Net income		757			410			476			(882	)		761
Net (income) loss attributable to noncontrolling interests, net of tax		-			(3	)		2			(3	)		(4	)
Net income attributable to controlling interests	$	757		$	407		$	478		$	(885	)	$	757

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Condensed Consolidating Statement of Income
Year ended December 31, 2008
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.

Operating revenues
Operating revenues	$	-		$	4,738		$	4,429		$	-		$	9,167
Affiliate revenues		-			-			361			(361	)		-
Total operating revenues		-			4,738			4,790			(361	)		9,167
Operating expenses
Fuel used in electric generation		-			1,675			1,346			-			3,021
Purchased power		-			953			346			-			1,299
Operation and maintenance		3			813			1,346			(342	)		1,820
Depreciation, amortization and accretion		-			306			533			-			839
Taxes other than on income		-			309			207			(8	)		508
Other		-			1			(4	)		-			(3	)
Total operating expenses		3			4,057			3,774			(350	)		7,484
Operating (loss) income		(3	)		681			1,016			(11	)		1,683
Other income (expense)
Interest income		11			9			16			(12	)		24
Allowance for equity funds used during construction		-			95			27			-			122
Other, net		-			(18	)		(4	)		5			(17	)
Total other income, net		11			86			39			(7	)		129
Interest charges
Interest charges		201			263			227			(12	)		679
Allowance for borrowed funds used during construction		-			(28	)		(12	)		-			(40	)
Total interest charges, net		201			235			215			(12	)		639
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(193	)		532			840			(6	)		1,173
Income tax (benefit) expense		(85	)		172			306			2			395
Equity in earnings of consolidated subsidiaries		941			-			-			(941	)		-
Income from continuing operations		833			360			534			(949	)		778
Discontinued operations, net of tax		(3	)		61			-			-			58
Net income		830			421			534			(949	)		836
Net income attributable to noncontrolling interests, net of tax		-			(6	)		-			-			(6	)
Net income attributable to controlling interests	$	830		$	415		$	534		$	(949	)	$	830

225

Condensed Consolidating Balance Sheet
December 31, 2010
	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	10,189	$	10,961	$	90		$	21,240
Current assets
Cash and cash equivalents		110		270		231		-			611
Receivables, net		-		497		536		-			1,033
Notes receivable from affiliated companies		14		48		115		(177	)		-
Regulatory assets		-		105		71		-			176
Derivative collateral posted		-		140		24		-			164
Income taxes receivable		14		1		90		(53	)		52
Prepayments and other current assets		16		750		894		(220	)		1,440
Total current assets		154		1,811		1,961		(450	)		3,476
Deferred debits and other assets
Investment in consolidated subsidiaries		14,316		-		-		(14,316	)		-
Regulatory assets		-		1,387		987		-			2,374
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		554		1,017		-			1,571
Other assets and deferred debits		75		238		894		(469	)		738
Total deferred debits and other assets		14,391		2,179		2,898		(11,130	)		8,338
Total assets	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,023	$	4,957	$	5,686	$	(10,643	)	$	10,023
Noncontrolling interests		-		4		-		-			4
Total equity		10,023		4,961		5,686		(10,643	)		10,027
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		-		(36	)		273
Long-term debt, net		3,989		4,182		3,693		-			11,864
Total capitalization		14,012		9,486		9,438		(10,679	)		22,257
Current liabilities
Current portion of long-term debt		205		300		-		-			505
Notes payable to affiliated companies		-		175		3		(178	)		-
Derivative liabilities		18		188		53		-			259
Other current liabilities		278		1,002		1,184		(273	)		2,191
Total current liabilities		501		1,665		1,240		(451	)		2,955
Deferred credits and other liabilities
Noncurrent income tax liabilities		3		528		1,608		(443	)		1,696
Regulatory liabilities		-		1,084		1,461		90			2,635
Other liabilities and deferred credits		29		1,416		2,073		(7	)		3,511
Total deferred credits and other liabilities		32		3,028		5,142		(360	)		7,842
Total capitalization and liabilities	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054

226

Condensed Consolidating Balance Sheet
December 31, 2009
	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	9,733	$	9,886	$	114		$	19,733
Current assets
Cash and cash equivalents		606		72		47		-			725
Receivables, net		-		358		442		-			800
Notes receivable from affiliated companies		30		46		303		(379	)		-
Regulatory assets		-		54		88		-			142
Derivative collateral posted		-		139		7		-			146
Income taxes receivable		5		97		50		(7	)		145
Prepayments and other current assets		14		800		935		(176	)		1,573
Total current assets		655		1,566		1,872		(562	)		3,531
Deferred debits and other assets
Investment in consolidated subsidiaries		13,348		-		-		(13,348	)		-
Regulatory assets		-		1,307		873		(1	)		2,179
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		496		871		-			1,367
Other assets and deferred debits		166		202		923		(520	)		771
Total deferred debits and other assets		13,514		2,005		2,667		(10,214	)		7,972
Total assets	$	14,169	$	13,304	$	14,425	$	(10,662	)	$	31,236
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	9,449	$	4,590	$	5,085	$	(9,675	)	$	9,449
Noncontrolling interests		-		3		3		-			6
Total equity		9,449		4,593		5,088		(9,675	)		9,455
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		115		(152	)		272
Long-term debt, net		4,193		3,883		3,703		-			11,779
Total capitalization		13,642		8,819		8,965		(9,827	)		21,599
Current liabilities
Current portion of long-term debt		100		300		6		-			406
Short-term debt		140		-		-		-			140
Notes payable to affiliated companies		-		376		3		(379	)		-
Derivative liabilities		-		161		29		-			190
Other current liabilities		261		941		902		(182	)		1,922
Total current liabilities		501		1,778		940		(561	)		2,658
Deferred credits and other liabilities
Noncurrent income tax liabilities		-		320		1,258		(382	)		1,196
Regulatory liabilities		-		1,103		1,293		114			2,510
Other liabilities and deferred credits		26		1,284		1,969		(6	)		3,273
Total deferred credits and other liabilities		26		2,707		4,520		(274	)		6,979
Total capitalization and liabilities	$	14,169	$	13,304	$	14,425	$	(10,662	)	$	31,236

227

Condensed Consolidating Statement of Cash Flows
Year ended December 31, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	16		$	1,181		$	1,562		$	(222	)	$	2,537
Investing activities
Gross property additions		-			(1,014	)		(1,231	)		24			(2,221	)
Nuclear fuel additions		-			(38	)		(183	)		-			(221	)
Purchases of available-for-sale securities and other investments		-			(6,391	)		(618	)		-			(7,009	)
Proceeds from available-for-sale securities and other investments		-			6,395			595			-			6,990
Changes in advances to affiliated companies		15			(2	)		188			(201	)		-
Return of investment in consolidated subsidiaries		54			-			-			(54	)		-
Contributions to consolidated subsidiaries		(171	)		-			-			171			-
Other investing activities		113			60			3			(115	)		61
Net cash provided (used) by investing activities		11			(990	)		(1,246	)		(175	)		(2,400	)
Financing activities
Issuance of common stock, net		434			-			-			-			434
Dividends paid on common stock		(717	)		-			-			-			(717	)
Dividends paid to parent		-			(102	)		(100	)		202			-
Dividends paid to parent in excess of retained earnings		-			-			(54	)		54			-
Net decrease in short-term debt		(140	)		-			-			-			(140	)
Proceeds from issuance of long-term debt, net		-			591			-			-			591
Retirement of long-term debt		(100	)		(300	)		-			-			(400	)
Cash distributions to noncontrolling interest		-			(3	)		-			(3	)		(6	)
Changes in advances from affiliated companies		-			(201	)		-			201			-
Contributions from parent		-			33			152			(185	)		-
Other financing activities		-			(11	)		(130	)		128			(13	)
Net cash (used) provided by financing activities		(523	)		7			(132	)		397			(251	)
Net (decrease) increase in cash and cash equivalents		(496	)		198			184			-			(114	)
Cash and cash equivalents at beginning of year		606			72			47			-			725
Cash and cash equivalents at end of year	$	110		$	270		$	231		$	-		$	611

228

Condensed Consolidating Statement of Cash Flows
Year ended December 31, 2009
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	108		$	1,079		$	1,282		$	(198	)	$	2,271
Investing activities
Gross property additions		-			(1,449	)		(858	)		12			(2,295	)
Nuclear fuel additions		-			(78	)		(122	)		-			(200	)
Proceeds from sales of assets to affiliated companies		-			-			11			(11	)		-
Purchases of available-for-sale securities and other investments		-			(1,548	)		(802	)		-			(2,350	)
Proceeds from available-for-sale securities and other investments		-			1,558			756			-			2,314
Changes in advances to affiliated companies		4			(2	)		(172	)		170			-
Return of investment in consolidated subsidiaries		12			-			-			(12	)		-
Contributions to consolidated subsidiaries		(688	)		-			-			688			-
Other investing activities		-			-			(1	)		-			(1	)
Net cash used by investing activities		(672	)		(1,519	)		(1,188	)		847			(2,532	)
Financing activities
Issuance of common stock, net		623			-			-			-			623
Dividends paid on common stock		(693	)		-			-			-			(693	)
Dividends paid to parent		-			(1	)		(200	)		201			-
Dividends paid to parent in excess of retained earnings		-			-			(12	)		12			-
Payments of short-term debt with original maturities greater than 90 days		(629	)		-			-			-			(629	)
Net decrease in short-term debt		100			(371	)		(110	)		-			(381	)
Proceeds from issuance of long-term debt, net		1,683			-			595			-			2,278
Retirement of long-term debt		-			-			(400	)		-			(400	)
Cash distributions to noncontrolling interests		-			(3	)		-			(3	)		(6	)
Changes in advances from affiliated companies		-			170			-			(170	)		-
Contributions from parent		-			653			49			(702	)		-
Other financing activities		(2	)		(9	)		12			13			14
Net cash provided (used) by financing activities		1,082			439			(66	)		(649	)		806
Net increase (decrease) in cash and cash equivalents		518			(1	)		28			-			545
Cash and cash equivalents at beginning of year		88			73			19			-			180
Cash and cash equivalents at end of year	$	606		$	72		$	47		$	-		$	725

229

Condensed Consolidating Statement of Cash Flows
Year ended December 31, 2008
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(90	)	$	221		$	1,114		$	(27	)	$	1,218
Investing activities
Gross property additions		-			(1,553	)		(794	)		14			(2,333	)
Nuclear fuel additions		-			(43	)		(179	)		-			(222	)
Proceeds from sales of assets to affiliated companies		-			12			-			(12	)		-
Purchases of available-for-sale securities and other investments		(7	)		(783	)		(800	)		-			(1,590	)
Proceeds from available-for-sale securities and other investments		-			788			746			-			1,534
Changes in advances to affiliated companies		123			105			8			(236	)		-
Return of investment in consolidated subsidiaries		20			10			-			(30	)		-
Contributions to consolidated subsidiaries		(101	)		-			-			101			-
Other investing activities		-			57			13			-			70
Net cash provided (used) by investing activities		35			(1,407	)		(1,006	)		(163	)		(2,541	)
Financing activities
Issuance of common stock, net		132			-			-			-			132
Dividends paid on common stock		(642	)		-			-			-			(642	)
Dividends paid to parent		-			(33	)		-			33			-
Dividends paid to parent in excess of retained earnings		-			-			(20	)		20			-
Payments of short-term debt with original maturities greater than 90 days		(176	)		-			-			-			(176	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		629			-			-			-			629
Net increase in short-term debt		15			371			110			-			496
Proceeds from issuance of long-term debt, net		-			1,475			322			-			1,797
Retirement of long-term debt		-			(577	)		(300	)		-			(877	)
Cash distributions to noncontrolling interests		-			(85	)		(10	)		10			(85	)
Changes in advances from affiliated companies		-			(21	)		(215	)		236			-
Contributions from parent		-			85			29			(114	)		-
Other financing activities		-			1			(32	)		5			(26	)
Net cash (used) provided by financing activities		(42	)		1,216			(116	)		190			1,248
Net (decrease) increase in cash and cash equivalents		(97	)		30			(8	)		-			(75	)
Cash and cash equivalents at beginning of year		185			43			27			-			255
Cash and cash equivalents at end of year	$	88		$	73		$	19		$	-		$	180

230

24.	QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data was as follows:

Progress Energy
(in millions except per share data)	First		Second		Third		Fourth
2010
Operating revenues	$	2,535	$	2,372	$	2,962	$	2,321
Operating income		494		440		753		367
Income from continuing operations		191		181		365		130
Net income		190		180		365		128
Net income attributable to controlling interests		190		180		361		125
Common stock data
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax		0.67		0.62		1.23		0.43
Net income attributable to controlling interests		0.67		0.62		1.23		0.42
Dividends declared per common share		0.620		0.620		0.620		0.620
Market price per share
High		41.35		40.69		44.82		45.61
Low		37.04		37.13		38.96		43.08
2009
Operating revenues	$	2,442	$	2,312	$	2,824	$	2,307
Operating income		393		379		676		324
Income from continuing operations		183		175		350		132
Net income		183		174		248		156
Net income attributable to controlling interests		182		174		247		154
Common stock data
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax		0.66		0.62		1.24		0.46
Net income attributable to controlling interests		0.66		0.62		0.88		0.55
Dividends declared per common share		0.620		0.620		0.620		0.620
Market price per share
High		40.85		38.20		40.05		42.20
Low		31.35		33.50		35.97		36.67

In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Typically, weather conditions in our service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to our customers. As a result, our overall operating results may fluctuate substantially on a seasonal basis.

In the third quarter of 2009, we recognized $102 million of expense from discontinued operations attributable to controlling interests, net of tax, primarily related to a jury delivering a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates previously engaged in coal-based solid synthetic fuels operations. In the fourth quarter of 2009, we recognized $25 million of earnings from discontinued operations primarily related to the tax benefits associated with the payment of the judgment. See Note 22D for additional information.

During the fourth quarter of 2009, we recorded a cumulative prior period adjustment related to certain employee life insurance benefits. The impact of this adjustment decreased total other income, net, by $17 million and decreased net income attributable to controlling interests by $10 million. The prior period adjustment is not material to 2009 or previously issued financial statements.

231

PEC

Summarized quarterly financial data was as follows:


(in millions)	First		Second		Third		Fourth
2010
Operating revenues	$	1,263	$	1,117	$	1,414	$	1,128
Operating income		266		196		402		207
Net income		136		111		236		119
Net income attributable to controlling interests		138		112		234		119
2009
Operating revenues	$	1,178	$	1,076	$	1,307	$	1,066
Operating income		249		182		367		168
Net income		128		94		208		84
Net income attributable to controlling interests		128		95		208		85

In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Typically, weather conditions in PEC’s service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to its customers. As a result, its overall operating results may fluctuate substantially on a seasonal basis.

During the fourth quarter of 2009, PEC recorded a cumulative prior period adjustment related to certain employee life insurance benefits. The impact of this adjustment decreased total other income, net, by $16 million and decreased net income attributable to controlling interests by $10 million. The prior period adjustment is not material to 2009 or previously issued financial statements.

PEF

Summarized quarterly financial data was as follows:


(in millions)	First		Second		Third		Fourth
2010
Operating revenues	$	1,270	$	1,252	$	1,543	$	1,189
Operating income		222		244		344		149
Net income		102		119		180		52
2009
Operating revenues	$	1,262	$	1,234	$	1,516	$	1,239
Operating income		140		195		314		153
Net income		89		119		177		77

In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Typically, weather conditions in PEF’s service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to its customers. As a result, its overall operating results may fluctuate substantially on a seasonal basis.

232

25.	SUBSEQUENT EVENT - MERGER AGREEMENT

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The Merger Agreement contemplates a reverse stock split of Duke Energy stock, effective immediately prior to the Merger. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, which will be subject to the Merger being completed and receipt of the requisite approval of the shareholders at Duke Energy. Accordingly, the 2.6125 exchange ratio for Progress Energy common shares, options and equity awards will be adjusted based on Duke Energy’s reverse stock split.

The combined company, to be called Duke Energy, will have an 18-member board of directors. The board will be comprised of, subject to their ability and willingness to serve, all 11 current directors of Duke Energy and seven current directors of Progress Energy. At the time of the Merger, William D. Johnson, Chairman, President and CEO of Progress Energy, will be President and CEO of Duke Energy and James E. Rogers, Chairman, President and CEO of Duke Energy, will be the Executive Chairman of the board of directors of Duke Energy, subject to their ability and willingness to serve.

Consummation of the Merger is subject to customary conditions, including, among others things, approval of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission, the SCPSC, the FPSC, the Indiana Utility Regulatory Commission, and the Ohio Public Utilities Commission.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the Merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share.

The Merger Agreement contains certain termination rights for both companies and under specified circumstances we may be required to pay Duke Energy $400 million and Duke Energy may be required to pay us $675 million. In addition, under specified circumstances each party may be required to reimburse the other party for up to $30 million of merger-related expenses.

Progress Energy shareholders have filed class action lawsuits in the state and federal courts in North Carolina against Progress Energy and each of the members of Progress Energy’s board of directors. The lawsuits seek to prohibit the Merger and, in some cases, seek damages in the event that the Merger is completed. Progress Energy intends to vigorously defend against these claims. We cannot predict the outcome of this matter.

Further information concerning the proposed merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4 to be filed by us with the SEC in connection with the Merger.

233

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A.

CONTROLS AND PROCEDURES

PROGRESS ENERGY

DISCLOSURE CONTROLS AND PROCEDURES

Pursuant to the Securities Exchange Act of 1934, we carried out an evaluation, with the participation of management, including our Chairman, President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of Progress Energy’s management to establish and maintain adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Progress Energy’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes 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 Progress Energy; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America; (3) provide reasonable assurance that receipts and expenditures of Progress Energy are being made only in accordance with authorizations of management and directors of Progress Energy; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Progress Energy’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of Progress Energy’s internal control over financial reporting at December 31, 2010. Management based this assessment on criteria for effective internal control over financial reporting described in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Progress Energy’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit and Corporate Performance Committee (Audit Committee) of the board of directors.

Based on our assessment, management determined that, at December 31, 2010, Progress Energy maintained effective internal control over financial reporting.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the internal control over financial reporting of Progress Energy as of December 31, 2010, as stated in their report, which is included below.

234

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There has been no change in Progress Energy's internal control over financial reporting during the quarter ended December 31, 2010, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.:

We have audited the internal control over financial reporting of Progress Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010, 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 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 Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit 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, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

235

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and consolidated financial statement schedule as of and for the year ended December 31, 2010 of the Company, and our report dated February 28, 2011, expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2011

PEC

DISCLOSURE CONTROLS AND PROCEDURES

Pursuant to the Securities Exchange Act of 1934, PEC carried out an evaluation, with the participation of its management, including PEC’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of PEC’s disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEC’s Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by PEC in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to PEC’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of PEC’s management to establish and maintain adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. PEC’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes 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 PEC; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America; (3) provide reasonable assurance that receipts and expenditures of PEC are being made only in accordance with authorizations of management and directors of PEC; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PEC’s assets that could have a material effect on the financial statements.

Management assessed the effectiveness of PEC’s internal control over financial reporting at December 31, 2010. Management based this assessment on criteria for effective internal control over financial reporting described in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of PEC’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the board of directors.

Based on our assessment, management determined that, at December 31, 2010, PEC maintained effective internal control over financial reporting.

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting for PEC. As PEC is a non-accelerated filer, management’s report

236

is not subject to attestation by our independent registered public accounting firm pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There has been no change in PEC’s internal control over financial reporting during the quarter ended December 31, 2010, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

DISCLOSURE CONTROLS AND PROCEDURES

Pursuant to the Securities Exchange Act of 1934, PEF carried out an evaluation, with the participation of its management, including PEF’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of PEF’s disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEF’s Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by PEF in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to PEF’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of PEF’s management to establish and maintain adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. PEF’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes 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 PEF; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America; (3) provide reasonable assurance that receipts and expenditures of PEF are being made only in accordance with authorizations of management and directors of PEF; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PEF’s assets that could have a material effect on the financial statements.

Management assessed the effectiveness of PEF’s internal control over financial reporting at December 31, 2010. Management based this assessment on criteria for effective internal control over financial reporting described in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of PEF’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the board of directors.

Based on our assessment, management determined that, at December 31, 2010, PEF maintained effective internal control over financial reporting.

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting for PEF. As PEF is a non-accelerated filer, management’s report

237

is not subject to attestation by our independent registered public accounting firm pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There has been no change in PEF’s internal control over financial reporting during the quarter ended December 31, 2010, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding Progress Energy’s directors is set forth in Progress Energy’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein. Information regarding PEC’s directors is set forth in PEC’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

b)	Information regarding both Progress Energy’s and PEC’s executive officers is set forth in PART I and incorporated by reference herein.

We have adopted a Code of Ethics that applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller (or persons performing similar functions). Our board of directors has adopted our Code of Ethics as its own standard. Board members, Progress Energy officers and Progress Energy employees certify their compliance with the Code of Ethics on an annual basis. Our Code of Ethics is posted on our website at www.progress-energy.com/investor and is available in print to any shareholder upon written request.

We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of the Code of Ethics applicable to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller by posting such information on our website cited above.

d)	Information regarding the Audit and Corporate Performance Committee of Progress Energy’s board of directors is set forth in Progress Energy’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

PEC does not have a separate audit committee. Information regarding the responsibilities of the Audit and Corporate Performance Committee of Progress Energy’s board with respect to PEC is set forth in PEC’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

The board of directors has determined that Carlos A. Saladrigas and Theresa M. Stone are the “Audit Committee Financial Experts,” as that term is defined in the rules promulgated by the SEC pursuant to the Sarbanes-Oxley Act of 2002, and have designated them as such. Both Mr. Saladrigas and Ms. Stone are “independent,” as that term is defined in the general independence standards of the New York Stock Exchange listing standards.

f)	Information regarding our compliance with Section 16(a) of the Securities Exchange Act of 1934 and certain corporate governance matters is set forth in Progress Energy’s and PEC’s definitive proxy statements for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

g)	The following are available on our website cited above and in print at no cost:

·	Audit and Corporate Performance Committee Charter

·	Corporate Governance Committee Charter

·	Organization and Compensation Committee Charter

·	Corporate Governance Guidelines

The information called for by Item 10 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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ITEM 11.

EXECUTIVE COMPENSATION

Information regarding Progress Energy’s executive compensation and certain matters related to the Organization and Compensation Committee of Progress Energy’s board is set forth in Progress Energy’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein. Information regarding PEC’s executive compensation and PEC’s decision to delegate authority to approve senior management compensation to the Organization and Compensation Committee of Progress Energy’s board rather than having its own standing compensation committee is set forth in PEC’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

The information called for by Item 11 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

a)	Information regarding any person Progress Energy knows to be the beneficial owner of more than 5 percent of any class of its voting securities is set forth in its definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

Information regarding any person PEC knows to be the beneficial owner of more than 5 percent of any class of its voting securities is set forth in its definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

b)	Information regarding the security ownership of Progress Energy’s and PEC’s management is set forth, respectively, in Progress Energy’s and PEC’s definitive proxy statements for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

c)	Information regarding the equity compensation plans of Progress Energy is set forth under the heading “Equity Compensation Plan Information” in Progress Energy’s definitive proxy statement for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

The information called for by Item 12 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information regarding certain relationships and related transactions is set forth, respectively, in Progress Energy’s and PEC’s definitive proxy statements for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

The information called for by Item 13 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The Audit Committee has actively monitored all services provided by its independent registered public accounting firm, Deloitte & Touche LLP, the member firms of Deloitte & Touche Tohmatsu, and their respective affiliates (collectively, Deloitte) and the relationship between audit and nonaudit services provided by Deloitte. Progress Energy has adopted policies and procedures for approving all audit and permissible nonaudit services rendered by Deloitte, and the fees billed for those services. These policies and procedures apply to Progress Energy and its subsidiaries. Progress Energy’s Controller (the Controller) is responsible to the Audit Committee for enforcement of this procedure, and for reporting noncompliance. Pursuant to the preapproval policy, the Audit Committee specifically preapproved the use of Deloitte for audit, audit-related and tax services.

The preapproval policy requires management to obtain specific preapproval from the Audit Committee for the use of Deloitte for any permissible nonaudit services, which, generally, are limited to tax services, including tax compliance, tax planning, and tax advice services such as return review and consultation and assistance. Other types of permissible nonaudit services will not be considered for approval except in limited instances, which could include circumstances in which proposed services provide significant economic or other benefits to us. In determining whether to approve these services, the Audit Committee will assess whether these services adversely impair the independence of Deloitte. Any permissible nonaudit services provided during a fiscal year that (i) do not aggregate more than 5 percent of the total fees paid to Deloitte for all services rendered during that fiscal year and (ii) were not recognized as nonaudit services at the time of the engagement must be brought to the attention of the Controller for prompt submission to the Audit Committee for approval. These de minimis nonaudit services must be approved by the Audit Committee or its designated representative before the completion of the services. Nonaudit services that are specifically prohibited under Sarbanes-Oxley Act Section 404, SEC rules, and Public Company Accounting Oversight Board rules are specifically prohibited under the policy.

Prior to the approval of permissible tax services by the Audit Committee, the policy requires Deloitte to (1) describe in writing to the Audit Committee (a) the scope of the service, the fee structure for the engagement and any side letter or other amendment to the engagement letter or any other agreement between Progress Energy and Deloitte relating to the service and (b) any compensation arrangement or other agreement, such as a referral agreement, a referral fee or fee-sharing arrangement, between Deloitte and any person (other than Progress Energy) with respect to the promoting, marketing or recommending of a transaction covered by the service; and (2) discuss with the Audit Committee the potential effects of the services on the independence of Deloitte.

The policy also requires the Controller to update the Audit Committee throughout the year as to the services provided by Deloitte and the costs of those services. The policy also requires Deloitte to annually confirm its independence in accordance with SEC and New York Stock Exchange standards. The Audit Committee will assess the adequacy of this policy and related procedure as it deems necessary and revise accordingly.

Information regarding principal accountant fees and services is set forth, respectively, in Progress Energy’s and PEC’s definitive proxy statements for the 2011 Annual Meeting of Shareholders and incorporated by reference herein.

PEF

Set forth in the table below is certain information relating to the aggregate fees billed by Deloitte for professional services rendered to PEF for the fiscal years ended December 31.

	2010		2009
Audit fees	$	1,736,000	$	1,763,000
Audit-related fees		50,000		54,000
Tax fees		4,000		4,000
Total	$	1,790,000	$	1,821,000

Audit fees include fees billed for services rendered in connection with (i) the audits of the annual financial statements of PEF, (ii) the reviews of the financial statements included in the Quarterly Reports on Form 10-Q of PEF, (iii) accounting consultations arising as part of the audits and (iv) audit services in connection with statutory,

241

regulatory or other filings, including comfort letters and consents in connection with SEC filings and financing transactions.

Audit-related fees include fees billed for (i) special procedures and letter reports, (ii) benefit plan audits when fees are paid by PEF rather than directly by the plan, and (iii) accounting consultations for prospective transactions not arising directly from the audits.

Tax fees include fees billed for tax compliance matters and tax planning and advisory services.

The Audit Committee has concluded that the provision of the nonaudit services listed above as Tax fees is compatible with maintaining Deloitte’s independence.

None of the services provided was approved by the Audit Committee pursuant to the “de minimis” waiver provisions described above.

242

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a) The following documents are filed as part of the report:

	1.	Financial Statements Filed:

		See Item 8 - Financial Statements and Supplementary Data

	2.	Financial Statement Schedules Filed:

		Consolidated Financial Statement Schedules for the Years Ended December 31, 2010, 2009 and 2008:

		Schedule II - Valuation and Qualifying Accounts - Progress Energy, Inc.	244

		Schedule II - Valuation and Qualifying Accounts - Carolina Power & Light d/b/a Progress Energy Carolinas, Inc.	245

		Schedule II - Valuation and Qualifying Accounts - Florida Power Corporation d/b/a Progress Energy Florida, Inc.	246

		All other schedules have been omitted as not applicable or are not required because the information required to be shown is scheduled in the Financial Statements or the Combined Notes to the Financial Statements.

	3.	Exhibits Filed:

		See EXHIBIT INDEX

243

PROGRESS ENERGY, INC.

Schedule II - Valuation and Qualifying Accounts

For the Years Ended December 31

(in millions)


Description	Balance at Beginning of Period		Additions Charged to Expenses		Other Additions			Deductions(a)			Balance at End of Period

Valuation and qualifying accounts deducted on the balance sheet from the related assets:

2010
Uncollectible accounts	$	18	$	18	$	24	(b)	$	(25	)	$	35
Inventory valuation(c)		14		3		-			-			17
Fossil fuel plants dismantlement reserve		143		4		-			(3	)		144
Nuclear refueling outage reserve		5		13		-			(3	)		15
Deferred tax asset valuation allowance		55		5		-			-			60

2009
Uncollectible accounts	$	18	$	32	$	-		$	(32	)	$	18
Inventory valuation(c)		-		14		-			-			14
Fossil fuel plants dismantlement reserve		145		1		-			(3	)		143
Nuclear refueling outage reserve		14		18		-			(27	)		5
Deferred tax asset valuation allowance		55		-		-			-			55

2008
Uncollectible accounts	$	29	$	24	$	-		$	(35	)	$	18
Fossil fuel plants dismantlement reserve		144		1		-			-			145
Nuclear refueling outage reserve		2		12		-			-			14
Deferred tax asset valuation allowance		79		12		-			(36	)		55

(a)

Deductions from valuation accounts represent write-offs, net of recoveries, or the release of valuation allowances.

(b)

Includes $18 million related to other non-customer receivables.

(c)

Relates to the impact of PEC's decision to retire 11 coal-fired units prior to the end of their estimated useful lives.

244

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

Schedule II - Valuation and Qualifying Accounts

For the Years Ended December 31

(in millions)


Description	Balance at Beginning of Period		Additions Charged to Expenses		Other Additions		Deductions(a)			Balance at End of Period

Valuation and qualifying accounts deducted on the balance sheet from the related assets:

2010
Uncollectible accounts	$	8	$	3	$	2	$	(3	)	$	10
Inventory valuation(b)		14		3		-		-			17

2009
Uncollectible accounts	$	6	$	14	$	1	$	(13	)	$	8
Inventory valuation(b)		-		14		-		-			14

2008
Uncollectible accounts	$	6	$	10	$	-	$	(10	)	$	6

(a)

Deductions from valuation accounts represent write-offs, net of recoveries.

(b)

Relates to the impact of PEC's decision to retire 11 coal-fired units prior to the end of their estimated useful lives.

245

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

Schedule II - Valuation and Qualifying Accounts

For the Years Ended December 31

(in millions)


Description	Balance at Beginning of Period		Additions Charged to Expenses		Other Additions			Deductions(a)			Balance at End of Period

Valuation and qualifying accounts deducted on the balance sheet from the related assets:

2010
Uncollectible accounts	$	10	$	15	$	22	(b)	$	(22	)	$	25
Fossil fuel plants dismantlement reserve		143		4		-			(3	)		144
Nuclear refueling outage reserve		5		13		-			(3	)		15

2009
Uncollectible accounts	$	11	$	18	$	(1	)	$	(18	)	$	10
Fossil fuel plants dismantlement reserve		145		1		-			(3	)		143
Nuclear refueling outage reserve		14		18		-			(27	)		5

2008
Uncollectible accounts	$	10	$	14	$	1		$	(14	)	$	11
Fossil fuel plants dismantlement reserve		144		1		-			-			145
Nuclear refueling outage reserve		2		12		-			-			14

(a)

Deductions from valuation accounts represent write-offs, net of recoveries.

(b)

Includes $18 million related to other non-customer receivables.

246

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

	PROGRESS ENERGY, INC.
Date: February 28, 2011	(Registrant)

	By: /s/ William D. Johnson
	William D. Johnson
	Chairman, President and Chief Executive Officer

	By: /s/ Mark F. Mulhern
	Mark F. Mulhern
	Senior Vice President and Chief Financial Officer

	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer and Controller

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Signature	Title	Date


/s/ William D. Johnson	Chairman	February 28, 2011
(William D. Johnson)

/s/ John D. Baker II	Director	February 28, 2011
(John D. Baker II)

/s/ James E. Bostic, Jr.	Director	February 28, 2011
(James E. Bostic, Jr.)

/s/ Harris E. DeLoach, Jr.	Director	February 28, 2011
(Harris E. DeLoach, Jr.)

/s/ James B. Hyler, Jr.	Director	February 28, 2011
(James B. Hyler, Jr.)

/s/ Robert W. Jones	Director	February 28, 2011
(Robert W. Jones)

/s/ W. Steven Jones	Director	February 28, 2011
(W. Steven Jones)

/s/ Melquiades R. Martinez	Director	February 28, 2011
(Melquiades R. Martinez)

/s/ E. Marie McKee	Director	February 28, 2011
(E. Marie McKee)

247


/s/ John H. Mullin, III	Director	February 28, 2011
(John H. Mullin, III)

/s/ Charles W. Pryor, Jr.	Director	February 28, 2011
(Charles W. Pryor, Jr.)

/s/ Carlos A. Saladrigas	Director	February 28, 2011
(Carlos A. Saladrigas)

/s/ Theresa M. Stone	Director	February 28, 2011
(Theresa M. Stone)

/s/ Alfred C. Tollison, Jr.	Director	February 28, 2011
(Alfred C. Tollison, Jr.)

248

SIGNATURES

	CAROLINA POWER & LIGHT COMPANY
Date: February 28, 2011	(Registrant)

	By: /s/ Lloyd M. Yates
	Lloyd M. Yates
	President and Chief Executive Officer

	By: /s/ Mark F. Mulhern
	Mark F. Mulhern
	Senior Vice President and Chief Financial Officer

	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer

Signature	Title	Date


/s/ William D. Johnson	Chairman	February 28, 2011
(William D. Johnson)

/s/ Jeffrey A. Corbett	Director	February 28, 2011
(Jeffrey A. Corbett)

/s/ Jeffrey J. Lyash	Director	February 28, 2011
(Jeffrey J. Lyash)

/s/ John R. McArthur	Director	February 28, 2011
(John R. McArthur)

/s/ Mark F. Mulhern	Director	February 28, 2011
(Mark F. Mulhern)

/s/ James Scarola	Director	February 28, 2011
(James Scarola)

/s/ Paula J. Sims	Director	February 28, 2011
(Paula J. Sims)

/s/ Lloyd M. Yates	Director	February 28, 2011
(Lloyd M. Yates)

249

SIGNATURES

	FLORIDA POWER CORPORATION
Date: February 28, 2011	(Registrant)

	By: /s/ Vincent M. Dolan
	Vincent M. Dolan
	President and Chief Executive Officer

	By: /s/ Mark F. Mulhern
	Mark F. Mulhern
	Senior Vice President and Chief Financial Officer

	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer

Signature	Title	Date


/s/ William D. Johnson	Chairman	February 28, 2011
(William D. Johnson)

/s/ Vincent M. Dolan	Director	February 28, 2011
(Vincent M. Dolan)

/s/ Michael A. Lewis	Director	February 28, 2011
(Michael A. Lewis)

/s/ Jeffrey J. Lyash	Director	February 28, 2011
(Jeffrey J. Lyash)

/s/ John R. McArthur	Director	February 28, 2011
(John R. McArthur)

/s/ Mark F. Mulhern	Director	February 28, 2011
(Mark F. Mulhern)

/s/ Paula J. Sims	Director	February 28, 2011
(Paula J. Sims)

250

EXHIBIT INDEX

Number	Exhibit	Progress Energy, Inc.	PEC	PEF
*2a(1)	Agreement and Plan of Merger, dated as of January 8, 2011, by and among Duke Energy Corporation, Diamond Acquisition Corporation and Progress Energy, Inc. (filed as Exhibit 2.1 to the Current Report on Form 8-K dated January 8, 2011, File No. 1-15929).	X

*3a(1)	Restated Charter of Carolina Power & Light Company, as amended May 10, 1995 (filed as Exhibit No. 3(i) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1995, File No. 1-3382).		X

*3a(2)	Restated Charter of Carolina Power & Light Company as amended on May 10, 1996 (filed as Exhibit No. 3(i) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-3382).		X

*3a(3)	Amended and Restated Articles of Incorporation of Progress Energy, Inc. (f/k/a CP&L Energy, Inc.), as amended and restated on June 15, 2000 (filed as Exhibit No. 3a(1) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15929 and No. 1-3382).	X

*3a(4)	Amended and Restated Articles of Incorporation of Progress Energy, Inc. (f/k/a CP&L Energy, Inc.), as amended and restated on December 4, 2000 (filed as Exhibit 3b(1) to Annual Report on Form 10-K for the year ended December 31, 2001, as filed with the SEC on March 28, 2002, File No. 1-15929).	X

*3a(5)	Amended Articles of Incorporation of Progress Energy, Inc., as amended on May 10, 2006 (filed as Exhibit 3.A to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006, File No. 1-15929, 1-3382 and 1-3274).	X

*3a(6)	Amended Articles of Incorporation of Florida Power Corporation (filed as Exhibit 3(a) to the Progress Energy Florida Annual Report on Form 10-K for the year ended December 31, 1991, as filed with the SEC on March 30, 1992, File No. 1-3274).			X

*3b(1)	By-Laws of Progress Energy, Inc., as amended on May 10, 2006 (filed as Exhibit 3.B to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006, File No. 1-15929, 1-3382 and 1-3274).	X

251

*3b(2)	By-Laws of Carolina Power & Light Company, as amended on May 13, 2009 (filed as Exhibit 3.B to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-15929, 1-3382 and 1-3274).	X

*3b(3)	By-Laws of Florida Power Corporation, as amended September 20, 2010 (filed as Exhibit 3.1 to the Florida Power Corporation Current Report on Form 8-K, dated September 20, 2010, File No. 1-3274).		X

*4a(1)	Description of Preferred Stock and the rights of the holders thereof (as set forth in Article Fourth of the Restated Charter of Carolina Power & Light Company, as amended, and Sections 1-9, 15, 16, 22-27, and 31 of the By-Laws of Carolina Power & Light Company, as amended (filed as Exhibit 4(f), File No.33-25560).	X

*4a(2)	Statement of Classification of Shares dated January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company’s Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560).	X

*4a(3)	Statement of Classification of Shares dated September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company’s Serial Preferred Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560).	X

*4b(1)	Mortgage and Deed of Trust dated as of May 1, 1940 between Carolina Power & Light Company and The Bank of New York (formerly, Irving Trust Company) and Frederick G. Herbst (Douglas J. MacInnes, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); the Sixth through Sixty-sixth Supplemental Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No. 2-19118; Exhibit 4(b)-2, File No. 2-22439; Exhibit 4(b)-2, File No. 2-24624; Exhibit 2(c), File No. 2-27297; Exhibit 2(c), File No. 2-30172; Exhibit 2(c), File No. 2-35694; Exhibit 2(c), File No. 2-37505; Exhibit 2(c), File No. 2-39002; Exhibit 2(c), File No. 2-41738; Exhibit 2(c), File No. 2-43439; Exhibit 2(c), File No. 2-47751; Exhibit 2(c), File No. 2-49347; Exhibit 2(c), File No. 2-53113; Exhibit 2(d), File No. 2-53113; Exhibit 2(c), File No. 2-59511; Exhibit 2(c), File No. 2-61611; Exhibit 2(d), File No. 2-64189; Exhibit 2(c), File No. 2-65514; Exhibits 2(c) and 2(d), File No. 2-66851; Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File No. 2-81299; Exhibits 4(c)-1 through 4(c)-8, File No. 2-95505; Exhibits 4(b) through 4(h), File No. 33-25560; Exhibits 4(b) and 4(c), File No. 33-33431;		X

252

	Exhibits 4(b) and 4(c), File No. 33-38298; Exhibits 4(h) and 4(i), File No. 33-42869; Exhibits 4(e)-(g), File No. 33-48607; Exhibits 4(e) and 4(f), File No. 33-55060; Exhibits 4(e) and 4(f), File No. 33-60014; Exhibits 4(a) and 4(b) to Post-Effective Amendment No. 1, File No. 33-38349; Exhibit 4(e), File No. 33-50597; Exhibit 4(e) and 4(f), File No. 33-57835; Exhibit to Current Report on Form 8-K dated August 28, 1997, File No. 1-3382; Form of Carolina Power & Light Company First Mortgage Bond, 6.80% Series Due August 15, 2007 filed as Exhibit 4 to Form 10-Q for the period ended September 30, 1998, File No. 1-3382; Exhibit 4(b), File No. 333-69237; and Exhibit 4(c) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382.); and the Sixty-eighth Supplemental Indenture (Exhibit No. 4(b) to Current Report on Form 8-K dated April 20, 2000, File No. 1-3382; and the Sixty-ninth Supplemental Indenture (Exhibit No. 4b(2) to Annual Report on Form 10-K dated March 29, 2001, File No. 1-3382); and the Seventieth Supplemental Indenture, (Exhibit 4b(3) to Annual Report on Form 10-K dated March 29, 2001, File No. 1-3382); and the Seventy-first Supplemental Indenture (Exhibit 4b(2) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3382 and 1-15929); the Seventy-second Supplemental Indenture (Exhibit 4 to PEC Current Report on Form 8-K dated September 12, 2003, File No. 1-3382); the Seventy-third Supplemental Indenture (Exhibit 4 to PEC Current Report on Form 8-K dated March 22, 2005, File No. 1-3382); the Seventy-fourth Supplemental Indenture (Exhibit 4 to PEC Current Report on Form 8-K dated November 30, 2005, File No. 1-3382); the Seventy-fifth Supplemental Indenture (Exhibit 4 to PEC Current Report on Form 8-K dated March 13, 2008, File No. 1-3382); the Seventy-sixth Supplemental Indenture (Exhibit 4 to PEC Current Report on Form 8-K dated January 8, 2009, File No. 1-3382); and the Seventy-seventh Supplemental Indenture (Exhibit 4 to PEC Current Report on Form 8-K dated June 18, 2009, File No. 1-3382).

*4b(2)	Indenture, dated as of January 1, 1944 (the "Indenture"), between Florida Power Corporation and Guaranty Trust Company of New York and The Florida National Bank of Jacksonville, as Trustees (filed as Exhibit B-18 to Florida Power's Registration Statement on Form A-2) (No. 2-5293) filed with the SEC on January 24, 1944).	X

*4b(3)	Seventh Supplemental Indenture (filed as Exhibit 4(b) to Florida Power Corporation's Registration Statement on Form S-3 (No. 33-16788) filed with the SEC on September 27, 1991); and the Eighth Supplemental Indenture (filed as Exhibit 4(c) to Florida Power Corporation's Registration Statement on Form S-3 (No. 33-16788) filed with the SEC on September 27, 1991); and the Sixteenth Supplemental Indenture (filed as Exhibit	X

253

	4(d) to Florida Power Corporation's Registration Statement on Form S-3 (No. 33-16788) filed with the SEC on September 27, 1991); and the Twenty-ninth Supplemental Indenture (filed as Exhibit 4(c) to Florida Power Corporation's Registration Statement on Form S-3 (No. 2-79832) filed with the SEC on September 17, 1982); and the Thirty-eighth Supplemental Indenture (filed as exhibit 4(f) to Florida Power's Registration Statement on Form S-3 (No. 33-55273) as filed with the SEC on August 29, 1994); and the Thirty-ninth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on July 23, 2001); and the Fortieth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on February 18, 2003); and the Forty-first Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on February 21, 2003); and the Forty-second Supplemental Indenture (filed as Exhibit 4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 filed with the SEC on September 11, 2003); and the Forty-third Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on November 21, 2003); and the Forty-fourth Supplemental Indenture (filed as Exhibit 4.(m) to the Progress Energy Florida Annual Report on Form 10-K dated March 16, 2005); and the Forty-fifth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K, filed on May 16, 2005); and the Forty-sixth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on September 19, 2007); the Forty-seventh Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on December 13, 2007); the Forty-eighth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on June 18, 2008); and the Forty-ninth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on March 25, 2010).

*4b(4)	Indenture, dated as of December 7, 2005, between Florida Power Corporation and J.P. Morgan Trust Company, National Association, as Trustee with respect to Senior Notes, (filed as Exhibit 4(a) to Current Report on Form 8-K dated December 13, 2005, File No. 1-3274).			X

*4b(5)	Indenture, dated as of February 15, 2001, between Progress Energy, Inc. and Bank One Trust Company, N.A., as Trustee, with respect to Senior Notes (filed as Exhibit 4(a) to Form 8-K dated February 27, 2001, File No. 1-15929).	X

*4c	Indenture (for Senior Notes), dated as of March 1, 1999 between Carolina Power & Light Company and The Bank of New York, as Trustee, (filed as Exhibit No. 4(a) to		X

254

	Current Report on Form 8-K dated March 19, 1999, File No. 1-3382), and the First and Second Supplemental Senior Note Indentures thereto (Exhibit No. 4(b) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382); Exhibit No. 4(a) to Current Report on Form 8-K dated April 20, 2000, File No. 1-3382).

*4d	Indenture (For Debt Securities), dated as of October 28, 1999 between Carolina Power & Light Company and The Chase Manhattan Bank, as Trustee (filed as Exhibit 4(a) to Current Report on Form 8-K dated November 5, 1999, File No. 1-3382), (Exhibit 4(b) to Current Report on Form 8-K dated November 5, 1999, File No. 1-3382).		X

*4e	Contingent Value Obligation Agreement, dated as of November 30, 2000, between CP&L Energy, Inc. and The Chase Manhattan Bank, as Trustee (Exhibit 4.1 to Current Report on Form 8-K dated December 12, 2000, File No. 1-3382).	X

*10a(1)	Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560).		X

*10a(2)	Operating and Fuel Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560).		X

*10a(3)	Power Coordination Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency and amending letter dated January 29, 1982 (filed as Exhibit 10(c), File No. 33-25560).		X

*10a(4)	Amendment dated December 16, 1982 to Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560).		X

*10b(1)

Progress Energy, Inc. $1,130,000,000 5-Year Revolving Credit Agreement dated as of May 3, 2006 (filed as

255

	Exhibit 10(c) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, File No. 1-15929, 1-3274 and 1-3382).

*10b(2)	Carolina Power & Light Company 3-Year $750,000,000 Credit Agreement, dated as of October 15, 2010 (filed as Exhibit 10.1 to Current Report on Form 8-K dated October 15, 2010, File No. 1-15929, 1-3382 and 1-3274).		X

*10b(3)	Florida Power Corporation 3-Year $750,000,000 Credit Agreement, dated as of October 15, 2010 (filed as Exhibit 10.2 to Current Report on Form 8-K dated October 15, 2010, File No. 1-15929, 1-3382 and 1-3274).			X

-+*10c(1)	Retirement Plan for Outside Directors (filed as Exhibit 10(i), File No. 33-25560).		X

+*10c(2)	Resolutions of Board of Directors dated July 9, 1997, amending the Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company.		X

+*10c(3)	Progress Energy, Inc. Form of Stock Option Agreement (filed as Exhibit 4.4 to Form S-8 dated September 27, 2001, File No. 333-70332).	X	X	X

+*10c(4)	Progress Energy, Inc. Form of Stock Option Award (filed as Exhibit 4.5 to Form S-8 dated September 27, 2001, File No. 333-70332).	X	X	X

+*10c(5)	2002 Progress Energy, Inc. Equity Incentive Plan, Amended and Restated effective January 1, 2007 (filed as Exhibit 10c(5) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

+*10c(6)	Amended and Restated Broad-Based Performance Share Sub-Plan, Exhibit B to the 2002 Progress Energy, Inc. Equity Incentive Plan, effective January 1, 2007 (filed as Exhibit 10c(6) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

+*10c(7)	Amended and Restated Executive and Key Manager Performance Share Sub-Plan, Exhibit A to the 2002 Progress Energy, Inc. Equity Incentive Plan (effective January 1, 2007) (filed as Exhibit 10c(7) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

256

+*10c(8)	Progress Energy, Inc. 2007 Equity Incentive Plan (filed as Exhibit C to Form DEF 14A, as filed with the SEC on March 30, 2007, File No. 1-15929).	X	X	X

+*10c(9)	Executive and Key Manager 2007 Performance Share Sub-Plan, Exhibit A to the 2007 Equity Incentive Plan, effective January 1, 2007 (filed as Exhibit 10.1 to Current Report on Form 8-K dated July 16, 2007, File No. 1- 15929, No. 1-3382 and No. 1-3274).	X	X	X

+*10c(10)	Amended and Restated Management Deferred Compensation Plan of Progress Energy, Inc., effective as of January 1, 2007 (filed as Exhibit 10c(9) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

+*10c(11)	Amended and Restated Non-Employee Director Deferred Compensation Plan of Progress Energy, Inc., effective January 1, 2007 (filed as Exhibit 10c(11) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

+*10c(12)	Amended and Restated Restoration Retirement Plan of Progress Energy, Inc., effective January 1, 2007 (filed as Exhibit 10c(12) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

+*10c(13)	Amended and Restated Non-Employee Director Stock Unit Plan of Progress Energy, Inc., effective January 1, 2007 (filed as Exhibit 10c(14) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).	X	X	X

+*10c(14)	Form of Progress Energy, Inc. Restricted Stock Agreement pursuant to the 2002 Progress Energy Inc. Equity Incentive Plan, as amended July 2002 (filed as Exhibit 10c(18) to Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the SEC on March 16, 2005, File No. 1-3382 and 1-15929).	X	X	X

+*10c(15)	Form of Restricted Stock Unit Award Agreement as of March 20, 2007 (filed as Exhibit 10.1 to Current Report on Form 8-K dated March 26, 2007, File No. 1- 15929, No. 1-3382 and No. 1-3274).	X	X	X

+*10c(16)	Form of Employment Agreement dated May 8, 2007 between (i) Progress Energy Service Company, LLC and Robert McGehee, John R. McArthur and Peter M. Scott III; (ii) PEC and Lloyd M. Yates, Fredrick N. Day IV,	X	X	X

257

	Paula M. Sims, William D. Johnson and Clayton S. Hinnant; and (iii) PEF and Jeffrey A. Corbett and Jeffrey J. Lyash (filed as Exhibit 10 to Quarterly Report on Form 10-Q for the period ended March 31, 2007, File No. 1-15929, No. 1-3382 and No. 1-3274).

+*10c(17)	Form of Employment Agreement between Progress Energy Service Company, LLC and Mark F. Mulhern dated September 18, 2007 (filed as Exhibit 10 to Quarterly Report on Form 10-Q for the period ended March 31, 2007, File No. 1-15929, No. 1-3382 and No. 1-3274).	X

+*10c(18)	Amendment, dated August 5, 2005, to Employment Agreement dated between Progress Energy Service Company, LLC and Peter M. Scott III (filed as Exhibit 10 to Quarterly Report on Form 10-Q for the period ended June 30, 2005, File No. 1-15929, 1-3382 and 1-3274).	X	X	X

+*10c(19)	Selected Executives Supplemental Deferred Compensation Program Agreement, dated August, 1996, between CP&L and C. S. Hinnant (filed as Exhibit 10c(22) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).		X

+*10c(20)	Form of Executive Permanent Life Insurance Agreement (filed as Exhibit 10c(23) to Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 1, 2007, File No. 1-3382, No. 1-15929, and No. 1-3274).

+10c(21)	Progress Energy, Inc. Management Change-in-Control Plan (Amended and Restated Effective January 1, 2008).	X	X	X

+*10c(22)	Form of Executive and Key Manager 2008 Performance Share Sub-Plan (filed as Exhibit 10(a) to Quarterly Report on Form 10-Q for the period ended March 31, 2008, File No. 1-15929, 1-3382 and 1-3274).	X	X	X

+*10c(23)	Form of Restricted Stock Unit Award Agreement (filed as Exhibit 10(b) to Quarterly Report on Form 10-Q for the period ended March 31, 2008, File No. 1-15929, 1-3382 and 1-3274).	X	X	X

+*10c(24)	Amended and Restated Supplemental Senior Executive Retirement Plan of Progress Energy, Inc., effective January 1, 2009 (filed as Exhibit 10(A) to Quarterly Report on Form 10-Q for the period ended March 31, 2009, File No. 1-15929, 1-3382 and 1-3274).	X	X	X

258

+*10c(25)	Executive and Key Manager 2009 Performance Share Sub-Plan (filed as Exhibit 10.1 to Current Report on Form 8-K dated March 17, 2009, File No. 1-15929).	X	X	X

+*10c(26)	Form of Progress Energy, Inc. Restricted Stock Unit Award Agreement (filed as Exhibit 10.2 to Current Report on Form 8-K dated March 17, 2009, File No. 1-15929).	X	X	X

+*10c(27)	Amended Management Incentive Compensation Plan of Progress Energy, Inc., as amended January 1, 2010 (filed as Exhibit 10.3 to Current Report on Form 8-K dated March 17, 2009, File No. 1-15929).	X	X	X

+*10c(28)	Progress Energy, Inc. 2009 Executive Incentive Plan, effective March 17, 2009 (filed as Exhibit D to Form DEF 14A, as filed with the SEC on March 31, 2009, File No. 1-15929)	X

+*10c(29)	Amended and Restated Management Incentive Compensation Plan of Progress Energy, Inc., effective September 1, 2010 (filed as Exhibit 10(a) to Quarterly Report on Form 10-Q for the period ended June 30, 2010, File No. 1-15929, 1-3382 and 1-3274).	X	X	X

+*10c(30)	Amended and Restated Management Deferred Compensation Plan of Progress Energy, Inc., effective September 1, 2010 (filed as Exhibit 10(b) to Quarterly Report on Form 10-Q for the period ended June 30, 2010, File No. 1-15929, 1-3382 and 1-3274).	X	X	X

+*10c(31)	Employment Agreement Term Sheet for William D. Johnson in connection with the Agreement and Plan of Merger, dated as of January 8, 2011, by and among Duke Energy Corporation, Diamond Acquisition Corporation and Progress Energy, Inc. (Exhibit C to the Agreement and Plan of Merger filed as Exhibit 2.1 to the Current Report on Form 8-K, dated January 8, 2011, File No. 1-15929).	X

+*10c(32)	Form of Letter Agreement, dated January 8, 2011, executed by certain officers of Progress Energy, Inc., waiving certain rights under Progress Energy, Inc.’s Management Change-in-Control Plan and their employment agreements (filed as Exhibit 10.1 to the Current Report on Form 8-K dated January 8, 2011, File No. 1-15929).	X

*10d(1)	Agreement dated November 18, 2004 between Winchester Production Company, Ltd., TGG Pipeline Ltd., Progress Energy, Inc. and EnCana Oil & Gas (USA), Inc. (filed as Exhibit 10d(1) to Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the SEC on March 16, 2005, File No. 1-3382 and 1-15929).	X		X

259

*10d(2)	Precedent and Related Agreements among Florida Power Corporation d/b/a Progress Energy Florida, Inc. (“PEF”), Southern Natural Gas Company, Florida Gas Transmission Company (“FGT”), and BG LNG Services, LLC (“BG”), including: a) Precedent Agreement by and between Southern Natural Gas Company and PEF, dated December 2, 2004; b) Gas Sale and Purchase Contract between BG and PEF, dated December 1, 2004; c) Interim Firm Transportation Service Agreement by and between FGT and PEF, dated December 2, 2004; d) Letter Agreement between FGT and PEF, dated December 2, 2004 and Firm Transportation Service Agreement by and between FGT and PEF to be entered into upon satisfaction of certain conditions precedent; e) Discount Agreement between FGT and PEF, dated December 2, 2004; f) Amendment to Gas Sale and Purchase Contract between BG and PEF, dated January 28, 2005; and g) Letter Agreement between FGT and PEF, dated January 31, 2005, (filed as Exhibit 10.1 to Current Report on Form 8-K/A filed March 15, 2005). (Confidential treatment has been requested for portions of this exhibit. These portions have been omitted from the above-referenced Current Report and submitted separately to the SEC.)	X		X

*10d(3)	Engineering, Procurement and Construction Agreement, dated as of December 31, 2008, between Florida Power Corporation d/b/a/ Progress Energy Florida, Inc., as owner, and a consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc., as contractor, for a two-unit AP1000 Nuclear Power Plant (filed as Exhibit 10.1 to Current Report on Form 8-K filed on March 2, 2009). (The Registrants’ have requested confidential treatment for certain portions of this exhibit pursuant to an application for confidential treatment submitted to the SEC. These portions have been omitted from the above-referenced Current Report and submitted separately to the SEC.)	X		X

12(a)	Computation of Ratio of Earnings to Fixed Charges.	X

12(b)	Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends Combined.		X

12(c)	Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends Combined.			X

18	Preferability Letter of Deloitte & Touche LLP.	X

260


21	Subsidiaries of Progress Energy, Inc.	X

23(a)	Consent of Deloitte & Touche LLP.	X

23(b)	Consent of Deloitte & Touche LLP.		X

23(c)	Consent of Deloitte & Touche LLP.			X

31(a)	302 Certification of Chief Executive Officer	X

31(b)	302 Certification of Chief Financial Officer	X

31(c)	302 Certification of Chief Executive Officer		X

31(d)	302 Certification of Chief Financial Officer		X

31(e)	302 Certification of Chief Executive Officer			X

31(f)	302 Certification of Chief Financial Officer			X

32(a)	906 Certification of Chief Executive Officer	X

32(b)	906 Certification of Chief Financial Officer	X

32(c)	906 Certification of Chief Executive Officer		X

32(d)	906 Certification of Chief Financial Officer		X

32(e)	906 Certification of Chief Executive Officer			X

32(f)	906 Certification of Chief Financial Officer			X

101.INS	XBRL Instance Document**	X

101.SCH	XBRL Taxonomy Extension Schema Document	X

101.CAL	XBRL Taxonomy Calculation Linkbase Document	X

101.LAB	XBRL Taxonomy Label Linkbase Document	X

101.PRE	XBRL Taxonomy Presentation Linkbase Document	X

101.DEF	XBRL Taxonomy Definition Linkbase Document	X

*Incorporated herein by reference as indicated.

+Management contract or compensation plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14 (c) of Form 10-K.

-Sponsorship of this management contract or compensation plan or arrangement was transferred from Carolina Power & Light Company to Progress Energy, Inc., effective August 1, 2000.

**Attached as Exhibit 101 are the following financial statements and notes thereto for Progress Energy from the Annual Report on Form 10-K for the year ended December 31, 2010, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the

261

Consolidated Statement of Cash Flows, (iv) the Consolidated Statements of Changes in Total Equity, (v) the Consolidated Statements of Comprehensive Income and (vi) the Notes to the Consolidated Financial Statements.

In accordance with Rule 406T of Regulation S-T, the XBRL-related information in Exhibit 101 to this Annual Report on Form 10-K is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections.

262