Duke Energy Progress 8-K Safe Harbor for Forward-looking Statements

Exhibit 99

TABLE OF CONTENTS

GLOSSARY OF TERMS

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

PART II

ITEM 6.	SELECTED FINANCIAL DATA
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9A.	CONTROLS AND PROCEDURES
ITEM 9A(T).	CONTROLS AND PROCEDURES

PART IV

 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

GLOSSARY OF TERMS

We use the words “Progress Energy,” “we,” “us” or “our” with respect to certain information to indicate that such 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 or acronyms are used by the Progress Registrants:

TERM	DEFINITION
2007 Form 10-K	Progress Registrats' annual report on Form 10-K for the fiscal year ended December 31, 2007
401(k)	Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC	Allowance for funds used during construction
AHI	Affordable housing investment
ARO	Asset retirement obligation
Annual Average Price	Average wellhead price per barrel for unregulated domestic crude oil for the year
Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
Audit Committee	Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART	Best Available Retrofit Technology
Broad River	Broad River LLC’s Broad River Facility
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CCO	Competitive Commercial Operations
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Ceredo	Ceredo Synfuel LLC
CIGFUR	Carolina Industrial Group for Fair Utility Rates II
Clean Smokestacks Act	North Carolina Clean Smokestacks Act, enacted in June 2002
Coal Mining	Two Progress Fuels subsidiaries engaged in the coal mining business
Coal and Synthetic Fuels	Former business segment that had been primarily engaged in the production and sales of coal-based solid synthetic fuels, the operation of synthetic fuels facilities for third parties and coal terminal services
the Code	Internal Revenue Code
CO2	Carbon dioxide
COL	Combined license
Colona	Colona Synfuel Limited Partnership, LLLP
Corporate and Other	Corporate and Other segment includes Corporate as well as other nonregulated businesses
CR3	PEF’s Crystal River Unit No. 3 Nuclear Plant
CR4 and CR5	PEF’s Crystal River Units No. 4 and 5 coal-fired steam turbines
CUCA	Carolina Utility Customers Association
CVO	Contingent value obligation
D.C. Court of Appeals	U.S. Court of Appeals for the District of Columbia Circuit
DeSoto	DeSoto County Generating Co., LLC
DIG Issue C20	FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”
Dixie Fuels	Dixie Fuels Limited
DOE	United States Department of Energy
DSM	Demand-side management
Earthco	Four coal-based solid synthetic fuels limited liability companies of which three are wholly owned
ECCR	Energy Conservation Cost Recovery Clause
ECRC	Environmental Cost Recovery Clause

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EIA	Energy Information Agency
EIP	Equity Incentive Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric reliability organization
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FDCA	Florida Department of Community Affairs
FGT	Florida Gas Transmission Company
FIN 39	FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts”
FIN 45	FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIN 46R	FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51”
FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
the Florida Global Case	U.S. Global, LLC v. Progress Energy, Inc. et al
Florida Progress	Florida Progress Corporation
FPSC	Florida Public Service Commission
FRCC	Florida Reliability Coordinating Council
FSP	FASB Staff Position
FSP FIN 39-1	FASB Staff Position No. FIN 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts”
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Gas	Natural gas drilling and production business
the Georgia Contracts	Full-requirements contracts with 16 Georgia electric membership cooperatives formerly serviced by CCO
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Operations	Former reporting unit consisting of the Effingham, Monroe, Walton and Washington nonregulated generation plants in service and the Georgia Contracts
Global	U.S. Global, LLC
GridSouth	GridSouth Transco, LLC
Gulfstream	Gulfstream Gas System, L.L.C.
Harris	PEC’s Shearon Harris Nuclear Plant
IBEW	International Brotherhood of Electrical Workers
IRS	Internal Revenue Service
kV	Kilovolt
kVA	Kilovolt-ampere
kWh	Kilowatt-hours
Level 3	Level 3 Communications, Inc.
LIBOR	London Inter Bank Offering Rate
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in Part II, Item 7 of the 2007 Form 10-K
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
MW	Megawatts
MWh	Megawatt-hours
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCDWQ	North Carolina Division of Water Quality
NCUC	North Carolina Utilities Commission
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
the Notes Guarantee	Florida Progress’ full and unconditional guarantee of the Subordinated Notes
NOx	Nitrogen Oxides

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NOx SIP Call EPA rule which requires 22 states including North Carolina, South Carolina and Georgia (but excluding Florida) to further reduce emissions of nitrogen oxides

NSR New Source Review requirements by the EPA

NRC	United States Nuclear Regulatory Commission
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
O&M	Operation and maintenance expense
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income
OPC	Florida’s Office of Public Counsel
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
the Phase-out Price	Price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits are fully eliminated
PM 2.5	EPA standard for particulate matter less than 2.5 microns in diameter
PM 2.5-10	EPA standard for particulate matter between 2.5 and 10 microns in diameter
PM 10	EPA standard for particulate matter less than 10 microns in diameter
Power Agency	North Carolina Eastern Municipal Power Agency
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
Progress Fuels	Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail	Progress Rail Services Corporation
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
PT LLC	Progress Telecom, LLC
PUHCA 1935	Public Utility Holding Company Act of 1935, as amended
PUHCA 2005	Public Utility Holding Company Act of 2005
PURPA	Public Utilities Regulatory Policies Act of 1978
PVI	Progress Energy Ventures, Inc., formerly referred to as Progress Ventures, Inc.
PWC	Public Works Commission of the City of Fayetteville, North Carolina
QF	Qualifying facility
RCA	Revolving credit agreement
REPS	North Carolina Renewable Energy and Energy Efficiency Portfolio Standard
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity
Rowan	Rowan County Power, LLC
RSA	Restricted stock awards program
RSU	Restricted stock unit
RTO	Regional transmission organization
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
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 316(b)	Section 316(b) of the Clean Water Act
Section 45K	Section 45K of the Code
(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 the 2007 Form 10-K
SERC	SERC Reliability Corporation

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SESH	Southeast Supply Header, L.L.C.
S&P	Standard & Poor’s Rating Services

SFAS	Statement of Financial Accounting Standards
SFAS No. 5	Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”
SFAS No. 71	Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 87	Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions”
SFAS No. 115	Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”
SFAS No. 123R	Statement of Financial Accounting Standards No. 123R, “Share-Based Payment”
SFAS No. 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative and Hedging Activities”
SFAS No. 141R	Statement of Financial Accounting Standards No. 141R, “Business Combinations”
SFAS No. 142	Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 143	Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 144	Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS No. 157	Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”
SFAS No. 158	Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS No. 159	Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”
SFAS No. 160	Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”
SNG	Southern Natural Gas Company
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
Terminals	Coal terminals and docks in West Virginia and Kentucky
the Threshold Price	Price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits begin to reduce
the Trust	FPC Captial I
the Utilities	Collectively, PEC and PEF
Winchester Production	Winchester Production Company, Ltd.
Winter Park	City of Winter Park, Fla.

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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.

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: the impact of fluid and complex laws and regulations, including those relating to the environment and the Energy Policy Act of 2005 (EPACT); the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; the financial resources and capital needed to comply with environmental laws and renewable energy portfolio standards and our ability to recover related eligible costs under cost-recovery clauses or base rates; our ability to meet current and future renewable energy requirements; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the impact on our facilities and businesses from a terrorist attack; 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; economic fluctuations and the corresponding impact on our customers, including downturns in the housing and consumer credit markets; 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 (O&M) and large construction projects; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the ability to successfully access capital markets on favorable terms; the impact that increases in leverage may have on each of the Progress Registrants; the Progress Registrants’ ability to maintain their current credit ratings and the impact on the Progress Registrants’ financial condition and ability to meet their cash and other financial obligations in the event their credit ratings are downgraded; 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); the investment performance of our nuclear decommissioning trust funds and assets of pension and benefit plans; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. 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 United States Securities and Exchange Commission (SEC). Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors section in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2007 (2007 Form 10-K), which was filed with the SEC on February 28, 2008. 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.

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PART II

 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.

PROGRESS ENERGY

	Years Ended December 31
(in millions except per share data)	2007		2006 (a)		2005 (a)		2004 (a)		2003 (a)
Operating results
Operating revenues	$	9,153	$	8,724	$	7,948	$	7,168	$	6,775
Income from continuing operations before cumulative effect of changes in accounting principles, net of tax		693		551		523		552		536
Net income		504		571		697		759		782
Per share data
Basic earnings
Income from continuing operations	$	2.71	$	2.20	$	2.12	$	2.28	$	2.26
Net income		1.97		2.28		2.82		3.13		3.30
Diluted earnings
Income from continuing operations		2.70		2.20		2.12		2.27		2.25
Net income		1.96		2.28		2.82		3.12		3.28

Assets(b) $ 26,365 $ 25,859 $ 27,114 $ 26,131 $ 26,558

Capitalization and Debt
Common stock equity	$	8,422	$	8,286	$	8,038	$	7,633	$	7,444
Preferred stock of subsidiaries – not subject to mandatory redemption		93		93		93		93		93
Minority interest		84		10		36		29		24
Long-term debt, net (c)		8,737		8,835		10,446		9,521		9,693
Current portion of long-term debt		877		324		513		349		868
Short-term debt		201		–		175		684		4
Capital lease obligations		247		72		18		19		20
Total capitalization and debt	$	18,661	$	17,620	$	19,319	$	18,328	$	18,146
Dividends declared per common share	$	2.45	$	2.43	$	2.38	$	2.32	$	2.26

(a)   Operating results and balance sheet data have been restated for discontinued operations.

(b)  Amounts have been revised for the retrospective implementation of FASB Staff Position No. FIN 39-1, "An Amendement of FIN 39, Offsetting of Amounts Related to Certain Contracts".

(c)   Includes long-term debt to affiliated trust of $271 million at December 31, 2007 and 2006 and $270 million at December 31, 2005, 2004 and 2003.  (See Note 23.)

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PEC

	Years Ended December 31
(in millions)	2007		2006		2005		2004		2003
Operating results
Operating revenues	$	4,385	$	4,086	$	3,991	$	3,629	$	3,600
Net income		501		457		493		461		482
Earnings for common stock		498		454		490		458		479
Assets(a)	$	11,982	$	12,026	$	11,502	$	10,787	$	10,938
Capitalization and Debt
Common stock equity	$	3,779	$	3,390	$	3,118	$	3,072	$	3,237
Preferred stock – not subject to mandatory redemption		59		59		59		59		59
Long-term debt, net		3,183		3,470		3,667		2,750		3,086
Current portion of long-term debt		300		200		–		300		300
Short-term debt (b)		154		–		84		337		29
Capital lease obligations		17		18		18		19		20
Total capitalizationand debt	$	7,492	$	7,137	$	6,946	$	6,537	$	6,731

(a)  Amounts have been revised for the retrospective implementation of FASB Staff Position No. FIN 39-1, "An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts".

(b)  Includes notes payable to affiliated companies, related to the money pool program, of $154 million, $11 million, $116 million and $25 million at December 31, 2007, 2005, 2004 and 2003, respectively.

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).

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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 mitigate such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties (See Note 17).

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 of the 2007 Form 10-K, “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 nuclear decommissioning trust 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

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 risk in the transaction is the cost of replacing the agreements at current market rates. We enter into interest rate derivative agreements only with banks with credit ratings of single A or better.

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 at the end of the reporting period using the Bloomberg Financial Markets system.

In accordance with SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133), 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.

The following tables provide information at December 31, 2007 and 2006, 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 Florida Progress-obligated mandatorily redeemable 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 swaps and interest rate forward contracts, the tables present notional amounts and weighted-average interest rates by contractual maturity dates for 2008 to 2012 and

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thereafter and the related fair value. Notional amounts are used to calculate the contractual cash flows to be exchanged under the interest rate swaps and the settlement amounts under the interest rate forward contracts. See Note 17 for more information on interest rate derivatives.

December 31, 2007 (dollars in millions)	2008			2009			2010			2011			2012			Thereafter			Total			Fair Value December 31, 2007
Fixed-rate long-term debt	$	427		$	400		$	306		$	1,000		$	950		$	4,865		$	7,948		$	8,192
Average interest rate		6.67	%		5.95	%		4.53	%		6.96	%		6.67	%		6.03	%		6.20	%
Variable-rate long-term debt	$	450			–		$	100			–			–		$	861		$	1,411		$	1,411
Average interest rate		5.27	%		–			5.69	%		–			–			4.45	%		4.80	%
Debt to affiliated trust(a)		–			–			–			–			–		$	309		$	309		$	294
Interest rate		–			–			–			–			–			7.10	%		7.10	%
Interest rate derivatives
Interest rate forward contracts(b)	$	200			–			–			–			–			–		$	200		$	(12	)
Average pay rate		5.41	%		–			–			–			–			–			5.41	%
Average receive rate	(c)				–			–			–			–			–		(c)

(a)   FPC Capital I – Quarterly Income Preferred Securities.

(b)   $100 million is for anticipated 10-year debt issue hedge maturing on April 1, 2018, and requires mandatory cash settlement on April 1, 2008. The remaining $100 million is for anticipated 30-year debt issue hedge maturing on April 1, 2038, and requires mandatory cash settlement on April 1, 2008.

(c)   Rate is 3-month London Inter Bank Offering Rate (LIBOR), which was 4.70% at December 31, 2007.

During 2007, PEF had entered into a combined $225 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances, which were terminated on September 13, 2007, in conjunction with PEF’s issuance of $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017.

On July 30, 2007, PEC entered into a $50 million notional forward starting swap and on October 24, 2007, PEC entered into $100 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. On September 25, 2007, PEC amended its 10-year forward starting swap in order to move the maturity date from October 1, 2017, to April 1, 2018.

On January 8, 2008, PEF entered into a combined $200 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

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December 31, 2006 (dollars in millions)	2007			2008			2009			2010			2011			Thereafter			Total			Fair Value December 31, 2006
Fixed-rate long-term debt	$	324		$	427		$	400		$	306		$	1,000		$	5,065		$	7,522		$	7,820
Average interest rate		6.79	%		6.67	%		5.95	%		4.53	%		6.96	%		6.13	%		6.23	%
Variable-rate long-term debt		–		$	450			–		$	100			–		$	861		$	1,411		$	1,411
Average interest rate		–			5.77	%		–			5.82	%		–			3.62	%		4.47	%
Debt to affiliated trust(a)		–			–			–			–			–		$	309		$	309		$	312
Interest rate		–			–			–			–			–			7.10	%		7.10	%
Interest rate derivatives
Pay variable/receive fixed		–			–			–			–		$	(50	)		–		$	(50	)	$	(1	)
Average pay rate		–			–			–			–		(b)				–		(b)
Average receive rate		–			–			–			–			4.65	%		–			4.65	%
Interest rate forward contracts(c)	$	100			–			–			–			–			–		$	100		$	(2	)
Average pay rate		5.61	%		–			–			–			–			–			5.61	%
Average receive rate	(b)				–			–			–			–			–		(b)

(a)   FPC Capital I – Quarterly Income Preferred Securities.

(b)   Rate is 3-month LIBOR, which was 5.36% at December 31, 2006.

(c)   Anticipated 10-year debt issue hedges matured on October 1, 2017, and required mandatory cash settlement on October 1, 2007.

On November 7, 2006, Progress Energy commenced a tender offer for up to $550 million aggregate principal amount of its 2011 and 2012 senior notes. Subsequently, we executed a total notional amount of $550 million of reverse treasury locks to reduce exposure to changes in cash flow due to fluctuating interest rates, which were then terminated on December 1, 2006. On December 6, 2006, Progress Energy repurchased, pursuant to the tender offer, $550 million, or 44.0 percent, of the outstanding aggregate principal amount of its 7.10% Senior Notes due March 1, 2011, at 108.361 percent of par, or $596 million, plus accrued interest.

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, 2007 and 2006, the fair value of these funds was $1.384 billion and $1.287 billion, respectively, including $804 million and $735 million, respectively, for PEC and $580 million and $552 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

In connection with the acquisition of Florida Progress, 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 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. The CVOs are derivatives and are recorded at fair value. Unrealized gains and losses from changes in fair value are recognized in earnings. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analysis 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. At December 31, 2007 and 2006, the CVO liability included in other

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liabilities and deferred credits on our Consolidated Balance Sheets was $34 million and $32 million, respectively. A hypothetical 10 percent decrease in the December 31, 2007, market price would result in a $3 million decrease in the fair value of the CVOs.

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. We also have oil price risk exposure related to synthetic fuels tax credits as discussed in MD&A – “Other Matters – Synthetic Fuels Tax Credits" of the 2007 Form 10-K.

Most of our physical commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments that are not eligible for recovery from ratepayers. The following discussion addresses the stand-alone commodity risk created by these derivative commodity instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge. The sensitivity analysis performed on these derivative commodity instruments uses quoted prices obtained from brokers to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. At December 31, 2007, the only derivative commodity instruments not eligible for recovery from ratepayers related to derivative contracts entered into on January 8, 2007, to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices as discussed below. These contracts ended on December 31, 2007, and were settled for cash on January 8, 2008, with no material impact to 2008 earnings. At December 31, 2006, derivative commodity instruments not eligible for recovery from ratepayers were included in discontinued operations as discussed below.

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

DISCONTINUED OPERATIONS

As discussed in Note 3A, our subsidiary, PVI, entered into a series of transactions to sell or assign substantially all of its CCO physical and commercial assets and liabilities. On June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of the Georgia Contracts, forward gas and power contracts, gas transportation, structured power and other contracts to a third party. This represented substantially all of our nonregulated energy marketing and trading operations. The sale of the generation assets closed on June 11, 2007. Additionally, we sold Gas on October 2, 2006 (See Note 3C). At December 31, 2007, with the exception of the oil price hedge instruments discussed below, our discontinued operations did not have outstanding positions in derivative instruments. For the year ended December 31, 2007, $88 million of after-tax gains from derivative instruments related to our nonregulated energy marketing and trading operations were included in discontinued operations on the Consolidated Statements of Income.

On January 8, 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge instruments was 25 million barrels and provided protection for the equivalent of approximately 8 million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts were marked-to-market with changes in fair value recorded through earnings. These contracts ended on December 31, 2007, and were settled for cash on January 8, 2008, with no material impact to 2008 earnings. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed in Note 3J, we disposed of our 100 percent

12

ownership interest in Ceredo on March 30, 2007. Progress Energy is the primary beneficiary of, and continues to consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there is no net earnings impact for the portion of the contracts entered into by Ceredo. At December 31, 2007, the fair value of all of these contracts was recorded as a $234 million short-term derivative asset position, including $79 million at Ceredo. The fair value of these contracts was included in receivables, net on the Consolidated Balance Sheet (See Note 6A).  We had a $108 million cash collateral liability related to these contracts at December 31, 2007, included in other current liabilities on the Consolidated Balance Sheet.  As discussed in Note 3B, on October 12, 2007, we permanently ceased production of synthetic fuels at our majority-owned facilities. Because we have abandoned our majority-owned facilities and our other synthetic fuels operations ceased as of December 31, 2007, gains and losses on these contracts were included in discontinued operations, net of tax on the Consolidated Statement of Income in 2007. During the year ended December 31, 2007, we recorded net pre-tax gains of $168 million related to these contracts. Of this amount, $57 million was attributable to Ceredo of which $42 million was attributed to minority interest for the portion of the gain subsequent to the disposal of Ceredo.

At December 31, 2006, derivative assets of $198 million and derivative liabilities of $122 million were included in assets to be divested and liabilities to be divested, respectively, on the Consolidated Balance Sheet.  At December 31, 2006, cash collateral  receievable of $9 million and cash collateral payable of $90 million were included in assets to be divested and liabilities to be divested, respectively, on the  Consolidated Balance Sheet.  Due to the divestitures discussed above, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts would be fulfilled and cash flow hedge accounting for the contracts was discontinued beginning in the second quarter of 2006 for Gas and in the fourth quarter of 2006 for CCO. Our discontinued operations did not have material outstanding positions in commodity cash flow hedges at December 31, 2006. For the years ended December 31, 2006 and 2005, excluding amounts reclassified to earnings due to discontinuance of the related cash flow hedges, net gains and losses from derivative instruments related to Gas and CCO on a consolidated basis were not material and are included in discontinued operations, net of tax on the Consolidated Statements of Income. For the year ended December 31, 2006, discontinued operations, net of tax includes $74 million in after-tax deferred income, which was reclassified to earnings due to discontinuance of the related cash flow hedges. For the year ended December 31, 2005, there were no reclassifications to earnings due to discontinuance of the related cash flow hedges.

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. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets on the Balance Sheets, respectively, until the contracts are settled (See Note 7A). Once settled, any realized gains or losses are passed through the fuel clause. During the year ended December 31, 2007, PEC recorded a net realized loss of $9 million. PEC’s net realized gains and losses were not material during the years ended December 31, 2006 and 2005. During the years ended December 31, 2007, 2006 and 2005, PEF recorded a net realized loss of $46 million, a net realized gain of $39 million and a net realized gain of $70 million, respectively.

13

Excluding amounts receiving regulatory accounting treatment and amounts related to our discontinued operations discussed above, gains and losses from contracts entered into for economic hedging purposes were not material to our or the Utilities’ results of operations during the years ended December 31, 2007, 2006 and 2005. Excluding derivative assets and derivative liabilities to be divested discussed above, we did not have material outstanding positions in such contracts at December 31, 2007 and 2006, other than those receiving regulatory accounting treatment at PEC and PEF, as discussed below.

At December 31, 2007, the fair value of PEC’s commodity derivative instruments was recorded as a $19 million long-term derivative asset position included in other assets and deferred debits and a $4 million short-term derivative liability position included in other current liabilities on the PEC Consolidated Balance Sheet. At December 31, 2006, PEC did not have material outstanding positions in such contracts.  PEC had no cash collateral position at December 31, 2007 or 2006.

At December 31, 2007, the fair value of PEF’s commodity derivative instruments was recorded as a $83 million short-term derivative asset position included in current derivative assets, a $100 million long-term derivative asset position included in derivative assets,  a $38 million short-term derivative liability position included in derivative liabilities, and a $9 million long-term derivative liablity position included in other liabilities and deferred credits on the PEF Balance Sheet.  At December 31, 2006, the fair value of such instruments was recorded as a $3 million short-term derivative asset position included in current derivative assets, a $19 million long-term derivative asset position included in derivative assets, a $90 million short-term derivative liability position included in derivative liabilities, and a $53 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet.  PEF had no cash collateral position at December 31, 2007 or 2006.

CASH FLOW HEDGES

PEC designates a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. PEF did not have any commodity derivative instruments designated as cash flow hedges at December 31, 2007 and 2006. At December 31, 2007 and 2006, we and PEC did not have material outstanding positions in such contracts.The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for 2007, 2006 and 2005.

At December 31, 2007 and 2006, the amount recorded in our or PEC’s accumulated other comprehensive income related to commodity cash flow hedges was not material. PEF had no amount recorded in accumulated other comprehensive income related to commodity cash flow hedges at December 31, 2007 or 2006.

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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 nuclear decommissioning trust funds, and changes in energy-related commodity prices.

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

INTEREST RATE RISK

The following tables provide information at December 31, 2007 and 2006, about PEC’s interest rate risk sensitive instruments:

December 31, 2007 (dollars in millions)	2008			2009			2010			2011		2012			Thereafter			Total			Fair Value December 31, 2007
Fixed-rate long-term debt	$	300		$	400		$	6		$	–	$	500		$	1,665		$	2,871		$	2,925
Average interest rate		6.65	%		5.95	%		6.30	%		–		6.50	%		5.57	%		5.90	%
Variable-rate long-term debt		–			–			–			–		–		$	620		$	620		$	620
Average interest rate		–			–			–			–		–			4.51	%		4.51	%
Interest rate forward contracts(a)	$	200			–			–			–		–			–		$	200		$	(12	)
Average pay rate		5.41	%		–			–			–		–			–			5.41	%
Average receive rate	(b)				–			–			–		–			–		(b)

(a)   $100 million is for anticipated 10-year debt issue hedge maturing on April 1, 2018, and requires mandatory cash settlement on April 1, 2008. The remaining $100 million is for anticipated 30-year debt issue hedge maturing on April 1, 2038, and requires mandatory cash settlement on April 1, 2008.

(b)   Rate is 3-month LIBOR, which was 4.70% at December 31, 2007.

December 31, 2006 (dollars in millions)	2007			2008			2009			2010			2011		Thereafter			Total			Fair Value December 31, 2006
Fixed-rate long-term debt	$	200		$	300		$	400		$	6			–	$	2,165		$	3,071		$	3,112
Average interest rate		6.80	%		6.65	%		5.95	%		6.30	%		–		5.79	%		5.96	%
Variable-rate long-term debt		–			–			–			–			–	$	620		$	620		$	620
Average interest rate		–			–			–			–			–		3.61	%		3.61	%
Interest rate forward contracts(a)	$	50			–			–			–			–		–		$	50		$	(1	)
Average pay rate		5.61	%		–			–			–			–		–			5.61	%
Average receive rate	(b)				–			–			–			–		–		(b)

(a)   Anticipated 10-year debt issue hedge matured on October 1, 2017, and required mandatory cash settlement on October 1, 2007.

(b)   Rate is 3-month LIBOR, which was 5.36% at December 31, 2006.

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 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

15

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. PEC may engage in limited economic hedging activity using natural gas and electricity financial instruments. See “Commodity Price Risk” discussion under Progress Energy above and Note 17 for additional information with regard to PEC’s commodity contracts and use of derivative financial instruments.

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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 nuclear decommissioning trust funds, and changes in energy-related commodity prices.

The information required by this item is incorporated herein by reference to the Quantitative and Qualitative Disclosures About Market Risk insofar as it relates to PEF.

INTEREST RATE RISK

The following tables provide information at December 31, 2007 and 2006, about PEF’s interest rate risk sensitive instruments:

December 31, 2007 (dollars in millions)	2008			2009		2010			2011			2012		Thereafter			Total			Fair Value December 31, 2007
Fixed-rate long-term debt	$	82		$	–	$	300		$	300		$	–	$	1,850		$	2,532		$	2,548
Average interest rate		6.87	%		–		4.50	%		6.65	%		–		5.69	%		5.70	%
Variable-rate long-term debt	$	450			–		–			–			–	$	241		$	691		$	691
Average interest rate		5.27	%		–		–			–			–		4.32	%		4.94	%

December 31, 2006 (dollars in millions)	2007			2008			2009		2010			2011			Thereafter			Total			Fair Value December 31, 2006
Fixed-rate long-term debt	$	89		$	82			–	$	300		$	300		$	1,100		$	1,871		$	1,876
Average interest rate		6.80	%		6.87	%		–		4.50	%		6.65	%		5.37	%		5.57	%
Variable-rate long-term debt		–		$	450			–		–			–		$	241		$	691		$	691
Average interest rate		–			5.77	%		–		–			–			3.66	%		5.04	%
Interest rate forward contracts(a)	$	50			–			–		–			–			–		$	50		$	(1	)
Average pay rate		5.61	%		–			–		–			–			–			5.61	%
Average receive rate	(b)				–			–		–			–			–		(b)

(a)   Anticipated 10-year debt issue hedge matured on October 1, 2017, and required mandatory cash settlement on October 1, 2007.

(b)   Rate is 3-month LIBOR, which was 5.36% at December 31, 2006.

During 2007, PEF had entered into a combined $225 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances, which were terminated on September 13, 2007, in conjunction with PEF’s issuance of $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017.

On January 8, 2008, PEF entered into a combined $200 million notional of 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 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

17

from the ratepayers, changes from year to year have no material impact on operating results. See “Commodity Price Risk” discussion under Progress Energy above and Note 17 for additional information with regard to PEF’s commodity contracts and use of derivative financial instruments.

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 ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements, supplementary data and financial statement schedules are included herein:

Page

Progress Energy, Inc. (Progress Energy)

Report of Independent Registered Public Accounting Firm	21
Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005	22
Consolidated Balance Sheets at December 31, 2007 and 2006	23
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	24
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2007, 2006 and 2005	25
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005	26

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

Report of Independent Registered Public Accounting Firm	27
Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005	28
Consolidated Balance Sheets at December 31, 2007 and 2006	29
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	30
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2007, 2006 and 2005	31
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005	31

Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)

Report of Independent Registered Public Accounting Firm	32
Statements of Income for the Years Ended December 31, 2007, 2006 and 2005	33
Balance Sheets at December 31, 2007 and 2006	34
Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	35
Statements of Changes in Common Stock Equity for the Years Ended December 31, 2007, 2006 and 2005	36
Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005	36

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	37
Note 2   – New Accounting Standards	44
Note 3   – Divestitures	45
Note 4   – Acquisitions	51
Note 5   – Property, Plant and Equipment	52
Note 6   – Current Assets	57
Note 7   – Regulatory Matters	57
Note 8   – Goodwill and Intangible Assets	65
Note 9   – Impairments of Long-Lived Assets and Investments	66
Note 10 – Equity	66
Note 11 – Preferred Stock of Subsidiaries – Not Subject to Mandatory Redemption	74
Note 12 – Debt and Credit Facilities	75
Note 13 – Investments and Fair Value of Financial Instruments	79
Note 14 – Income Taxes	83

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	Page
Note 15 – Contingent Value Obligations	91
Note 16 – Benefit Plans	91
Note 17 – Risk Management Activities and Derivatives Transactions	102
Note 18 – Related Party Transactions	105
Note 19 – Financial Information by Business Segment	106
Note 20 – Other Income and Other Expense	108
Note 21 – Environmental Matters	110
Note 22 – Commitments and Contingencies	113
Note 23 – Condensed Consolidating Statements	120
Note 24 – Quarterly Financial Data (Unaudited)	132

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, 5 through 10, 12 through 14, 16 through 22 and 24
PEF	1 through 3, 5 through 10, 12 through 14, 16 through 22 and 24

Consolidated Financial Statement Schedules for the Years Ended December 31, 2007, 2006 and 2005:

Schedule II – Valuation and Qualifying Accounts – Progress Energy, Inc.	136
Schedule II – Valuation and Qualifying Accounts – Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.	137
Schedule II – Valuation and Qualifying Accounts – Florida Power Corporation d/b/a Progress Energy Florida, Inc.	138

All other schedules have been omitted as not applicable or are not required because the information required to be shown is included in the Financial Statements or the Combined Notes to the Financial Statements.

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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 its subsidiaries (the Company) at December 31, 2007 and 2006, and the related consolidated 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, 2007.  Our audits also included the consolidated financial statement schedule listed in the Index at Item 15.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such 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.

As discussed in Note 2 to the consolidated financial statements, on January 1, 2008 the Company adopted Financial Accounting Standards Board Staff Position FIN 39-1 and, retrospectively, adjusted all periods presented in theconsolidated financial statements for the change.  Additionally, as discussed in Note 14 and Note 16 to the consolidated financial statements, on January 1, 2007 the Company adopted Financial Accounting Standards Board Interpretation No. 48 and on December 31, 2006 the Company adopted Statement of Financial Accounting Standards No. 158.

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 at December 31, 2007, 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, 2008, expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2008

(November 6, 2008 as to the effects of the retrospective implementation of Financial Accounting Standards Board Staff Position FIN 39-1 as described in Note 2 and the restatement as described in Note 23)

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PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of INCOME
(in millions except per share data)
Years ended December 31	2007			2006			2005
Operating revenues	$	9,153		$	8,724		$	7,948
Operating expenses
Fuel used in electric generation		3,145			3,008			2,359
Purchased power		1,184			1,100			1,048
Operation and maintenance		1,842			1,583			1,770
Depreciation and amortization		905			1,011			926
Taxes other than on income		501			500			460
Other		30			35			(3	)
Total operating expenses		7,607			7,237			6,560
Operating income		1,546			1,487			1,388
Other income (expense)
Interest income		34			59			13
Other, net		44			(16	)		(1	)
Total other income		78			43			12
Interest charges
Net interest charges		605			631			588
Allowance for borrowed funds used during construction		(17	)		(7	)		(13	)
Total interest charges, net		588			624			575
Income from continuing operations before income tax and minority interest		1,036			906			825
Income tax expense		334			339			298
Income from continuing operations before minority interest		702			567			527
Minority interest in subsidiaries’ income, net of tax		(9	)		(16	)		(4	)
Income from continuing operations		693			551			523
Discontinued operations, net of tax		(189	)		20			173
Cumulative effect of change in accounting principle, net of tax		–			–			1
Net income	$	504		$	571		$	697
Average common shares outstanding – basic		256			250			247
Basic earnings per common share
Income from continuing operations	$	2.71		$	2.20		$	2.12
Discontinued operations, net of tax		(0.74	)		0.08			0.70
Net income	$	1.97		$	2.28		$	2.82
Diluted earnings per common share
Income from continuing operations	$	2.70		$	2.20		$	2.12
Discontinued operations, net of tax		(0.74	)		0.08			0.70
Net income	$	1.96		$	2.28		$	2.82
Dividends declared per common share	$	2.45		$	2.43		$	2.38

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

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PROGRESS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
(in millions)
December 31	2007			2006
ASSETS
Utility plant
Utility plant in service	$	25,327		$	23,743
Accumulated depreciation		(10,895	)		(10,064	)
Utility plant in service, net		14,432			13,679
Held for future use		37			10
Construction work in progress		1,765			1,289
Nuclear fuel, net of amortization		371			267
Total utility plant, net		16,605			15,245
Current assets
Cash and cash equivalents		255			265
Short-term investments		1			71
Receivables, net		1,167			949
Inventory		994			936
Deferred fuel cost		154			196
Deferred income taxes		27			142
Assets to be divested		52			1,057
Prepayments and other current assets		179			113
Total current assets		2,829			3,729
Deferred debits and other assets
Regulatory assets		946			1,251
Nuclear decommissioning trust funds		1,384			1,287
Miscellaneous other property and investments		448			465
Goodwill		3,655			3,655
Derivative assets		119			19
Other assets and deferred debits		379			208
Total deferred debits and other assets		6,931			6,885
Total assets	$	26,365		$	25,859
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 260 and 256 million shares issued	$	6,028		$	5,791
and outstanding, respectively
Unearned ESOP shares (2 million shares)		(37	)		(50	)
Accumulated other comprehensive loss		(34	)		(49	)
Retained earnings		2,465			2,594
Total common stock equity		8,422			8,286
Preferred stock of subsidiaries – not subject to mandatory redemption		93			93
Minority interest		84			10
Long-term debt, affiliate		271			271
Long-term debt, net		8,466			8,564
Total capitalization		17,336			17,224
Current liabilities
Current portion of long-term debt		877			324
Short-term debt		201			–
Accounts payable		819			731
Interest accrued		173			171
Dividends declared		160			156
Customer deposits		255			227
Regulatory liabilities		173			76
Liabilities to be divested		8			339
Income taxes accrued		8			284
Other current liabilities		628			627
Total current liabilities		3,302			2,935
Deferred credits and other liabilities
Noncurrent income tax liabilities		361			312
Accumulated deferred investment tax credits		139			151
Regulatory liabilities		2,554			2,563
Asset retirement obligations		1,378			1,304
Accrued pension and other benefits		763			957
Capital lease obligations		239			70
Other liabilities and deferred credits		293			343
Total deferred credits and other liabilities		5,727			5,700
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	26,365		$	25,859

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

23

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2007			2006			2005
Operating activities
Net income	$	504		$	571		$	697
Adjustments to reconcile net income to net cash provided by operating activities
Impairment of assets		–			174			–
Charges for voluntary enhanced retirement program		–			–			159
Depreciation and amortization		1,026			1,190			1,216
Deferred income taxes and investment tax credits, net		177			(251	)		(340	)
Deferred fuel cost (credit)		117			396			(317	)
Deferred income		(128	)		(69	)		–
Other adjustments to net income		124			88			135
Cash (used) provided by changes in operating assets and liabilities
Receivables		(186	)		59			(170	)
Inventory		(11	)		(168	)		(163	)
Prepayments and other current assets		90			(133	)		69
Income taxes, net		(275	)		197			101
Accounts payable		(40	)		34			124
Other current liabilities		81			10			(16	)
Other assets and deferred debits		(198	)		(70	)		(87	)
Other liabilities and deferred credits		(29	)		(27	)		59
Net cash provided by operating activities		1,252			2,001			1,467
Investing activities
Gross property additions		(1,973	)		(1,572	)		(1,313	)
Nuclear fuel additions		(228	)		(114	)		(126	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		675			1,657			475
Purchases of available-for-sale securities and other investments		(1,413	)		(2,452	)		(3,985	)
Proceeds from sales of available-for-sale securities and other investments		1,452			2,631			3,845
Other investing activities		30			(23	)		(40	)
Net cash (used) provided by investing activities		(1,457	)		127			(1,144	)
Financing activities
Issuance of common stock		151			185			208
Dividends paid on common stock		(627	)		(607	)		(582	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		176			–			–
Net increase (decrease) in short-term debt		25			(175	)		(509	)
Proceeds from issuance of long-term debt, net		739			397			1,642
Retirement of long-term debt		(324	)		(2,200	)		(564	)
Other financing activities		55			(68	)		32
Net cash provided (used) by financing activities		195			(2,468	)		227
Net (decrease) increase in cash and cash equivalents		(10	)		(340	)		550
Cash and cash equivalents at beginning of year		265			605			55
Cash and cash equivalents at end of year	$	255		$	265		$	605
Supplemental disclosures
Cash paid during the year
Interest (net of amount capitalized)	$	585		$	698		$	645
Income taxes (net of refunds)		176			311			168
Significant noncash transactions
Capital lease obligation incurred		182			54			–
Note receivable for disposal of ownership interest in Ceredo		48			–			–
Noncash property additions accrued for as of December 31		329			231			116

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

24

    PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
(in millions)	Common Stock Outstanding                           Shares                           Amount		Unearned Restricted Shares	Unearned ESOP Shares	Accumulated Other Comprehensive (Loss) Income	Retained Earnings	Total Common Stock Equity
Balance, December 31, 2004	247	$5,360	$(13)	$(76)	$(164)	$2,526	$7,633
Net income		–	–	–	–	697	697
Other comprehensive income		–	–	–	60	–	60
Comprehensive income							757
Issuance of shares	5	199	–	–	–	–	199
Presentation reclassification –SFAS No.
123R adoption		(13)	13	–	–	–	–
Stock options exercised		8	–	–	–	–	8
Purchase of restricted stock		(8)	–	–	–	–	(8)
Allocation of ESOP shares		12	–	13	–	–	25
Stock-based compensation expense		13	–	–	–	–	13
Dividends ($2.38 per share)		–	–	–	–	(589)	(589)
Balance, December 31, 2005	252	5,571	–	(63)	(104)	2,634	8,038
Net income		–	–	–	–	571	571
Other comprehensive loss		–	–	–	(18)	–	(18)
Comprehensive income							553
Adjustment to initially apply SFAS
No. 158, net of tax		–	–	–	73	–	73
Issuance of shares	4	70	–	–	–	–	70
Stock options exercised		115	–	–	–	–	115
Purchase of restricted stock		(8)	–	–	–	–	(8)
Allocation of ESOP shares		13	–	13	–	–	26
Stock-based compensation expense		30	–	–	–	–	30
Dividends ($2.43 per share)		–	–	–	–	(611)	(611)
Balance, December 31, 2006	256	5,791	–	(50)	(49)	2,594	8,286
Net income		–	–	–	–	504	504
Other comprehensive income		–	–	–	15	–	15
Comprehensive income							519
Adjustment to initially apply FASB
Interpretation No. 48		–	–	–	–	(2)	(2)
Issuance of shares	4	46	–	–	–	–	46
Stock options exercised		105	–	–	–	–	105
Allocation of ESOP shares		15	–	13	–	–	28
Stock-based compensation expense		71	–	–	–	–	71
Dividends ($2.45 per share)		–	–	–	–	(631)	(631)
Balance, December 31, 2007	260	$6,028	$–	$(37)	$(34)	$2,465	$8,422

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

25

        PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31	2007			2006			2005
Net income	$	504		$	571		$	697
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax (expense) benefit of $(3), $28 and $(26), respectively)		4			(46	)		46
Foreign currency translation adjustments included in discontinued operations		–			–			(6	)
Minimum pension liability adjustment included in discontinued operations (net of tax expense of $1)		–			–			1
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $1)		2			–			–
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $8, $16 and $(26), respectively)		(13	)		(23	)		37
Net unrecognized items on pension and other postretirement benefits (net of tax expense of $16)		23			–			–
Minimum pension liability adjustment (net of tax (expense) benefit of $(30) and $22, respectively)		–			48			(19	)
Other (net of tax benefit (expense) of $3, $- and $(1), respectively)		(1	)		3			1
Other comprehensive income (loss)		15			(18	)		60
Comprehensive income	$	519		$	553		$	757

See Notes to Progress Energy, Inc. Consolidated Financial Statements.
 

26

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 its subsidiaries (PEC) at December 31, 2007 and 2006, and the related consolidated 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, 2007.  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 include 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 PEC at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such 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.

As discussed in Note 2 to the consolidated financial statements, on January 1, 2008 PEC adopted Financial Accounting Standards Board Staff Position FIN 39-1 and, retrospectively, adjusted all periods presented in the consolidated financial statements for the change.  Additionally, as discussed in Note 14 and Note 16 to the consolidated financial statements, on January 1, 2007 PEC adopted Financial Accounting Standards Board Interpretation No. 48 and on December 31, 2006 the Company adopted Statement of Financial Accounting Standards No. 158.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2008

(November 6, 2008 as to the effects of the retrospective implementation of Financial Accounting Standards Board Staff Position FIN 39-1 described in Note 2)

27

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED STATEMENTS of INCOME
(in millions)
Years ended December 31	2007			2006			2005
Operating revenues	$	4,385		$	4,086		$	3,991
Operating expenses
Fuel used in electric generation		1,381			1,173			1,036
Purchased power		302			334			354
Operation and maintenance		1,024			930			941
Depreciation and amortization		519			571			561
Taxes other than on income		192			191			178
Other		(2	)		–			(10	)
Total operating expenses		3,416			3,199			3,060
Operating income		969			887			931
Other income (expense)
Interest income		21			25			8
Other, net		16			25			(15	)
Total other income (expense)		37			50			(7	)
Interest charges
Interest charges		215			217			197
Allowance for borrowed funds used during construction		(5	)		(2	)		(5	)
Total interest charges, net		210			215			192
Income before income tax		796			722			732
Income tax expense		295			265			239
Net income		501			457			493
Preferred stock dividend requirement		3			3			3
Earnings for common stock	$	498		$	454		$	490

See Notes to PEC Consolidated Financial Statements.

28

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED BALANCE SHEETS
(in millions)
December 31	2007			2006
ASSETS
Utility plant
Utility plant in service	$	15,117		$	14,356
Accumulated depreciation		(7,097	)		(6,408	)
Utility plant in service, net		8,020			7,948
Held for future use		2			3
Construction work in progress		566			617
Nuclear fuel, net of amortization		292			209
Total utility plant, net		8,880			8,777
Current assets
Cash and cash equivalents		25			71
Short-term investments		1			50
Receivables, net		491			476
Receivables from affiliated companies		42			27
Notes receivable from affiliated companies		–			24
Inventory		510			497
Deferred fuel cost		148			196
Prepayments and other current assets		49			47
Total current assets		1,266			1,388
Deferred debits and other assets
Regulatory assets		680			778
Nuclear decommissioning trust funds		804			735
Miscellaneous other property and investments		192			193
Other assets and deferred debits		160			155
Total deferred debits and other assets		1,836			1,861
Total assets	$	11,982		$	12,026
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,054		$	2,010
Unearned ESOP common stock		(37	)		(50	)
Accumulated other comprehensive loss		(10	)		(1	)
Retained earnings		1,772			1,431
Total common stock equity		3,779			3,390
Preferred stock – not subject to mandatory redemption		59			59
Long-term debt, net		3,183			3,470
Total capitalization		7,021			6,919
Current liabilities
Current portion of long-term debt		300			200
Notes payable to affiliated companies		154			–
Accounts payable		308			313
Payables to affiliated companies		71			108
Interest accrued		58			69
Customer deposits		70			59
Income taxes accrued		27			68
Current portion of unearned revenue		3			71
Other current liabilities		179			156
Total current liabilities		1,170			1,044
Deferred credits and other liabilities
Noncurrent income tax liabilities		936			909
Accumulated deferred investment tax credits		122			128
Regulatory liabilities		1,098			1,321
Asset retirement obligations		1,063			1,004
Accrued pension and other benefits		459			581
Other liabilities and deferred credits		113			120
Total deferred credits and other liabilities		3,791			4,063
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	11,982		$	12,026

See Notes to PEC Consolidated Financial Statements.

29

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2007			2006			2005
Operating activities
Net income	$	501		$	457		$	493
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program		–			–			42
Depreciation and amortization		608			656			644
Deferred income taxes and investment tax credits, net		41			(59	)		(150	)
Deferred fuel cost (credit)		48			(8	)		(144	)
Other adjustments to net income		(47	)		(23	)		69
Cash (used) provided by changes in operating assets and liabilities
Receivables		(16	)		33			(111	)
Receivables from affiliated companies		(15	)		9			11
Inventory		(10	)		(69	)		(91	)
Prepayments and other current assets		(17	)		10			9
Income taxes, net		(37	)		(24	)		163
Accounts payable		33			59			9
Payables to affiliated companies		(37	)		32			(13	)
Other current liabilities		(29	)		(16	)		76
Other assets and deferred debits		(28	)		38			(19	)
Other liabilities and deferred credits		23			(1	)		44
Net cash provided by operating activities		1,018			1,094			1,032
Investing activities
Gross property additions		(757	)		(705	)		(603	)
Nuclear fuel additions		(184	)		(102	)		(79	)
Purchases of available-for-sale securities and other investments		(603	)		(896	)		(1,832	)
Proceeds from sales of available-for-sale securities and other investments		622			1,006			1,692
Changes in advances to affiliated companies		24			(24	)		–
Other investing activities		6			(1	)		11
Net cash used by investing activities		(892	)		(722	)		(811	)
Financing activities
Dividends paid on preferred stock		(3	)		(3	)		(3	)
Dividends paid to parent		(143	)		(339	)		(457	)
Net decrease in short-term debt		–			(73	)		(148	)
Proceeds from issuance of long-term debt, net		–			–			898
Retirement of long-term debt		(200	)		–			(300	)
Changes in advances from affiliated companies		154			(11	)		(105	)
Other financing activities		20			–			1
Net cash used by financing activities		(172	)		(426	)		(114	)
Net (decrease) increase in cash and cash equivalents		(46	)		(54	)		107
Cash and cash equivalents at beginning of year		71			125			18
Cash and cash equivalents at end of year	$	25		$	71		$	125
Supplemental disclosures
Cash paid during the year
Interest (net of amount capitalized)	$	210		$	210		$	187
Income taxes (net of refunds)		291			347			222
Significant noncash transactions
Noncash property additions accrued for as of December 31		87			104			53

See Notes to PEC Consolidated Financial Statements.

30

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
(in millions)	Common Stock Outstanding           Shares                   Amount					Unearned ESOP Shares			Accumulated Other Comprehensive (Loss) Income			Retained Earnings			Total Common Stock Equity
Balance, December 31, 2004		160	$	1,975		$	(76	)	$	(114	)	$	1,287		$	3,072
Net income				–			–			–			493			493
Other comprehensive loss				–			–			(6	)		–			(6	)
Comprehensive income																487
Stock-based compensation expense				3			–			–			–			3
Allocation of ESOP shares				20			13			–			–			33
Noncash dividend to parent				(17	)		–			–			–			(17	)
Preferred stock dividends at stated rates				–			–			–			(3	)		(3	)
Dividends paid to parent				–			–			–			(457	)		(457	)
Balance, December 31, 2005		160		1,981			(63	)		(120	)		1,320			3,118
Net income				–			–			–			457			457
Other comprehensive income				–			–			36			–			36
Comprehensive income																493
Adjustment to initially apply SFAS
No. 158, net of tax				–			–			83			–			83
Stock-based compensation expense				10			–			–			–			10
Allocation of ESOP shares				19			13			–			–			32
Preferred stock dividends at stated rates				–			–			–			(3	)		(3	)
Dividends paid to parent				–			–			–			(339	)		(339	)
Tax benefit dividend				–			–			–			(4	)		(4	)
Balance, December 31, 2006		160		2,010			(50	)		(1	)		1,431			3,390
Net income				–			–			–			501			501
Other comprehensive loss				–			–			(9	)		–			(9	)
Comprehensive income																492
Adjustment to initially apply FASB
Interpretation No. 48				–			–			–			(6	)		(6	)
Stock-based compensation expense				24			–			–			–			24
Allocation of ESOP shares				20			13			–			–			33
Preferred stock dividends at stated rates				–			–			–			(3	)		(3	)
Dividends paid to parent				–			–			–			(143	)		(143	)
Tax benefit dividend				–			–			–			(8	)		(8	)
Balance, December 31, 2007		160	$	2,054		$	(37	)	$	(10	)	$	1,772		$	3,779

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31	2007			2006			2005
Net income	$	501		$	457		$	493
Other comprehensive (loss) income
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $4, $2 and $(2), respectively)		(5	)		(2	)		3
Reclassification adjustment included in net income (net of tax expense of $-)		–			–			1
Minimum pension liability adjustment (net of tax (expense) benefit of $(23) and $7, respectively)		–			36			(12	)
Other (net of tax benefit (expense) of $1, $1 and $(1), respectively)		(4	)		2			2
Other comprehensive (loss) income		(9	)		36			(6	)
Comprehensive income	$	492		$	493		$	487

See Notes to PEC Consolidated Financial Statements.

31

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) at December 31, 2007 and 2006, 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, 2007. 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 include 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 at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the financial statements, on January 1, 2008 PEF adopted Financial Accounting Standards Board Staff Position FIN 39-1 and, retrospectively, adjusted all periods presented in the financial statements for the change.  Additionally, as discussed in Note 14 and Note 16 to the financial statements, on January 1, 2007 the Company adopted Financial Accounting Standards Board Interpretation No. 48 and on December 31, 2006 the Company adopted Statement of Financial Accounting Standards No. 158.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2008

(November 6, 2008 as to the effects of the retrospective implementation of Financial Accounting Standards Board Staff Position FIN 39-1 described in Note 2)

32

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.

STATEMENTS of INCOME
(in millions)
Years ended December 31	2007			2006			2005
Operating revenues	$	4,749		$	4,639		$	3,955
Operating expenses
Fuel used in electric generation		1,764			1,835			1,323
Purchased power		882			766			694
Operation and maintenance		834			684			852
Depreciation and amortization		366			404			334
Taxes other than on income		309			309			279
Other		8			(2	)		(26	)
Total operating expenses		4,163			3,996			3,456
Operating income		586			643			499
Other income
Interest income		9			15			1
Other, net		39			13			7
Total other income		48			28			8
Interest charges
Interest charges		185			155			134
Allowance for borrowed funds used during construction		(12	)		(5	)		(8	)
Total interest charges, net		173			150			126
Income before income tax		461			521			381
Income tax expense		144			193			121
Net income		317			328			260
Preferred stock dividend requirement		2			2			2
Earnings for common stock	$	315		$	326		$	258

See Notes to PEF Financial Statements.

33

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.

BALANCE SHEETS
(in millions)
December 31	2007			2006
ASSETS
Utility plant
Utility plant in service	$	10,025		$	9,202
Accumulated depreciation		(3,738	)		(3,602	)
Utility plant in service, net		6,287			5,600
Held for future use		35			7
Construction work in progress		1,199			672
Nuclear fuel, net of amortization		79			58
Total utility plant, net		7,600			6,337
Current assets
Cash and cash equivalents		23			23
Receivables, net		351			356
Receivables from affiliated companies		8			11
Notes receivable from affiliated companies		149			–
Deferred income taxes	��	39			86
Inventory		484			436
Income taxes receivable		41			47
Derivative assets		83			3
Prepayments and other current assets		9			62
Total current assets		1,187			1,024
Deferred debits and other assets
Regulatory assets		266			473
Nuclear decommissioning trust funds		580			552
Miscellaneous other property and investments		46			45
Derivative assets		100			19
Prepaid pension cost		221			174
Other assets and deferred debits		63			24
Total deferred debits and other assets		1,276			1,287
Total assets	$	10,063		$	8,648
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,109		$	1,100
Accumulated other comprehensive loss		(8	)		(1	)
Retained earnings		1,901			1,588
Total common stock equity		3,002			2,687
Preferred stock – not subject to mandatory redemption		34			34
Long-term debt, net		2,686			2,468
Total capitalization		5,722			5,189
Current liabilities
Current portion of long-term debt		532			89
Notes payable to affiliated companies		–			47
Accounts payable		473			308
Payables to affiliated companies		87			116
Interest accrued		57			38
Customer deposits		185			168
Derivative liabilities		38			92
Regulatory liabilities		173			76
Other current liabilities		92			89
Total current liabilities		1,637			1,023
Deferred credits and other liabilities
Noncurrent income tax liabilities		401			466
Accumulated deferred investment tax credits		17			23
Regulatory liabilities		1,330			1,110
Asset retirement obligations		315			299
Accrued pension and other benefits		304			332
Capital lease obligations		224			53
Other liabilities and deferred credits		113			153
Total deferred credits and other liabilities		2,704			2,436
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	10,063		$	8,648

See Notes to PEF Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.

STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2007			2006			2005
Operating activities
Net income	$	317		$	328		$	260
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program		–			–			92
Depreciation and amortization		385			433			367
Deferred income taxes and investment tax credits, net		(44	)		(48	)		(50	)
Deferred fuel cost (credit)		69			404			(173	)
Other adjustments to net income		36			19			19
Cash (used) provided by changes in operating assets and liabilities
Receivables		(8	)		(39	)		(70	)
Receivables from affiliated companies		3			–			4
Inventory		(35	)		(128	)		(34	)
Prepayments and other current assets		72			(37	)		(22	)
Income taxes, net		3			(56	)		(14	)
Accounts payable		43			19			52
Payables to affiliated companies		(29	)		15			21
Other current liabilities		35			20			7
Other assets and deferred debits		(44	)		13			(55	)
Other liabilities and deferred credits		(4	)		(50	)		26
Net cash provided by operating activities		799			893			430
Investing activities
Gross property additions		(1,214	)		(727	)		(496	)
Nuclear fuel additions		(44	)		(12	)		(47	)
Purchases of available-for-sale securities and other investments		(640	)		(625	)		(405	)
Proceeds from sales of available-for-sale securities and other investments		640			625			405
Changes in advances to affiliated companies		(149	)		–			–
Other investing activities		5			4			37
Net cash used by investing activities		(1,402	)		(735	)		(506	)
Financing activities
Dividends paid on preferred stock		(2	)		(2	)		(2	)
Dividends paid to parent		–			(234	)		–
Net decrease in short-term debt		–			(102	)		(191	)
Proceeds from issuance of long-term debt, net		739			–			744
Retirement of long-term debt		(89	)		(48	)		(102	)
Changes in advances from affiliated companies		(47	)		34			(165	)
Other financing activities		2			(1	)		(2	)
Net cash provided (used) by financing activities		603			(353	)		282
Net (decrease) increase in cash and cash equivalents		–			(195	)		206
Cash and cash equivalents at beginning of year		23			218			12
Cash and cash equivalents at end of year	$	23		$	23		$	218
Supplemental disclosures
Cash paid during the year
Interest (net of amount capitalized)	$	149		$	152		$	131
Income taxes (net of refunds)		184			296			185
Significant noncash transactions
Capital lease obligation incurred		182			54			–
Noncash property additions accrued for as of December 31		238			119			50

See Notes to PEF Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of CHANGES in COMMON STOCK EQUITY
(in millions except shares outstanding)	Common Stock Outstanding           Shares                   Amount				Accumulated Other Comprehensive Loss			Retained Earnings			Total Common Stock Equity
Balance, December 31, 2004		100	$	1,081	$	–		$	1,240		$	2,321
Net income				–		–			260			260
Comprehensive income												260
Stock-based compensation expense				1		–			–			1
Noncash contribution from parent				15		–			–			15
Preferred stock dividends at stated rates				–		–			(2	)		(2	)
Balance, December 31, 2005		100		1,097		–			1,498			2,595
Net income				–		–			328			328
Other comprehensive loss				–		(1	)		–			(1	)
Comprehensive income												327
Stock-based compensation expense				3		–			–			3
Preferred stock dividends at stated rates				–		–			(2	)		(2	)
Dividends paid to parent				–		–			(234	)		(234	)
Tax benefit dividend				–		–			(2	)		(2	)
Balance, December 31, 2006		100		1,100		(1	)		1,588			2,687
Net income				–		–			317			317
Other comprehensive loss				–		(7	)		–			(7	)
Comprehensive income												310
Stock-based compensation expense				9		–			–			9
Preferred stock dividends at stated rates				–		–			(2	)		(2	)
Tax benefit dividend				–		–			(2	)		(2	)
Balance, December 31, 2007		100	$	1,109	$	(8	)	$	1,901		$	3,002

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31	2007			2006			2005
Net income	$	317		$	328		$	260
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $5 and $1, respectively)		(7	)		(1	)		–
Other comprehensive loss		(7	)		(1	)		–
Comprehensive income	$	310		$	327		$	260

See Notes to PEF Financial Statements.

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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, INC.

The Parent is a holding company headquartered in Raleigh, N.C. As such, we are subject to regulation by the Federal Energy Regulatory Commission (FERC) under the regulatory provisions of the Public Utility Holding Company Act of 2005 (PUHCA 2005).

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 (PESC) and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a separate 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 provisions 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 provisions 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) and 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. Noncontrolling interests in subsidiaries along with the income or loss attributed to these interests are included in minority interest in both the Consolidated Balance Sheets and in the Consolidated Statements of Income. The results of operations for minority interest 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 (generally 20 percent to 50 percent ownership), 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 (See Note 20). 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 13 for more information about our investments.

Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the ratemaking process is probable.

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 2006 and 2005 have been reclassified to conform to the 2007 presentation. In addition, our 2007 presentation of operating, investing and financing cash flows combines the respective cash flows from our continuing and discontinued operations as permitted under SFAS No. 95, “Statement of Cash Flows.” Previously, we had provided separate disclosure of cash flows from continuing operations and discontinued operations. These changes in cash flow presentations had no impact on total cash and cash equivalents, net change in cash and cash equivalents, or results of operations.

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 for which we are the primary beneficiary in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46R, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51” (FIN 46R).

PROGRESS ENERGY

In addition to the variable interests listed below for PEC and PEF, we have interests through other subsidiaries in several variable interest entities for which we are not the primary beneficiary. These arrangements include investments in five limited liability partnerships and limited liability corporations. At December 31, 2007, the aggregate additional maximum loss exposure that we could be required to record in our income statement as a result of these arrangements was $6 million, which represents our net remaining investment in the entities. The creditors of these variable interest entities do not have recourse to our general credit in excess of the aggregate maximum loss exposure.

PEC

PEC is the primary beneficiary of, and consolidates, two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code (the Code). At December 31, 2007, the total assets of the two entities were $37 million, the majority of which are collateral for the entities’ obligations and are included in miscellaneous other property and investments in the Consolidated Balance Sheet.

PEC has an interest in and consolidates a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. PEC has requested the necessary information to determine if the 17 partnerships are variable interest entities or to identify the primary beneficiaries; all entities from which the necessary financial information was requested declined to provide the information to PEC and, accordingly, PEC has applied the information scope exception in FIN 46R, paragraph 4(g), to the 17 partnerships. PEC believes that if it is determined to be the primary beneficiary of these entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings or cash flows.

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PEC also has an interest in one power plant resulting from long-term power purchase contracts. Our only significant exposure to variability from these contracts results from fluctuations in the market price of fuel used by the entity’s plants to produce the power purchased by PEC. We are able to recover these fuel costs under PEC’s fuel clause. Total purchases from this counterparty were $39 million, $45 million and $44 million in 2007, 2006 and 2005, respectively. The generation capacity of the entity’s power plant is approximately 847 megawatts (MW). PEC has requested the necessary information to determine if the power plant owner is a variable interest entity or to identify the primary beneficiary. The entity declined to provide us with the necessary financial information and PEC has applied the information scope exception in FIN 46R, paragraph 4(g), to the power plant. PEC believes that if it is determined to be the primary beneficiary of the entity, the effect of consolidating the entity would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings or cash flows. However, because PEC has not received any financial information from the counterparty, the impact cannot be determined at this time.

PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include investments in 21 limited liability partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. At December 31, 2007, the aggregate maximum loss exposure that PEC could be required to record on its income statement as a result of these arrangements totals $19 million, which primarily represents its net remaining investment in these entities. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure.

PEF

PEF has interests in four variable interest entities for which PEF is not the primary beneficiary. These arrangements include investments in one venture capital fund, one limited liability corporation, one building lease with a special-purpose entity and one operating lease with a special-purpose entity. At December 31, 2007, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was $56 million. The majority of this exposure is related to a prepayment clause in the building lease and is not considered equity at risk. The creditors of these variable interest entities do not have recourse to the general credit of PEF in excess of the aggregate maximum loss exposure.

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 revenues earned when service has been delivered but not billed by the end of the accounting period, and diversified business revenues, which are generally recognized at the time products are shipped or as services are rendered. Customer prepayments are recorded as deferred revenue and recognized as revenues as the services are provided.

FUEL COST DEFERRALS

Fuel expense includes fuel costs or 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

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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)	2007		2006		2005
Progress Energy	$	299	$	293	$	258
PEC		99		94		91
PEF		200		199		167

STOCK-BASED COMPENSATION

Prior to July 2005, we accounted for stock-based compensation under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for our stock-based compensation costs. In addition, we followed the disclosure requirements contained in SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123), as amended by SFAS No. 148, "Accounting for Stock-Based Compensation – Transition and Disclosure." Effective July 1, 2005, we adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), for stock-based compensation utilizing the modified prospective transition method (See Note 10B).

RELATED PARTY TRANSACTIONS

Our subsidiaries provide and receive services, at cost, to and from the Parent and its subsidiaries, in accordance with PUHCA 2005. 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 that would otherwise not be capitalized under GAAP 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 occur every two years. 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 (ARO) under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), 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.

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ASSET RETIREMENT OBLIGATIONS

We account for AROs, which represent legal obligations associated with the retirement of certain tangible long-lived assets, in accordance with SFAS No. 143. 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 an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. In addition, effective December 31, 2005, we also adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarified certain requirements of SFAS No. 143.

The adoption of SFAS No. 143 and FIN 47 had no impact on the income of the Utilities as the effects were offset by the establishment of regulatory assets and regulatory liabilities pursuant to SFAS No. 71 (See Note 7A) and in accordance with orders issued by the NCUC, the SCPSC and the FPSC.

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 5A). Pursuant to their rate-setting authority, the NCUC, SCPSC and FPSC can also grant approval to accelerate or reduce depreciation and amortization 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.

The North Carolina Clean Smokestacks Act (Clean Smokestacks Act) was enacted in 2002. The Clean Smokestacks Act froze North Carolina electric utility base rates for a five-year period, which ended in December 2007, unless there were extraordinary events beyond the control of the utilities or unless the utilities persistently earned a return substantially in excess of the rate of return established and found reasonable by the NCUC in the respective utility’s last general rate case. There were no adjustments to PEC’s base rates during the five-year period ended December 2007. Subsequent to 2007, PEC’s current North Carolina base rates are continuing subject to traditional cost-based rate regulation. During the rate freeze period, the legislation provided for the amortization and recovery of 70 percent of the original estimated compliance costs for the Clean Smokestacks Act while providing significant flexibility in the amount of annual amortization recorded from none up to $174 million per year. During 2007, the NCUC approved PEC's request to amortize the remaining 30 percent of the original estimated compliance costs during 2008 and 2009, with discretion to amortize up to $174 million in either year.

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.

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. We value inventory of nonregulated subsidiaries at the lower of cost or market.

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REGULATORY ASSETS AND LIABILITIES

The Utilities’ operations are subject to SFAS No. 71, 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.

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.

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. Since 2002, Progress Energy tax benefits not related to acquisition interest expense had been allocated to profitable subsidiaries in accordance with an order under the Public Utilities Holding Company Act of 1935, as amended (PUHCA 1935). Except for the allocation of these Progress Energy tax benefits, income taxes are provided as if PEC and PEF filed separate returns. Due to the repeal of PUHCA 1935, effective February 8, 2006, we stopped allocating these tax benefits.

Deferred income taxes have been provided for temporary differences. These occur when there are differences between the 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. 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 on the Consolidated Statements of Income.

DERIVATIVES

We account for derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities – An Amendment of FASB Statement No. 133,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments

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embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value, unless the derivatives meet the SFAS No. 133 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 SFAS No. 133 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 SFAS No. 133 hedge criteria are met. 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. See Note 17 for additional information regarding risk management activities and derivative transactions.

LOSS CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

We accrue for loss contingencies in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5). Under SFAS No. 5, contingent losses such as unfavorable results of litigation are recorded when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. Unless otherwise required by GAAP, we do not accrue 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 SFAS No. 5 have been met. 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. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. 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

As discussed in Note 9, we account for impairment of long-lived assets in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). 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 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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SUBSIDIARY STOCK TRANSACTIONS

Gains and losses realized as a result of common stock sales by our subsidiaries are recorded in the Consolidated Statements of Income, except for any transactions that must be credited directly to equity in accordance with the provisions of Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary.”

2.   NEW ACCOUNTING STANDARDS

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”

Refer to Note 14 for information regarding our first quarter 2007 implementation of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" (FIN 48).

SFAS No. 157, “Fair Value Measurements”

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which redefines 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.” SFAS No. 157 establishes a framework for measuring fair value and a fair value hierarchy that categorizes and prioritizes the inputs that should be used to estimate fair value. The effective date of SFAS No. 157 for us and the Utilities is January 1, 2008. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2, which for us and the Utilities delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. We will implement SFAS No. 157 as of January 1, 2008, and will utilize the deferral provision of FSP No. FAS 157-2 for all nonfinancial assets and liabilities within its scope. We do not expect the adoption of SFAS No. 157 to have a material impact on our or the Utilities' financial position or results of operations.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”

In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115" (SFAS No. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The decision about whether to elect the fair value option is applied on an instrument by instrument basis, is irrevocable (unless a new election date occurs) and is applied to the entire financial instrument. SFAS No. 159 is effective for us and the Utilities on January 1, 2008. We do not expect the adoption of SFAS No. 159 to have a material impact on our or the Utilities' financial position or results of operations.

FASB Staff Position No. FIN 39-1,  "An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts"

On January 1, 2008 Progress Energy, PEC and PEF implemented FASB Staff Position No. FIN 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1), which allows a reporting entity to make an accounting election whether or not to offset fair value amounts recognized for derivative instruments and related collateral assets and liabilities with the same counterparty under a master netting agreement.  Prior to the adoption of FSP FIN 39-1, we and the Utilities offset fair value amounts recognized for derivative instruments under master netting arrangements. FSP FIN 39-1 was implemented as a retrospective change in accounting principle and upon adoption, Progress Energy, PEC and PEF discontinued the offset of fair value amounts for such derivatives. The change had no impact on our or the Utilities’ results of operations or equity and resulted in increases in the previously reported December 31, 2007 and 2006 assets and liabilities in the combined Annual Report on Form 10-K for the year ended December 31, 2007, as follows:

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	Progress Energy		PEC		PEF
(in millions)	2007	2006	2007	2006	2007	2006
Current assets	$54	$115	$19	$5	$35	$19
Noncurrent assets	25	37	1	1	24	36
Current liabilities	54	115	19	5	35	19
Noncurrent liabilities	25	37	1	1	24	36

The increase in current assets and current liabilities for Progress Energy in 2006 includes $91 million for assets to be divested and liabilities to be divested.

SFAS No. 141R, “Business Combinations”

In December 2007, the FASB issued SFAS Statement No. 141R, “Business Combinations” (SFAS No. 141R), which introduces significant changes in the accounting for business acquisitions. SFAS No. 141R considerably broadens the definition of a “business” and a “business combination,” which will result in an increased number of transactions or other events that will qualify as business combinations. This will affect us and the Utilities primarily in our assessment of variable interest entities (“VIEs”). SFAS No. 141R amends FIN 46R to clarify that the initial consolidation of a business that is a VIE is a business combination in which the acquirer should recognize and measure the fair value of the acquiree as a whole, and the assets acquired and liabilities assumed at their full fair values as of the date control is obtained, regardless of the percentage ownership in the acquiree or how the acquisition was achieved. Other significant changes include the expensing of all acquisition-related transaction costs and most acquisition-related restructuring costs, the fair value remeasurement of certain earn-out arrangements and the discontinuance of the expense at acquisition of acquired-in-process research and development. SFAS No. 141R is effective for us for business combinations for which the acquisition date is on or after January 1, 2009. Earlier application is prohibited. We do not expect the adoption of SFAS No. 141R to have a material impact on our or the Utilities' financial position or results of operations.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”

In conjunction with the issuance of SFAS No. 141R, in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160) which introduces significant changes in the accounting for noncontrolling interests in a partially owned consolidated subsidiary. SFAS No. 160 also changes the accounting for and reporting for the deconsolidation of a subsidiary. SFAS No. 160 requires that a noncontrolling interest in a consolidated subsidiary be displayed in the consolidated statement of financial position as a separate component of equity rather than as a “mezzanine” item between liabilities and equity. SFAS No. 160 also requires that earnings attributed to the noncontrolling interests be reported as part of consolidated earnings, and requires disclosure of the attribution of consolidated earnings to the controlling and noncontrolling interests on the face of the consolidated income statement. SFAS No. 160 must be adopted concurrently with the effective date of SFAS No. 141R, which for us is January 1, 2009. We do not expect the adoption of SFAS No. 160 to have a material impact on our or the Utilities' financial position or results of operations.

3.    DIVESTITURES

A.     CCO – GEORGIA OPERATIONS

On March 9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series of transactions to sell or assign substantially all of its Competitive Commercial Operations (CCO) physical and commercial assets and liabilities. Assets divested include approximately 1,900 MW of gas-fired generation assets in Georgia. The sale of the generation assets closed on June 11, 2007, for a net sales price of $615 million. We recorded an estimated after-tax loss of $226 million in December 2006. Based on the terms of the final agreement and post-closing adjustments, during the year ended December 31, 2007, we reversed $18 million after-tax of the impairment recorded in 2006.

Additionally, on June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of full-requirements contracts with 16 Georgia electric membership cooperatives (the Georgia Contracts), forward gas and power contracts, gas transportation, structured power and other contracts to a third party. This represents

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substantially all of our nonregulated energy marketing and trading operations. As a result of the assignments, PVI made a net cash payment of $347 million, which represents the net cost to assign the Georgia Contracts and other related contracts. In the year ended December 31, 2007, we recorded a charge associated with the costs to exit the Georgia Contracts, and other related contracts, of $349 million after-tax (charge included in the net loss from discontinued operations in the table below). We used the net proceeds from the divestiture of CCO and the Georgia Contracts for general corporate purposes.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of CCO as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the years ended December 31, 2007, 2006 and 2005 was $11 million, $36 million and $39 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in December 2006. After-tax depreciation expense during each of the years ended December 31, 2006 and 2005 was $14 million. Results of discontinued operations for CCO for the years ended December 31 were as follows:

(in millions)	2007			2006			2005
Revenues	$	407		$	754		$	627
Loss before income taxes	$	(449	)	$	(92	)	$	(93	)
Income tax benefit		166			35			39
Net loss from discontinued operations		(283	)		(57	)		(54	)
Gain (loss) on disposal of discontinued operations, including income tax								–
benefit of $7 and $123, respectively		18			(226	)
Loss from discontinued operations	$	(265	)	$	(283	)	$	(54	)

B.TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

On December 24, 2007, we signed an agreement to sell coal terminals and docks in West Virginia and Kentucky (Terminals) for $71 million in gross cash proceeds. Terminals was previously a component of our former Coal and Synthetic Fuels segment. The terminals have a total annual capacity in excess of 40 million tons for transloading, blending and storing coal and other commodities. Proceeds from the sale are expected to be used for general corporate purposes. We expect this transaction to close by the end of the first quarter of 2008.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of Terminals as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the years ended December 31, 2007, 2006 and 2005 was $1 million, $1 million and $3 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in November 2007. After-tax depreciation expense during each of the years ended December 31, 2007, 2006 and 2005 was $2 million, $4 million and $7 million, respectively.

Historically, we have had substantial operations associated with the production of coal-based solid synthetic fuels (Synthetic Fuels) as defined under Section 29 of the Code. The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. Synthetic fuels are generally not economical to produce and sell absent the credits. On September 14, 2007, we idled production of synthetic fuels at our majority-owned synthetic fuels facilities due to the high level of oil prices. On October 12, 2007, based upon the continued high level of oil prices, unfavorable oil price projections through the end of 2007, and the expiration of the synthetic fuels tax credit program at the end of 2007, we permanently ceased production of synthetic fuels at our majority-owned facilities. 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. In accordance with the provisions of SFAS No. 144, a long-lived asset is abandoned when it ceases to be used. The accompanying consolidated income statements have been restated for all periods presented to reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

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Results of discontinued operations for the years ended December 31 for Terminals and Synthetic Fuels were as follows:

(in millions)	2007		2006			2005
Revenues	$	1,126	$	847		$	1,220
Earnings (loss) before income taxes and minority interest	$	2	$	(179	)	$	(171	)
Income tax benefit, including tax credits		64		135			336
Minority interest share of losses		17		7			33
Net earnings (loss) from discontinued operations	$	83	$	(37	)	$	198

C.NATURAL GAS DRILLING AND PRODUCTION

On October 2, 2006, we sold our natural gas drilling and production business (Gas) for approximately $1.1 billion in net proceeds. Gas included Winchester Production Company, Ltd. (Winchester Production), Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets Ltd.; all were subsidiaries of Progress Fuels. Proceeds from the sale have been used primarily to reduce holding company debt and for other corporate purposes.

Based on the net proceeds associated with the sale, we recorded an after-tax net gain on disposal of $300 million during the year ended December 31, 2006. We recorded an after-tax loss of $2 million during the year ended December 31, 2007, primarily related to working capital adjustments.

The accompanying consolidated financial statements reflect the operations of Gas as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for each of the years ended December 31, 2006, and 2005 was $13 million. We ceased recording depreciation upon classification of the assets as discontinued operations in July 2006. After-tax depreciation expense during the years ended December 31, 2006, and 2005 was $16 million and $26 million, respectively. Results of discontinued operations for Gas for the years ended December 31 were as follows:

(in millions)	2007			2006			2005
Revenues	$	–		$	192		$	159
Earnings before income taxes	$	–		$	135		$	73
Income tax benefit (expense)		4			(53	)		(25	)
Net earnings from discontinued operations		4			82			48
(Loss) gain on disposal of discontinued operations, including income tax benefit (expense) of $1 and $(188), respectively		(2	)		300			–
Earnings from discontinued operations	$	2		$	382		$	48

D.CCO – DESOTO AND ROWAN GENERATION FACILITIES

On May 2, 2006, our board of directors approved a plan to divest of two subsidiaries of PVI, DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (Rowan). DeSoto owned a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Fla., and Rowan owned a 925 MW dual-fuel combined cycle and combustion turbine electric generation facility in Rowan County, N.C. On May 8, 2006, we entered into definitive agreements to sell DeSoto and Rowan, including certain existing power supply contracts, to Southern Power Company, a subsidiary of Southern Company, for gross purchase prices of approximately $80 million and $325 million, respectively. We used the proceeds from the sales to reduce debt and for other corporate purposes.

The sale of DeSoto closed in the second quarter of 2006 and the sale of Rowan closed during the third quarter of 2006. Based on the gross proceeds associated with the sales, we recorded an after-tax loss on disposal of $67 million during the year ended December 31, 2006.

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The accompanying consolidated financial statements reflect the operations of DeSoto and Rowan as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the years ended December 31, 2006, and 2005 was $6 million and $13 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in May 2006. After-tax depreciation expense during the years ended December 31, 2006, and 2005 was $3 million and $8 million, respectively. Results of discontinued operations for DeSoto and Rowan for the years ended December 31 were as follows:

(in millions)	2006			2005
Revenues	$	64		$	67
Earnings before income taxes	$	15		$	5
Income tax expense		(5	)		(2	)
Net earnings from discontinued operations		10			3
Loss on disposal of discontinued operations, including income tax benefit of $37		(67	)		–
(Loss) earnings from discontinued operations	$	(57	)	$	3

E.PROGRESS TELECOM, LLC

On March 20, 2006, we completed the sale of Progress Telecom, LLC (PT LLC) to Level 3 Communications, Inc. (Level 3). We received gross proceeds comprised of cash of $69 million and approximately 20 million shares of Level 3 common stock valued at an estimated $66 million on the date of the sale. Our net proceeds from the sale of approximately $70 million, after consideration of minority interest, were used to reduce debt. Prior to the sale, we had a 51 percent interest in PT LLC. See Note 20 for a discussion of the subsequent sale of the Level 3 stock in 2006.

Based on the net proceeds associated with the sale and after consideration of minority interest, we recorded an after-tax net gain on disposal of $28 million during the year ended December 31, 2006.

The accompanying consolidated financial statements reflect the operations of PT LLC as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated was $1 million for the year ended December 31, 2005. We ceased recording depreciation upon classification of the assets as discontinued operations in January 2006. After-tax depreciation expense during the years ended December 31, 2006, and 2005 was $1 million and $8 million, respectively. Results of discontinued operations for PT LLC for the years ended December 31 were as follows:

(in millions)	2006			2005
Revenues	$	18		$	76
Earnings before income taxes and minority interest	$	7		$	11
Income tax expense		(4	)		(3	)
Minority interest share of earnings		(5	)		(4	)
Net (loss) earnings from discontinued operations		(2	)		4
Gain on disposal of discontinued operations, including income tax expense of $8 and minority interest of $35		28			–
Earnings from discontinued operations	$	26		$	4

In connection with the sale, PEC and PEF provided indemnification against costs associated with certain asset performances to Level 3. See general discussion of guarantees at Note 22C. The ultimate resolution of these matters could result in adjustments to the gain on sale in future periods.

F.DIXIE FUELS AND OTHER FUELS BUSINESS

On March 1, 2006, we sold Progress Fuels’ 65 percent interest in Dixie Fuels Limited (Dixie Fuels) to Kirby Corporation for $16 million in cash. Dixie Fuels operates a fleet of four ocean-going dry-bulk barge and tugboat

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units. Dixie Fuels primarily transports coal from the lower Mississippi River to Progress Energy’s Crystal River facility. We recorded an after-tax gain of $2 million on the sale of Dixie Fuels during the year ended December 31, 2006. During the year ended December 31, 2007, we recorded an additional gain of $2 million primarily related to the expiration of indemnifications.

The accompanying consolidated financial statements reflect Dixie Fuels and the other fuels business as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated was $1 million for each of the years ended December 31, 2006, and 2005. We ceased recording depreciation upon classification of the assets as discontinued operations. After-tax depreciation expense during the years ended December 31, 2006, and 2005 was $1 million and $2 million, respectively. Results of discontinued operations for Dixie Fuels and other fuels businesses for the years ended December 31 were as follows:

(in millions)	2007		2006			2005
Revenues	$	–	$	20		$	32
Earnings before income taxes	$	–	$	11		$	8
Income tax expense		–		(4	)		(3	)
Net earnings from discontinued operations		–		7			5
Gain on disposal of discontinued operations, including income tax expense of $1 and $1, respectively		2		2			–
Earnings from discontinued operations	$	2	$	9		$	5

G.COAL MINING BUSINESSES

Progress Fuels owned five subsidiaries engaged in the coal mining business. These businesses were previously included in our former Coal and Synthetic Fuels business segment. On May 1, 2006, we sold certain net assets of three of our coal mining businesses to Alpha Natural Resources, LLC for gross proceeds of $23 million plus a $4 million working capital adjustment. As a result, during the year ended December 31, 2006, we recorded an after-tax loss of $10 million on the sale of these assets.

On December 24, 2007, we signed an agreement to sell the remaining net assets of the coal mining business for gross cash proceeds of $23 million. These assets include Powell Mountain Coal Co. and Dulcimer Land Co., which consist of about 30,000 acres in Lee County, Va. and Harlan County, Ky. The property contains an estimated 40 million tons of high quality coal reserves. We expect this transaction to close by the end of the first quarter of 2008.

The accompanying consolidated financial statements reflect the coal mining operations as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of the coal mines, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the years ended December 31, 2007, 2006 and 2005 was $1 million, $1 million and $3 million, respectively. We ceased recording depreciation expense upon classification of the coal mining operations as discontinued operations in November 2005. After-tax depreciation expense during the year ended December 31, 2005, was $10 million. Results of discontinued operations for the coal mining businesses for the years ended December 31 were as follows:

(in millions)	2007			2006			2005
Revenues	$	28		$	84		$	184
Loss before income taxes	$	(17	)	$	(11	)	$	(16	)
Income tax benefit		6			7			5
Net loss from discontinued operations		(11	)		(4	)		(11	)
Loss on disposal of discontinued operations, including income tax benefit of $16		–			(10	)		–
Loss from discontinued operations	$	(11	)	$	(14	)	$	(11	)

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H.PROGRESS RAIL

On March 24, 2005, we completed the sale of Progress Rail Services Corporation (Progress Rail) to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Cash proceeds from the sale were approximately $429 million, consisting of $405 million base proceeds plus a working capital adjustment. Proceeds from the sale were used to reduce debt.

Based on the gross proceeds associated with the sale of $429 million, we recorded an estimated after-tax loss on disposal of $25 million during the year ended December 31, 2005. During the year ended December 31, 2006, we recorded an additional after-tax loss on disposal of $6 million in connection with guarantees and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters to One Equity Partners LLC. The ultimate resolution of these matters could result in adjustments to the loss on sale in future periods. See general discussion of guarantees at Note 22C.

The accompanying consolidated financial statements reflect the operations of Progress Rail as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of Progress Rail, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the year ended December 31, 2005, was $4 million. We ceased recording depreciation upon classification of Progress Rail as discontinued operations in February 2005. After-tax depreciation expense during the year ended December 31, 2005, was $3 million. Results of discontinued operations for Progress Rail for the years ended December 31 were as follows:

(in millions)	2006			2005
Revenues	$	–		$	358
Earnings before income taxes	$	–		$	8
Income tax expense		–			(3	)
Net earnings from discontinued operations		–			5
Loss on disposal of discontinued operations, including income tax (expense) benefit of $(6) and $15, respectively		(6	)		(25	)
Loss from discontinued operations	$	(6	)	$	(20	)

I. NET ASSETS TO BE DIVESTED

At December 31, 2007, the assets and liabilities of Terminals and the remaining assets and liabilities of the coal mining operations were included in net assets to be divested. At December 31, 2006, the assets and liabilities of CCO, Terminals, the remaining coal mining operations and other fuels businesses were included in net assets to be divested. The major balance sheet classes included in assets and liabilities to be divested in the Consolidated Balance Sheets were as follows:

(in millions)	December 31, 2007		December 31, 2006
Accounts receivable	$	–	$	44
Inventory		6		56
Other current assets		2		113
Property, plant and equipment, net		38		595
Other assets		6		249
Assets to be divested	$	52	$	1,057
Accounts payable	$	–	$	43
Accrued expenses		3		248
Long-term liabilities		5		48
Liabilities to be divested	$	8	$	339

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J.CEREDO SYNTHETIC FUELS INTERESTS

On March 30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership interest in Ceredo Synfuel LLC (Ceredo), a subsidiary that produces and sells qualifying coal-based solid synthetic fuels, to a third-party buyer. In addition, we entered into an agreement to operate the Ceredo facility on behalf of the buyer. At closing, we received cash proceeds of $10 million and a non-recourse note receivable of $54 million. Payments on the note are due as we produce and sell qualifying synthetic fuels on behalf of the buyer. In accordance with the terms of the agreement, we received payments on the note related to 2007 production of $49 million in 2007 and $5 million in 2008. The total amount of proceeds is subject to adjustment once the final value of the 2007 Section 29/45K credits  is known. The note bears interest at a rate equal to the three-month London Inter Bank Offering Rate (LIBOR) rate plus 1%. The estimated fair value of the note at the inception of the transaction was $48 million.

Pursuant to the terms of the disposal agreement, the buyer had the right to unwind the transaction if an Internal Revenue Service (IRS) reconfirmation private letter ruling was not received by November 9, 2007, or if certain adverse changes in tax law, as defined in the agreement, occurred before November 19, 2007. The IRS reconfirmation private letter ruling was received on October 29, 2007, and no adverse change in tax law occurred prior to November 19, 2007. As of December 31, 2007, due to indemnification provisions discussed below, we recorded losses on disposal of $3 million based on the estimated value of the 2007 Section 29/45K tax credits. The operations of Ceredo have been reclassified to discontinued operations for all periods presented. See discussion of the abandonment of our synthetic fuels operations at Note 3B.

On the date of the transaction, the carrying value of the disposed ownership interest totaled $37 million, which consisted primarily of the fair value of crude oil call options purchased in January 2007. Subsequent to the disposal, we remained the primary beneficiary of Ceredo and continued to consolidate Ceredo in accordance with FIN 46R, but recorded a 100 percent minority interest. In connection with the disposal, Progress Fuels and Progress Energy provided guarantees and indemnifications for certain legal and tax matters to the buyer. The ultimate resolution of these matters could result in adjustments to the loss on disposal in future periods. See general discussion of guarantees at Note 22C.

K.WINTER PARK DISTRIBUTION ASSETS

As discussed in Note 7C, PEF sold certain electric distribution assets to Winter Park, Fla. (Winter Park), on June 1, 2005.

L.SYNTHETIC FUELS PARTNERSHIP INTERESTS

In two June 2004 transactions, Progress Fuels sold a combined 49.8 percent partnership interest in Colona Synfuel Limited Partnership, LLLP (Colona), one of its synthetic fuels facilities. Substantially all proceeds from the sales were received over time, which is typical of such sales in the industry. Gains from the sales were recognized on a cost-recovery basis. The book value of the interests sold totaled approximately $5 million. We recognized gains on these transactions of $4 million and $30 million in the years ended December 31, 2006, and 2005, respectively. In 2007, due to the increase in the price of oil that limits synthetic fuels tax credits, we did not record any additional gains. The operations of Colona have been reclassified to discontinued operations for all periods presented. See discussion of the abandonment of our synthetic fuels operations at Note 3B.

4.     ACQUISITIONS

In May 2005, Winchester Production, an indirectly wholly owned subsidiary of Progress Fuels, acquired a 50 percent interest in 11 natural gas producing wells and proven reserves of approximately 25 billion cubic feet equivalent from a privately owned company headquartered in Texas. In addition to the natural gas reserves, the transaction also included a 50 percent interest in the gas gathering systems related to these reserves. The total cash purchase price for the transaction was $46 million. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for 2005. In 2006, we sold our 50 percent interest in the wells, reserves and gas gathering system as part of our transaction with EXCO Resources, Inc. (See Note 3C).

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5.     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		2007		2006		2007		2006		2007		2006
Production plant		7-43	$	13,765	$	12,685	$	8,968	$	8,422	$	4,612	$	4,078
Transmission plant		17-75		2,684		2,509		1,361		1,300		1,323		1,209
Distribution plant		13-55		7,676		7,351		4,147		3,992		3,529		3,359
General plant and other		5-35		1,202		1,198		641		642		561		556
Utility plant in service			$	25,327	$	23,743	$	15,117	$	14,356	$	10,025	$	9,202

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 12C).

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 8.8%, 8.7% and 5.6% in 2007, 2006 and 2005, respectively. The composite AFUDC rate for PEF’s electric utility plant was 8.8%, 8.8% and 7.8% in 2007, 2006 and 2005, respectively.

Our depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.4%, 2.3% and 2.2% in 2007, 2006 and 2005, respectively. The depreciation provisions related to utility plant were $560 million, $533 million and $477 million in 2007, 2006 and 2005, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 5D), regulatory approved expenses (See Notes 7 and 21) and Clean Smokestacks Act amortization (See Note 7B).

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, for the years ended December 31, 2007, 2006 and 2005 was $139 million, $140 million and $136 million, respectively. This amortization expense is included in fuel used for electric generation in the Consolidated Statements of Income.

PEC’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.1% for 2007, 2006 and 2005. The depreciation provisions related to utility plant were $303 million, $294 million and $286 million in 2007, 2006 and 2005, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 5D), regulatory approved expenses (See Note 7B) and Clean Smokestacks Act amortization (See Note 7B).

PEF’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.7%, 2.7% and 2.3% in 2007, 2006 and 2005, respectively. The depreciation provisions related to utility plant were $257 million, $239 million and $191 million in 2007, 2006 and 2005, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 5D) and regulatory approved expenses (See Notes 7 and 21).

Amortization of nuclear fuel costs, including disposal costs associated with obligations to the DOE and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities, for the years ended December 31, 2007, 2006 and 2005 was $110 million, $109 million and $107 million, respectively,

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for PEC and $29 million, $31 million and $29 million, respectively, for PEF. These costs were included in fuel used for electric generation in the Statements of Income.

B.    DIVERSIFIED BUSINESS PROPERTY

Net diversified business property is included in miscellaneous other property and investments on our and PEC’s Consolidated Balance Sheets. Diversified business property excludes amounts reclassified as assets to be divested (See Note 3I).

Progress Energy

The balances of diversified business property at December 31 are listed below, with a range of depreciable lives for each:

(in millions)	2007			2006
Equipment (3-25 years)	$	6		$	10
Land and mineral rights		–			1
Buildings and plants (5-40 years)		9			47
Accumulated depreciation		(9	)		(50	)
Diversified business property, net	$	6		$	8

Diversified business depreciation expense was $3 million, $2 million and $4 million for the years ended December 31, 2007, 2006 and 2005, respectively.

PEC

Net diversified business property was $6 million at December 31, 2007 and $7 million at December 31, 2006. These amounts consist primarily of buildings and equipment that are being depreciated over periods ranging from 10 to 40 years. Accumulated depreciation was $2 million at both December 31, 2007 and December 31, 2006. Diversified business depreciation expense was less than $1 million each in 2007, 2006 and 2005.

C.    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 (See Note 21B). Each of the Utilities' share of operating costs of the above 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:

2007 (in millions) Subsidiary	Facility	Company Ownership Interest			Plant Investment		Accumulated Depreciation		Construction Work in Progress
PEC	Mayo		83.83	%	$	519	$	270	$	128
PEC	Harris		83.83	%		3,175		1,581		21
PEC	Brunswick		81.67	%		1,647		959		16
PEC	Roxboro Unit 4		87.06	%		634		164		39
PEF	Crystal River Unit 3		91.78	%		817		450		177
PEF	Intercession City Unit P11		66.67	%		23		9		–

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2006 (in millions) Subsidiary	Facility	Company Ownership Interest			Plant Investment		Accumulated Depreciation		Construction Work in Progress
PEC	Mayo		83.83	%	$	517	$	263	$	–
PEC	Harris		83.83	%		3,159		1,489		18
PEC	Brunswick		81.67	%		1,632		941		15
PEC	Roxboro Unit 4		87.06	%		356		163		1
PEF	Crystal River Unit 3		91.78	%		811		452		76
PEF	Intercession City Unit P11		66.67	%		23		7		–

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.

D.    ASSET RETIREMENT OBLIGATIONS

At December 31, 2007 and 2006, the asset retirement costs, included in utility plant, related to nuclear decommissioning of irradiated plant, net of accumulated depreciation for PEC, totaled $29 million and $30 million, respectively. No costs related to nuclear decommissioning of irradiated plant were recorded at December 31, 2007 and 2006 at PEF. At December 31, 2007 and 2006, additional PEF-related asset retirement costs, net of accumulated depreciation, of $121 million and $126 million, respectively, were recorded at Progress Energy as purchase accounting adjustments when we purchased Florida Progress Corporation (Florida Progress) in 2000. The fair value of funds set aside in the Utilities’ nuclear decommissioning trust funds for the nuclear decommissioning liability totaled $804 million and $735 million at December 31, 2007 and 2006, respectively, for PEC and $580 million and $552 million, respectively, for PEF. Net nuclear decommissioning trust unrealized gains are included in regulatory liabilities (See Note 7A).

PEC’s nuclear decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million each in 2007, 2006 and 2005. 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 are not SFAS No. 143 AROs, which are included in depreciation and amortization expense, were $96 million, $96 million and $90 million in 2007, 2006 and 2005, respectively, for PEC and $30 million, $27 million and $78 million in 2007, 2006 and 2005, respectively, for PEF.

During 2005, PEF performed a depreciation study as required by the FPSC no less than every four years. Implementation of the depreciation study decreased the rates used to calculate cost of removal expense with a resulting decrease of approximately $55 million in 2006.

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)	2007		2006		2007		2006		2007		2006
Removal costs	$	1,410	$	1,341	$	794	$	727	$	616	$	614
Nonirradiated decommissioning costs		141		137		80		76		61		61
Dismantlement costs		125		124		–		–		125		124
Non-ARO cost of removal	$	1,676	$	1,602	$	874	$	803	$	802	$	799

The NCUC requires that PEC update its cost estimate for nuclear decommissioning every five years. PEC’s most recent site-specific estimates of decommissioning costs were developed in 2004, using 2004 cost factors, and are 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

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nuclear fuel on site until such time that it can be transferred to a DOE facility (See Note 22D). These estimates, in 2004 dollars, were $569 million for Unit No. 2 at Robinson Nuclear Plant (Robinson), $418 million for Brunswick Nuclear Plant (Brunswick) Unit No. 1, $444 million for Brunswick Unit No. 2 and $775 million 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 attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in Brunswick and Harris. NRC operating licenses held by PEC currently expire in July 2030, December 2034 and September 2036 for Robinson and Brunswick Units No. 2 and No. 1, respectively. The NRC operating license held by PEC for Harris currently expires in October 2026. An application to extend this license 20 years was submitted in the fourth quarter of 2006. Based on updated assumptions, in 2005 PEC further reduced its asset retirement cost net of accumulated depreciation and its ARO liability by approximately $14 million and $49 million, respectively.

The FPSC requires that PEF update its cost estimate for nuclear decommissioning every five years. PEF filed a new site-specific estimate of decommissioning costs for the Crystal River Unit No. 3 (CR3) with the FPSC on April 29, 2005, as part of PEF’s base rate filing. 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 2005 dollars, is $614 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. The NRC operating license held by PEF for CR3 currently expires in December 2016. We expect to submit an application requesting a 20-year extension of this license in the first quarter of 2009. As part of this new estimate and assumed license extension, PEF reduced its asset retirement cost net of accumulated depreciation and its ARO liability by approximately $36 million and $94 million, respectively. In addition, we reduced PEF-related asset retirement costs, net of accumulated depreciation, by an additional $53 million at Progress Energy. Retail accruals on PEF’s reserves for nuclear decommissioning were previously suspended through December 2005 under the terms of a previous base rate agreement, and the base rate agreement resulting from a base rate proceeding in 2005 continues that suspension. 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 filed an updated fossil dismantlement study with the FPSC on April 29, 2005, as part of its base rate filing. PEF’s reserve for fossil plant dismantlement was approximately $146 million and $145 million at December 31, 2007 and 2006, including amounts in the ARO liability for asbestos abatement, discussed below. Retail accruals on PEF’s reserves for fossil plant dismantlement were previously suspended through December 2005 under the terms of PEF’s previous base rate agreement. The base rate agreement resulting from a base rate proceeding in 2005 continued the suspension of PEF’s collection from customers of the expenses to dismantle fossil plants (See Note 7C).

Upon implementation of FIN 47 as of December 31, 2005, the Utilities recognized additional ARO liabilities for asbestos abatement costs (See Note 1D).

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.

Our nonregulated AROs relate to our abandoned synthetic fuels operations. The related asset retirement costs, net of accumulated depreciation, totaled $1 million at December 31, 2006, and none at December 31, 2007.

The following table presents the changes to the AROs during the years ended December 31, 2007 and 2006. Revisions to prior estimates of the PEC regulated ARO are related to remeasuring the nuclear decommissioning costs of irradiated plants to take into account updated site-specific decommissioning cost studies, which are required by the NCUC every five years. Revisions to prior estimates of the PEF regulated ARO are related to the updated cost estimate for nuclear decommissioning described above.

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	Progress Energy
(in millions)	Regulated			Nonregulated			PEC			PEF
Asset retirement obligations at January 1, 2006	$	1,239		$	–		$	949		$	290
Accretion expense		72			–			57			15
Remediation		(2	)		1			(2	)		–
Revisions to prior estimates		(6	)		–			–			(6	)
Asset retirement obligations at December 31, 2006		1,303			1			1,004			299
Accretion expense		75			–			59			16
Remediation		–			(1	)		–			–
Asset retirement obligations at December 31, 2007	$	1,378		$	–		$	1,063		$	315

E.    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 NEIL, following a 12-week deductible period, for 52 weeks in the amount of $4 million per week at the Brunswick, Harris and Robinson plants, and $5 million per week at the Crystal River plant. An additional 110 weeks of coverage is 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 $34 million with respect to the primary coverage, $37 million with respect to the decontamination, decommissioning and excess property coverage, and $24 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, 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.

Both of the Utilities are insured against public liability for a nuclear incident up to $10.760 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 $100 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 $15 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 31, 2008.

Under the NEIL policies, if there were multiple terrorism losses occurring within one year, NEIL would make available one industry aggregate limit of $3.200 billion for non-certified 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.

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 pursuant to a regulatory order and may defer losses in excess of the reserve (See Note 7C).

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6.    CURRENT ASSETS

A.    RECEIVABLES

Income tax receivables and interest income receivables are not included in receivables. These amounts are included in prepaids and other current assets on the Consolidated Balance Sheets. At December 31 receivables were comprised of:

	Progress Energy						PEC						PEF
(in millions)	2007			2006			2007			2006			2007			2006
Trade accounts receivable	$	616		$	647		$	310		$	288		$	276		$	304
Unbilled accounts receivable		220			227			156			157			59			55
Notes receivable		67			57			–			–			–			–
Derivatives accounts receivable		247			–			–			–			13			–
Other receivables		46			46			31			36			13			5
Allowance for doubtful receivables		(29	)		(28	)		(6	)		(5	)		(10	)		(8	)
Total receivables	$	1,167		$	949		$	491		$	476		$	351		$	356

 B.   INVENTORY

At December 31 inventory was comprised of:

	Progress Energy				PEC				PEF
(in millions)	2007		2006		2007		2006		2007		2006
Fuel for production	$	455	$	470	$	210	$	230	$	245	$	240
Inventory for sale		–		2		–		–		–		–
Materials and supplies		520		442		284		247		236		194
Emission allowances		19		22		16		20		3		2
Total inventory	$	994	$	936	$	510	$	497	$	484	$	436

Materials and supplies amounts above exclude long-term combustion turbine inventory amounts included in other assets and deferred debits for Progress Energy of $65 million and $44 million at December 31, 2007 and 2006, respectively, and PEC of $44 million at December 31, 2007 and 2006.

Emission allowances above exclude long-term emission allowances included in other assets and deferred debits for Progress Energy, PEC and PEF of $32 million, $3 million and $29 million, respectively, at December 31, 2007. Progress Energy, PEC and PEF did not have any long-term emission allowance amounts at December 31, 2006.

7.    REGULATORY MATTERS

A.    REGULATORY ASSETS AND LIABILITIES

As regulated entities, the Utilities are subject to the provisions of SFAS No. 71. 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 SFAS No. 71 could be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 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 could result in an impairment of utility plant assets as determined pursuant to SFAS No. 144.

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At December 31 the balances of regulatory assets (liabilities) were as follows:

Progress Energy
(in millions)	2007			2006
Deferred fuel cost – current (Note 7B)	$	154		$	196
Deferred fuel cost – long-term (Note 7B)		114			114
Deferred impact of ARO – PEC (Note 1D)		294			282
Income taxes recoverable through future rates (Note 14)		141			114
Loss on reacquired debt (Note 1D)		43			46
Storm deferral (Notes 7B and 7C)		22			102
Postretirement benefits (Note 16)		212			373
Derivative mark-to-market adjustment (Note 17A)		14			98
Environmental (Notes 7B, 7C and 21A)		40			72
Investment in GridSouth (Note 7D)		22			–
Other		44			50
Total long-term regulatory assets		946			1,251
Deferred fuel cost – current (Note 7C)		(154	)		(63	)
Deferred energy conservation cost and other current regulatory liabilities		(19	)		(13	)
Total current regulatory liabilities		(173	)		(76	)
Non-ARO cost of removal (Note 5D)		(1,676	)		(1,602	)
Deferred impact of ARO – PEF (Note 1D)		(226	)		(221	)
Net nuclear decommissioning trust unrealized gains (Note 5D)		(351	)		(330	)
Clean Smokestacks Act compliance (Note 7B)		–			(333	)
Derivative mark-to-market adjustment (Note 17A)		(200	)		(20)
Storm reserve (Note 7C)		(63	)		(2	)
Other		(38	)		(55	)
Total long-term regulatory liabilities		(2,554	)		(2,563	)
Net regulatory liabilities	$	(1,627	)	$	(1,192	)

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PEC
(in millions)	2007			2006
Deferred fuel cost – current (Note 7B)	$	148		$	196
Deferred fuel cost – long-term (Note 7B)		114			114
Deferred impact of ARO (Note 1D)		294			282
Income taxes recoverable through future rates (Note 14)		51			50
Loss on reacquired debt (Note 1D)		18			19
Storm deferral (Note 7B)		6			12
Postretirement benefits (Note 16)		126			243
Environmental (Note 7B)		10			15
Investment in GridSouth (Note 7D)		22			–
Other		39			43
Total long-term regulatory assets		680			778
Non-ARO cost of removal (Note 5D)		(874	)		(803	)
Net nuclear decommissioning trust unrealized gains (Note 5D)		(188	)		(171	)
Derivative mark-to-market adjustment (Note 17A)		(20	)		(1)
Clean Smokestacks Act compliance (Note 7B)		–			(333	)
Other		(16	)		(13	)
Total long-term regulatory liabilities		(1,098	)		(1,321	)
Net regulatory liabilities	$	(270	)		(347	)

PEF
(in millions)	2007			2006
Deferred fuel cost – current (Note 7C)	$	6		$	–
Storm deferral (Note 7C)		16			90
Income taxes recoverable through future rates (Note 14)		90			64
Loss on reacquired debt (Note 1D)		25			27
Postretirement benefits (Note 16)		86			130
Derivative mark-to-market adjustment (Note 17A)		14			98
Environmental (Notes 7C and 21A)		30			57
Other		5			7
Total long-term regulatory assets		266			473
Deferred fuel cost – current (Note 7C)		(154	)		(63	)
Deferred energy conservation cost and other current regulatory liabilities		(19	)		(13	)
Total current regulatory liabilities		(173	)		(76	)
Non-ARO cost of removal (Note 5D)		(802	)		(799	)
Deferred impact of ARO (Note 1D)		(96	)		(88	)
Net nuclear decommissioning trust unrealized gains (Note 5D)		(163	)		(159	)
Derivative mark-to-market adjustment (Note 17A)		(180	)		(19	)
Storm reserve (Note 7C)		(63	)		(2	)
Other		(26	)		(43	)
Total long-term regulatory liabilities		(1,330	)		(1,110	)
Net regulatory liabilities	$	(1,231	)	$	(713	)

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 anticipate recovering long-term deferred fuel costs in 2009 and loss on reacquired debt over the applicable lives of the debt. We expect to fully recover our regulatory assets and refund our regulatory liabilities through customer rates under current regulatory practice.

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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 return on equity (ROE) of 12.75 percent. In June 2002, the North Carolina Clean Smokestacks Act (Clean Smokestacks Act) was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) from their North Carolina coal-fired power plants in phases by 2013. The Clean Smokestacks Act froze North Carolina electric utility base rates for a five-year period, which ended December 31, 2007, unless there were extraordinary events beyond the control of the utilities or unless the utilities persistently earned a return substantially in excess of the rate of return established and found reasonable by the NCUC in the respective utility’s last general rate case. There were no adjustments to PEC’s base rates during the five-year period ended December 31, 2007. Subsequent to 2007, PEC’s current North Carolina base rates are continuing subject to traditional cost-based rate regulation.

During the rate freeze period, the legislation provided for a minimum amortization and recovery of 70 percent of the original estimated compliance costs of $813 million (or $569 million) while providing significant flexibility in the amount of annual amortization recorded from none up to $174 million per year. For the years ended December 31, 2007, 2006 and 2005, PEC recognized amortization of $34 million, $140 million and $147 million, respectively, and recognized $569 million in cumulative amortization through December 31, 2007.

On March 23, 2007, PEC filed a petition with the NCUC requesting that it be allowed to amortize the remaining 30 percent (or $244 million) of the original estimated compliance costs for the Clean Smokestacks Act during 2008 and 2009, with discretion to amortize up to $174 million in either year. Additionally, among other things, PEC requested that the NCUC allow PEC to include in its rate base those eligible compliance costs exceeding the original estimated compliance costs and that PEC be allowed to accrue AFUDC on all eligible compliance costs in excess of the original estimated compliance costs. PEC also requested that any prudency review of PEC’s environmental compliance costs be deferred until PEC’s next ratemaking proceeding in which PEC seeks to adjust its base rates. On October 22, 2007, PEC filed with the NCUC a settlement agreement with the NCUC Public Staff, the Carolina Utility Customers Associations (CUCA) and the Carolina Industrial Group for Fair Utility Rates II (CIGFUR) supporting PEC’s proposal. The NCUC held a hearing on this matter on October 30, 2007. On December 20, 2007, the NCUC approved the settlement agreement on a provisional basis, with the NCUC indicating that it intended to initiate a review in 2009 to consider all reasonable alternatives and proposals related to PEC’s recovery of its Clean Smokestacks Act compliance costs in excess of the original estimated costs of $813 million. Additionally, the NCUC ordered that no portion of Clean Smokestacks Act compliance costs directly assigned, allocated or otherwise attributable to another jurisdiction shall be recovered from PEC’s retail North Carolina customers, even if recovery of these costs is disallowed or denied, in whole or in part, in another jurisdiction. We cannot predict the outcome of PEC’s recovery of eligible compliance costs exceeding the original estimated compliance costs.

See Note 21B for additional information about the Clean Smokestacks Act.

FUEL COST RECOVERY

On May 2, 2007, PEC filed with the SCPSC for an increase in the fuel rate charged to its South Carolina ratepayers. PEC asked the SCPSC to approve a $12 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements and to meet future expected fuel costs. On June 27, 2007, the SCPSC approved a settlement agreement filed jointly by PEC and all other parties to the proceedings. The settlement agreement resolved all issues and provided for a $12 million increase in fuel rates. Effective July 1, 2007, residential electric bills increased by $1.83 per 1,000 kilowatt-hours (kWh), or 1.9 percent, for fuel cost recovery. At December 31, 2007, PEC’s South Carolina deferred fuel balance was $21 million.

On June 8, 2007, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. PEC asked the NCUC to approve a $48 million increase in fuel rates. On September 25, 2007, the NCUC approved PEC’s petition. The increase took effect October 1, 2007, and increased residential electric bills by $1.30 per 1,000 kWh, or 1.3 percent, for fuel cost recovery. This was the second increase associated with a three-year settlement approved by the NCUC in 2006. The settlement provided for an increase of $177 million effective October 1, 2006;

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$48 million effective October 1, 2007, as discussed above; and an additional increase of approximately $30 million in October 2008. On November 21, 2006, CUCA filed an appeal with the North Carolina Tenth District Court of Appeals of the NCUC’s order approving the settlement on the grounds that the NCUC did not have the statutory authority to establish fuel rates for more than one year. On October 24, 2007, CUCA filed a motion to withdraw their appeal. On November 7, 2007, the North Carolina Tenth District Court of Appeals granted CUCA’s motion. At December 31, 2007, PEC’s North Carolina deferred fuel balance was $241 million, of which $114 million is expected to be collected after 2008 and has been classified as a long-term regulatory asset.

STORM COST RECOVERY

In February 2004, PEC filed with the SCPSC seeking permission to defer expenses incurred from the first quarter 2004 winter storm. In September 2004, the SCPSC approved PEC’s request to defer the costs and amortize them ratably over five years beginning in January 2005. Approximately $9 million related to storm costs was deferred in 2004. For the years ended December 31, 2007, 2006 and 2005, PEC recognized $2 million of South Carolina storm amortization.

In October 2003, PEC filed with the NCUC seeking permission to defer approximately $24 million of expenses incurred from Hurricane Isabel and the February 2003 winter storms. In December 2003, the NCUC approved PEC’s request to defer the costs associated with Hurricane Isabel and the February 2003 winter storms and amortize them over a period of five years. For the years ended December 31, 2007, 2006 and 2005, PEC recognized $5 million of North Carolina storm amortization.

OTHER MATTERS

PEC filed petitions on September 14, 2006, and September 22, 2006, with the SCPSC and NCUC, respectively, seeking authorization to defer and amortize the respective jurisdictional portion of $18 million of previously recorded operation and maintenance (O&M) expense relating to certain environmental remediation sites (See Note 21A). On October 11, 2006, the SCPSC granted PEC’s petition to defer its jurisdictional amount, totaling $3 million, and amortize it over a five-year period beginning January 1, 2007. On October 19, 2006, the NCUC granted PEC’s petition to defer its jurisdictional amount, totaling $15 million, and amortize it over a five-year period. However, the NCUC order directed that amortization begin in 2006, with an amortization expense of $3 million. As a result, during the fourth quarter of 2006, PEC reversed $18 million of O&M expense, established a regulatory asset and recorded $3 million of amortization expense. During the year ended December 31, 2007, PEC recorded $3 million of amortization expense. Additionally, PEC reduced the regulatory asset by $2 million during the year ended December 31, 2007, based on newly available data regarding certain remediation sites and insurance proceeds (See Note 21A).

The NCUC and SCPSC approved proposals to accelerate cost recovery of PEC’s nuclear generating assets beginning January 1, 2000, and continuing through 2009. The aggregate minimum and maximum amounts of cost recovery are $530 million and $750 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 $37 million in 2007. No additional depreciation expense from accelerated cost recovery was recorded in 2006 or 2005. Through December 31, 2007, PEC recorded total accelerated depreciation of $440 million, of which $363 million was recorded for the North Carolina jurisdiction and $77 million was recorded for the South Carolina jurisdiction.

During 2007, the North Carolina legislature passed comprehensive energy legislation, which became law on August 20, 2007. Among other provisions, the law allows the utility to recover the costs of new demand-side management (DSM) and energy-efficiency programs through an annual DSM clause. The law allows PEC to capitalize those costs that are intended to produce future benefits and authorizes the NCUC to approve other forms of financial incentives to the utility for DSM and energy-efficiency programs. DSM programs include 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 and interruptible load. PEC has begun implementing a series of DSM and energy-efficiency programs and deferred $2 million of implementation and program costs through December 31, 2007, for future recovery.

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PEC filed a petition on November 30, 2007, with the SCPSC seeking authorization to create a deferred account for DSM and energy-efficiency expenses. On December 21, 2007, the SCPSC issued an order granting PEC’s petition. As a result, PEC has deferred an immaterial amount of implementation and program costs through December 31, 2007, for future recovery in the South Carolina jurisdiction. PEC anticipates applying for a DSM and energy- efficiency clause to recover the costs of these programs in 2008. We cannot predict the outcome of this matter.

C.    PEF RETAIL RATE MATTERS

BASE RATE AGREEMENT

As a result of a base rate proceeding in 2005, PEF is party to a base rate settlement agreement that was effective with the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009, with PEF having sole option to extend the agreement through the last billing cycle of June 2010 pursuant to the agreement. In accordance with the base rate agreement and as modified by a stipulation and settlement agreement approved by the FPSC on October 23, 2007, base rates were adjusted in January 2008 due to specified generation facilities placed in service in 2007. The settlement agreement also provides for revenue sharing between PEF and its ratepayers beginning in 2006 whereby PEF will refund two-thirds of retail base revenues between the specified threshold and specified cap and 100 percent of revenues above the specified cap. However, PEF’s retail base revenues did not exceed the specified 2007 threshold of $1.537 billion and thus no revenues were subject to revenue sharing. Both the 2007 base threshold of $1.537 billion and the 2007 cap of $1.588 billion will be adjusted annually for rolling average 10-year retail kWh sales growth. PEF’s 2006 retail base rates did not exceed the threshold and no revenues were subject to the revenue sharing provisions. The settlement agreement provides for PEF to continue to recover certain costs through clauses, such as the recovery of post-9/11 security costs through the capacity clause and the carrying costs of coal inventory in transit and coal procurement costs through the fuel clause. Under the settlement agreement, PEF is authorized to include an adjustment to increase common equity for the impact of Standard & Poor’s Rating Services’ (S&P’s) imputed off-balance sheet debt for future capacity payments to qualifying facilities (QFs) and other entities under long-term purchase power agreements. This adjusted capital structure will be used for surveillance reporting with the FPSC and pass-through clause return calculations. PEF will use an authorized 11.75 percent ROE for cost-recovery clauses and AFUDC. In addition, PEF’s adjusted equity ratio will be capped at 57.83 percent as calculated on a financial capital structure that includes the adjustment for the S&P imputed off-balance sheet debt. If PEF’s regulatory ROE falls below 10 percent, and for certain other events, PEF is authorized to petition the FPSC for a base rate increase.

PASS-THROUGH CLAUSE COST RECOVERY

On September 4, 2007, PEF filed a request with the FPSC seeking approval of a cost adjustment to reflect a projected over-collection of fuel costs in 2007, declining projected fuel costs for 2008 and other recovery clause factors. PEF asked the FPSC to approve a $163 million, or 4.53 percent, decrease in rates effective January 1, 2008. This cost adjustment would decrease residential bills by $5.00 for the first 1,000 kWh. As discussed above, residential base rates increased due to specified generation facilities placed in service in 2007 by $2.73 for the first 1,000 kWh effective January 1, 2008. After considering the net effect of the base rate increase and the proposed fuel cost adjustment, 2008 residential bills would decrease by a net amount of $2.27 for the first 1,000 kWh. The FPSC approved the cost-recovery rates for 2008 in an order dated January 8, 2008. At December 31, 2007, PEF’s current regulatory liabilities totaled $173 million, which were comprised of over-recovered fuel and capacity costs of $140 million, accrued disallowed fuel costs of $14 million, over-recovered conservation costs of $14 million and over-recovered environmental compliance of $5 million.

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus interest, of alleged excessive past fuel recovery charges and SO2 allowance costs during the period 1996 to 2005. The OPC subsequently revised its claim to $135 million, plus interest. The OPC claimed that although Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) were designed to burn a blend of coals, PEF failed to act to lower ratepayers’ costs by purchasing the most economical blends of coal. During the period specified in the petition, PEF’s costs recovered through fuel recovery clauses were annually reviewed for prudence and approval by the FPSC. On July 31, 2007, the FPSC heard this matter. On October 10, 2007, the FPSC issued its order rejecting most of the OPC’s contentions. However, the 4-1 majority

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found that PEF had not been prudent in purchasing a portion of its coal requirements during the period from 2003 to 2005. Accordingly, the FPSC ordered PEF to refund its ratepayers approximately $14 million, inclusive of interest, over a 12-month period beginning January 1, 2008. For the year ended December 31, 2007, PEF recorded a pre-tax other operating expense of $12 million, interest expense of $2 million and an associated $14 million regulatory liability included within PEF’s deferred fuel cost at December 31, 2007. On October 25, 2007, the OPC requested the FPSC to reconsider its October 10, 2007 order asserting that the FPSC erred in not ordering a larger refund. PEF filed its opposition to the OPC’s request on November 1, 2007. On February 12, 2008, the FPSC denied the OPC’s request for reconsideration. PEF is also evaluating its options, including an appeal to the Florida Supreme Court of the FPSC’s October 10, 2007 order. We cannot predict the outcome of this matter. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish a separate docket on the prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. The OPC filed testimony in support of its position to require PEF to refund at least $14 million for alleged excessive fuel recovery charges for 2006 coal purchases. PEF believes its coal procurement practices have been prudent. We cannot predict the outcome of this matter.

On September 22, 2006, PEF filed a petition with the FPSC for Determination of Need to uprate CR3, bid rule exemption and recovery of the revenue requirements of the uprate through PEF’s fuel recovery clause. To the extent the expenditures are prudently incurred, PEF’s investment in the CR3 uprate is eligible for recovery through base rates. PEF’s petition would allow for more prompt recovery. The multi-stage uprate will increase CR3’s gross output by approximately 180 MW by 2012. PEF received NRC approval for a license amendment and implemented the first stage’s design modification on January 31, 2008, and will apply for the required license amendment for the third stage’s design modification. The petition filed with the FPSC included estimated project costs of approximately $382 million. These cost estimates may continue to change depending upon the results of more detailed engineering and development work and increased material, labor and equipment costs. On February 8, 2007, the FPSC issued an order approving the need certification petition and bid rule exemption. The request for recovery through PEF’s fuel recovery clause was transferred to a separate docket filed on January 16, 2007. On February 2, 2007, intervenors filed a motion to abate the cost-recovery portion of PEF’s request. On February 9, 2007, PEF requested that the FPSC deny the intervenors’ motion as legally deficient and without merit. On March 27, 2007, the FPSC denied the motion to abate and directed the staff of the FPSC to conduct a hearing to determine whether the revenue requirements of the uprate should be recovered through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony clarifying the scope of the project. The FPSC held a hearing on this matter on August 7 and 8, 2007. The staff of the FPSC recommended that PEF be allowed to recover prudent and reasonable costs of Phase 1, estimated at $6 million, through the fuel clause. The staff of the FPSC recommended that the costs of all other phases, estimated at $376 million, be considered in a base rate proceeding. On October 19, 2007, PEF filed a notice of withdrawal of its cost-recovery petition with the FPSC. On November 21, 2007, PEF filed a petition with the FPSC seeking cost recovery under Florida’s comprehensive energy bill enacted in 2006, and the FPSC's new nuclear cost- recovery rule. On February 13, 2008, PEF filed a notice of withdrawal of its cost-recovery petition with the FPSC. PEF will proceed with cost recovery under Florida’s comprehensive energy bill and the FPSC's nuclear cost-recovery rule based on the regulatory precedence established by a FPSC order to an unaffiliated Florida utility for a nuclear uprate project. We cannot predict the outcome of this matter.

STORM COST RECOVERY

On July 14, 2005, the FPSC issued an order authorizing PEF to recover $232 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power associated with the four hurricanes in 2004. The ruling allowed PEF to include a charge of approximately $3.27 on the average residential monthly customer bill of 1,000 kWh beginning August 1, 2005. The ruling by the FPSC approved the majority of PEF’s requests with two exceptions: the reclassification of $8 million of previously deferred costs to utility plant and the reclassification of $17 million of previously deferred costs as O&M expense, which was expensed in the second quarter of 2005. The amount included in the original November 2004 petition requesting recovery of $252 million was an estimate. On September 12, 2005, PEF filed a true-up to the original amount comprised primarily of an additional $19 million of costs partially offset by $6 million of adjustments resulting from allocating a higher portion of the costs to the wholesale jurisdiction and refining the FPSC adjustments. On November 9, 2005, the recovery of this difference was administratively approved by the FPSC, subject to audit by

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the FPSC staff. The net impact was included in customer bills beginning January 1, 2006. In 2007, 2006 and 2005, PEF recorded amortization of $75 million, $122 million and $50 million, respectively, associated with the recovery of these storm costs. The retail portion of storm restoration costs were fully recovered at December 31, 2007.

On April 25, 2006, PEF entered into a settlement agreement with certain intervenors in its storm cost-recovery docket that would allow PEF to extend its then-current two-year storm surcharge, which equals approximately $3.61 on the average residential monthly customer bill of 1,000 kWh, for an additional 12-month period to replenish its storm reserve. The requested extension, which began August 2007, is expected to replenish the existing storm reserve by an estimated $126 million. During the third quarter of 2006, PEF and the intervenors modified the settlement agreement such that in the event future storms deplete the reserve, PEF would be able to petition the FPSC for implementation of an interim surcharge of at least 80 percent and up to 100 percent of the claimed deficiency of its storm reserve. The intervenors agreed not to oppose the interim recovery of 80 percent of the future claimed deficiency but reserved the right to challenge the interim surcharge recovery of the remaining 20 percent. The FPSC has the right to review PEF’s storm costs for prudence. On August 29, 2006, the FPSC approved the settlement agreement as modified. Through December 31, 2007, PEF had recorded an additional $55 million of storm reserve from the extension of the storm surcharge. At December 31, 2007, PEF’s storm reserve totaled $63 million.

FRANCHISE MATTERS

On June 1, 2005, Winter Park acquired PEF’s electric distribution system that serves Winter Park for approximately $42 million. On June 1, 2005, PEF transferred the distribution system to Winter Park and recognized a pre-tax gain of approximately $25 million on the transaction, which is included as an offset to other utility expense on the Statements of Income. This amount was decreased $1 million in the third quarter of 2005 upon accumulation of the final capital expenditures incurred since arbitration. PEF also recorded a regulatory liability of $8 million for stranded cost revenues, which will be amortized to revenues over six years in accordance with the provisions of the transfer agreement with Winter Park. In June 2004, Winter Park executed a wholesale power supply contract with PEF with a five-year term and a renewal option.

OTHER MATTERS

On October 29, 2007, PEF submitted a revised Open Access Transmission Tariff (OATT) filing, including a settlement agreement, with the FERC requesting an increase in transmission rates. The purpose of the filing was to implement formula rates for the PEF OATT in order to more accurately reflect the costs that PEF incurs in providing transmission service. In the filing, PEF proposed to move from a fixed rate to a formula rate, which allows for transmission rates to be updated each year based on the prior year’s actual costs. Settlement discussions were held with major customers prior to the filing and a settlement agreement was reached on all issues. The settlement proposed a formula rate with a rate of return on equity of 10.8 percent. PEF received FERC approval of the settlement agreement on December 17, 2007. The new rates were effective January 1, 2008, and PEF estimates the impact of the new rates will increase 2008 revenues by $1 million to $2 million.

D.    REGIONAL TRANSMISSION ORGANIZATIONS

In 2000, the FERC issued Order 2000, which set minimum characteristics and functions that regional transmission organizations (RTOs) must meet, including independent transmission service. In October 2000, as a result of Order 2000, PEC, along with Duke Energy Corporation and South Carolina Electric & Gas Company, filed an application with the FERC for approval of an RTO, GridSouth Transco, LLC (GridSouth). In July 2001, the FERC issued an order provisionally approving GridSouth. However, in July 2001, the FERC issued orders recommending that companies in the southeastern United States engage in mediation to develop a plan for a single RTO. PEC participated in the mediation; no consensus was reached on creating a southeast RTO. On August 11, 2005, the GridSouth participants notified the FERC that they had terminated the GridSouth project. By order issued October 20, 2005, the FERC terminated the GridSouth proceeding.

On November 16, 2007, PEC petitioned the NCUC to allow it to establish a regulatory asset for PEC’s development costs of GridSouth pending disposition in a general rate proceeding. On January 14, 2008, the NCUC issued an order requesting interested parties to file comments regarding PEC’s petition on or before January 28, 2008. On

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February 11, 2008, PEC filed response comments. On December 20, 2007, the NCUC issued an order for one of the other GridSouth partners. As part of that order, the NCUC ruled that the utility’s GridSouth development costs should be amortized and recovered over a 10-year period beginning June 2002. Until the NCUC rules upon PEC’s petition, PEC will apply the same accounting treatment to its GridSouth development costs. Consequently, in December 2007, PEC recorded an $11 million charge to amortization expense to reduce the North Carolina portion of development costs, which is included in depreciation and amortization on the Consolidated Statements of Income. PEC’s recorded investment in GridSouth totaled $22 million and $33 million at December 31, 2007 and 2006. PEC expects to recover its GridSouth development costs based on precedent regulatory proceedings; in 2007, PEC reclassified its investment in GridSouth from other assets and deferred debits to regulatory assets on the Consolidated Balance Sheets. We cannot predict the outcome of this matter.

PEF was one of three major investor-owned Florida utilities that formed the GridFlorida RTO in 2000. A cost-benefit study conducted during 2005 concluded that the GridFlorida RTO was not cost effective for FPSC jurisdictional customers and shifted benefits to nonjurisdictional customers. In light of these findings, during 2006 the FPSC and the FERC closed their respective docketed proceedings and GridFlorida was dissolved. PEF fully recovered its development costs in GridFlorida from retail ratepayers through base rates.

E.    NUCLEAR LICENSE RENEWALS

The NRC operating license for Robinson expires in 2030 and the licenses for Brunswick expire in 2036 for Unit No. 1 and 2034 for Unit No. 2. On November 14, 2006, PEC filed an application for a 20-year extension from the NRC on the operating license for Harris, which would extend the operating license through 2046, if approved. PEC anticipates a decision from the NRC in 2008. The NRC operating license held by PEF for CR3 currently expires in December 2016. PEF expects to submit an application requesting a 20-year extension of this license in the first quarter of 2009.

8.    GOODWILL AND INTANGIBLE ASSETS

We perform annual goodwill impairment tests in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Goodwill was tested for impairment for both the PEC and PEF segments in the second quarters of 2007, 2006 and 2005; each test indicated no impairment.

Under SFAS No. 142, all goodwill is assigned to our reporting units that are expected to benefit from the synergies of the business combination. At December 31, 2007 and 2006, 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. There were no changes to the assignment of the carrying amounts to PEC and PEF in 2007 or 2006.

Goodwill impairment tests were performed at our CCO-Georgia Operations reporting unit level, which was comprised of four nonregulated generating plants (Georgia Operations). As a result of our evaluation of certain business opportunities that impacted the future cash flows of our Georgia Operations, we performed the annual goodwill impairment test during the first quarter of 2006. We estimated the fair value of that reporting unit using the expected present value of future cash flows. As a result of that test, we recognized a pre-tax goodwill impairment charge of $64 million ($39 million after-tax) during the first quarter of 2006, which has been reclassified to discontinued operations, net of tax on the Consolidated Statements of Income (See Note 3A).

We apply SFAS No. 144 for the accounting and reporting of impairment or disposal of long-lived assets. On May 22, 2006, we idled our synthetic fuels facilities due to significant uncertainty surrounding future synthetic fuels production. With the idling of these facilities, we performed an evaluation of the intangible assets, which were comprised primarily of capitalized acquisition costs (See Note 9 for impairment of related long-lived assets). The impairment test considered numerous factors including, among other things, continued high oil prices and the then-current idled state of our synthetic fuels facilities. We estimated the fair value using the expected present value of future cash flows. Based on the results of the impairment test, we recorded a pre-tax impairment charge of $27 million ($17 million after-tax) during the quarter ended June 30, 2006, which has been reclassified to discontinued operations, net of tax on the Consolidated Statements of Income. This charge represented the entirety of the

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synthetic fuels intangible assets; these assets had been reported within our former Coal and Synthetic Fuels segment (See Note 3B).

9.    IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS

We apply SFAS No. 144 for the accounting and reporting of impairment or disposal of long-lived assets. In 2006, we recorded pre-tax long-lived asset and investment impairments and other charges of $65 million, of which $64 million has been reclassified to discontinued operations, net of tax on the Consolidated Statements of Income. PEC recorded pre-tax long-lived asset and investment impairments and other charges of $1 million in both 2006 and 2005.

A.    LONG-LIVED ASSETS

Due to rising current and future oil prices, in the third and fourth quarters of 2005 we tested our synthetic fuels plant assets for impairment. These tests indicated that the assets were recoverable and no impairment charge was recorded. See Note 22D for additional information.

Concurrent with the synthetic fuels intangibles impairment evaluation discussed in Note 8, we also performed an impairment evaluation of related long-lived assets during the second quarter of 2006. Based on the results of the impairment test, we recorded a pre-tax impairment charge of $64 million ($38 million after-tax) during the quarter ended June 30, 2006, which has been reclassified to discontinued operations, net of tax on the Consolidated Statements of Income, as discussed in Note 3B. This charge represents the entirety of the asset carrying value of our synthetic fuels manufacturing facilities, as well as a portion of the asset carrying value associated with the river terminals at which the synthetic fuels manufacturing facilities are located. These assets had been reported within our former Coal and Synthetic Fuels segment. There were no impairments of long-lived assets in 2007.

B.   INVESTMENTS

We evaluate declines in value of investments under the criteria of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115), and FASB Staff Position FAS 115-1/124-1, “The Meaning of Other-Than-Temporary Impairments and Its Application to Certain Investments” (See Note 1D). 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 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 and other available-for-sale securities. See Note 13 for additional information.

We continually review PEC’s affordable housing investment (AHI) portfolio for impairment. There were no other-than-temporary impairments in 2007. As a result of various factors, including continued operating losses of the AHI portfolio and management issues arising at certain properties within the AHI portfolio, we recorded impairment charges of $1 million on a pre-tax basis in both 2006 and 2005.

10.   EQUITY

A.    COMMON STOCK

PROGRESS ENERGY

At December 31, 2007 and 2006, we had 500 million shares of common stock authorized under our charter, of which 260 million shares and 256 million shares, respectively, were outstanding. During 2007, 2006 and 2005, respectively, we issued approximately 3.4 million, 4.2 million and 4.8 million shares of common stock, resulting in approximately $151 million, $185 million and $208 million in proceeds. Included in these amounts for 2007, 2006 and 2005, respectively, were approximately 1.0 million, 1.6 million and 4.6 million shares for proceeds of approximately $46 million, $70 million and $199 million, to meet the requirements of the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan.

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At December 31, 2007 and 2006, we had approximately 50 million shares and 54 million shares, respectively, of common stock authorized by the board of directors that remained unissued and reserved, primarily to satisfy the requirements of our stock plans. In 2002, the board of directors authorized meeting the requirements of the 401(k) and the Investor Plus Stock Purchase Plan with original issue shares. We continue to meet the requirements of the restricted stock plan with issued and outstanding shares.

There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2007, there were no significant restrictions on the use of retained earnings (See Note 12).

PEC

At December 31, 2007 and 2006, 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, 2007, there were no significant restrictions on the use of retained earnings. See Note 12 for additional dividend restrictions related to PEC.

PEF

At December 31, 2007 and 2006, 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, 2007, there were no significant restrictions on the use of retained earnings. See Note 12 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. At December 31, 2007 and 2006, participating subsidiaries were PEC, PEF, PVI, Progress Fuels (corporate employees) and PESC. The 401(k), which has matching and incentive goal features, 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 is held by the 401(k) Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is 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.

There were 1.7 million and 2.3 million ESOP suspense shares at December 31, 2007 and 2006, respectively, with a fair value of $82 million and $112 million, respectively. ESOP shares allocated to plan participants totaled 10.6 million and 10.9 million at December 31, 2007 and 2006, respectively. Our matching and incentive goal compensation cost under the 401(k) is determined based on matching percentages and incentive goal attainment as defined in the plan. Such compensation cost is 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. We currently meet common stock share needs with open market purchases, with shares released from the ESOP suspense account and with newly issued shares. Costs for incentive goal compensation are accrued during the fiscal year and typically paid in shares in the following year, while costs for the matching component are typically met with shares in the same year incurred. Matching and incentive costs, which

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were met and will be met with shares released from the suspense account, totaled approximately $23 million, $14 million and $18 million for the years ended December 31, 2007, 2006 and 2005, respectively. Total matching and incentive costs were approximately $30 million, $23 million and $30 million for the years ended December 31, 2007, 2006 and 2005, respectively. We have 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 is included in the determination of unearned ESOP common stock, which reduces common stock equity. ESOP shares that have not been committed to be released to participants’ accounts are not considered outstanding for the determination of earnings per common share. Interest income on the note receivable and dividends on unallocated ESOP shares are not recognized for financial statement purposes.

Effective January 1, 2008, the 401(k) Plan was revised. As revised, the employer match percentage was increased and the employee stock incentive plan based on goal attainment was discontinued.

PEC

PEC’s matching and incentive costs, which were met and will be met with shares released from the suspense account, totaled approximately $14 million, $8 million and $11 million for the years ended December 31, 2007, 2006 and 2005, respectively. Total matching and incentive costs were approximately $18 million, $13 million and $17 million for the years ended December 31, 2007, 2006 and 2005, respectively.

PEF

PEF’s matching and incentive costs, which were met and will be met with shares released from the suspense account, totaled approximately $4 million, $2 million and $4 million for the years ended December 31, 2007, 2006 and 2005, respectively. Total matching and incentive costs were approximately $6 million, $4 million and $6 million for the years ended December 31, 2007, 2006 and 2005, respectively.

STOCK OPTIONS

Pursuant to our 1997 Equity Incentive Plan (EIP) and 2002 EIP, amended and restated as of July 10, 2002, we may grant options to purchase shares of Progress Energy common stock to directors, officers and eligible employees for up to 5 million and 15 million shares, respectively. Generally, options granted to employees vest one-third per year with 100 percent vesting at the end of year three, while options granted to directors vest 100 percent at the end of one year. The options expire 10 years from the date of grant. All option grants have an exercise price equal to the fair market value of our common stock on the grant date. We curtailed our stock option program in 2004 and replaced that compensation program with other programs. No stock options have been granted since 2004. We issue new shares of common stock to satisfy the exercise of previously issued stock options.

PROGRESS ENERGY

A summary of the status of our stock options at December 31, 2007, and changes during the year then ended, is presented below:

(option quantities in millions)	Number of Options	Weighted-Average Exercise Price
Options outstanding, January 1	4.0	$43.70
Canceled	–	45.55
Exercised	(2.3)	43.47
Options outstanding, December 31	1.7	43.99
Options exercisable, December 31	1.7	43.99

The options outstanding and exercisable at December 31, 2007, had a weighted-average remaining contractual life of 5.0 years and an aggregate intrinsic value of $8 million. Total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005, respectively, was $17 million, $10 million and less than $1 million.

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Compensation cost, for pro forma purposes prior to the adoption of SFAS No. 123R and for expense purposes subsequent to the adoption, is measured at the grant date based on the fair value of the award and is recognized over the vesting period. The fair value for these options was estimated at the grant date using a Black-Scholes option pricing model. Dividend yield and the volatility factor were calculated using three years of historical trend information. The expected term was based on the contractual life of the options.

As of December 31, 2006, all options were fully vested; therefore, no compensation expense was recognized in 2007. Stock option expense totaling $2 million was recognized in income during the year ended December 31, 2006, with a recognized tax benefit of $1 million. No compensation cost related to stock options was capitalized during the year. Stock option expense totaling $3 million was recognized in income during the year ended December 31, 2005, with a recognized tax benefit of $1 million. No compensation cost related to stock options was capitalized during the year.

As previously indicated, we did not record stock option expense prior to the adoption of SFAS No. 123R as of July 1, 2005. The following table illustrates the effect on our net income and earnings per share if the fair value method had been applied to all outstanding and nonvested awards in each period:

(in millions, except per share data)	2005
Net income, as reported	$	697
Deduct: Total stock option expense determined under fair value method for
all awards, net of related tax effects		2
Pro forma net income	$	695
Earnings per share
Basic – as reported	$	2.82
Basic – pro forma		2.81
Diluted – as reported		2.82
Diluted – pro forma		2.81

Cash received from the exercise of stock options totaled $105 million, $115 million and $8 million, respectively, during the years ended December 31, 2007, 2006 and 2005. The actual tax benefit for tax deductions from stock option exercises for the years ended December 31, 2007 and 2006, was $6 million and $4 million, respectively. The actual tax benefit for tax deductions from stock option exercises for the year ended December 31, 2005, was not significant.

PEC

Stock option expense totaling $1 million was recognized in income during the year ended December 31, 2006, with a recognized tax benefit of less than $1 million. No compensation cost related to stock options was capitalized during the year. As of December 31, 2006, all options were fully vested; therefore no compensation expense was recognized in 2007.

Stock option expense totaling $1 million was recognized in income during the year ended December 31, 2005, with a recognized tax benefit of less than $1 million. No compensation cost related to stock options was capitalized during the year.

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As previously indicated, we did not record stock option expense prior to the adoption of SFAS No. 123R as of July 1, 2005. The following table illustrates the effect on our net income if the fair value method had been applied to all outstanding and nonvested awards in each period:

(in millions)	2005
Net income, as reported	$	493
Deduct: Total stock option expense determined under fair value method for
all awards, net of related tax effects		2
Pro forma net income	$	491

PEF

Stock option expense totaling less than $1 million was recognized in income during the year ended December 31, 2006, with a recognized tax benefit of less than $1 million. No compensation cost related to stock options was capitalized during the year. As of December 31, 2006, all options were fully vested; therefore no compensation expense was recognized in 2007.

Stock option expense totaling $1 million was recognized in income during the year ended December 31, 2005, with a recognized tax benefit of less than $1 million. No compensation cost related to stock options was capitalized during the year.

As previously indicated, we did not record stock option expense prior to the adoption of SFAS No. 123R as of July 1, 2005. The following table illustrates the effect on our net income if the fair value method had been applied to all outstanding and nonvested awards in each period:

(in millions)	2005
Net income, as reported	$	260
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1
Pro forma net income	$	259

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 EIP and was continued under our 2002 and 2007 EIPs, as amended and restated from time to time.

We granted cash-settled PSSP awards prior to 2005. Since 2005, we have been granting stock-settled PSSP awards. Under the terms of the PSSP, our officers and key employees are granted a target number of performance shares on an annual basis that vest over a three-year consecutive period. Each performance share has a value that is equal to, and changes with, the value of a share of Progress Energy common stock, and dividend equivalents are accrued on, and reinvested in, additional performance shares. Prior to 2007, shares issued under the PSSP (both cash-settled and stock-settled) had two equally weighted performance measures, both of which were based on our results as compared to a peer group of utilities. In 2007, the PSSP was redesigned, and shares issued under the revised plan use one performance measure. The outcome of the performance measures can result in an increase or decrease from the target number of performance shares granted. For cash-settled awards, compensation expense is recognized over the vesting period based on the estimated fair value of the award, which is periodically updated to reflect factors such as changes in stock price and the status of performance measures. The stock-settled PSSP is similar to the cash-settled PSSP, except that we distribute common stock shares to participants equivalent to the number of performance shares that ultimately vest. 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

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performance measure. Compensation expense for all awards is reduced by estimated forfeitures. PSSP cash-settled liabilities totaling $3 million, $4 million and $5 million were paid in the years ended December 31, 2007, 2006 and 2005, respectively. A summary of the status of the target performance shares under the stock-settled PSSP plan at December 31, 2007, and changes during the year then ended is presented below:

	Number of Stock-Settled Performance Shares(a)	Weighted-Average  Grant Date Fair Value
Beginning balance	1,044,583	$44.26
Granted	892,410	50.70
Paid(b)	(190,567)	50.70
Forfeited	(116,431)	44.84
Ending balance	1,629,995	$44.97

a)   Amounts reflect target shares to be issued. The final number of shares issued will be dependent upon the outcome of the performance measures discussed above.

b)   Shares paid include only target shares as originally granted. Additional shares of 106,478 were issued and paid due to exceeding established performance thresholds and due to dividends earned.

For the years ended December 31, 2006 and 2005, the weighted-average grant date fair value of stock-settled performance shares granted was $44.27 and $44.24, respectively.

The Restricted Stock Award (RSA) program allows us to grant shares of restricted common stock to our officers and key employees. The restricted shares generally vest on a graded vesting schedule over a minimum of three years. Compensation expense, which is 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. Restricted shares are not included as shares outstanding in the basic earnings per share calculation until the shares are no longer forfeitable. A summary of the status of the nonvested restricted stock shares at December 31, 2007, and changes during the year then ended, is presented below:

	Number of Restricted Shares	Weighted-Average Grant Date Fair Value
Beginning balance	604,238	$43.82
Granted	7,000	49.54
Vested	(303,935)	44.08
Forfeited	(38,668)	43.16
Ending balance	268,635	$43.77

For the years ended December 31, 2006 and 2005, the weighted-average grant date fair value of restricted stock granted was $44.51 and $42.56, respectively.

The total fair value of restricted stock awards vested during the years ended December 31, 2007, 2006 and 2005 was $13 million, $4 million and $7 million, respectively. Cash expended to purchase shares for the restricted stock program totaled $8 million during the years ended December 31, 2006 and 2005, respectively. Cash expended to purchase shares for 2007 was not significant due to the curtailment of the RSA program and the rollout of the new restricted stock unit (RSU) program.

Beginning in 2007, we began issuing RSUs rather than 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 five-year graded vesting. Compensation expense, which is 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 not included as shares outstanding in the basic earnings per share calculation until shares are

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no longer forfeitable. Units are converted to shares upon vesting. A summary of the status of nonvested RSUs at December 31, 2007, and changes during the year then ended, is presented below:

	Number of Restricted Units	Weighted-Average Grant Date Fair Value
Beginning balance	–	$        –
Granted	913,282	50.33
Vested	(49,430)	50.70
Forfeited	(39,394)	50.70
Ending balance	824,458	$50.29

The total fair value of RSUs vested during the year ended December 31, 2007, was $3 million. There were no expenditures to purchase stock to satisfy RSU plan obligations in 2007.

Our Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $70 million for the year ended December 31, 2007, with a recognized tax benefit of $27 million. The total expense recognized on our Consolidated Statements of Income for other stock-based compensation plans was $25 million with a recognized tax benefit of $10 million and $10 million, with a recognized tax benefit of $4 million, for the years ended December 31, 2006 and 2005, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

At December 31, 2007, there was $51 million of total unrecognized compensation cost related to nonvested other stock-based compensation plan awards, which is expected to be recognized over a weighted-average period of 1.8 years.

PEC

PEC’s Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $41 million for the year ended December 31, 2007, with a recognized tax benefit of $16 million. The total expense recognized on PEC’s Consolidated Statements of Income for other stock-based compensation plans was $14 million with a recognized tax benefit of $6 million and $7 million, with a recognized tax benefit of $3 million, for the years ended December 31, 2006 and 2005, 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 $22 million for the year ended December 31, 2007, with a recognized tax benefit of $9 million. The total expense recognized on PEF’s Statements of Income for other stock-based compensation plans was $7 million for the year ended December 31, 2006, with a recognized tax benefit of $3 million. The total expense recognized on PEF’s Statements of Income for other stock-based compensation plans was $3 million for the year ended December 31, 2005, with a recognized tax benefit of $1 million. 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. Diluted earnings per share include the effects of the nonvested portion of restricted stock, restricted stock unit awards and performance share awards and the effect of stock options outstanding.

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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)	2007	2006	2005
Weighted-average common shares – basic	256.1	250.4	246.6
Net effect of dilutive stock-based compensation plans	0.6	0.4	0.4
Weighted-average shares – fully diluted	256.7	250.8	247.0

There were no adjustments to net income or to income from continuing operations between the calculations of basic and fully diluted earnings per common share. ESOP shares that have not been committed to be released to participants’ accounts are not considered outstanding for the determination of earnings per common share. The weighted-average shares totaled 1.8 million, 2.4 million and 3.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. There were 0.1 million, 1.8 million and 2.9 million stock options outstanding at December 31, 2007, 2006 and 2005, 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

Components of accumulated other comprehensive loss, net of tax, at December 31 were as follows:

		Progress Energy						PEC						PEF
(in millions)		2007			2006			2007			2006			2007			2006
Loss on cash flow hedges		$	(23	)	$	(14	)	$	(10	)	$	(5	)	$	(8	)	$	(1	)
Pension and other postretirement benefits	��		(13	)		(39	)		–			–			–			–
Other			2			4			–			4			–			–
Total accumulated other comprehensive loss		$	(34	)	$	(49	)	$	(10	)	$	(1	)	$	(8	)	$	(1	)

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11.   PREFERRED STOCK OF SUBSIDIARIES – NOT SUBJECT TO MANDATORY REDEMPTION

All of our preferred stock was issued by our subsidiaries and was not subject to mandatory redemption. At December 31, 2007 and 2006, preferred stock outstanding consisted of the following:

	Shares				Redemption
(dollars in millions, except share and per share data)	Authorized		Outstanding		Price		Total
PEC
Cumulative, no par value $5 Preferred Stock		300,000
$5 Preferred				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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12.   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, 2007):

(in millions)		2007	2006
Progress Energy, Inc.
Senior unsecured notes, maturing 2010-2031	6.98%	$2,600	$2,600
Unamortized fair value hedge gain, net		–	(1)
Unamortized premium and discount, net		(3)	(18)
Long-term debt, net		2,597	2,581
PEC
First mortgage bonds, maturing 2009-2035	5.65%	2,000	2,200
Pollution control obligations, maturing 2017-2024	4.57%	669	669
Senior unsecured notes, maturing 2012	6.50%	500	500
Medium-term notes, maturing 2008	6.65%	300	300
Miscellaneous notes		22	22
Unamortized premium and discount, net		(8)	(21)
Current portion of long-term debt		(300)	(200)
Long-term debt, net		3,183	3,470
PEF
First mortgage bonds, maturing 2008-2037	5.64%	2,380	1,630
Pollution control obligations, maturing 2018-2027	4.32%	241	241
Senior unsecured notes, maturing 2008	5.27%	450	450
Medium-term notes, maturing 2008-2028	6.75%	152	241
Unamortized premium and discount, net		(5)	(5)
Current portion of long-term debt		(532)	(89)
Long-term debt, net		2,686	2,468
Florida Progress Funding Corporation (See Note 23)
Debt to affiliated trust, maturing 2039	7.10%	309	309
Unamortized premium and discount, net		(38)	(38)
Long-term debt, net		271	271
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2008	6.46%	45	80
Current portion of long-term debt		(45)	(35)
Long-term debt, net		–	45
Progress Energy consolidated long-term debt, net		$8,737	$8,835

On September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017. The proceeds were used to repay PEF’s utility money pool borrowings and the remainder was placed in temporary investments for general corporate use as needed.

At December 31, 2007 and 2006, we had committed lines of credit used to support our commercial paper borrowings. At December 31, 2007 and 2006, we had no outstanding borrowings under our credit facilities. We are required to pay minimal annual commitment fees to maintain our credit facilities.

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The following table summarizes our revolving credit agreements (RCAs) and available capacity at December 31, 2007:

(in millions)	Description	Total		Outstanding		Reserved(a)		Available
Progress Energy, Inc.	Five-year (expiring 5/3/11)	$	1,130	$	–	$	220	$	910
PEC	Five-year (expiring 6/28/10)		450		–		–		450
PEF	Five-year (expiring 3/28/10)		450		–		–		450
Total credit facilities		$	2,030	$	–	$	220	$	1,810

(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, 2007, Progress Energy, Inc. had a total amount of $19 million of letters of credit issued, which were supported by the RCA.

The RCAs provide liquidity support for issuances of commercial paper and other short-term obligations. Fees and interest rates under Progress Energy’s RCA are based upon the credit rating of Progress Energy’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa2 by Moody’s Investors Service, Inc. (Moody’s) and BBB by S&P. Fees and interest rates under PEC’s RCA are based upon the credit rating of PEC’s long-term unsecured senior noncredit-enhanced debt, currently rated as A3 by Moody’s and BBB by S&P. Fees and interest rates under PEF’s RCA are based upon the credit rating of PEF’s long-term unsecured senior noncredit-enhanced debt, currently rated as A3 by Moody’s and BBB by S&P.

The following table summarizes our outstanding commercial paper and other short-term debt and related weighted-average interest rates at December 31, 2007:

(in millions)
Progress Energy, Inc.	5.48	%	$	201
PEC				–
PEF				–
Total	5.48	%	$	201

We had no commercial paper outstanding or other short-term debt at December 31, 2006.

The following table presents the aggregate maturities of long-term debt at December 31, 2007:

(in millions)	Progress Energy Consolidated		PEC		PEF
2008	$	877	$	300	$	532
2009		400		400		–
2010		406		6		300
2011		1,000		–		300
2012		950		500		–
Thereafter		6,035		2,285		2,091
Total	$	9,668	$	3,491	$	3,223

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B.    COVENANTS AND DEFAULT PROVISIONS

FINANCIAL COVENANTS

Progress Energy, Inc.’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, 2007, 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)
Progress Energy, Inc.		68%		54.4%
PEC		65%		48.8%
PEF		65%		53.2%

(a) Indebtedness as defined by the bank agreements includes certain letters of credit and guarantees that are 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 Progress Energy, Inc. 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. Progress Energy, Inc.’s cross-default provision can be triggered by Progress Energy, Inc. and its significant subsidiaries, as defined in the credit agreement, (i.e., PEC, Florida Progress, PEF, Progress Capital Holdings, Inc. and PVI). PEC’s and PEF’s cross-default provisions can only be triggered by defaults of indebtedness by PEC and its subsidiaries and PEF, respectively, not each other or other affiliates of PEC and PEF.

Additionally, certain of Progress Energy, Inc.’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 Progress Energy, Inc., 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 approximately $2.6 billion in long-term debt. 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 Progress Energy, Inc.’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, 2007, Progress Energy, Inc. had no shares of preferred stock outstanding.

Certain documents restrict the payment of dividends by Progress Energy, Inc.’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, 2007, none of PEC’s cash dividends or distributions on common stock was restricted.

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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 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 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, 2007, PEC’s common stock equity was approximately 53.8 percent of total capitalization. At December 31, 2007, 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, 2007, 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 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, 2007, PEF’s common stock equity was approximately 52.5 percent of total capitalization. At December 31, 2007, 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, 2007, PEC and PEF had a total of $2.669 billion and $2.621 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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13.   INVESTMENTS AND FAIR VALUE OF FINANCIAL INSTRUMENTS

A.    INVESTMENTS

At December 31, 2007 and 2006, 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)	2007		2006		2007		2006		2007		2006
Nuclear decommissioning trust (See Note 5D)	$	1,384	$	1,287	$	804	$	735	$	580	$	552
Investments in equity securities (a)		–		5		–		4		–		–
Equity method investments (b)		23		24		11		13		2		1
Cost investments (c)		8		8		3		2		–		–
Benefit investment trusts (d)		82		80		2		2		–		–
Company-owned life insurance (d)		168		161		112		99		39		39
Marketable debt securities (e)		1		71		1		50		–		–
Total	$	1,666	$	1,636	$	933	$	905	$	621	$	592

(a)   Certain investments in equity securities that have readily determinable market values, and for which we do not have control, are accounted for as available-for-sale securities at fair value in accordance with SFAS No. 115 (See Note 1). These investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

(b)   Investments in unconsolidated companies are included in miscellaneous other property and investments in the Consolidated Balance Sheets using the equity method of accounting (See Note 1). These investments are primarily in limited liability corporations and limited partnerships, and the earnings from these investments are recorded on a pre-tax basis (See Note 20).

(c)   Investments stated principally at cost are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

(d)   Investments in company-owned life insurance and other benefit plan assets are included in miscellaneous other property and investments in the Consolidated Balance Sheets and approximate fair value due to the short maturity of the instruments.

(e)   We actively invest available cash balances in various financial instruments, such as tax-exempt debt securities that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through arrangements with banks that provide daily and weekly liquidity and 7-, 28- and 35-day auctions that allow for the redemption of the investment at its face amount plus earned income. As we intend to sell these instruments within one year or less, generally within 30 days, from the balance sheet date, they are classified as short-term investments.

B.    FAIR VALUE OF FINANCIAL INSTRUMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $9.614 billion and $9.159 billion at December 31, 2007 and 2006, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $9.897 billion and $9.543 billion at December 31, 2007 and 2006, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values, and for which we do not have control, are accounted for as available-for-sale securities at fair value in accordance with SFAS No. 115. These investments include investments held in trust funds, pursuant to NRC requirements, to fund certain costs of

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decommissioning nuclear plants (See Note 5D). These nuclear decommissioning trust funds are primarily invested in stocks, bonds and cash equivalents that are classified as available-for-sale. Nuclear decommissioning trust funds are presented on the Consolidated Balance Sheets at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments. In addition to the nuclear decommissioning trust funds, we hold other debt and equity investments classified as available-for-sale in miscellaneous other property and investments on the Consolidated Balance Sheets at amounts that approximate fair value. Our available-for-sale securities at December 31, 2007 and 2006 are summarized below. Net nuclear decommissioning trust fund unrealized gains are included in regulatory liabilities (See Note 7A).

2007
(in millions)	Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	465	$	354	$	819
Debt securities		574		11		585
Cash equivalents		18		–		18
Total	$	1,057	$	365	$	1,422

2006
(in millions)	Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	428	$	324	$	752
Debt securities		606		13		619
Cash equivalents		19		–		19
Total	$	1,053	$	337	$	1,390

At December 31, 2007, the fair value of available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	8
Due after one through five years		145
Due after five through 10 years		198
Due after 10 years		234
Total	$	585

Selected information about our sales of available-for-sale securities during the years ended December 31 is presented below. Realized gains and losses were determined on a specific identification basis.

(in millions)	2007		2006		2005
Proceeds	$	1,334	$	2,547	$	3,755
Realized gains		35		33		26
Realized losses		37		24		31

The NRC requires nuclear decommissioning trusts to be managed by third-party investment managers who have a right to sell securities without our authorization. Therefore, we consider available-for-sale securities in our nuclear decommissioning trust funds to be impaired if they are in a loss position. These impairments along with unrealized gains are included in our regulatory liabilities (See Note 7A) and have no earnings impact. Some of our benefit investment trusts are also managed by third-party investment managers who have the right to sell securities without our authorization. Losses at December 31, 2007 and 2006 for investments in these 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 (See Note 1D). At December 31, 2007 and 2006 our other securities had no investments in a continuous loss position for greater than 12 months.

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PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $3.483 billion and $3.670 billion at December 31, 2007 and 2006, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3.545 billion and $3.732 billion at December 31, 2007 and 2006, respectively.

INVESTMENTS

External trust funds have been established to fund certain costs of nuclear decommissioning (See Note 5D). These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalentsand are classified as available-for-sale. Nuclear decommissioning trust funds are presented on the PEC Consolidated Balance Sheets at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments.In addition to the nuclear decommissioning trust fund, PEC holds other debt and equity investments classified as available-for-sale in miscellaneous other property and investments on the PEC Consolidated Balance Sheets at amounts that approximate fair value. PEC’s available-for-sale securities at December 31, 2007 and 2006 are summarized below. Net nuclear decommissioning trust fund unrealized gains are included in regulatory liabilities (See Note 7A).

2007
(in millions)	Book Value		Unrealized Gains		Estimated  Fair Value
Equity securities	$	256	$	191	$	447
Debt securities		341		6		347
Cash equivalents		11		–		11
Total	$	608	$	197	$	805

2006
(in millions)	Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	232	$	170	$	402
Debt securities		364		7		371
Cash equivalents		9		–		9
Total	$	605	$	177	$	782

At December 31, 2007, the fair value of available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	7
Due after one through five years		86
Due after five through 10 years		99
Due after 10 years		155
Total	$	347

Selected information about PEC’s sales of available-for-sale securities during the years ended December 31 is presented below. Realized gains and losses were determined on a specific identification basis.

(in millions)	2007		2006		2005
Proceeds	$	609	$	995	$	1,678
Realized gains		12		21		13
Realized losses		22		14		16

Available-for-sale securities in PEC’s nuclear decommissioning trust funds are impaired if they are in a loss position as described above. Other securities are evaluated on an individual basis to determine if a decline in fair value below

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the carrying value is other-than-temporary (See Note 1D). At December 31, 2007 and 2006 PEC’s other securities had no investments in a continuous loss position for greater than 12 months.

PEF

DEBT

The carrying amount of PEF’s long-term debt, including current maturities, was $3.218 billion and $2.557 billion at December 31, 2007 and 2006, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3.239 and $2.567 billion at December 31, 2007 and 2006, respectively.

INVESTMENTS

External trust funds have been established to fund certain costs of nuclear decommissioning (See Note 5D). These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalentsand are classified as available-for-sale. Nuclear decommissioning trust funds are presented on the Balance Sheets at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments. PEF’s available-for-sale securities at December 31, 2007 and 2006 are summarized below. Net nuclear decommissioning trust fund unrealized gains are included in regulatory liabilities (See Note 7A).

2007
(in millions)	Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	209	$	163	$	372
Debt securities		193		5		198
Cash equivalents		7		–		7
Total	$	409	$	168	$	577
2006
(in millions)	Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	196	$	154	$	350
Debt securities		184		6		190
Cash equivalents		9		–		9
Total	$	389	$	160	$	549

At December 31, 2007, the fair value of available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	1
Due after one through five years		51
Due after five through 10 years		84
Due after 10 years		62
Total	$	198

Selected information about PEF’s sales of available-for-sale securities for the years ended December 31 is presented below. Realized gains and losses were determined on a specific identification basis.

(in millions)	2007		2006		2005
Proceeds	$	535	$	509	$	330
Realized gains		22		12		13
Realized losses		14		9		13

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Available-for-sale securities in PEF’s nuclear decommissioning trust funds are impaired if they are in a loss position as described above. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary (See Note 1D). At December 31, 2007 and 2006 PEF’s other securities had no investments in a loss position.

14.   INCOME TAXES

We provide deferred income taxes for temporary differences. These occur when there are 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 under SFAS No. 109 is different from the recovery of taxes by the Utilities through the ratemaking process, the differences are deferred pursuant to SFAS No. 71. 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)	2007			2006
Deferred income tax assets
Asset retirement obligation liability	$	146		$	141
Compensation accruals		101			86
Deferred revenue		–			28
Derivative instruments		–			42
Environmental remediation liability		32			36
Income taxes refundable through future rates		324			224
Investments		–			28
Pension and other postretirement benefits		306			364
Unbilled revenue		41			36
Other		122			103
Federal income tax credit carry forward		836			851
State net operating loss carry forward (net of federal expense)		87			54
Valuation allowance		(79	)		(71	)
Total deferred income tax assets		1,916			1,922
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(1,482	)		(1,379	)
Deferred fuel recovery		(64	)		(60	)
Deferred storm costs		(6	)		(51	)
Derivative instruments		(59	)		–
Income taxes recoverable through future rates		(391	)		(444	)
Investments		(25	)		–
Prepaid pension costs		(18	)		–
Other		(50	)		(66	)
Total deferred income tax liabilities		(2,095	)		(2,000	)
Total net deferred income tax liabilities	$	(179	)	$	(78	)

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The above amounts were classified in the Consolidated Balance Sheets as follows:

(in millions)	2007			2006
Current deferred income tax assets	$	27		$	142
Noncurrent deferred income tax assets, included in other assets and deferred debits		65			17
Current deferred income tax liabilities, included in other current liabilities		(5	)		–
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(266	)		(237	)
Total net deferred income tax liabilities	$	(179	)	$	(78	)

At December 31, 2007, the federal income tax credit carry forward includes $772 million of alternative minimum tax credits that do not expire and $64 million of general business credits that will expire during the period 2020 through 2027.

At December 31, 2007, we had gross state net operating loss carry forwards of $1.9 billion that will expire during the period 2008 through 2026.

Valuation allowances have been established due to the uncertainty of realizing certain future state tax benefits. We established additional valuation allowances of $8 million during 2007. 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.

Reconciliations of our effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:

	2007		2006		2005
Effective income tax rate	32.3	%	37.5	%	36.1	%
State income taxes, net of federal benefit	(2.8	)	(3.5	)	(3.5	)
Investment tax credit amortization	1.1		1.3		1.6
Employee stock ownership plan dividends	1.1		1.3		1.5
Domestic manufacturing deduction	1.0		0.4		1.0
Other differences, net	2.3		(2.0	)	(1.7	)
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)	2007			2006			2005
Current  – federal	$	285		$	394		$	441
– state		36			70			74
Deferred – federal		13			(94	)		(173	)
– state		11			(17	)		(31	)
State net operating loss carry forward		1			(2	)		–
Investment tax credit		(12	)		(12	)		(13	)
Total income tax expense	$	334		$	339		$	298

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Total income tax expense applicable to continuing operations excluded the following:

·   Less than $1 million of deferred tax expense related to the cumulative effect of changes in accounting principle recorded net of tax during 2005. There was no cumulative effect of changes in accounting principle recorded during 2007 or 2006.

·   Taxes related to discontinued operations recorded net of tax for 2007, 2006 and 2005, which are presented separately in Notes 3A through 3H.

·   Taxes related to other comprehensive income recorded net of tax for 2007, 2006 and 2005, which are presented separately in the Consolidated Statements of Comprehensive Income.

·   Current tax benefit of $6 million, which was recorded in common stock during 2007, 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. Current tax benefit of $3 million, which was recorded in common stock during 2006, related to excess tax deductions resulting from vesting of restricted stock awards, vesting of stock-settled PSSP awards and exercises of nonqualified stock options pursuant to the terms of our EIP. Current tax benefit of $2 million, which was recorded in common stock during 2005, related to excess tax deductions resulting from vesting of restricted stock awards and exercises of nonqualified stock options pursuant to the terms of our EIP.

In July 2006, the FASB issued FIN 48, which clarifies the accounting for income taxes 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 for the application of FIN 48; 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. We adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a $2 million reduction of the January 1, 2007, balance of retained earnings and a $4 million increase in regulatory assets. Including the cumulative effect impact, our liability for unrecognized tax benefits at January 1, 2007, was $126 million. Of the total amount of unrecognized tax benefits at January 1, 2007, $24 million would have affected the effective tax rate for income from continuing operations, if recognized. At December 31, 2007, our liability for unrecognized tax benefits decreased to $93 million and the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations decreased to $10 million. A reconciliation of the 2007 beginning and ending balances for unrecognized tax benefits is as follows:

(in millions)
Unrecognized tax benefits at January 1, 2007	$	126
Gross amounts of increases as a result of tax positions taken in a prior period		32
Gross amounts of decreases as a result of tax positions taken in a prior period		(41	)
Gross amounts of increases as a result of tax positions taken in the current period		22
Gross amounts of decreases as a result of tax positions taken in the current period		(32	)
Amounts of net decreases relating to settlements with taxing authorities		(14	)
Reductions as a result of a lapse of the applicable statute of limitations		–
Unrecognized tax benefits at December 31, 2007	$	93

At December 31, 2006 and 2005, we had recorded $76 million and $115 million, respectively, related to probable tax liabilities associated with prior filings, excluding accrued interest and penalties, which were included in noncurrent income tax liabilities on the Consolidated Balance Sheets.

Prior to the adoption of FIN 48, we and the Utilities accounted for potential losses of tax benefits in accordance with SFAS No. 5. At December 31, 2006 and 2005, we had recorded $27 million and $60 million, respectively, of tax contingency reserves under SFAS No. 5, excluding accrued interest and penalties, which were included in taxes accrued on the Consolidated Balance Sheets.

85

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state jurisdictions. During 2007, we closed federal tax years 1998 to 2003. Our open federal tax years are from 2004 forward and our open state tax years in our major jurisdictions are generally from 1992 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. We cannot predict when those examinations will be completed. We are not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the 12-month period ending December 31, 2008.

We include interest expense related to unrecognized tax benefits in interest charges and we include penalties in other, net on the Consolidated Statements of Income. During 2007, the interest expense related to unrecognized tax benefits was $1 million, net, of which a $15 million expense component was deferred as a regulatory asset by PEF and not recognized in our Consolidated Statement of Operations. During 2007 there were no penalties related to unrecognized tax benefits. As of January 1, 2007, we had accrued $24 million for interest and penalties. As of December 31, 2007, we have accrued $23 million for interest and penalties, which are included in other liabilities and deferred credits on the Consolidated Balance Sheets.

PEC

Accumulated deferred income tax assets (liabilities) at December 31 were:

(in millions)	2007			2006
Deferred income tax assets:
Asset retirement obligation liability	$	140		$	132
Compensation accruals		55			47
Deferred revenue		–			28
Income taxes refundable through future rates		83			68
Pension and other postretirement benefits		166			200
Other		40			37
Federal income tax credit carry forward		1			1
Total deferred income tax assets		485			513
Deferred income tax liabilities:
Accumulated depreciation and property cost differences		(1,013	)		(930	)
Deferred fuel recovery		(60	)		(55	)
Income taxes recoverable through future rates		(292	)		(317	)
Other		(7	)		(37	)
Total deferred income tax liabilities		(1,372	)		(1,339	)
Total net deferred income tax liabilities	$	(887	)	$	(826	)

The above amounts were classified in the Consolidated Balance Sheets as follows:

(in millions)	2007			2006
Current deferred income tax assets, included in prepayments and other current assets	$	8		$	34
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(895	)		(860	)
Total net deferred income tax liabilities	$	(887	)	$	(826	)

At December 31, 2007, the federal income tax credit carry forward includes $1 million of general business credits that will expire in 2020.

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Reconciliations of PEC’s effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:

	2007			2006			2005
Effective income tax rate		37.1	%		36.7	%		32.7	%
State income taxes, net of federal benefit		(2.3	)		(2.3	)		(2.1	)
Investment tax credit amortization		0.7			0.8			1.1
Domestic manufacturing deduction		1.1			0.6			0.7
Progress Energy tax benefit allocation		–			–			2.9
Other differences, net		(1.6	)		(0.8	)		(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)	2007			2006			2005
Current – federal	$	235		$	285		$	343
– state		19			39			45
Deferred – federal		34			(42	)		(120	)
– state		13			(11	)		(21	)
Investment tax credit		(6	)		(6	)		(8	)
Total income tax expense	$	295		$	265		$	239

Total income tax expense applicable to continuing operations excluded the following:

·   Less than $1 million of deferred tax expense related to the cumulative effect of changes in accounting principle recorded net of tax during 2005. There was no cumulative effect of changes in accounting principle recorded during 2007 or 2006.

·   Taxes related to other comprehensive income recorded net of tax for 2007, 2006 and 2005, which are presented separately in the Consolidated Statements of Comprehensive Income.

·   Current tax benefit of $3 million, which was recorded in common stock during 2007, 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. Current tax benefit of $1 million, which was recorded in common stock during 2006, related to excess tax deductions resulting from vesting of restricted stock awards, vesting of stock-settled PSSP awards and exercises of nonqualified stock options pursuant to the terms of our EIP. Current tax benefit of $1 million, which was recorded in common stock during 2005, related to excess tax deductions resulting from vesting of restricted stock awards and exercises of nonqualified stock options pursuant to the terms of our EIP.

PEC and each of its wholly owned subsidiaries have entered into the Tax Agreement with Progress Energy (See Note 1D). PEC’s intercompany tax payable was approximately $27 million and $51 million at December 31, 2007 and 2006, respectively.

PEC adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a $6 million reduction of the January 1, 2007, balance of retained earnings. Including the cumulative effect impact, PEC’s liability for unrecognized tax benefits at January 1, 2007, was $43 million. Of the total amount of unrecognized tax benefits at January 1, 2007, $9 million would have affected the effective tax rate, if recognized. At December 31, 2007, PEC’s liability for unrecognized tax benefits decreased to $41 million, and the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate was $9 million. A reconciliation of the 2007 beginning and ending balances for unrecognized tax benefits is as follows:

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(in millions)
Unrecognized tax benefits at January 1, 2007	$	43
Gross amounts of increases as a result of tax positions taken in a prior period		3
Gross amounts of decreases as a result of tax positions taken in a prior period		(15	)
Gross amounts of increases as a result of tax positions taken in the current period		22
Gross amounts of decreases as a result of tax positions taken in the current period		(5	)
Amounts of decreases relating to settlements with taxing authorities		(7	)
Reductions as a result of a lapse of the applicable statute of limitations		–
Unrecognized tax benefits at December 31, 2007	$	41

At December 31, 2006 and 2005, PEC had recorded $49 million and $92 million, respectively, related to probable tax liabilities associated with prior filings, excluding accrued interest and penalties, which were included in noncurrent income tax liabilities on the Consolidated Balance Sheets.

At December 31, 2006 and 2005, PEC had recorded $5 million and $2 million, respectively, of tax contingency reserves under SFAS No. 5, excluding accrued interest and penalties, which were included in taxes accrued on the Consolidated Balance Sheets.

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. During 2007, we closed federal tax years 1998 to 2003. PEC’s open federal tax years are from 2004 forward and PEC’s open state tax years in our major jurisdictions are generally from 1992 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEC cannot predict when those examinations will be completed. PEC is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the twelve-month period ending December 31, 2008.

PEC includes interest expense related to unrecognized tax benefits in interest charges and includes penalties in other, net on the Consolidated Statements of Income. During 2007, the interest expense and penalties related to uncertain tax benefits was $4 million and $0 respectively. As of January 1, 2007, PEC had accrued $4 million for interest and penalties. At December 31, 2007, PEC had accrued $8 million for interest and penalties, which is included in 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)	2007			2006
Deferred income tax assets
Compensation accruals	$	21		$	15
Derivative instruments		–			30
Environmental remediation liability		18			24
Income taxes refundable through future rates		190			103
Pension and other postretirement benefits		142			150
Reserve for storm damage		25			2
Unbilled revenue		41			36
Other		56			53
Total deferred income tax assets		493			413
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(451	)		(429	)
Deferred storm costs		(6	)		(45	)
Derivative instruments		(64	)		–
Income taxes recoverable through future rates		(99	)		(127	)
Investments		(63	)		(61	)
Prepaid pension costs		(86	)		(67	)
Other		(31	)		(38	)
Total deferred income tax liabilities		(800	)		(767	)
Total net deferred income tax liabilities	$	(307	)	$	(354	)

The above amounts were classified in the Balance Sheets as follows:

(in millions)	2007			2006
Current deferred income tax assets	$	39		$	86
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(346	)		(440	)
Total net deferred income tax liabilities	$	(307	)	$	(354	)

Reconciliations of PEF’s effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:

	2007			2006			2005
Effective income tax rate		31.2	%		37.0	%		31.8	%
State income taxes, net of federal benefit		(3.3	)		(3.6	)		(3.3	)
Investment tax credit amortization		1.3			1.2			1.4
Domestic manufacturing deduction		0.8			0.3			0.9
Progress Energy tax benefit allocation		–			–			3.2
AFUDC equity		2.6			0.7			0.7
Other differences, net		2.4			(0.6	)		0.3
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

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Income tax expense applicable to continuing operations for the years ended December 31 was comprised of:

(in millions)	2007			2006			2005
Current   – federal	$	160		$	207		$	146
– state		28			34			25
Deferred – federal		(33	)		(36	)		(39	)
– state		(5	)		(6	)		(6	)
Investment tax credit		(6	)		(6	)		(5	)
Total income tax expense	$	144		$	193		$	121

Total income tax expense applicable to continuing operations excluded the following:

·   Less than $1 million of deferred tax expense related to the cumulative effect of changes in accounting principle recorded net of tax during 2005. There was no cumulative effect of changes in accounting principle recorded during 2007 or 2006.

·   Taxes related to other comprehensive income recorded net of tax for 2007, 2006 and 2005, which are presented separately in the Statements of Comprehensive Income.

·   Less than $1 million of current tax benefit, which was recorded in common stock during 2007, 2006 and 2005, related to excess tax deductions resulting from vesting of restricted stock awards and exercises of nonqualified stock options pursuant to the terms of our EIP.

PEF has entered into the Tax Agreement with Progress Energy (See Note 1D). PEF’s intercompany tax receivable was approximately $41 million and $47 million at December 31, 2007 and 2006, respectively.

PEF adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a less than $1 million reduction of the January 1, 2007, balance of retained earnings and a $4 million increase in regulatory assets. Including the cumulative effect impact, PEF’s liability for unrecognized tax benefits at January 1, 2007, was $72 million. Of the total amount of unrecognized tax benefits at January 1, 2007, $4 million would have affected the effective tax rate, if recognized. At December 31, 2007, PEF’s liability for unrecognized tax benefits decreased to $55 million and the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate decreased to $3 million. A reconciliation of the 2007 beginning and ending balances for unrecognized tax benefits is as follows:

(in millions)
Unrecognized tax benefits at January 1, 2007	$	72
Gross amounts of increases as a result of tax positions taken in a prior period		23
Gross amounts of decreases as a result of tax positions taken in a prior period		(4	)
Gross amounts of increases as a result of tax positions taken in the current period		2
Gross amounts of decreases as a result of tax positions taken in the current period		(25	)
Amounts of decreases relating to settlements with taxing authorities		(13	)
Reductions as a result of a lapse of the applicable statute of limitations		–
Unrecognized tax benefits at December 31, 2007	$	55

At December 31, 2006 and 2005, PEF had recorded $26 million and $17 million, respectively, related to probable tax liabilities associated with prior filings, excluding accrued interest and penalties, which were included in noncurrent income tax liabilities on the Balance Sheets.

At December 31, 2006 and 2005, respectively, PEF had recorded $5 million and $7 million of tax contingency reserves under SFAS No. 5, excluding accrued interest and penalties, which were included in other current liabilities on the Balance Sheets.

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We file consolidated federal and state income tax returns that include PEF. During 2007, we closed federal tax years 1998 to 2003. PEF’s open federal tax years are from 2004forward and PEF’s open state tax years are generally from 1998 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEF cannot predict when those examinations will be completed. PEF is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the twelve-month period ending December 31, 2008.

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, with the amortization included in interest charges on the Statements of Income. Penalties are included in other, net on the Statements of Income. During 2007, the interest expense recorded as a regulatory asset was $15 million and penalties related to unrecognized tax benefits was $0. At January 1, 2007, PEF had accrued $7 million for interest and penalties. At December 31, 2007, PEF had accrued $18 million for interest and penalties, which is included in other liabilities and deferred credits on the Balance Sheets.

15.    CONTINGENT VALUE OBLIGATIONS

In connection with the acquisition of Florida Progress during 2000, the Parent issued 98.6 million contingent value obligations (CVOs). Each CVO represents the right of the holder to receive contingent payments based on the performance of four Earthco 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. We will 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. Monies held in the trust are generally not payable to the CVO holders until the completion of income tax audits. 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, 2007 and 2006, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $34 million and $32 million, respectively.

During 2007, a $5 million deposit was made into a CVO trust for the net after-tax cash flows generated by the four Earthco synthetic fuels facilities in 2004. Deposits into the trust will be classified as a restricted cash asset until the applicable tax years are closed, at which time a payment will be disbursed to the CVO holders. Future payments will include principal and interest earned during the investment period net of expenses deducted. The interest earned on the payment held in trust for 2007 was insignificant. The asset is included in other assets and deferred debits on the Consolidated Balance Sheet at December 31, 2007.

16.   BENEFIT PLANS

A.    POSTRETIREMENT BENEFITS

We have noncontributory defined benefit retirement plans for substantially all full-time employees that provide pension benefits. 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.

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The components of the net periodic benefit cost for the years ended December 31 were:

Progress Energy
	Pension Benefits									Other Postretirement Benefits
(in millions)	2007			2006			2005			2007			2006			2005
Service cost	$	46		$	45		$	47		$	7		$	9		$	9
Interest cost		123			117			117			32			33			33
Expected return on plan assets		(155	)		(148	)		(147	)		(6	)		(6	)		(5	)
Amortization of actuarial loss(a)		15			18			21			2			4			6
Other amortization, net (a)		2			–			–			5			5			5
Net periodic cost	$	31		$	32		$	38		$	40		$	45		$	48

(a) Adjusted to reflect PEF’s rate treatment (See Note 16B).

In addition to the net periodic cost reflected above, in 2005, we recorded costs for special termination benefits related to a voluntary enhanced retirement program of $123 million for pension benefits and $19 million for other postretirement benefits.

We and the Utilities adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R),” (SFAS No. 158) as of December 31, 2006. SFAS No. 158 amended prior accounting requirements for pension and OPEB plans. Prior to the implementation of SFAS No. 158, other comprehensive income (OCI) reflected minimum pension adjustments related to our pension plans. Our pre-tax minimum pension adjustments recognized as a component of OCI for the years ended December 31, 2006 and 2005 were net actuarial gains (losses) of $78 million and $(41) million, respectively. No amounts related to our OPEB plans were recognized as a component of OCI for the years ended December 31, 2006 and 2005. The table below provides a summary of amounts recognized in other comprehensive income for 2007 and other comprehensive income reclassification adjustments for amounts included in net income for 2007. The table also includes comparable items that affected regulatory assets of PEC and PEF. Refer to the PEC and PEF sections below for more information with regard to these regulatory assets.

(in millions)	Pension Benefits			Other Postretirement Benefits
Other comprehensive income (loss)
Recognized for the year
Net actuarial gain	$	24		$	16
Other, net		(1	)		–
Reclassification adjustments
Net actuarial loss		2			–
Other, net		1			–
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial gain		66			82
Other, net		(8	)		–
Amortized to income
Net actuarial loss		13			2
Other, net		1			4

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PEC
	Pension Benefits									Other Postretirement Benefits
(in millions)	2007			2006			2005			2007			2006			2005
Service cost	$	23		$	22		$	22		$	5		$	4		$	4
Interest cost		56			52			53			15			17			17
Expected return on plan assets		(60	)		(59	)		(62	)		(4	)		(4	)		(4	)
Amortization of actuarial loss		12			11			10			–			2			5
Other amortization, net		2			1			1			1			1			1
Net periodic cost	$	33		$	27		$	24		$	17		$	20		$	23

In addition to the net periodic cost reflected above, in 2005, PEC recorded costs for special termination benefits related to a voluntary enhanced retirement program of $21 million for pension benefits and $8 million for other postretirement benefits.

No amounts related to PEC’s OPEB plans were recognized as a component of OCI for the years ended December 31, 2006 and 2005. Pre-tax minimum pension adjustments recognized as a component of OCI for the years ended December 31, 2006 and 2005 were net actuarial gains (losses) of $59 million and $(19) million, respectively. In conjunction with the implementation of SFAS No. 158, amounts that would otherwise be recorded in OCI are recorded as adjustments to regulatory assets consistent with the recovery of the related costs through the ratemaking process. The table below provides a summary of amounts recognized in regulatory assets for 2007 and amounts amortized from regulatory assets to net income for 2007.

(in millions)	Pension Benefits			Other Postretirement Benefits
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial gain	$	26			$	82
Other, net		(6	)			–
Amortized to net income
Net actuarial loss		12				–
Other, net		2				1

PEF
	Pension Benefits									Other Postretirement Benefits
(in millions)	2007			2006			2005			2007			2006			2005
Service cost	$	16		$	16		$	16		$	2		$	3		$	3
Interest cost		52			49			48			14			14			13
Expected return on plan assets		(84	)		(78	)		(73	)		(1	)		(1	)		(1	)
Amortization of actuarial loss		1			3			8			2			1			2
Other amortization, net		(1	)		(1	)		(1	)		3			4			4
Net periodic (benefit) cost	$	(16	)	$	(11	)	$	(2	)	$	20		$	21		$	21

In addition to the net periodic cost and benefit reflected above, in 2005 PEF recorded costs for special termination benefits related to a voluntary enhanced retirement program of $84 million for pension benefits and $7 million for other postretirement benefits.

No amounts related to PEF’s OPEB or pension plans were recorded as a component of OCI for the years ended December 31, 2007, 2006 and 2005. Amounts that would otherwise be recorded in OCI are recorded as adjustments

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to regulatory assets consistent with the recovery of the related costs through the ratemaking process. The table below provides a summary of amounts recognized in regulatory assets for 2007 and amounts amortized from regulatory assets to net income for 2007.

(in millions)	Pension Benefits			Other Postretirement Benefits
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial gain	$	40			$	–
Other, net		(1	)			–
Amortized to net income
Net actuarial loss		1				2
Other, net		(1	)			3

The following weighted-average actuarial assumptions were used by Progress Energy in the calculation of its net periodic cost:

	Pension Benefits									Other Postretirement Benefits
	2007			2006			2005			2007			2006			2005
Discount rate		5.95	%		5.65	%		5.70	%		5.95	%		5.65	%		5.70	%
Rate of increase in future compensation
Bargaining		4.25	%		3.50	%		3.50	%		–			–			–
Supplementary plans		5.25	%		5.25	%		5.25	%		–			–			–
Expected long-term rate of return on
plan assets		9.00	%		9.00	%		9.00	%		7.70	%		8.30	%		8.25	%

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 9.00% for PEC and 5.00% for PEF, for all years presented.

The expected long-term rates of return on plan assets were determined by considering long-term historical returns for the plans and long-term projected returns based on the plans’ target asset allocation. For all pension plan assets and a substantial portion of OPEB plans assets, those benchmarks support an expected long-term rate of return between 9.0% and 9.5%. The Progress Registrants used an expected long-term rate of 9.0%, the low end of the range, for 2007, 2006 and 2005.

BENEFIT OBLIGATIONS AND ACCRUED COSTS

SFAS No. 158 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.

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Reconciliations of the changes in the Progress Registrants’ benefit obligations and the funded status as of December 31, 2007 and 2006 are presented in the tables below, with each table followed by related supplementary information.

Progress Energy
	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Projected benefit obligation at January 1	$	2,123		$	2,164		$	628		$	650
Service cost		46			45			7			9
Interest cost		123			117			32			33
Benefit payments		(131	)		(174	)		(30	)		(29	)
Plan amendment		8			18			–			(4	)
Actuarial gain		(27	)		(47	)		(96	)		(31	)
Obligation at December 31		2,142			2,123			541			628
Fair value of plan assets at December 31		1,996			1,836			75			74
Funded status	$	(146	)	$	(287	)	$	(466	)	$	(554	)

The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $463 million and $2.123 billion at December 31, 2007 and 2006, respectively. Those plans had accumulated benefit obligations totaling $422 million and $2.083 billion at December 31, 2007 and 2006, respectively, and plan assets of $269 million and $1.836 billion at December 31, 2007 and 2006, respectively. The total accumulated benefit obligation for pension plans was $2.100 billion and $2.083 billion at December 31, 2007 and 2006, respectively.

The accrued benefit costs reflected in the Consolidated Balance Sheets at December 31 were as follows:

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Noncurrent assets	$	48		$	–		$	–		$	–
Current liabilities		(10	)		(14	)		–			(1	)
Noncurrent liabilities		(184	)		(273	)		(466	)		(553	)
Funded status	$	(146	)	$	(287	)	$	(466	)	$	(554	)

The table below provides a summary of amounts not yet recognized as a component of net periodic cost, as of December 31.

	Pension Benefits				Other Postretirement Benefits
(in millions)	2007		2006		2007			2006
Recognized in accumulated other comprehensive loss
Net actuarial loss (gain)	$	22	$	49	$	(9	)	$	7
Other, net		6		5		1			1
Recognized in regulatory assets, net
Net actuarial loss		136		215		25			108
Other, net		28		22		23			28
Total not yet recognized as a component of net periodic cost(a)	$	192	$	291	$	40		$	144

(a) All components are adjusted to reflect PEF’s rate treatment (See Note 16B).

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The following table presents the amounts we expect to recognize as components of net periodic cost in 2008.

(in millions)	Pension Benefits		Other Postretirement Benefits
Amortization of actuarial loss (a)	$	7		$	1
Amortization of other, net(a)		2			5
(a)  Adjusted to reflect PEF's rate treatment (See Note 16B).

PEC
	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Projected benefit obligation at January 1	$	952		$	969		$	330		$	333
Service cost		23			22			5			4
Interest cost		56			52			15			17
Plan amendment		6			9			–			–
Benefit payments		(60	)		(83	)		(12	)		(11	)
Actuarial (gain) loss		3			(17	)		(81	)		(13	)
Obligation at December 31		980			952			257			330
Fair value of plan assets at December 31		805			741			44			45
Funded status	$	(175	)	$	(211	)	$	(213	)	$	(285	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $980 million and $952 million at December 31, 2007 and 2006, respectively. Those plans had accumulated benefit obligations totaling $974 million and $946 million at December 31, 2007 and 2006, respectively, and plan assets of $805 million and $741 million at December 31, 2007 and 2006, respectively.

The accrued benefit costs reflected in the Consolidated Balance Sheets at December 31 were as follows:

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Current liabilities	$	(2	)	$	(2	)	$	–		$	–
Noncurrent liabilities		(173	)		(209	)		(213	)		(285	)
Funded status	$	(175	)	$	(211	)	$	(213	)	$	(285	)

The table below provides a summary of amounts not yet recognized as a component of net periodic cost, as of December 31.

	Pension Benefits				Other Postretirement Benefits
(in millions)	2007		2006		2007			2006
Recognized in regulatory assets
Net actuarial loss (gain)	$	104	$	142	$	(12	)	$	69
Other, net		29		25		5			7
Total not yet recognized as a component of net periodic cost	$	133	$	167	$	(7	)	$	76

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The following table presents the amounts PEC expects to recognize as components of net periodic cost in 2008.

(in millions)	Pension Benefits		Other Postretirement Benefits
Amortization of actuarial loss	$	5		$	–
Amortization of other, net		2			1

PEF
	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Projected benefit obligation at January 1	$	880		$	896		$	246		$	259
Service cost		16			16			2			3
Interest cost		52			49			14			14
Plan amendment		1			8			–			(4	)
Benefit payments		(57	)		(69	)		(16	)		(17	)
Actuarial gain		(11	)		(20	)		(1	)		(9	)
Obligation at December 31		881			880			245			246
Fair value of plan assets at December 31		1,026			952			26			24
Funded status	$	145		$	72		$	(219	)	$	(222	)

The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $345 million and $342 million at December 31, 2007 and 2006, respectively. Those plans had accumulated benefit obligations totaling $313 million and $311 million at December 31, 2007 and 2006, respectively, and plan assets of $269 million and $240 million at December 31, 2007 and 2006, respectively. The total accumulated benefit obligation for pension plans was $849 million at December 31, 2007 and 2006.

The accrued benefit costs reflected in the Consolidated Balance Sheets at December 31 were as follows:

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Noncurrent assets	$	221		$	174		$	–		$	–
Current liabilities		(3	)		(3	)		–			–
Noncurrent liabilities		(73	)		(99	)		(219	)		(222	)
Funded status	$	145		$	72		$	(219	)	$	(222	)

The table below provides a summary of amounts not yet recognized as a component of net periodic cost, as of December 31.

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007		2006
Recognized in regulatory assets, net
Net actuarial loss	$	32		$	72		$	37	$	39
Other, net		(1	)		(2	)		18		21
Total not yet recognized as a component of net periodic cost	$	31		$	70		$	55	$	60

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The following table presents the amounts PEF expects to recognize as components of net periodic cost in 2008.

(in millions)	Pension Benefits			Other Postretirement Benefits
Amortization of actuarial loss	$	–		$	1
Amortization of other, net		(1	)		4

The following weighted-average actuarial assumptions were used in the calculation of our year-end obligations:

	Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006
Discount rate		6.20	%		5.95	%		6.20	%		5.95	%
Rate of increase in future compensation
Bargaining		4.25	%		4.25	%		–			–
Supplementary plans		5.25	%		5.25	%		–			–
Initial medical cost trend rate for pre-Medicare Act benefits		–			–			9.00	%		9.00	%
Initial medical cost trend rate for post-Medicare Act benefits		–			–			9.00	%		9.00	%
Ultimate medical cost trend rate		–			–			5.00	%		5.00	%
Year ultimate medical cost trend rate is achieved		–			–		2015			2014

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 as defined in EITF Issue No. 03-4, “Determining the Classification and Benefit Attribution Method for a ‘Cash Balance’ Pension Plan.” Therefore, effective December 31, 2003, we began to 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.

(in millions)	Progress Energy			PEC			PEF
1 percent increase in medical cost trend rate
Effect on total of service and interest cost	$	2		$	1		$	1
Effect on postretirement benefit obligation		31			15			14
1 percent decrease in medical cost trend rate
Effect on total of service and interest cost		(2	)		(1	)		(1	)
Effect on postretirement benefit obligation		(26	)		(12	)		(12	)

ASSETS OF BENEFIT PLANS

In the plan asset reconciliation tables that follow, our, PEC’s and PEF’s employer contributions for 2007 include contributions directly to pension plan assets of $63 million, $33 million and $15 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

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after participant contributions. Participant contributions represent approximately 20 percent of gross benefit payments for Progress Energy, 30 percent for PEC and 15 percent for PEF. The OPEB benefits payments are also reduced by prescription drug-related federal subsidies received. In 2007, the subsidies totaled $3 million for us, $1 million for PEC and $2 million for PEF. In 2006, the subsidies totaled $2 million for us, $1 million for PEC and $1 million for PEF.

Reconciliations of the fair value of plan assets at December 31 follow:

Progress Energy
	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Fair value of plan assets at January 1	$	1,836		$	1,770		$	74		$	76
Actual return on plan assets		219			222			7			8
Benefit payments		(131	)		(174	)		(30	)		(29	)
Employer contributions		72			18			24			19
Fair value of plan assets at December 31	$	1,996		$	1,836		$	75		$	74

PEC
	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Fair value of plan assets at January 1	$	741		$	731		$	45		$	49
Actual return on plan assets		89			91			5			6
Benefit payments		(60	)		(83	)		(12	)		(11	)
Employer contributions		35			2			6			1
Fair value of plan assets at December 31	$	805		$	741		$	44		$	45

PEF
	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Fair value of plan assets at January 1	$	952		$	895		$	24		$	22
Actual return on plan assets		113			114			1			1
Benefit payments		(57	)		(69	)		(16	)		(17	)
Employer contributions		18			12			17			18
Fair value of plan assets at December 31	$	1,026		$	952		$	26		$	24

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The asset allocation for the benefit plans at the end of 2007 and 2006 and the target allocation for the plans, by asset category, are presented in the following tables. The pension benefit plan allocations and targets are consistent for all Progress Registrants.

	Pension Benefits
	Target Allocations	Percentage of Plan Assets at Year End
Asset Category	2008	2007	2006
Equity – domestic	40%	42%	44%
Equity – international	15%	25%	23%
Debt – domestic	20%	11%	12%
Debt – international	10%	12%	9%
Other	15%	10%	12%
Total	100%	100%	100%

	Other Postretirement Benefits
Progress Energy	Target Allocations	Percentage of Plan Assets  at Year End
Asset Category	2008	2007		2006
Equity – domestic	25%	28%		30%
Equity – international	10%	16%		15%
Debt – domestic	50%	41%		40%
Debt – international	5%	8%		7%
Other	10%	7%		8%
Total	100%	100%		100%
PEC	Target Allocations	Percentage of Plan Assets  at Year End
Asset Category	2008	2007	2006
Equity - domestic	40%	42%	44%
Equity – international	15%	25%	23%
Debt – domestic	20%	11%	12%
Debt – international	10%	12%	9%
Other	15%	10%	12%
Total	100%	100%	100%

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	Other Postretirement Benefits
PEF	Target Allocations	Percentage of Plan Assets  at Year End
Asset Category	2008	2007	2006
Debt – domestic	100%	100%	100%

For pension plan assets and a substantial portion of OPEB plan assets, the Progress Registrants set target allocations among asset classes to provide broad diversification to protect against large investment losses and excessive volatility, while recognizing the importance of offsetting the impacts of benefit cost escalation. In addition, external investment managers who have complementary investment philosophies and approaches are employed to manage the assets. 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.

CONTRIBUTION AND BENEFIT PAYMENT EXPECTATIONS

In 2008, we expect to make $34 million of contributions 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 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $149, $153, $155, $157, $164 and $877, respectively. The expected benefit payments for the OPEB plan for 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $37, $40, $43, $45, $47 and $247, 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 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $3, $3, $4, $4, $5 and $39, respectively.

In 2008, PEC expects to make $24 million in contributions directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $73, $76, $78, $78, $81 and $426, respectively. The expected benefit payments for the OPEB plan for 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $16, $17, $19, $20, $22, and $121, 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 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $1, $2, $2, $2, $2 and $17, respectively.

In 2008, PEF does not expect to make contributions 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 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $56, $57, $58, $59, $61 and $334, respectively. The expected benefit payments for the OPEB plan for 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $19, $20, $21, $22, $22 and $108, 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 2008 through 2012 and in total for 2013 through 2017, in millions, are approximately $2, $2, $2, $2, $2 and $14, respectively.

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 DERIVATIVES 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 reviews using, among other things, 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.

As discussed in Note 15, in connection with the acquisition of Florida Progress during 2000, the Parent issued 98.6 million CVOs. 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, 2007 and 2006, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $34 million and $32 million, respectively.

A.COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” (DIG Issue C20). The related liability is being amortized to earnings over the term of the related contract (See Note 20). At December 31, 2007 and 2006, the remaining liability was $10 million and $14 million, respectively.

DISCONTINUED OPERATIONS

As discussed in Note 3A, our subsidiary, PVI, entered into a series of transactions to sell or assign substantially all of its CCO physical and commercial assets and liabilities. On June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of the Georgia Contracts, forward gas and power contracts, gas transportation, structured power and other contracts to a third party. This represented substantially all of our nonregulated energy marketing and trading operations. The sale of the generation assets closed on June 11, 2007. Additionally, we sold Gas on October 2, 2006 (See Note 3C). At December 31, 2007, with the exception of the oil price hedge instruments discussed below, our discontinued operations did not have outstanding positions in derivative instruments. For the year ended December 31, 2007, $88 million of after-tax gains from derivative instruments related to our nonregulated energy marketing and trading operations were included in discontinued operations on the Consolidated Statements of Income.

On January 8, 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge instruments was 25 million barrels and provided protection for the equivalent of approximately 8 million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts were marked-to-market with changes in fair value recorded through earnings. These contracts ended on December 31, 2007, and were settled for cash on January 8, 2008, with no material impact to 2008 earnings. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed in Note 3J, we disposed of our 100 percent ownership interest in Ceredo on March 30, 2007. Progress Energy is the primary beneficiary of, and continues to consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there is no net earnings impact for the portion of the contracts entered into

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by Ceredo. At December 31, 2007, the fair value of all of these contracts was recorded as a $234 million short-term derivative asset position, including $79 million at Ceredo. The fair value of these contracts was included in receivables, net on the Consolidated Balance Sheet (See Note 6A).  We had a $108 million cash collateral liability related to these contracts at December 31, 2007, included in other current liabilities on the Consolidated Balance Sheet.  As discussed in Note 3B, on October 12, 2007, we permanently ceased production of synthetic fuels at our majority-owned facilities. Because we have abandoned our majority-owned facilities and our other synthetic fuels operations ceased as of December 31, 2007, gains and losses on these contracts were included in discontinued operations, net of tax on the Consolidated Statement of Income in 2007. During the year ended December 31, 2007, we recorded net pre-tax gains of $168 million related to these contracts. Of this amount, $57 million was attributable to Ceredo of which $42 million was attributed to minority interest for the portion of the gain subsequent to the disposal of Ceredo.

At December 31, 2006, derivative assets of $198 million and derivative liabilities of $122 million were included in assets to be divested and liabilities to be divested, respectively, on the Consolidated Balance Sheet.  At December 31, 2006, cash collateral receivable of $9 million and cash collateral payable of $90 million were included in  assets to be divested and liabilities to be divested, respectively, on the Consolidated Balance Sheet.  Due to the divestitures discussed above, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts would be fulfilled, and cash flow hedge accounting for the contracts was discontinued beginning in the second quarter of 2006 for Gas and in the fourth quarter of 2006 for CCO. Our discontinued operations did not have material outstanding positions in commodity cash flow hedges at December 31, 2006. For the years ended December 31, 2006 and 2005, excluding amounts reclassified to earnings due to discontinuance of the related cash flow hedges, net gains and losses from derivative instruments related to Gas and CCO on a consolidated basis were not material and are included in discontinued operations, net of tax on the Consolidated Statements of Income. For the year ended December 31, 2006, discontinued operations, net of tax includes $74 million in after-tax deferred income, which was reclassified to earnings due to discontinuance of the related cash flow hedges. For the year ended December 31, 2005, there were no reclassifications to earnings due to discontinuance of the related cash flow hedges.

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. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets on the Balance Sheets, respectively, until the contracts are settled (See Note 7A). Once settled, any realized gains or losses are passed through the fuel clause. During the year ended December 31, 2007, PEC recorded a net realized loss of $9 million. PEC’s net realized gains and losses were not material during the years ended December 31, 2006 and 2005. During the years ended December 31, 2007, 2006 and 2005, PEF recorded a net realized loss of $46 million, a net realized gain of $39 million and a net realized gain of $70 million, respectively.

Excluding amounts receiving regulatory accounting treatment and amounts related to our discontinued operations discussed above, gains and losses from contracts entered into for economic hedging purposes were not material to our or the Utilities’ results of operations during the years ended December 31, 2007, 2006 and 2005. Excluding derivative assets and derivative liabilities to be divested discussed above, we did not have material outstanding positions in such contracts at December 31, 2007 and 2006, other than those receiving regulatory accounting treatment at PEC and PEF, as discussed below.

At December 31, 2007, the fair value of PEC’s commodity derivative instruments was recorded as a $19 million long-term derivative asset position included in other assets and deferred debits and a $4 million short-term derivative liability position included in other current liabilities on the PEC Consolidated Balance Sheet. At

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December 31, 2006, PEC did not have material outstanding positions in such contracts.  PEC had no cash collateral position at December 31, 2007 or 2006.

At December 31, 2007, the fair value of PEF’s commodity derivative instruments was recorded as a $83 million short-term derivative asset position included in current derivative assets, a $100 million long-term derivative asset position included in derivative assets, a $38 million short-term derivative liability position included in derivative liabilities, and a $9 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. At December 31, 2006, the fair value of such instruments was recorded as a $3 million short-term derivative asset position included in current derivative assets, a $19 million long-term derivative asset position included in derivative assets, a $90 million short-term derivative liability position included in derivative liabilities, and a $53 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. PEF had no cash collateral position at December 31, 2007 or 2006.

CASH FLOW HEDGES

PEC designates a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. PEF did not have any commodity derivative instruments designated as cash flow hedges at December 31, 2007 and 2006. At December 31, 2007 and 2006, we and PEC did not have material outstanding positions in such contracts.The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for 2007, 2006 and 2005.

At December 31, 2007 and 2006, the amount recorded in our or PEC’s accumulated other comprehensive income related to commodity cash flow hedges was not material. PEF had no amount recorded in accumulated other comprehensive income related to commodity cash flow hedges at December 31, 2007 or 2006.

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. 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

The fair values of open interest rate cash flow hedges at December 31 were as follows:

	Progress Energy						PEC						PEF
(in millions)	2007			2006			2007			2006			2007		2006
Fair value of liabilities	$	(12	)	$	(2	)	$	(12	)	$	(1	)	$	–	$	(1	)

Gains and losses from cash flow hedges are recorded in accumulated other comprehensive income and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in accumulated other comprehensive income related to terminated hedges are reclassified to earnings as the interest expense is recorded. The ineffective portion of interest rate cash flow hedges was not material to our or the Utilities’ results of operations for 2007, 2006 and 2005.

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The following table presents selected information related to interest rate cash flow hedges included in accumulated other comprehensive income at December 31, 2007:

(term in years/millions of dollars)	Progress Energy			PEC			PEF
Maximum term	Less than 1			Less than 1				–
Accumulated other comprehensive loss, net of tax(a)	$	(24	)	$	(12	)	$	(8	)
Portion expected to be reclassified to earnings during the next 12 months(b)	$	(2	)	$	(1	)	$	(1	)

(a)     Includes amounts related to terminated hedges.

(b) Actual amounts that will be reclassified to earnings may vary from the expected amounts presented above as a result of changes in interest rates.

At December 31, 2006, including amounts related to terminated hedges, we had $14 million of after-tax deferred losses, including $5 million of after-tax deferred losses at PEC and $1 million of after-tax deferred losses at PEF, recorded in accumulated other comprehensive income related to interest rate cash flow hedges.

At December 31, 2007 and 2006, PEC had $200 million notional and $50 million notional, respectively, of interest rate cash flow hedges. During 2007, PEC entered into a combined $150 million notional of forward starting swaps and amended its $50 million notional 10-year forward starting swap in order to move the maturity date from October 1, 2017 to April 1, 2018, which now requires mandatory cash settlement on April 1, 2008.

In 2007, PEF entered into a combined $225 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. At December 31, 2006, PEF had $50 million notional of interest rate cash flow hedges. All of PEF’s forward starting swaps were terminated on September 13, 2007, in conjunction with PEF’s issuance of $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017. On January 8, 2008, PEF entered into a combined $200 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

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, 2007, we had no open interest rate fair value hedges. At December 31, 2006, we had $50 million notional of interest rate fair value hedges. At December 31, 2007 and 2006, the Utilities had no open interest rate fair value hedges.

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 include performance obligations under power supply agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. Our guarantees also include standby letters of credit and surety bonds. At December 31, 2007, the Parent had issued $433 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 in the Consolidated Balance Sheet.

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 PUHCA 1935. The repeal of PUHCA 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

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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 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 services under the approved agreements. Services provided by PESC during 2007, 2006 and 2005 to PEC amounted to $182 million, $188 million and $202 million, respectively, and services provided to PEF were $174 million, $165 million and $169 million, respectively.

PEC and PEF also provide and receive services at cost. Services provided by PEC to PEF during 2007, 2006 and 2005 amounted to $54 million, $34 million and $54 million, respectively. Services provided by PEF to PEC during 2007, 2006 and 2005 amounted to $10 million, $8 million and $14 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 5.49%, 5.17% and 3.77% at December 31, 2007, 2006 and 2005, 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.

Progress Fuels sold coal to PEF at cost in 2007 and 2006 and for an insignificant profit in 2005. These intercompany revenues and expenses are eliminated in consolidation; however, in accordance with SFAS No. 71, profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of sales price through the ratemaking process is probable. Sales, net of insignificant profits, if any, of $2 million, $321 million and $402 million for the years ended December 31, 2007, 2006 and 2005, respectively, are included in fuel used in electric generation on the Consolidated Statements of Income. In 2006, PEF began entering into coal contracts on its own behalf.

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 PEC and PEF business segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. These electric operations also distribute and sell electricity to other utilities, primarily in the eastern 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 disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” as a separate business segment. The profit or loss of our reportable segments plus the profit or loss of Corporate and Other represents our total income from continuing operations.

Our former Coal and Synthetic Fuels segment was previously involved in the production and sale of coal-based solid synthetic fuels as defined under the Code, the operation of synthetic fuels facilities for third parties and coal terminal services. In 2007, we reclassified the operations of our synthetic fuels businesses and coal terminal services as discontinued operations (See Note 3B). For comparative purposes, prior year results have been restated to conform to the current segment presentation.

The postretirement and severance charges incurred in 2005 resulted from a workforce restructuring and voluntary enhanced retirement program that was approved in February 2005 and concluded in December 2005. Postretirement and severance charges reclassified to discontinued operations are not included in the table below.

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Products and services are sold between the various reportable segments. All intersegment transactions are at cost except for transactions between PEF and the former Coal and Synthetic Fuels segment, which are at rates set by the FPSC. In accordance with SFAS No. 71, profits on intercompany sales between PEF and the former Coal and Synthetic Fuels segment are not eliminated if the sales price is reasonable and the future recovery of sales price through the ratemaking process is probable. The profits realized for 2007, 2006 and 2005 were not significant. Prior to 2006, income tax expense (benefit) by segment includes the Parent’s allocation to profitable subsidiaries of income tax benefits not related to acquisition interest expense in accordance with the Tax Agreement. Due to the repeal of PUHCA 1935, the Parent stopped allocating these tax benefits in 2006.

In the following tables, capital and investment expenditures include property additions, acquisitions of nuclear fuel and other capital investments. Operational results and assets to be divested are not included in the table presented below.

(in millions)	PEC		PEF		Corporate and Other			Eliminations			Totals
As of and for the year ended December 31, 2007
Revenues
Unaffiliated	$	4,385	$	4,748	$	20		$	–		$	9,153
Intersegment		–		1		393			(394	)		–
Total revenues		4,385		4,749		413			(394	)		9,153
Depreciation and amortization		519		366		20			–			905
Interest income		21		9		55			(51	)		34
Total interest charges, net		210		173		258			(53	)		588
Income tax expense (benefit)		295		144		(105	)		–			334
Segment profit (loss)		498		315		(120	)		–			693
Total assets		11,982		10,063		16,383			(12,115	)		26,313
Capital and investment expenditures		941		1,262		3			(2	)		2,204

(in millions)	PEC		PEF		Corporate and Other			Eliminations			Totals
As of and for the year ended December 31, 2006
Revenues
Unaffiliated	$	4,086	$	4,638	$	–		$	–		$	8,724
Intersegment		–		1		729			(730	)		–
Total revenues		4,086		4,639		729			(730	)		8,724
Depreciation and amortization		571		404		36			–			1,011
Interest income		25		15		85			(66	)		59
Total interest charges, net		215		150		326			(67	)		624
Income tax expense (benefit)		265		193		(119	)		–			339
Segment profit (loss)		454		326		(229	)		–			551
Total assets		12,026		8,648		15,421			(11,293	)		24,802
Capital and investment expenditures		808		741		12			(9	)		1,552

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(in millions)	PEC	PEF	Corporate and Other	Eliminations	Totals
As of and for the year ended December 31, 2005

Revenues
Unaffiliated	$	3,991	$	3,955	$	2		$	–		$	7,948
Intersegment		–		–		839			(839	)		–
Total revenues		3,991		3,955		841			(839	)		7,948
Depreciation and amortization		561		334		31			–			926
Interest income		8		1		94			(90	)		13
Total interest charges, net		192		126		342			(85	)		575
Postretirement and severance charges		55		102		1			–			158
Income tax expense (benefit)		239		121		(62	)		–			298
Segment profit (loss)		490		258		(225	)		–			523
Total assets		11,502		8,328		18,278			(13,673	)		24,435
Capital and investment expenditures		682		543		19			(19	)		1,225

20.   OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income and other income and expense items as discussed 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. AFUDC equity represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets. The components of other, net as shown on the accompanying Statements of Income for the years ended December 31 were as follows:

Progress Energy
(in millions)	2007		2006			2005
Other income
Nonregulated energy and delivery services income	$	36	$	41		$	32
DIG Issue C20 amortization (Note 17A)		4		5			7
Contingent value obligation unrealized gain (Note 15)		2		–			6
Gain on sale of Level 3 stock (a)		–		32			–
Investment gains		9		4			4
Income from equity investments		2		1			1
AFUDC equity		51		21			16
Reversal of indemnification liability (Note 21B)		–		29			–
Other		15		13			16
Total other income		119		146			82
Other expense
Nonregulated energy and delivery services expenses		24		27			23
Donations		22		20			18
Contingent value obligation unrealized loss (Note 15)		4		25			–
Investment losses		4		–			1
Loss from equity investments		5		3			7
Loss on debt redemption(b)		–		59			–
FERC audit settlement		–		–			7
Indemnification liability (Note 21B)		–		13			16
Other		16		15			11
Total other expense		75		162			83
Other, net – Progress Energy	$	44	$	(16	)	$	(1	)

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PEC
(in millions)	2007		2006		2005
Other income
Nonregulated energy and delivery services income	$	14	$	15	$	12
DIG Issue C20 amortization (Note 17A)		4		5		7
Investment gains		4		–		–
Income from equity investments		1		–		1
AFUDC equity		10		4		3
Reversal of indemnification liability (Note 21B)		–		29		–
Other		11		10		9
Total other income		44		63		32
Other expense
Nonregulated energy and delivery services expenses		8		7		9
Donations		9		10		8
Investment losses		3		–		–
Losses from equity investments		1		1		–
FERC audit settlement		–		–		4
Indemnification liability (Note 21B)		–		13		16
Other		7		7		10
Total other expense		28		38		47
Other, net – PEC	$	16	$	25	$	(15	)

PEF
(in millions)	2007		2006		2005
Other income
Nonregulated energy and delivery services income	$	24	$	26	$	20
Investment gains		2		2		2
AFUDC equity		41		17		13
Other		1		1		–
Total other income		68		46		35
Other expense
Nonregulated energy and delivery services expenses		16		20		14
Donations		8		10		10
Losses from equity investments		1		1		–
FERC audit settlement		–		–		3
Other		4		2		1
Total other expense		29		33		28
Other, net – PEF	$	39	$	13	$	7

(a)   Other income includes pre-tax gains of $32 million for the year ended December 31, 2006, from the sale of approximately 20 million shares of Level 3 stock received as part of the sale of our interest in PT LLC (See Note 3E). These gains are prior to the consideration of minority interest.

(b)   On November 27, 2006, Progress Energy redeemed the entire outstanding $350 million principal amount of its 6.05% Senior Notes due April 15, 2007, and the entire outstanding $400 million principal amount of its 5.85% Senior Notes due October 30, 2008. On December 6, 2006, Progress Energy repurchased, pursuant to a tender offer, $550 million, or 44.0 percent, of the aggregate principal amount of its 7.10% Senior Notes due March 1, 2011. We recognized a total pre-tax loss of $59 million in conjunction with these redemptions.

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21.   ENVIRONMENTAL MATTERS

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 always be precisely estimated.

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 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. 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 these potential claims cannot be predicted. No material claims are currently pending. A discussion of sites by legal entity follows.

We record accruals for probable and estimable costs related to environmental sites on an undiscounted basis. We measure our liability for these 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 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 table contains information about accruals for environmental remediation expenses described below. Accruals for probable and estimable costs related to various environmental sites, which were included in other liabilities and deferred credits on the Balance Sheets, at December 31 were:

(in millions)	2007		2006
PEC
MGP and other sites(a)	$	16	$	22
PEF
Remediation of distribution and substation transformers		31		43
MGP and other sites		17		18
Total PEF environmental remediation accruals(b)		48		61
Progress Energy nonregulated operations		–		3
Total Progress Energy environmental remediation accruals	$	64	$	86

(a) Expected to be paid out over one to five years.

(b) Expected to be paid out over one to fifteen years.

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PROGRESS ENERGY

In addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, our environmental sites include the following related to our nonregulated operations.

In 2001, we, through our Progress Fuels subsidiary, established an accrual to address indemnities and retained an environmental liability associated with the sale of our Inland Marine Transportation business. At December 31, 2006, the remaining accrual balance was approximately $3 million. For the year ended December 31, 2007, the accrual was reduced by approximately $3 million due to a reduction in the anticipated scope of work based on responses from regulatory agencies. Expenditures related to this liability were not material during 2007 and 2006.

On March 24, 2005, we completed the sale of our Progress Rail subsidiary. In connection with the sale, we incurred indemnity obligations related to certain pre-closing liabilities, including certain environmental matters (See discussion under Guarantees in Note 22C).

PEC

There are currently eight former MGP sites and a number of other sites associated with PEC that have required or are anticipated to require investigation and/or remediation. Three of these sites are in the long-term monitoring phase.

For the year ended December 31, 2007, including the Carolina Transformer site, the Ward Transformer site and MGP sites discussed below, PEC’s accrual was reduced by a net amount of approximately $2 million and PEC spent approximately $4 million. For the year ended December 31, 2006, PEC accrued approximately $21 million and spent approximately $6 million. In October 2006, PEC received orders from the NCUC and SCPSC to defer and amortize certain environmental remediation expenses, net of insurance proceeds (See Note 7B).

For the year ended December 31, 2006, based upon newly available data for several of PEC’s MGP sites, which had individual site remediation costs ranging from approximately $2 million to $4 million, a remediation liability of approximately $12 million was recorded for the minimum estimated total remediation cost for all of PEC’s remaining MGP sites. The maximum amount of the range for all the sites cannot be determined at this time as one of the remaining sites is significantly larger than the sites for which we have historical experience. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC and a number of other PRPs the opportunity to negotiate cleanup of the site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the site. For the year ended December 31, 2006, based upon continuing assessment work performed at the site, PEC recorded an additional $9 million accrual for its portion of the estimated remediation costs. At December 31, 2006, after cumulative expenditures for the Ward site of approximately $3 million, PEC’s recorded liability for the site was approximately $9 million. During 2007, the PRP agreement was amended to include an additional participating PRP, which reduced PEC’s allocable share, and the estimated scope of work increased. These factors resulted in a net reduction to PEC’s accrual for this site. At December 31, 2007, PEC’s recorded liability for the site was approximately $6 million. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. The outcome of this matter cannot be predicted.

The EPA has also proposed, but not yet selected, a final remedial action plan to address stream segments downstream from the Ward Transformer site. The outcome of this matter cannot be predicted.

In September 2005, the EPA advised PEC that it had been identified as a PRP at the Carolina Transformer site located in Fayetteville, N.C. The EPA offered PEC and a number of other PRPs the opportunity to share in the reimbursement to the EPA of past expenditures in addressing conditions at the site, which are currently approximately $33 million. During the year ended December 31, 2007, a settlement was reached between the PRPs and the EPA, and PEC recorded and paid an immaterial amount for its share of the settlement.

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PEF

PEF has received approval from the FPSC for recovery of the majority of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection, PEF is in the process of examining distribution transformer sites and substation sites for mineral oil-impacted soil remediation caused by equipment integrity issues. PEF has reviewed a number of distribution transformer sites and all substation sites. Based on changes to the estimated time frame for inspections of distribution transformer sites, PEF currently expects to have completed this review by the end of 2008. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC. For the year ended December 31, 2007, PEF accrued approximately $10 million due to an increase in estimated remediation costs and spent approximately $22 million related to the remediation of transformers. For the year ended December 31, 2006, PEF accrued approximately $42 million due to additional sites expected to require remediation and spent approximately $19 million related to the remediation of transformers. At December 31, 2007, PEF has recorded a regulatory asset for the probable recovery of these costs through the ECRC (See Note 7A).

The amounts for MGP and other sites, in the table above, 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 amounts include approximately $12 million in insurance claim settlement proceeds received in 2004, which are restricted for use in addressing costs associated with environmental liabilities. For the year ended December 31, 2007, PEF made no accruals and spent approximately $1 million. For the year ended December 31, 2006, PEF made no accruals and PEF’s expenditures were not material to our or PEF’s results of operations or financial condition.

B.       AIR AND WATER QUALITY

We are 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 include the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call), the Clean Smokestacks Act and mercury regulation (see “Other Matters – Environmental Matters” for discussion regarding Clean Air Mercury Rule (CAMR)). At December 31, 2007, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.567 billion, including $1.244 billion at PEC and $323 million at PEF. At December 31, 2006, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $932 million, including $904 million at PEC and $28 million at PEF.

As discussed in Note 7A, in June 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. Two of PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements, the joint owners are required to pay a portion of the costs of owning and operating these plants. PEC has determined that the most cost-effective Clean Smokestacks Act compliance strategy is to maximize the SO2 removal from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to avoid the installation of expensive emission controls on its smaller coal-fired units. In order to address the joint owner's concerns that such a compliance strategy would result in a disproportionate share of the cost of compliance for the jointly owned units, PEC entered into an agreement with the joint owner to limit its aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act to approximately $38 million. PEC recorded a related liability for the joint owner's share of estimated costs in excess of the contract amount. At December 31, 2007, and 2006, the amount of the liability was $30 million and $29 million, respectively, based upon the respective current estimates for Clean Smokestacks Act compliance. Because PEC has taken a system-wide compliance approach, its North Carolina retail ratepayers have significantly benefited from the strategy of focusing emission reduction efforts on the jointly owned units, and, therefore, PEC believes that any costs in excess of the joint owner’s share should be recovered from North Carolina retail ratepayers, consistent with other capital expenditures associated with PEC’s compliance with the Clean Smokestacks Act. In 2006, PEC notified the NCUC of its intent to record these estimated excess costs as part of the $569 million amortization required to be recorded by December 31, 2007, and accordingly, recorded the indemnification expense to Clean Smokestacks Act amortization. In a settlement agreement provisionally approved by the NCUC on December 20,

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2007, eligible compliance costs in excess of the joint owner’s share will be treated in the same manner as PEC’s Clean Smokestacks Act compliance costs in excess of the original estimated compliance costs, as ultimately approved by the NCUC (See Note 7A).

22.   COMMITMENTS AND CONTINGENCIES

A.    PURCHASE OBLIGATIONS

At December 31, 2007, the following table reflects contractual cash obligations and other commercial commitments in the respective periods in which they are due:

Progress Energy
(in millions)	2008		2009		2010		2011		2012		Thereafter
Fuel	$	2,018	$	1,745	$	1,202	$	1,001	$	675	$	5,103
Purchased power		455		422		409		443		415		3,756
Construction obligations		714		211		42		–		–		–
Other purchase obligations		94		39		32		16		16		64
Total	$	3,281	$	2,417	$	1,685	$	1,460	$	1,106	$	8,923

PEC
(in millions)	2008		2009		2010		2011		2012		Thereafter
Fuel	$	958	$	761	$	664	$	487	$	308	$	976
Purchased power		85		87		69		80		63		540
Construction obligations		84		22		–		–		–		–
Other purchase obligations		26		12		7		4		3		13
Total	$	1,153	$	882	$	740	$	571	$	374	$	1,529

PEF
(in millions)	2008		2009		2010		2011		2012		Thereafter
Fuel	$	1,060	$	984	$	538	$	514	$	367	$	4,127
Purchased power		370		335		340		363		352		3,216
Construction obligations		630		189		42		–		–		–
Other purchase obligations		56		20		19		12		12		50
Total	$	2,116	$	1,528	$	939	$	889	$	731	$	7,393

FUEL AND PURCHASED POWER

Through our subsidiaries, we have entered into various long-term contracts for coal, oil, gas and nuclear fuel. Our payments under these commitments were $2.360 billion, $1.628 billion and $1.470 billion for 2007, 2006 and 2005, respectively. PEC’s total payments under these commitments for its generating plants were $1.049 billion, $1.051 billion and $964 million in 2007, 2006 and 2005, respectively. PEF’s payments totaled $1.311 billion, $577 million and $506 million in 2007, 2006 and 2005, respectively.

Both PEC and PEF have ongoing purchased power contracts with certain cogenerators (primarily QFs) with expiration dates ranging from 2008 to 2030. These purchased power contracts generally provide for capacity and energy payments.

PEC has a long-term agreement for the purchase of power and related transmission services from Indiana Michigan Power Company’s Rockport Unit No. 2 (Rockport). The agreement provides for the purchase of 250 MW of capacity through 2009 with estimated minimum annual payments of approximately $42 million, representing capital-related capacity costs. Total purchases (including energy and transmission use charges) under the Rockport agreement amounted to $77 million, $80 million and $71 million for 2007, 2006 and 2005, respectively.

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PEC executed two long-term agreements for the purchase of power from Broad River LLC’s Broad River facility (Broad River). One agreement provides for the purchase of approximately 500 MW of capacity through 2021 with an original minimum annual payment of approximately $16 million, primarily representing capital-related capacity costs. The second agreement provided for the additional purchase of approximately 335 MW of capacity through 2022 with an original minimum annual payment of approximately $16 million representing capital-related capacity costs. Total purchases for both capacity and energy under the Broad River agreements amounted to $39 million, $40 million and $44 million in 2007, 2006 and 2005, respectively.

In 2007, PEC executed a long-term agreement for the purchase of power from Southern Power Company. The agreement provides for capacity purchases of 305 MW for 2010, 310 MW for 2011 and 150 MW annually thereafter through 2019. Estimated payments for capacity and energy under the agreement are $22 million for 2010, $33 million for 2011 and $14 million annually thereafter through 2019.

PEC has various pay-for-performance contracts with QFs for approximately 195 MW of capacity expiring at various times through 2014. Payments for both capacity and energy are contingent upon the QFs’ ability to generate. Payments made under these contracts were $95 million, $182 million and $112 million in 2007, 2006 and 2005, respectively.

PEF has long-term contracts for approximately 489 MW of purchased power with other utilities, including a contract with The Southern Company for approximately 414 MW of purchased power annually through 2016. Total purchases, for both energy and capacity, under these agreements amounted to $161 million, $162 million and $175 million for 2007, 2006 and 2005, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $70 million annually through 2011, $50 million for 2012 and $32 million annually thereafter through 2016.

PEF has ongoing purchased power contracts with certain QFs for 965 MW of capacity with expiration dates ranging from 2008 to 2030. 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 generating capacity of each of the facilities. All commitments, except one for 75 MW, have been approved by the FPSC. Total capacity purchases under these contracts amounted to $288 million, $277 million and $262 million for 2007, 2006 and 2005, respectively. At December 31, 2007, minimum expected future capacity payments under these contracts were $297 million, $263 million, $267 million, $281 million and $292 million for 2008 through 2012, respectively, and $3.053 billion 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 January 2006, PEF entered into a conditional contract with Gulfstream Natural Gas System, L.L.C. (Gulfstream) for firm pipeline transportation capacity to augment PEF’s gas supply needs for the period from September 1, 2008, through January 1, 2031. The total cost to PEF associated with this agreement is approximately $777 million. The transaction is subject to several conditions precedent, including the completion and commencement of operation of the necessary related expansions to Gulfstream’s natural gas pipeline system, and other standard closing conditions. Due to the conditions of this agreement the estimated costs associated with this agreement are not included in the contractual cash obligations table above.

In July 2006, PEF entered into a conditional contract with Devon Gas Services for the supply of natural gas to augment PEF’s gas supply needs for the period from May to September for the years 2008 through 2011. The total cost to PEF associated with this agreement is approximately $251 million. The transaction is subject to several conditions precedent, including the completion and commencement of operation of necessary related interstate pipeline expansions, and other standard closing conditions. Due to the conditions of this agreement the estimated costs associated with this agreement are not included in the contractual cash obligations table above.

In December 2006, PEF entered into a conditional contract with Cross Timbers Energy Services, Inc. for the supply of natural gas to augment PEF’s gas supply needs for the period from June 1, 2008, through May 31, 2013. The total cost to PEF associated with this agreement is approximately $1.026 billion. The transaction is subject to several conditions precedent, including the completion and commencement of operation of necessary related interstate

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natural gas pipeline system expansions, and other standard closing conditions. Due to the conditions of this agreement the estimated costs associated with this agreement are not included in the contractual cash obligations table above.

In December 2006, PEF entered into a conditional contract with Southeast Supply Header, L.L.C. (SESH) for firm pipeline transportation capacity to augment PEF’s gas supply needs for the period from June 1, 2008, through May 31, 2023. The total cost to PEF associated with this agreement is approximately $271 million. The transaction is subject to several conditions precedent, including FPSC approval, the completion and commencement of operation of the SESH pipeline project, and other standard closing conditions. Due to the conditions of this agreement the estimated costs associated with this agreement are not included in the contractual cash obligations table above.

In December 2006, PEF entered into a conditional contract with a private oil and gas company for the supply of natural gas to augment PEF’s gas supply needs for the period from June 1, 2008, through March 31, 2013. The total cost to PEF associated with this agreement is approximately $146 million. The transaction is subject to several conditions precedent, including the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions, and other standard closing conditions. Due to the conditions of this agreement the estimated costs associated with this agreement are not included in the contractual cash obligations table above.

In January and February 2007, PEF entered into conditional contracts with Chevron Natural Gas for the supply of natural gas to augment PEF’s gas supply needs for the period from June 1, 2008, to May 31, 2013. The total cost to PEF associated with these agreements is approximately $935 million. The transactions are subject to several conditions precedent, including the completion and commencement of operation of necessary related interstate pipeline expansions, and other standard closing conditions. Due to the conditions of these agreements the estimated costs associated with these agreements are not included in the contractual cash obligations table above.

CONSTRUCTION OBLIGATIONS

We have purchase obligations related to various capital construction projects. Our total payments under these contracts were $675 million, $365 million and $91 million for 2007, 2006 and 2005, respectively. PEC’s future obligations related to Clean Smokestacks Act capital projects are $84 million for 2008 and $22 million for 2009. Total payments under PEC’s contracts related to Clean Smokestacks Act projects were $208 million and $225 million for 2007 and 2006, respectively. PEC did not have any payments related to construction obligations in 2005. PEF has purchase obligations related to various capital projects related to new generation and Florida CAIR. Total payments under PEF’s contracts were $467 million, $140 million and $91 million for 2007, 2006 and 2005, respectively. PEF’s future obligations under these contracts are $631 million, $188 million and $42 million for 2008 through 2010, respectively.

OTHER PURCHASE OBLIGATIONS

We have entered into various other contractual obligations primarily related to service contracts for operational services entered into by PESC, parts and services contracts, and a PEF service agreement related to the Hines Energy Complex. Our payments under these agreements were $97 million, $122 million and $100 million for 2007, 2006 and 2005, respectively.

We have entered into various other contractual obligations primarily related to capacity and service contracts for operational services associated with discontinued CCO operations. Total payments under these contracts were $8 million, $18 million and $17 million for 2007, 2006 and 2005, respectively. Estimated future payments under these contracts of $6 million are not reflected in the contractual cash obligations table above. Included in these contracts are purchase obligations with a counterparty for pipeline capacity through 2009.

PEC has various purchase obligations for emission obligations, limestone supply and the purchase of capital parts. Total purchases under these contracts were $21 million, $2 million and $10 million for 2007, 2006 and 2005, respectively. Future obligations under these contracts are $22 million for 2008, $4 million each for 2009 and 2010, and $3 million each for 2011 and 2012 and $13 million thereafter.

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PEC has various purchase obligations related to reactor vessel head replacements, power uprates and spent fuel storage. Total purchases under these contracts were $8 million for 2006 and $13 million for 2005, with no purchases in 2007. Future obligations under these contracts are for spent fuel storage and total $5 million, $8 million, $3 million and $1 million for 2008 through 2011, respectively.

PEF has long-term service agreements for the Hines Energy Complex. Total payments under these contracts were $11 million, $12 million and $8 million for 2007, 2006 and 2005, respectively. Future obligations under these contracts are $21 million, $14 million, $19 million, $12 million and $12 million for 2008 through 2012, respectively, with approximately $50 million payable thereafter.

PEF has various purchase obligations and contractual commitments related to the purchase and replacement of machinery. Total payments under these contracts were $22 million, $21 million and $34 million for 2007, 2006 and 2005, respectively. Future obligations under these contracts are $8 million and $6 million for 2008 and 2009, respectively.

B.    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 $40 million, $42 million and $38 million for 2007, 2006 and 2005, respectively. Our purchased power expense under agreements classified as operating leases was approximately $69 million, $60 million and $14 million in 2007, 2006 and 2005, respectively.

PEC’s rent expense under operating leases totaled $23 million, $25 million and $24 million during 2007, 2006 and 2005, respectively. These amounts include rent expense allocated from PESC to PEC of $6 million, $8 million and $7 million for 2007, 2006 and 2005, respectively. Purchased power expense under agreements classified as operating leases was approximately $10 million, $10 million and $11 million in 2007, 2006 and 2005, respectively.

PEF’s rent expense under operating leases totaled $15 million, $16 million and $11 million during 2007, 2006 and 2005, respectively. These amounts include rent expense allocated from PESC to PEF of $6 million for 2007 and $7 million each for 2006 and 2005. Purchased power expense under agreements classified as operating leases was approximately $59 million, $49 million and $3 million in 2007, 2006 and 2005, respectively.

Assets recorded under capital leases at December 31 consisted of:

	Progress Energy						PEC						PEF
(in millions)	2007			2006			2007			2006			2007			2006
Buildings	$	267		$	84		$	30		$	30		$	237		$	54
Less:  Accumulated amortization		(20	)		(12	)		(13	)		(12	)		(7	)		–
Total	$	247		$	72		$	17		$	18		$	230		$	54

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At December 31, 2007, 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
2008	$	28		$	62	$	2		$	35	$	26		$	22
2009		29			41		3			30		26			6
2010		28			25		2			17		26			4
2011		28			20		2			13		26			4
2012		28			38		2			13		26			23
Thereafter		308			554		10			127		298			424
Minimum annual payments		449		$	740		21		$	235		428		$	483
Less amount representing imputed interest		(202	)				(4	)				(198	)
Present value of net minimum lease payments under capital leases	$	247				$	17				$	230

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 2007, PEF entered into a purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $28 million from 2012 through 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 annual payments of approximately $5 million from 2007 through 2026 for a total of approximately $103 million. The lease term provides for no payments during the last 20 years of the lease, during which period approximately $51 million of rental expense will be recorded in the Statements of Income.

In 2006, PEF extended the terms of an agreement for purchased power, which is classified as a capital lease, for an additional 10 years. The agreement calls for minimum annual payments of approximately $21 million from 2007 through 2024 for a total of approximately $348 million. Due to the conditions of the agreement, the capital lease was not recorded on our or PEF’s Balance Sheets until 2007.

In 2006, PEF entered into an agreement for purchased power, which is classified as a capital lease. Due to the conditions of the agreement, the capital lease will not be recorded on PEF’s Balance Sheet until approximately 2011. Therefore, this capital lease is not included in the table above. The agreement calls for minimum annual payments of approximately $8 million from 2012 through 2036 for a total of approximately $208 million.

Excluding the Utilities, we are also a lessor of land, buildings and other types of properties we own under operating leases with various terms and expiration dates. The leased buildings are depreciated under the same terms as other buildings included in diversified business property. Minimum rentals receivable under noncancelable leases are approximately $8 million, $7 million, $5 million, $4 million and $2 million for 2008 through 2012, respectively. Rents received under these operating leases totaled $8 million, $9 million and $8 million for 2007, 2006 and 2005, respectively.

The Utilities are lessors of electric poles, streetlights and other facilities. PEC’s minimum rentals receivable under noncancelable leases are $10 million for 2008 and none thereafter. PEC’s rents received are contingent upon usage and totaled $33 million for 2007 and $31 million each for 2006 and 2005. PEF’s rents received are based on a fixed minimum rental where price varies by type of equipment or contingent usage and totaled $78 million, $72 million and $63 million for 2007, 2006 and 2005, respectively. PEF’s minimum rentals receivable under noncancelable leases are not material for 2008 and thereafter.

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C.    GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). Such agreements include guarantees, standby letters of credit and surety bonds. At December 31, 2007, 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, 2007, 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, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations, which are within the scope of FIN 45. Related to the sales of businesses, the latest notice period extends until 2012 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. In 2005, PEC entered into an agreement with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 21B). PEC’s maximum exposure cannot be determined. At December 31, 2007, the estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $427 million, including $32 million at PEF. At December 31, 2007 and 2006, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $80 million and $60 million, respectively. These amounts include $30 million and $29 million, respectively, for PEC and $8 million for PEF at December 31, 2007 and 2006. As current estimates change, it is possible that 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 of guarantees of certain payments of two wholly owned indirect subsidiaries (See Note 23).

D.    OTHER COMMITMENTS AND CONTINGENCIES

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. Our damages due to the DOE’s breach will be significant, but have yet to be determined. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

The DOE and the Utilities agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called “rate issues,” or the minimum mandatory schedule for the acceptance of spent nuclear fuel and high-level radioactive waste by which the government was contractually obligated to accept contract holders’ spent nuclear fuel and/or high-level waste, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been presented in the trials or appeals during 2006 and 2007. Resolution of these issues in other cases could facilitate agreements by the parties in the Utilities’ lawsuit, or at a minimum, inform the court of decisions reached by other courts if they remain contested and require resolution in this case. In July 2005, the parties jointly requested a continuance of the stay through December 15, 2005, which the trial court granted.

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Subsequently, the trial court continued the stay until March 17, 2006. The trial court lifted the stay on March 22, 2006, and discovery commenced. The trial court issued a scheduling order on March 23, 2006, and the case went to trial beginning November 5, 2007. Closing arguments are anticipated in the second quarter of 2008 with a ruling expected later in 2008. The Utilities cannot predict the outcome of this matter. In the event that the Utilities recover damages in this matter, such recovery is not expected to have a material impact on the Utilities’ results of operations given the anticipated regulatory and accounting treatment.

In July 2002, Congress passed an override resolution to Nevada’s veto of the DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.; and the city of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. These same parties also challenged the EPA’s radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. In August 2005, the EPA issued new proposed standards. The proposed standards include a 1,000,000-year compliance period in the radiation protection standard. Comments were due November 21, 2005, and are being reviewed by the EPA. The DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004. However, in November 2004, the DOE announced it would not submit the license application until mid-2005 or later. The DOE did not submit the license application in 2005 and subsequently reported that the license application would be submitted by June 2008 if full funding was obtained for the project. The DOE requested $545 million for fiscal year 2007 and received $445 million. The DOE requested $495 million for fiscal year 2008. However, Congress passed an appropriations bill which allocates $390 million in fiscal year 2008 for DOE’s Yucca Mountain repository program. As a result of the fiscal year budget reductions, the schedule for submitting the license application is being re-evaluated by the DOE. The impact to the Yucca Mountain repository program cannot be predicted at this time.

On October 19, 2007, the DOE certified the regulatory compliance of the document database that will be used by all parties involved in the federal licensing process for the Yucca Mountain facility. The NRC did not uphold the DOE’s prior certification in 2004 in response to challenges from the state of Nevada. The state again is expected to challenge the DOE’s certification process. The DOE has stated that if legislative changes requested by the Bush administration are enacted, the repository may be able to accept spent nuclear fuel starting in 2017, but 2020 is more probable due to anticipated litigation by the state of Nevada. The Utilities cannot predict the outcome of this matter.

With certain modifications and additional approvals by the NRC, including the installation 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 extensions, for their nuclear generating units. Harris has sufficient storage capacity in its spent fuel pools through the expiration of its operating license, including any license extensions.

SYNTHETIC FUELS MATTERS

A number of our subsidiaries and affiliates are parties to two lawsuits arising out of an Asset Purchase Agreement dated as of October 19, 1999, by and among U.S. Global, LLC (Global); the Earthco synthetic fuels facilities (Earthco); certain affiliates of Earthco; EFC Synfuel LLC (which is 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 (currently named Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase Agreement). Global has asserted (1) that pursuant to the Asset Purchase Agreement, it is entitled to an interest in two synthetic fuels facilities currently owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities, (2) that it is entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities and (3) a number of tort claims related to the contracts.

The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al. (the Florida Global Case), asserts the above claims in a case filed in the Circuit Court for Broward County, Fla., in March 2003, and requests an unspecified amount of compensatory damages, as well as declaratory relief. The Progress Affiliates have answered the Complaint by generally denying all of Global’s substantive allegations and asserting numerous substantial affirmative defenses.

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The case is at issue, but neither party has requested a trial. The parties are currently engaged in discovery in the Florida Global Case.

The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), was filed by the Progress Affiliates in the Superior Court for Wake County, N.C., seeking 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. Since that time, the parties have been engaged in discovery in the Florida Global Case.

In December 2006, we reached agreement with Global to settle an additional claim in the suit related to amounts due to Global that were placed in escrow pursuant to a defined tax event. Upon the successful resolution of the IRS audit of the Earthco synthetic fuels facilities in 2006, and pursuant to a settlement agreement, the escrow totaling $42 million as of December 31, 2006, was paid to Global in January 2007.

In January 2008, Global agreed to simplify the Florida action by dismissing the tort claims. The suit continues now under contract theories alone. 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 in accordance with SFAS No. 5 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.

23.   CONDENSED CONSOLIDATING STATEMENTS

As previously disclosed in the Progress Registrant's Form 10-Q for the quarter ended March 31, 2008, under Item 5, Other Information, certain affiliate revenues of discontinued operations of our coal terminals and docks were incorrectly included in continuing operations. This resulted in misclassifications between income from continuing operations and discontinued operations, net of tax in the Subsidiary Guarantor column in the condensed consolidating Statements of Income for the years ended December 31, 2007, 2006 and 2005. There were equal and offsetting errors in the Other column, with no impact to the Parent or Progress Energy, Inc. columns. This correction is limited to the Subsidiary Guarantor and the Other columns in the condensed consolidating Statements of Income in Note 23 and does not affect Progress Energy’s Consolidated Statements of Income, Consolidated Balance Sheets or Consolidated Statements of Cash Flows.

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The schedules below present the effect of our previously disclosed correction of an error in the presentation of the condensed consolidating Statements of Income for the fiscal years ended December 31, 2007, 2006 and 2005:

Condensed Consolidating Statement of Income Year ended December 31, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
As originally reported
Affiliate revenues	$	–		$	89		$	(89	)	$	–
Total operating revenues		–			4,857			4,296			9,153
Operating (loss) income		(10	)		679			877			1,546
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(186	)		528			694			1,036
Income (loss) from continuing operations		489			402			(198	)		693
Discontinued operations, net of tax		15			(59	)		(145	)		(189	)
As restated
Affiliate revenues	$	–		$	–		$	–		$	–
Total operating revenues		–			4,768			4,385			9,153
Operating (loss) income		(10	)		590			966			1,546
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(186	)		439			783			1,036
Income (loss) from continuing operations		489			313			(109	)		693
Discontinued operations, net of tax		15			30			(234	)		(189	)

Condensed Consolidating Statement of Income Year ended December 31, 2006
(in millions)	Parent			Subsidiary Guarantor		Other			Progress Energy, Inc.
As originally reported
Affiliate revenues	$	–		$	41	$	(41	)	$	–
Total operating revenues		–			4,678		4,046			8,724
Operating (loss) income		(14	)		657		844			1,487
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(323	)		530		699			906
Income (loss) from continuing operations		579			340		(368	)		551
Discontinued operations, net of tax		(8	)		359		(331	)		20
As restated
Affiliate revenues	$	–		$	–	$	–		$	–
Total operating revenues		–			4,637		4,087			8,724
Operating (loss) income		(14	)		616		885			1,487
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(323	)		489		740			906
Income (loss) from continuing operations		579			299		(327	)		551
Discontinued operations, net of tax		(8	)		400		(372	)		20

121

Condensed Consolidating Statement of Income Year ended December 31, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
As originally reported
Affiliate revenues	$	–		$	188		$	(188	)	$	–
Total operating revenues		–			4,144			3,804			7,948
Operating (loss) income		(16	)		664			740			1,388
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(255	)		500			580			825
Income (loss) from continuing operations		693			400			(570	)		523
Discontinued operations, net of tax		4			(26	)		195			173
As restated
Affiliate revenues	$	–		$	–		$	–		$	–
Total operating revenues		–			3,956			3,992			7,948
Operating (loss) income		(16	)		476			928			1,388
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(255	)		312			768			825
Income (loss) from continuing operations		693			212			(382	)		523
Discontinued operations, net of tax		4			162			7			173

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.  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 (the Notes Guarantee). In addition, Florida Progress guaranteed the payment of all distributions related to the $300 million 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 Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by Florida Progress of the Trust’s obligations under the Preferred Securities. The Preferred Securities and 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 yearly interest expense is $21 million and is reflected in the Consolidated Statements of Income.

122

We have guaranteed the payment of all distributions related to the Trust's Preferred Securities. As of December 31, 2007, 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 12B, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a special-purpose entity and in accordance with the provisions of FIN 46R, we deconsolidated the Trust on December 31, 2003. The deconsolidation was not material to our financial statements. 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 Other column includes the consolidated financial results of all other non-guarantor subsidiaries, primarily our wholly owned subsidiary PEC, and elimination entries for all intercompany transactions. Financial statements for PEC and PEF are separately presented elsewhere in this Exhibit 99 to the Form 8-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. The accompanying condensed consolidating financial statements have been restated for all periods presented to reflect the operations of Terminals and the synthetic fuels businesses as discontinued operations as described in Note 3B.

123

Condensed Consolidating Statement of Income Year ended December 31, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	4,768		$	4,385		$	9,153
Operating expenses
Fuel used in electric generation		–			1,764			1,381			3,145
Purchased power		–			882			302			1,184
Operation and maintenance		10			834			998			1,842
Depreciation and amortization		–			369			536			905
Taxes other than on income		–			309			192			501
Other		–			20			10			30
Total operating expenses		10			4,178			3,419			7,607
Operating (loss) income		(10	)		590			966			1,546
Other income, net		27			47			4			78
Interest charges, net		203			198			187			588
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(186	)		439			783			1,036
Income tax (benefit) expense		(79	)		117			296			334
Equity in earnings of consolidated subsidiaries		596			–			(596	)		–
Minority interest in subsidiaries’ income, net of tax		–			(9	)		–			(9	)
Income (loss) from continuing operations		489			313			(109	)		693
Discontinued operations, net of tax		15			30			(234	)		(189	)
Net income (loss)	$	504		$	343		$	(343	)	$	504

124

Condensed Consolidating Statement of Income Year ended December 31, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	4,637		$	4,087		$	8,724
Operating expenses
Fuel used in electric generation		–			1,835			1,173			3,008
Purchased power		–			766			334			1,100
Operation and maintenance		14			684			885			1,583
Depreciation and amortization		–			406			605			1,011
Taxes other than on income		–			309			191			500
Other		–			21			14			35
Total operating expenses		14			4,021			3,202			7,237
Operating (loss) income		(14	)		616			885			1,487
Other (expense) income, net		(33	)		55			21			43
Interest charges, net		276			182			166			624
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(323	)		489			740			906
Income tax (benefit) expense		(123	)		174			288			339
Equity in earnings of consolidated subsidiaries		779			–			(779	)		–
Minority interest in subsidiaries’ income, net of tax		–			(16	)		–			(16	)
Income (loss) from continuing operations		579			299			(327	)		551
Discontinued operations, net of tax		(8	)		400			(372	)		20
Net income (loss)	$	571		$	699		$	(699	)	$	571

125

Condensed Consolidating Statement of Income Year ended December 31, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	3,956		$	3,992		$	7,948
Operating expenses
Fuel used in electric generation		–			1,323			1,036			2,359
Purchased power		–			694			354			1,048
Operation and maintenance		12			852			906			1,770
Depreciation and amortization		–			337			589			926
Taxes other than on income		4			279			177			460
Other		–			(5	)		2			(3	)
Total operating expenses		16			3,480			3,064			6,560
Operating (loss) income		(16	)		476			928			1,388
Other income (expense), net		66			(1	)		(53	)		12
Interest charges, net		305			163			107			575
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(255	)		312			768			825
Income tax (benefit) expense		(64	)		96			266			298
Equity in earnings of consolidated subsidiaries		884			–			(884	)		–
Minority interest in subsidiaries’ income, net of tax		–			(4	)		–			(4	)
Income (loss) from continuing operations		693			212			(382	)		523
Discontinued operations, net of tax		4			162			7			173
Cumulative effect of change in accounting principle, net of tax		–			–			1			1
Net income (loss)	$	697		$	374		$	(374	)	$	697

126

Condensed Consolidating Balance Sheet December 31, 2007
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	7,600	$	9,005		$	16,605
Current assets
Cash and cash equivalents		185		43		27			255
Short-term investments		–		–		1			1
Notes receivable from affiliated companies		157		149		(306	)		–
Deferred fuel cost		–		6		148			154
Assets to be divested		–		48		4			52
Prepayments and other current assets		21		1,246		1,100			2,367
Total current assets		363		1,492		974			2,829
Deferred debits and other assets
Investment in consolidated subsidiaries		10,969		–		(10,969	)		–
Goodwill		–		1		3,654			3,655
Other assets and deferred debits		149		1,575		1,552			3,276
Total deferred debits and other assets		11,118		1,576		(5,763	)		6,931
Total assets	$	11,481	$	10,668	$	4,216		$	26,365
CAPITALIZATION AND LIABILITIES
Common stock equity	$	8,422	$	3,052	$	(3,052	)	$	8,422
Preferred stock of subsidiaries –not subject to mandatory redemption		–		34		59			93
Minority interest		–		81		3			84
Long-term debt, affiliate		–		309		(38	)		271
Long-term debt, net		2,597		2,686		3,183			8,466
Total capitalization		11,019		6,162		155			17,336
Current liabilities
Current portion of long-term debt		–		577		300			877
Short-term debt		201		–		–			201
Notes payable to affiliated companies		–		227		(227	)		–
Regulatory liabilities		–		173		–			173
Liabilities to be divested		–		8		–			8
Other current liabilities		215		1,064		764			2,043
Total current liabilities		416		2,049		837			3,302
Deferred credits and other liabilities
Noncurrent income tax liabilities		–		59		302			361
Regulatory liabilities		–		1,330		1,224			2,554
Accrued pension and other benefits		12		347		404			763
Capital lease obligations		–		224		15			239
Other liabilities and deferred credits		34		497		1,279			1,810
Total deferred credits and other liabilities		46		2,457		3,224			5,727
Total capitalization and liabilities	$	11,481	$	10,668	$	4,216		$	26,365

127

Condensed Consolidating Balance Sheet December 31, 2006
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	6,337	$	8,908		$	15,245
Current assets
Cash and cash equivalents		153		40		72			265
Short-term investments		21		–		50			71
Notes receivable from affiliated companies		58		37		(95	)		–
Deferred fuel cost		–		–		196			196
Assets to be divested		–		121		936			1,057
Prepayments and other current assets		27		1,078		1,035			2,140
Total current assets		259		1,276		2,194			3,729
Deferred debits and other assets
Investment in consolidated subsidiaries		10,740		–		(10,740	)		–
Goodwill		–		1		3,654			3,655
Other assets and deferred debits		126		1,593		1,511			3,230
Total deferred debits and other assets		10,866		1,594		(5,575	)		6,885
Total assets	$	11,125	$	9,207	$	5,527		$	25,859
CAPITALIZATION AND LIABILITIES
Common stock equity	$	8,286	$	2,708	$	(2,708	)	$	8,286
Preferred stock of subsidiaries – not subject to mandatory redemption		–		34		59			93
Minority interest		–		6		4			10
Long-term debt, affiliate		–		309		(38	)		271
Long-term debt, net		2,582		2,512		3,470			8,564
Total capitalization		10,868		5,569		787			17,224
Current liabilities
Current portion of long-term debt		–		124		200			324
Notes payable to affiliated companies		–		77		(77	)		–
Liabilities to be divested		–		72		267			339
Other current liabilities		210		1,243		819			2,272
Total current liabilities		210		1,516		1,209			2,935
Deferred credits and other liabilities
Noncurrent income tax liabilities		–		61		251			312
Regulatory liabilities		–		1,110		1,453			2,563
Accrued pension and other benefits		14		377		566			957
Other liabilities and deferred credits		33		574		1,261			1,868
Total deferred credits and other liabilities		47		2,122		3,531			5,700
Total capitalization and liabilities	$	11,125	$	9,207	$	5,527		$	25,859

128

Condensed Consolidating Statement of Cash Flows Year ended December 31, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	76		$	489		$	687		$	1,252
Investing activities
Gross property additions		–			(1,218	)		(755	)		(1,973	)
Nuclear fuel additions		–			(44	)		(184	)		(228	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			51			624			675
Purchases of available-for-sale securities and other investments		–			(640	)		(773	)		(1,413	)
Proceeds from sales of available-for-sale securities and other investments		21			640			791			1,452
Changes in advances to affiliates		(99	)		(112	)		211			–
Return of investment in consolidated subsidiary		340			–			(340	)		–
Other investing activities		(31	)		32			29			30
Net cash provided (used) by investing activities		231			(1,291	)		(397	)		(1,457	)
Financing activities
Issuance of common stock		151			–			–			151
Dividends paid on common stock		(627	)		–			–			(627	)
Dividends paid to parent		–			(10	)		10			–
Proceeds from issuance of short-term debt with original maturities greater than 90 days		176			–			–			176
Net increase in short-term debt		25			–			–			25
Proceeds from issuance of long-term debt, net		–			739			–			739
Retirement of long-term debt		–			(124	)		(200	)		(324	)
Changes in advances from affiliates		–			151			(151	)		–
Other financing activities		–			49			6			55
Net cash (used) provided by financing activities		(275	)		805			(335	)		195
Net increase (decrease) in cash and cash equivalents		32			3			(45	)		(10	)
Cash and cash equivalents at beginning of year		153			40			72			265
Cash and cash equivalents at end of year	$	185		$	43		$	27		$	255

129

Condensed Consolidating Statement of Cash Flows Year ended December 31, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided (used) by operating activities	$	1,295		$	1,110		$	(404	)	$	2,001
Investing activities
Gross property additions		–			(865	)		(707	)		(1,572	)
Nuclear fuel additions		–			(12	)		(102	)		(114	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			1,242			415			1,657
Purchases of available-for-sale securities and other investments		(919	)		(625	)		(908	)		(2,452	)
Proceeds from sales of available-for-sale securities and other investments		898			724			1,009			2,631
Changes in advances to affiliates		409			(39	)		(370	)		–
Proceeds from repayment of long-term affiliate debt		131			–			(131	)		–
Return of investment in consolidated subsidiaries		287			–			(287	)		–
Other investing activities		(63	)		(6	)		46			(23	)
Net cash provided (used) by investing activities		743			419			(1,035	)		127
Financing activities
Issuance of common stock		185			–			–			185
Dividends paid on common stock		(607	)		–			–			(607	)
Dividends paid to parent		–			(1,135	)		1,135			–
Net decrease in short-term debt		–			(102	)		(73	)		(175	)
Proceeds from issuance of long-term debt, net		397			–			–			397
Retirement of long-term debt		(2,091	)		(109	)		–			(2,200	)
Retirement of long-term affiliate debt		–			(131	)		131			–
Changes in advances from affiliates		–			(243	)		243			–
Other financing activities		(8	)		(8	)		(52	)		(68	)
Net cash (used) provided by financing activities		(2,124	)		(1,728	)		1,384			(2,468	)
Net decrease in cash and cash equivalents		(86	)		(199	)		(55	)		(340	)
Cash and cash equivalents at beginning of year		239			239			127			605
Cash and cash equivalents at end of year	$	153		$	40		$	72		$	265

130

Condensed Consolidating Statement of Cash Flows Year ended December 31, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	257		$	509		$	701		$	1,467
Investing activities
Gross property additions		–			(714	)		(599	)		(1,313	)
Nuclear fuel additions		–			(47	)		(79	)		(126	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			462			13			475
Purchases of available-for-sale securities and other investments		(1,702	)		(405	)		(1,878	)		(3,985	)
Proceeds from sales of available-for-sale securities and other investments		1,702			405			1,738			3,845
Changes in advances to affiliates		333			5			(338	)		–
Proceeds from repayment of long-term affiliate debt		369			–			(369	)		–
Other investing activities		(12	)		(26	)		(2	)		(40	)
Net cash provided (used) by investing activities		690			(320	)		(1,514	)		(1,144	)
Financing activities
Issuance of common stock		208			–			–			208
Dividends paid on common stock		(582	)		–			–			(582	)
Dividends paid to parent		–			(2	)		2			–
Net decrease in short-term debt		(170	)		(191	)		(148	)		(509	)
Proceeds from issuance of long-term debt, net		–			744			898			1,642
Retirement of long-term debt		(160	)		(104	)		(300	)		(564	)
Retirement of long-term affiliate debt		–			(369	)		369			–
Changes in advances from affiliates		–			(101	)		101			–
Other financing activities		(9	)		50			(9	)		32
Net cash (used) provided by financing activities		(713	)		27			913			227
Net increase in cash and cash equivalents		234			216			100			550
Cash and cash equivalents at beginning of year		5			23			27			55
Cash and cash equivalents at end of year	$	239		$	239		$	127		$	605

131

24.   QUARTERLY FINANCIAL DATA (UNAUDITED)

As previously disclosed in the Progress Registrant’s Form 10-Q for the quarter ended March 31, 2008, under Item 5. Other Information, the Progress Energy quarterly data reported for 2007 and 2006 contained misclassifications between income from continuing operations and income from discontinued operations relating to the impacts of quarterly tax levelization adjustments. In accordance with the provisions of Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. The tax levelization expense or benefit recorded during the interim period, which has no impact on total year net income, maintains an effective tax rate consistent with the estimated annual effective tax rate. When the synthetic fuels businesses were reclassified to discontinued operations in the fourth quarter of 2007, the impacts of the quarterly tax levelization adjustments associated with the synthetic fuels tax credits were not also reclassified to discontinued operations. This correction is limited to amounts reported for Progress Energy only in Note 24 in the 2007 Form 10-K and does not affect the information presented in Note 24 for PEC and PEF or our previously filed quarterly reports on Form 10-Q. This correction does not affect our Consolidated Statements of Income for 2007 or 2006, as the quarterly tax levelization adjustments net to zero on an annual basis.

132

The schedules below present the effect of our previously disclosed correction of an error in the presentation of the quarterly financial data for the years ended December 31, 2007 and 2006.

Progress Energy
(in millions except per share data)	First		Second		Third		Fourth
2007
As originally reported
Income from continuing operations	$	159	$	106	$	327	$	101
Common stock data
Basic earnings per common share
Income from continuing operations		0.63		0.42		1.27		0.39
Diluted earnings per common share
Income from continuing operations		0.62		0.41		1.27		0.39
As restated
Income from continuing operations		149		138		311		95
Common stock data
Basic earnings per common share
Income from continuing operations		0.59		0.54		1.21		0.37
Diluted earnings per common share
Income from continuing operations		0.59		0.54		1.21		0.37

2006
As originally reported
Income from continuing operations	$	67	$	110	$	268	$	106
Common stock data
Basic earnings per common share
Income from continuing operations before cumulative effect of change in accounting principle		0.27		0.44		1.07		0.42
Diluted earnings per common share
Income from continuing operations before cumulative effect of change in accounting principle		0.27		0.44		1.07		0.42
As restated
Income from continuing operations		85		112		246		108
Common stock data
Basic earnings per common share
Income from continuing operations		0.34		0.45		0.98		0.43
Diluted earnings per common share
Income from continuing operations		0.34		0.45		0.98		0.43

133

Summarized quarterly financial data was as follows:

Progress Energy
(in millions except per share data)	First (a)		Second (a)			Third (a)		Fourth (a)
2007
Operating revenues	$	2,072	$	2,129		$	2,750	$	2,202
Operating income		351		301			610		284
Income from continuing operations		149		138			311		95
Net income (loss)		275		(193	)		319		103
Common stock data
Basic earnings per common share
Income from continuing operations		0.59		0.54			1.21		0.37
Net income (loss)		1.08		(0.75	)		1.24		0.40
Diluted earnings per common share
Income from continuing operations		0.59		0.54			1.21		0.37
Net income (loss)		1.08		(0.75	)		1.24		0.40
Dividends declared per common share		0.610		0.610			0.610		0.615
Market price per share  – High		51.60		52.75			49.48		50.25
– Low		47.05		45.15			43.12		44.75
2006
Operating revenues	$	1,985	$	2,083		$	2,599	$	2,057
Operating income		295		332			570		290
Income from continuing operations		85		112			246		108
Net income (loss)		45		(47	)		319		254
Common stock data
Basic earnings per common share
Income from continuing operations before cumulative effect of change in accounting principle		0.34		0.45			0.98		0.43
Net income (loss)		0.18		(0.19	)		1.27		1.01
Diluted earnings per common share
Income from continuing operations before cumulative effect of change in accounting principle		0.34		0.45			0.98		0.43
Net income (loss)		0.18		(0.19	)		1.27		1.01
Dividends declared per common share		0.605		0.605			0.605		0.610
Market price per share – High		45.31		45.16			46.22		49.55
– Low		42.54		40.27			42.05		44.40
(a) Operating results have been restated for discontinued operations.

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.

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PEC 

Summarized quarterly financial data was as follows:

(in millions)	First		Second		Third		Fourth
2007
Operating revenues	$	1,058	$	996	$	1,286	$	1,045
Operating income		235		180		375		179
Net income		124		88		204		85
2006
Operating revenues	$	978	$	936	$	1,200	$	972
Operating income		189		174		346		178
Net income		86		76		189		106

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.

PEF

Summarized quarterly financial data was as follows:

(in millions)	First		Second		Third		Fourth
2007
Operating revenues	$	1,011	$	1,129	$	1,456	$	1,153
Operating income		117		125		235		109
Net income		61		68		138		50
2006
Operating revenues	$	1,007	$	1,147	$	1,399	$	1,086
Operating income		117		167		237		122
Net income		53		87		125		63

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.

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PROGRESS ENERGY, INC.
Schedule II – Valuation and Qualifying Accounts
For the Years Ended
(in millions)
	Balance at	Additions			Balance at
	Beginning	Charged to	Other		End of
Description	of Period	Expenses	Additions	Deductions (a)	Period

Valuation and qualifying accounts deducted in the balance sheet from the related assets:
DECEMBER 31, 2007
Uncollectible accounts	$	28	$	26	$	(1	)	$	(24	)	$	29
Fossil fuel plants dismantlement reserve		145		1		–			(2	)		144
Nuclear refueling outage reserve		16		15		–			(29	)		2
DECEMBER 31, 2006
Uncollectible accounts	$	19	$	29	$	–		$	(20	)	$	28
Fossil fuel plants dismantlement reserve		145		1		–			(1	)		145
Nuclear refueling outage reserve		2		14		–			–			16
DECEMBER 31, 2005
Uncollectible accounts	$	22	$	16	$	–		$	(19	)	$	19
Fossil fuel plants dismantlement reserve		144		1		–			–			145
Nuclear refueling outage reserve		12		11		–			(21	) (b)		2
(a)  Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for uncollectible accounts, such deductions are reduced  by recoveries of amounts previously written off.
(b)  Represents payments of actual expenditures related to the outages.

136

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
Schedule II – Valuation and Qualifying Accounts
For the Years Ended
(in millions)
	Balance at		Additions							Balance at
	Beginning		Charged to		Other					End of
Description	of Period		Expense		Additions		Deductions (a)			Period
Valuation and qualifying accounts deducted in the balance sheet from the related assets:
DECEMBER 31, 2007
Uncollectible accounts	$	5	$	10	$	2	$	(11	)	$	6
DECEMBER 31, 2006
Uncollectible accounts	$	4	$	9	$	–	$	(8	)	$	5
DECEMBER 31, 2005
Uncollectible accounts	$	10	$	5	$	–	$	(11	)	$	4
(a)  Deductions from provisions represent losses or expenses for which the respective provisions were created. Such deductions are reduced by recoveries of amounts previously written off.

137

FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
Schedule II – Valuation and Qualifying Accounts
For the Years Ended
(in millions)
	Balance at		Additions							Balance at
	Beginning		Charged to		Other					End of
Description	Of Period		Expense		Additions		Deductions (a)			Period
Valuation and qualifying accounts deducted in the balance sheet from the related assets:
DECEMBER 31, 2007
Uncollectible accounts	$	8	$	14	$	1	$	(13	)	$	10
Fossil fuel plants dismantlement reserve		145		1		–		(2	)		144
Nuclear refueling outage reserve		16		15		–		(29	)		2
DECEMBER 31, 2006
Uncollectible accounts	$	6	$	14	$	–	$	(12	)	$	8
Fossil fuel plants dismantlement reserve		145		1		–		(1	)		145
Nuclear refueling outage reserve		2		14		–		–			16
DECEMBER 31, 2005
Uncollectible accounts	$	2	$	10	$	–	$	(6	)	$	6
Fossil fuel plants dismantlement reserve		144		1		–		–			145
Nuclear refueling outage reserve		12		11		–		(21	) (b)		2
(a)  Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for uncollectible accounts, such deductions are reduced by recoveries of amounts previously written off.
(b)  Represents payments of actual expenditures related to the outages.

138

ITEM 9A.                      CONTROLS AND PROCEDURES

PROGRESS ENERGY, INC.

DISCLOSURE CONTROLS AND PROCEDURES

Pursuant to the Securities Exchange Act of 1934, we carried out an evaluation, with the participation of our management, including our 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 required to be disclosed by us 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 our management, including our 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, 2007. 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 Committee of the board of directors.

Based on our assessment, management determined that, at December 31, 2007, 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, 2007, as stated in their report which is included below.

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, 2007, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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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. (the Company), as of December 31, 2007 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 at December 31, 2007,  based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007, of the Company and our report dated February 28, 2008 (November 6, 2008 as to the effects of the retrospective implementation of Financial Accounting Standards Board Staff Position FIN 39-1 as described in Note 2 and the restatement as described in Note 23), expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph concerning the retrospective adoption of a new accounting principle in 2008 and the adoption of new accounting principles in 2007 and 2006.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2008

140

ITEM 9A(T).  CONTROLS AND PROCEDURES

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.

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 PEC’s internal control over financial reporting at December 31, 2007. 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, 2007, PEC maintained effective internal control over financial reporting.

This annual report does not include an attestation report of PEC’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PEC’s registered public accounting firm pursuant to the temporary rules of the SEC that permit PEC to provide only management’s report in this annual report.

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, 2007 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

141

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.

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 PEF’s internal control over financial reporting at December 31, 2007. 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, 2007, PEF maintained effective internal control over financial reporting.

This annual report does not include an attestation report of PEF’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PEF’s registered public accounting firm pursuant to the temporary rules of the SEC that permit PEF to provide only management’s report in this annual report.

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, 2007 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

142

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:

 See Item 8 –Financial Statements and Supplementary Data

143