10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2006

OR

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

For the transition period from to

Commission File Number	Exact name of registrants as specified in their charters, state of incorporation, address of principal executive offices, and telephone number	I.R.S. Employer Identification Number
1-15929	Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina	56-2155481
1-3382	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina	56-0165465
1-3274	Florida Power Corporation d/b/a Progress Energy Florida, Inc. 299 First Avenue North St. Petersburg, Florida 33701 Telephone: (727) 820-5151 State of Incorporation: Florida	59-0247770

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

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

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

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

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

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

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

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

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

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

Progress Energy	(   )
PEC	(X)
PEF	(X)

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

Progress Energy	Large accelerated filer (X)	Accelerated filer (   )	Non-accelerated filer (   )
PEC	Large accelerated filer (   )	Accelerated filer (   )	Non-accelerated filer (X)
PEF	Large accelerated filer (   )	Accelerated filer (   )	Non-accelerated filer (X)

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

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

As of June 30, 2006, the aggregate market value of the voting and nonvoting common equity of Progress Energy held by nonaffiliates was $10,832,028,534. As of June 30, 2006, the aggregate market value of the common equity of PEC held by nonaffiliates was $0. All of the common stock of PEC is owned by Progress Energy. As of June 30, 2006, the aggregate market value of the common equity of PEF held by nonaffiliates was $0. All of the common stock of PEF is indirectly owned by Progress Energy.

As of February 23, 2007, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	257,109,374
PEC	Common Stock (Without Par Value)	159,608,055
PEF	Common Stock (Without Par Value)	100

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Progress Energy and PEC definitive proxy statements for the 2007 Annual Meeting of Shareholders are incorporated into PART III, Items 10, 11, 12 , 13 and 14 hereof.

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

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

TABLE OF CONTENTS

PART I
ITEM 1.	BUSINESS
ITEM 1A.	RISK FACTORS
ITEM 1B.	UNRESOLVED STAFF COMMENTS
ITEM 2.	PROPERTIES
ITEM 3.	LEGAL PROCEEDINGS
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
ITEM 5.	MARKET FOR THE REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6.	SELECTED FINANCIAL DATA
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A.	CONTROLS AND PROCEDURES
ITEM 9B.	OTHER INFORMATION
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNACE
ITEM 11.	EXECUTIVE COMPENSATION
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES

1

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
401(k)	Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC	Allowance for funds used during construction
AHI	Affordable housing investment
AOCI	Accumulated other comprehensive income, a component of common stock equity
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
Bcf	Billion cubic feet
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	Former Progress Ventures segment’s nonregulated Competitive Commercial Operations
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Smokestacks Act	North Carolina Clean Smokestacks Act, enacted in June 2002
Coal	Coal terminals and marketing operations that blend and transload coal as part of the transportation network for coal delivery
Coal and Synthetic Fuels	Business segment primarily engaged in synthetic fuels production and sales operations, 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	Collectively, the Parent, PESC and consolidation entities
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 coal-fired steam turbines Crystal River Units No. 4 and 5
CUCA	Carolina Utility Customers Association
CVO	Contingent value obligation
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

2

Earthco	Four wholly owned coal-based solid synthetic fuels limited liability companies
ECRC	Environmental Cost Recovery Clause
EIA	Energy Information Agency
Energy Delivery	Distribution operations of the Utilities
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
FGT	Florida Gas Transmission Company
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”
Fitch	Fitch Ratings
Florida Global Case	U.S. Global LLC v. Progress Energy, Inc. et al
Florida Progress	Florida Progress Corporation, one of our wholly owned subsidiaries
FPSC	Florida Public Service Commission
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Gas	Former Progress Ventures segment’s natural gas drilling and production business
the Georgia Contracts	Fixed price full-requirement contracts serviced by CCO
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Region	Reporting unit consisting of our Effingham, Monroe, Walton and Washington nonregulated generation plants in service
Global	U.S. Global 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/s	Kilowatt-hour/s
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 this Form 10-K
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
MW	Megawatt
MWh/s	Megawatt-hour/s
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCDWQ	North Carolina Division of Water Quality
NCNG	North Carolina Natural Gas Corporation
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Council
NOPR	Notice of Proposed Rulemaking
the Notes Guarantee	Florida Progress’ full and unconditional guarantee of the Subordinated Notes
NOx	Nitrogen Oxide
NOx SIP Call	EPA rule which requires 22 states including North Carolina, South Carolina and Georgia (but excluding Florida) to further reduce nitrogen oxide emissions

3

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
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	Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company
PEF	Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation
PESC	Progress Energy Service Company, LLC
the Phase-out Price	Price per barrel of unregulated domestic crude oil at which 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 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
Progress Ventures	Former business segment that primarily engaged in nonregulated energy generation, energy marketing activities and natural gas drilling and production
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
PTC	Progress Telecommunications Corporation
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, N.C.
QF	Qualifying facility
RCA	Revolving credit agreement
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
RTO	Regional transmission organization
SAB 108	SEC Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”
SCPSC	Public Service Commission of South Carolina
Scrubber	A device that neutralizes sulfur compounds formed during coal combustion
SEC	United States Securities and Exchange Commission
Section 29	Section 29 of the Code

4

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 this Form 10-K
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. 109	Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
SFAS No. 115	Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”
SFAS No. 123	Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”
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. 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”
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
the Threshold Price	Price per barrel of unregulated domestic crude oil at which Section 29/45K tax credits begin to be reduced
the Trust	FPC Capital I, a wholly owned subsidiary of Florida Progress
the Utilities	Collectively, PEC and PEF
Winchester Production	Winchester Production Company, Ltd.
Winter Park	City of Winter Park, Fla.

5

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

In this combined report, each of the Progress Registrants makes forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-K that are not historical facts are forward looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

In addition, examples of forward-looking statements discussed in this Form 10-K include, but are not limited to, 1) statements made in PART I, Item 1A, “Risk Factors” and 2) PART II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the following headings: a) “Strategy” about our future strategy and goals; b) “Results of Operations” about trends and uncertainties; c) “Liquidity and Capital Resources” about operating cash flows, estimated capital requirements through the year 2009 and future financing plans; and d) “Other Matters” about our synthetic fuels facilities, the effects of new environmental regulations, nuclear decommissioning costs and the effect of electric utility industry restructuring.

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; the financial resources and capital needed to comply with environmental laws and our ability to recover eligible costs under cost-recovery clauses; weather conditions that directly influence the production, delivery and demand for electricity; the ability to recover through the regulatory process costs associated with future significant weather events; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; economic fluctuations and the corresponding impact on our commercial and industrial customers; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the impact on our facilities and businesses from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; 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 ability to successfully access capital markets on favorable terms; 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; the impact that increases in leverage may have on each of the Progress Registrants; the impact of derivative contracts used in the normal course of business; the investment performance of our pension and benefit plans; the Progress Registrants’ ability to control costs, including pension and benefit expense, and achieve our cost-management targets for 2007; our ability to generate and utilize tax credits from the production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); the impact that future crude oil prices may have on our earnings from our coal-based solid synthetic fuels businesses; the execution of our announced intent to dispose of our Competitive Commercial Operations (CCO) business and additional resulting charges to income, which could exceed $200 million; our ability to manage the risks involved with the CCO business, including dependence on third parties and related counterparty risks, until completion of our disposal strategy; 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 Item 1A, “Risk Factors,” which you should carefully read. 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 it assess the effect of each such factor on the Progress Registrants.

6

PART I

ITEM 1. BUSINESS

GENERAL

ORGANIZATION

Progress Energy, Inc., headquartered in Raleigh, N.C., with its regulated and nonregulated subsidiaries, is an integrated energy company serving the southeast region of the United States. In this report, Progress Energy (which includes Progress Energy, Inc.’s holding company operations (the Parent) and its subsidiaries on a consolidated basis), is at times referred to as “we,” “our” or “us.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

The Parent was incorporated on August 19, 1999 initially as CP&L Energy, Inc. and became the holding company for PEC on June 19, 2000. All shares of common stock of PEC were exchanged for an equal number of shares of CP&L Energy, Inc. common stock. On November 30, 2000, we completed our acquisition of Florida Progress Corporation (Florida Progress), a diversified, exempt electric utility holding company whose primary subsidiaries are PEF and Progress Fuels Corporation (Progress Fuels). In the $5.4 billion purchase transaction, we paid cash consideration of approximately $3.5 billion and issued 46.5 million shares of common stock valued at approximately $1.9 billion. In addition, we issued 98.6 million contingent value obligations (CVOs) valued at approximately $49 million. Prior to February 8, 2006, the Parent was a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA 1935). Effective February 8, 2006, the Federal Energy Regulatory Commission (FERC) was provided with new oversight responsibilities for the electric utility industry by the Public Utility Holding Company Act of 2005 (PUHCA 2005) as discussed below.

Our wholly owned regulated subsidiaries, PEC and PEF, each a business segment, are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. We have approximately 21,300 megawatts (MW) of regulated electric generation capacity and serve approximately 3.1 million retail electric customers as well as other load-serving entities. The Utilities operate in retail service territories that are anticipated to have population growth higher than the U.S. average. In addition, PEC’s greater proportion of commercial and industrial customers, combined with PEF’s greater proportion of residential customers, creates a balanced customer base. We are dedicated to meeting the growth needs of our service territories and delivering reliable, competitively priced energy from a diverse portfolio of power plants.

Our nonregulated Coal and Synthetic Fuels segment is involved in the production and sale of coal-based solid synthetic fuels as defined under the Internal Revenue Code (the Code), the operation of synthetic fuels facilities for third parties as well as coal terminal services. Our terminal operations support our synthetic fuels operations for the procuring and processing of coal and the transloading and marketing of synthetic fuels. On May 22, 2006, we idled our synthetic fuels facilities due to significant uncertainty surrounding synthetic fuels production. During September and October 2006, we resumed limited synthetic fuels production at our facilities, which continued through the end of 2006. The tax credit program for production of qualifying synthetic fuels is scheduled to expire at the end of 2007.

The Corporate and Other segment is comprised of nonregulated business areas that do not separately meet the disclosure requirements as a business segment. It primarily includes the activities of the Parent and Progress Energy Service Company, LLC (PESC) as well as miscellaneous nonregulated businesses. PESC provides centralized administrative, management and support services to our subsidiaries. See Note 18 for additional information about PESC services provided and costs allocated to subsidiaries.

As discussed in “Significant Developments” below, many of our nonregulated business operations have been divested or are in the process of being divested. Consequently, we no longer report a Progress Ventures segment and

7

the composition of other continuing segments has been impacted by these divestitures. See Note 19 for information regarding the revenues, income and assets attributable to our business segments.

For the year ended December 31, 2006, our consolidated revenues were $9.6 billion and our consolidated assets at year-end were $25.7 billion.

SIGNIFICANT DEVELOPMENTS

As discussed more fully in Note 3 and under MD&A - “Discontinued Operations,” we divested, or announced divestitures, of multiple nonregulated businesses during 2006 in accordance with our business strategy to reduce our business risk from nonregulated operations and to focus on the core operations of the Utilities. The 2006 divestitures resulted in net cash proceeds of $1.654 billion, which were used primarily to reduce debt, and for other corporate purposes. As discussed in Note 3, certain of our divestiture transactions announced in 2006 are anticipated to close in 2007 and we anticipate recording charges in excess of $200 million after-tax related to these divestitures. Prior to 2006, the divested entities had been included within the following segments:

Former Progress Ventures segment:

·CCO - Georgia Operations

·    KCCO - Operations of DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (Rowan) generation facilities

·    KNatural gas drilling and production business (Gas)

Coal and Synthetic Fuels segment:

·Dixie Fuels Limited (Dixie Fuels)

·Progress Materials, Inc.

Corporate and Other segment:

·Progress Telecom, LLC (PT LLC)

In addition to the divestitures and acquisitions discussed in Notes 3 and 4, we also completed the following transactions during the five-year period ended December 31, 2006:

·   During 2003, we sold certain gas-producing properties owned by Mesa Hydrocarbons, LLC, a wholly owned subsidiary of Progress Fuels. Net proceeds were approximately $97 million. During 2006, we sold our remaining Gas operations.

·   During 2003, two wholly owned subsidiaries of Progress Energy and a wholly owned subsidiary of Odyssey Telecorp, Inc. contributed substantially all of their assets and transferred certain liabilities to PT LLC. Following a series of transactions, Progress Telecommunications Corporation (PTC) held a 51 percent ownership interest in, and was the parent of, PT LLC. PTC sold its interest in PT LLC in 2006.

·   During 2003, Progress Fuels entered into several unrelated transactions to acquire approximately 200 natural gas-producing wells with proven reserves of approximately 190 billion cubic feet (Bcf) from four companies headquartered in Texas. The total cash purchase price for the transactions was $168 million.

·   During 2003, we entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire, for a cash payment of $188 million, a long-term full requirements power supply agreement at fixed prices with Jackson Electric Membership Corporation, located in Jefferson, Ga. We anticipate that a third party will acquire this contract as part of our CCO divestiture strategy.

AVAILABLE INFORMATION

The Progress Registrants’ annual reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge through the Investors section of our Web site at www.progress-energy.com. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The public may read and copy any material we have filed with the SEC at the SEC’s Public Reference Room

8

at 100 F Street, N.E., Washington, D.C. 20549. Information regarding the operations of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains a Web site, www.sec.gov, containing reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

The Investors section of our Web site also includes our corporate governance guidelines and code of ethics as well as the charters of the following committees of our board of directors: Executive; Audit and Corporate Performance; Corporate Governance; Finance; Operations and Nuclear Oversight; and Organization and Compensation. This information is available in print to any shareholder who requests it. Requests should be directed to: Shareholder Relations, Progress Energy, Inc., 410 S. Wilmington Street, Raleigh, NC 27601.

Information on our Web site is not incorporated herein and should not be deemed part of this Report.

COMPETITION

REGULATED UTILITIES

RETAIL COMPETITION

To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give retail customers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. However, the Utilities compete with suppliers of other forms of energy in connection with their retail customers.

WHOLESALE COMPETITION

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

Increased competition in the wholesale electric utility industry and the availability of transmission access could affect the Utilities’ load forecasts, plans for power supply and wholesale energy sales and related revenues. Wholesale energy sales will be impacted by the extent to which additional generation is available to sell to the wholesale market and the ability of the Utilities to retain current wholesale customers who have existing contracts with PEC or PEF.

On August 8, 2005, the Energy Policy Act of 2005 (EPACT) was signed into law. This federal law contained key provisions affecting the electric power industry, including competition among generators of electricity. The FERC has implemented and is considering a number of related regulations to implement EPACT that may impact, among other things, requirements for reliability, Qualified Facilities (QFs), transmission information availability, transmission congestion, security constrained dispatch, energy market transparency, energy market manipulation and behavioral rules.

In addition to EPACT, other policies and orders issued by the FERC have supported increased competition within the electric generation industry. EPACT clarified and expanded the FERC’s authority to assure that markets operate fairly without imposing new, mandatory intrusion on state authorities. On February 15, 2007, the FERC adopted Order 890, which reforms the open-access transmission regulatory framework previously established under Orders 888 and 889. Order 890 is designed to ensure that transmission service is provided on a nondiscriminatory and just and reasonable basis, as well as provide for more effective regulation and transparency in the operation of the transmission grid. We are currently evaluating the expected impact on our operations from compliance with Order 890.

In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued a second order that re-affirmed its April order and initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. The Utilities do not have market-based rate authority for wholesale sales in peninsular Florida.

9

Given the difficulty PEC believed it would experience in passing one of the interim screens, on September 6, 2005, PEC filed revisions to its market-based rate tariffs restricting PEC to sales outside of PEC’s control area and peninsular Florida, and filed a new cost-based tariff for sales within PEC’s control area. The FERC has accepted these revised tariffs.

On June 6, 2005, the Utilities submitted market power studies to the FERC demonstrating that neither company possessed market power outside of PEC’s control area and peninsular Florida. The FERC accepted the Utilities’ respective market power studies and allowed PEC and PEF to continue selling power at market-based rates in areas outside of PEC’s control area and peninsular Florida.

We do not anticipate that the operations of the Utilities will be materially impacted by these market-based rates decisions.

REGIONAL TRANSMISSION ORGANIZATIONS

The FERC’s Order 2000, issued in late 1999, established national standards for regional transmission organizations (RTOs) and advocated the view that regulated, unbundled transmission would facilitate competition in both wholesale and retail electricity markets. In October 2000, as a result of FERC Order 2000, PEC, along with Duke Energy Corporation and South Carolina Electric & Gas Company, filed an application with the FERC for approval of the GridSouth RTO. In July 2001, the FERC issued an order provisionally approving GridSouth. However, in July 2001, the FERC issued orders recommending that companies in the Southeast engage in mediation to develop a plan for a single RTO for the Southeast. 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. PEC’s investment in GridSouth totaled $33 million at December 31, 2006. PEC expects to recover this investment.

Also as a result of FERC Order 2000, PEF, Florida Power & Light Company and Tampa Electric Company collectively filed an application with the FERC in October 2000 for approval of the GridFlorida RTO for peninsular Florida. In 2002, the Florida Public Service Commission (FPSC) approved many of the aspects of a modified GridFlorida structure and held workshops in 2004 to address other GridFlorida issues. A cost-benefit study performed by an independent consulting firm concluded in 2005 that the GridFlorida RTO was not cost effective. The study further segregated the costs and benefits between FPSC jurisdictional and nonjurisdictional customers, concluding that the jurisdictional customers would incur even more costs, and benefits would be shifted to nonjurisdictional customers. In light of the findings and conclusions of the cost-benefit study, during 2006 the GridFlorida docketed proceedings were closed by both the FPSC and the FERC, and GridFlorida was dissolved. PEF fully recovered its startup costs in GridFlorida from retail ratepayers through base rates.

FRANCHISE MATTERS

PEC has nonexclusive franchises with varying expiration dates in most of the municipalities in North Carolina and South Carolina in which it distributes electricity. The general effect of these franchises is to provide for the manner in which PEC occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. Of these 239 franchises, the majority covers 60-year periods from the date enacted, and 45 have no specific expiration dates. Of the franchise agreements with expiration dates, three expire during the period January 1, 2007 through December 31, 2011, and the remainder expires between January 1, 2012 and 2061. PEC also provides service within a number of municipalities and in all of its unincorporated areas without franchise agreements.

PEF has nonexclusive franchises with varying expiration dates in 110 of the Florida municipalities in which it distributes electricity. PEF also provides service to 12 other municipalities and in all of its unincorporated areas without franchise agreements. The general effect of these franchises is to provide for the manner in which PEF occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. The franchise agreements cover periods ranging from 10 to 30 years with the majority covering 30-year periods from the date enacted. Of the 110 franchise agreements, three expire between January 1, 2007 and December 31, 2011, and the remainder expires between January 1, 2012 and December 31, 2036.

10

STRANDED COSTS

If the retail jurisdictions served by the Utilities become subject to deregulation, the recovery of “stranded costs” could become a significant consideration. Stranded costs primarily include the generation assets of utilities whose value in a competitive marketplace would be less than their current book value, as well as above-market purchased power commitments to QFs. Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs. Assessing the amount of stranded costs for a utility requires various assumptions about future market conditions, including the future price of electricity.

Our largest stranded cost exposure is for PEF’s purchased power commitments with QFs, under which PEF has future minimum expected capacity payments through 2033 of $4.930 billion (See Note 22A). PEF was obligated to enter into these contracts under provisions of the Public Utilities Regulatory Policies Act of 1978 (PURPA). PEF continues to seek ways to address the impact of escalating payments under these contracts. However, the FPSC allows for full recovery of the retail portion of the cost of power purchased from QFs. PEC does not have significant future minimum expected capacity payments under their purchased power commitments with QFs.

EPACT repealed the mandatory purchase and sales requirements of PURPA in competitive markets as determined by the FERC. The law also requires the FERC to revise the criteria for new QFs and removes the ownership limitations on QFs. On October 20, 2006, the FERC issued a final rule to implement a provision from EPACT that provides for termination of an electric utility’s obligation to enter into new power purchase contracts with a QF if the FERC makes specific findings about the QF’s access to competitive markets. The order establishes a rebuttable presumption that any utility located in areas covered by certain RTOs (neither PEC nor PEF are within these specified areas) will be relieved from the must-buy requirement with respect to QFs larger than 20 MW. With respect to other markets, and with respect to all QFs 20 MW or smaller, the utility bears the burden of showing that it qualifies for relief from the must-buy requirement. Any electric utility seeking relief from the must-buy requirements, regardless of location, must apply to the FERC for relief. If the must-buy requirement is terminated in an electric utility’s service territory, QFs, state agencies, or others may later petition for reinstatement of the requirement if circumstances change. The final rule went into effect January 2, 2007. We cannot predict at this time what impact this rule will have on our business.

NONREGULATED BUSINESSES

Coal and Synthetic Fuels operations compete in the steam and industrial coal markets of the eastern United States. Factors contributing to success in these markets include a competitive cost structure and strategic locations. There are, however, numerous competitors in each of these markets, although no one competitor is dominant in any industry. As discussed previously, we idled our synthetic fuels facilities for a portion of 2006 due to uncertainty surrounding synthetic fuels production. The tax credit program for production of qualifying synthetic fuels is scheduled to expire at the end of 2007.

Our CCO business, anticipated to be divested during 2007, operates in the nonregulated wholesale market where competitive pricing is the primary driver.

REGULATORY MATTERS

HOLDING COMPANY REGULATION

As a result of the acquisition of Florida Progress, Progress Energy was a registered public utility holding company subject to regulation by the SEC under PUHCA 1935, including provisions relating to the issuance of securities, sales, acquisitions of securities and utility assets, and services performed by PESC. Effective February 8, 2006, EPACT provisions repealed PUHCA 1935 and enacted PUHCA 2005. Subsequent to that date, the Parent is subject to regulation by the FERC as a public utility holding company rather than by the SEC. EPACT granted the FERC certain new powers, previously addressed under PUHCA 1935, including accounting and record retention authority and cost allocation jurisdiction at the election of the holding company system or the state utility commissions with jurisdiction over its utility subsidiaries.

11

UTILITY REGULATION

FEDERAL REGULATION

Other EPACT provisions included tax changes for the utility industry; incentives for emissions reductions; federal insurance and incentives to build new nuclear power plants; and certain protection for native retail load customers of load-serving entities. EPACT gave the FERC "backstop" transmission siting authority which provides for federal intervention, subject to limitations, when states are unable or unwilling to resolve transmission issues. EPACT also provided incentives and funding for clean coal technologies, provided initiatives to voluntarily reduce greenhouse gases and redesignated the Code’s Section 29 (Section 29) tax credit as a general business credit under the Code’s Section 45K (Section 45K). In addition, the law requires both the FERC and the U.S. Department of Energy (DOE) to study how utilities dispatch their resources to meet the needs of their customers. The results of these studies or any related actions taken by the DOE could impact the Utilities’ system operations.

The FERC has adopted final rules implementing much of its new authority under EPACT. These new rules require the FERC’s approval prior to any merger involving a public utility; require the FERC’s approval prior to the disposition of any utility asset with a market value in excess of $10 million; prohibit market participants from intentionally or recklessly making any fraudulent or misleading statements with regard to transactions subject to the FERC’s jurisdiction; and provides the procedures and rules for the establishment of an electric reliability organization (ERO) that will propose and enforce mandatory reliability standards for the bulk power electric system.

On July 20, 2006, the FERC certified the North American Electric Reliability Council (NERC) as the ERO. In addition, on October 20, 2006, the FERC issued a Notice of Proposed Rulemaking (NOPR) on reliability standards originally proposed by the NERC, which would transition compliance with these standards from voluntary to mandatory. The proposed reliability standards were based on the current NERC reliability standards. The FERC proposes to approve 83 reliability standards, as currently written, and make compliance mandatory. After these standards are approved, the FERC has directed the NERC to make technical improvements to 62 of the 83 standards. An additional 24 standards proposed by the NERC that were not adopted remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. Mandatory reliability standards are expected to be in place by the summer of 2007. All users, owners and operators of the bulk power system, including PEC and PEF, will be subject to these standards upon their approval by the FERC.

Recent reliability audits of PEC operations have not resulted in any standards violations. PEF is in the process of executing a mitigation plan associated with findings from a 2004 reliability audit. Based on the direction the FERC has given to the NERC to make revisions to 62 of the standards proposed for adoption, we expect standards to migrate to stricter requirements over time. We are committed to meeting those standards. The financial impact of mandatory compliance cannot currently be determined. If we are unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, failure to comply with the reliability standards approved by the FERC could result in the imposition of fines and civil penalties.

On January 18, 2007, the FERC issued a NOPR regarding Standards of Conduct in response to a 2006 court case, which invalidated certain portions of the Standards of Conduct as they relate to natural gas companies. The NOPR requests comment with respect to whether the electric Standards of Conduct should be limited to marketing affiliates and proposes to create two new categories of shared employees: one for employees involved in resource competitive solicitations and the other for employees involved in integrated resource planning. We cannot predict the outcome of this matter.

PEC and PEF are subject to regulation by the FERC with respect to wholesale rates for transmission and sale of electric energy and the interconnection of facilities in interstate commerce (other than interconnections for use in the event of certain emergency situations). PEC and its wholesale customers last agreed to a general increase in wholesale rates in 1988. PEF and its wholesale customers last agreed to a general increase in wholesale rates in 1995. However, wholesale rates for both of the Utilities have been adjusted since that time through contractual negotiations.

12

The Utilities are also subject to regulation by other federal regulatory agencies, including the United States Nuclear Regulatory Commission (NRC) and the Environmental Protection Agency (EPA). The Utilities’ nuclear generating units are regulated by the NRC under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974. The NRC is responsible for granting licenses for the construction, operation and retirement of nuclear power plants and subjects these plants to continuing review and regulation. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved.

STATE REGULATION

PEC is subject to regulation in North Carolina by the North Carolina Utilities Commission (NCUC), and in South Carolina by the Public Service Commission of South Carolina (SCPSC). PEF is subject to regulation in Florida by the FPSC. The Utilities are regulated by their respective regulatory bodies with respect to, among other things, rates and service for electricity sold at retail; retail cost recovery of unusual or unexpected expenses, such as severe storm costs; and issuances of securities. The underlying concept of utility ratemaking is to set rates at a level that allows the utility to collect revenues equal to its cost of providing service plus earn a reasonable rate of return on its invested capital, including equity.

Retail Rate Matters

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

In PEC’s most recent rate cases in 1988, the NCUC and the SCPSC each authorized a return on equity of 12.75 percent for PEC. The Clean Smokestacks Act enacted in North Carolina in 2002 (Clean Smokestacks Act) froze PEC’s retail base rates in North Carolina through December 31, 2007, unless PEC experiences extraordinary events beyond the control of PEC, in which case PEC can petition for a rate increase. Subsequent to 2007, PEC’s current North Carolina base rates will continue subject to traditional cost-based rate regulation.

During 2005, the FPSC approved a four-year base rate agreement with PEF. The new base rates took effect the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009 with PEF having the sole option to extend the agreement through the last billing cycle of June 2010. Base rates will be adjusted in late 2007 depending on the in-service date of specified generation facilities. PEF’s base rate settlement also provides for revenue sharing between PEF and its ratepayers. For 2006, PEF agreed to refund two-thirds of retail base revenues between the $1.499 billion threshold and the $1.549 billion cap and 100 percent of revenues above the $1.549 billion cap. However, PEF’s 2006 retail base rates did not exceed the threshold and no revenues were subject to the revenue sharing provisions. Both the threshold and cap will be adjusted annually for rolling average 10-year retail kilowatt-hour (kWh) sales growth.

Retail Cost-recovery Clauses

Each of the Utilities’ state utility commissions allows recovery of certain costs through various cost-recovery clauses, to the extent the respective commission determines in an annual hearing that such costs are prudent. Each state utility commission’s determination results in the addition of a rider to a utility’s base rates to reflect the approval of these costs and to reflect any past over- or under-recovery of costs. The Utilities do not earn a return on the recovery of eligible operating expenses under such clauses; however, the FPSC has authorized PEF to earn a return for specified capital investments for environmental compliance and utility plant. Fuel and certain purchased power costs are eligible for recovery by the Utilities. The Utilities use coal, oil, hydroelectric (PEC only), natural gas and nuclear power to generate electricity thereby maintaining a diverse fuel mix that helps mitigate the impact of cost increases in any one fuel. Due to the regulatory treatment of these costs and the method allowed for recovery, changes in fuel costs from year to year have no material impact on operating results of the Utilities, unless a commission finds a portion of such costs to have been imprudently incurred. However, delays between the expenditure for fuel costs and recovery from ratepayers can adversely impact the cash flow of the Utilities. See MD&A - “Regulatory Matters and Recovery of Costs” for additional discussion regarding cost-recovery clauses.

13

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

·   North Carolina Retail - fuel costs and the fuel portion of purchased power;

·   South Carolina Retail - fuel costs, certain purchased power costs, and sulfur dioxide (SO₂) emission allowance expense; and

·   Florida Retail - fuel costs, purchased power costs, capacity costs, energy conservation expense and specified environmental costs, including SO₂ emission allowance expense and nitrogen oxide (NOx) compliance.

Storm Recovery

In accordance with its base rate agreement, PEF accrues $6 million annually in base rates to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm reserve is charged with operation and maintenance (O&M) expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions.

On July 14, 2005, the FPSC issued an order authorizing PEF to recover $232 million over a two-year period, including interest, of its incurred storm restoration costs associated with the four hurricanes in 2004. The initial amount approved for recovery was based on PEF’s estimate of costs and its impact was included in customer bills beginning August 1, 2005, as a storm surcharge. On September 12, 2005, PEF filed a true-up of an additional $19 million in costs. The increase was partially offset by $6 million of adjustments. The FPSC administratively approved the true-up amount, subject to audit by the FPSC staff. The net true-up effect was included in customer bills beginning January 1, 2006.

During 2006, PEF entered into, and the FPSC approved, a settlement agreement with certain intervenors in its storm cost-recovery docket. The settlement agreement, as amended, allows PEF to extend its current two-year storm surcharge for an additional 12-month period. The extension, which begins August 2007, will replenish the existing storm reserve by an estimated additional $130 million. The amended settlement agreement provides that in the event future storms cause the reserve to be depleted, 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.

PEC does not maintain a storm damage reserve account and does not have an ongoing regulatory mechanism, such as a surcharge, to recover storm costs. In the past, PEC has sought and received permission from the SCPSC and NCUC to defer and amortize certain storm recovery costs.

See Note 7 for further discussion of regulatory matters.

NUCLEAR MATTERS

GENERAL

The nuclear power industry faces uncertainties with respect to the cost and long-term availability of disposal sites for spent nuclear fuel and other radioactive waste, compliance with changing regulatory requirements, nuclear plant operations, capital outlays for modifications, the technological and financial aspects of decommissioning plants at the end of their licensed lives and requirements relating to nuclear insurance.

PEC owns and operates four nuclear generating units, Brunswick Nuclear Plant (Brunswick) Unit No. 1 and Unit No. 2, Shearon Harris Nuclear Plant (Harris), and Robinson Nuclear Plant (Robinson). NRC operating licenses, including license extensions granted through 2006, for Brunswick No. 1 and No. 2, Harris and Robinson currently expire in September 2036, December 2034, October 2026 and July 2030, respectively. On June 26, 2006, Brunswick received 20-year extensions from the NRC on the operating licenses for its two nuclear reactors. On November 14, 2006, we submitted an application to the NRC requesting a 20-year extension of the Harris operating license.

14

PEF owns and operates one nuclear generating unit, Crystal River Unit No. 3 (CR3). The NRC operating license for CR3 currently expires in December 2016. We expect to submit an application to extend this license 20 years in the first quarter of 2009.

Nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications.

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

Since 2002, the NRC has issued various bulletins and orders addressing inspection activities associated with pressurized water reactor vessels. We have complied with all requests. Additionally, we replaced the reactor vessel head at CR3 in 2003 and at Robinson in 2005.

POTENTIAL NEW CONSTRUCTION

We have announced that we are pursuing development of combined license (COL) applications. Our announcement is not a commitment to build a nuclear plant. It is a necessary step to keep open the option of building a plant or plants. On January 23, 2006, we announced that PEC selected the Harris site to evaluate for possible future nuclear expansion. We currently expect to file the application for the COL for PEC’s Harris site in 2007. We have selected the Westinghouse Electric AP-1000 reactor design as the technology upon which to base PEC’s potential application submission. On December 12, 2006, we announced that PEF selected a site in Levy County, Fla. to evaluate for possible future nuclear expansion and PEF expects to file the application for the COL in 2008. We have not selected the reactor design technology upon which to base PEF’s potential application submission. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, construction activities could begin as early as 2010, and new plants could be online in late 2016.The NRC estimates that it will take approximately three to four years to review and process the COL applications.

SECURITY

The NRC has issued various orders since September 2001 with regard to security at nuclear plants. These orders include additional restrictions on access, increased security measures at nuclear facilities and closer coordination with our partners in intelligence, military, law enforcement and emergency response at the federal, state and local levels. We completed the requirements as outlined in the orders by the committed dates. As the NRC, other governmental entities and the industry continue to consider security issues, it is possible that more extensive security plans could be required.

SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE

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

With certain modifications and additional approvals by the NRC, including the installation of onsite 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 pool through the expiration of its operating license, including any license extension.

On January 16, 2007, the U.S. Supreme Court declined to hear an appeal of a Ninth Circuit U.S. Court of Appeals’ decision in which the Ninth Circuit held that the NRC is required to consider the environmental impacts of terrorist attacks under the National Environmental Policy Act in authorizing an independent spent fuel storage installation. Similar cases, including cases involving operating license renewals, are pending in seven other jurisdictions. The NRC is considering the scope and import of the Ninth Circuit’s decision in reviewing its operating license renewal

15

program. The extent and timing of the NRC’s application of the case is unclear at this time, and the impact, if any, on PEC’s pending Harris operating license renewal application or any future PEC or PEF operating licensing proceedings cannot be predicted at this time.

Since 2001, PEC and PEF have made various modifications to increase the output of their nuclear facilities. To date, the cumulative increase is approximately 315 MW, of which 311 MW is at PEC and 4 MW is at PEF. In January 2007, the FPSC approved PEF’s petition to uprate CR3’s gross output by approximately 180 MW (See Note 7C).

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

DECOMMISSIONING

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 jurisdiction, the provisions for nuclear decommissioning costs are approved by the FERC. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. See Note 5D for a discussion of the Utilities’ nuclear decommissioning costs.

ENVIRONMENTAL

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. The current estimated capital costs associated with compliance with pollution control laws and regulations that we expect to incur are included within MD&A - “Liquidity and Capital Resources - Capital Expenditures” and within MD&A - “Other Matters - Environmental Matters.”

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of legislation. 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, including 10 manufactured gas plant (MGP) sites, with respect to which we have been notified by the EPA, the State of North Carolina or the State of Florida of our potential liability, as a potentially responsible party (PRP). We have accrued costs for the sites to the extent our liability is probable and the costs can be reasonably estimated. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 7 and 21). Both PEC and PEF evaluate potential claims against other potential 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. While we accrue for probable costs that can be reasonably estimated, based upon the current status of some sites, not all costs can be reasonably estimated or accrued and actual costs may materially exceed our accruals. Material costs in excess of our accruals could have an adverse impact on our financial condition and results of operations.

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

EMPLOYEES

As of February 15, 2007, we employed approximately 11,000 full-time employees. Of this total, approximately 2,000 employees at PEF are represented by the International Brotherhood of Electrical Workers (IBEW). The three-year labor contract with the IBEW expires in November 2008. We consider our relationship with employees,

16

including those covered by collective bargaining agreements, to be good.

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

As of February 15, 2007, PEC and PEF employed approximately 5,000 and 4,000 full-time employees, respectively.

ELECTRIC - PEC

GENERAL

PEC is a regulated public utility formed under the laws of North Carolina in 1926 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina. At December 31, 2006, PEC had a total summer generating capacity (including jointly owned capacity) of 12,409 MW. For additional information about PEC’s generating plants, see “Electric - PEC” in Item 2, “Properties.” PEC’s system normally experiences its highest peak demands during the summer, and the all-time system peak of 12,577 megawatt-hour (MWh) was set on July 27, 2005.

PEC distributes and sells electricity in North Carolina and northeastern South Carolina. The service territory covers approximately 34,000 square miles, including a substantial portion of the coastal plain of North Carolina extending from the Piedmont to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in western North Carolina in and around the city of Asheville and an area in the northeastern portion of South Carolina. At December 31, 2006, PEC was providing electric services, retail and wholesale, to approximately 1.4 million customers. Major wholesale power sales customers include North Carolina Eastern Municipal Power Agency (Power Agency), North Carolina Electric Membership Corporation and Public Works Commission of the City of Fayetteville, North Carolina (PWC). PEC is subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the NRC. No single customer accounts for more than 10 percent of PEC’s revenues.

BILLED ELECTRIC REVENUES

PEC’s electric revenues billed by customer class, for the last three years, are shown as a percentage of total PEC electric revenues in the table below:

BILLED ELECTRIC REVENUE PERCENTAGES
	2006	2005	2004
Residential	37%	37%	38%
Commercial	25%	24%	25%
Industrial	18%	18%	19%
Wholesale	18%	19%	16%
Other retail	2%	2%	2%

Major industries in PEC’s service area include textiles, chemicals, metals, paper, food, rubber and plastics, wood products and electronic machinery and equipment.

FUEL AND PURCHASED POWER

SOURCES OF GENERATION

PEC’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEC’s customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies. PEC’s total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table:

17

ENERGY MIX PERCENTAGES
	2006	2005	2004
Coal	47%	47%	47%
Nuclear	43%	42%	43%
Purchased power	6%	6%	6%
Oil/Gas	3%	4%	3%
Hydro	1%	1%	1%

PEC is generally permitted to pass the cost of fuel and certain purchased power costs to its customers through fuel adjustment clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. See “Commodity Price Risk” under Item 7A, “Quantitative And Qualitative Disclosures About Market Risk” and Item 1A, “Risk Factors.” However, PEC believes that its fuel supply contracts, as described below and in Note 22A, will be adequate to meet its fuel supply needs.

PEC’s average fuel costs per million British thermal units (Btu) for the last three years were as follows:

AVERAGE FUEL COST
(per million Btu)	2006		2005		2004
Coal	$	2.90	$	2.72	$	2.17
Nuclear		0.43		0.42		0.42
Oil		11.04		8.60		6.78
Gas		9.87		10.90		8.29
Weighted-average		2.06		2.03		1.57

Changes in the unit price for coal, oil and gas are due to market conditions. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income.

Coal

PEC anticipates a requirement of approximately 13 million tons of coal in 2007. Almost all of the coal will be supplied from Appalachian coal sources in the United States and will be primarily delivered by rail.

For 2007, PEC has short-term, intermediate and long-term agreements from various sources for approximately 99 percent of its estimated burn requirements of its coal units. The contracts have expiration dates ranging from one to five years. PEC will continue to sign contracts of various lengths, terms and quality to meet its expected burn requirements.

Nuclear

Nuclear fuel is processed through four distinct stages. Stages I and II involve the mining and milling of the natural uranium ore to produce a uranium oxide concentrate and the conversion of this concentrate into uranium hexafluoride. Stages III and IV entail the enrichment of the uranium hexafluoride and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

PEC has sufficient uranium, conversion, enrichment and fabrication contracts to meet its near-term nuclear fuel requirement needs. PEC’s nuclear fuel contracts typically have terms ranging from three to ten years. For a discussion of PEC’s plans with respect to spent fuel storage, see “Nuclear Matters.”

Oil and Gas

Oil and natural gas supply for PEC’s generation fleet is purchased under term and spot contracts from several suppliers. PEC has dual-fuel generating facilities that can operate with both oil and gas. The cost of PEC’s oil and gas is hedged at a fixed price or determined by market prices as reported in certain industry publications. PEC believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. PEC’s natural

18

gas transportation for its baseload gas generation is purchased under term firm transportation contracts with interstate pipelines. PEC also purchases capacity under other contracts and utilizes interruptible transportation for its peaking load requirements.

Hydroelectric

PEC has three hydroelectric generating plants licensed by the FERC: Walters, Tillery and Blewett. PEC also owns the Marshall Plant, which has a license exemption. The total maximum dependable capacity for all four units is 225 MW. PEC submitted an application to relicense for 50 years its Tillery and Blewett Plants. The remaining phase of the application process is expected to take up to one year. The license for these plants currently expires in April 2008. The Walters Plant license will expire in 2034.

Purchased Power

PEC purchased approximately 4.2 million MWh, 4.7 million MWh and 4.0 million MWh of its system energy requirements during 2006, 2005 and 2004 and had 1,461 MW of firm purchased capacity under contract during 2006. PEC may acquire additional purchased power capacity in the future to accommodate a portion of its system load needs, and PEC believes that it can obtain enough purchased power to meet these needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected.

ELECTRIC - PEF

GENERAL

PEF, incorporated in Florida in 1899, is an operating public utility engaged in the generation, transmission, distribution and sale of electricity. At December 31, 2006, PEF had a total summer generating capacity (including jointly owned capacity) of 8,913 MW. For additional information about PEF’s generating plants, see “Electric - PEF” in Item 2, “Properties.” PEF’s system normally experiences its highest peak demands during the winter, and the all-time system peak of 10,131 MWh was set on January 24, 2003.

PEF distributes and sells electricity in Florida. The service territory covers approximately 20,000 square miles and includes the densely populated areas around Orlando, as well as the cities of St. Petersburg and Clearwater. PEF is interconnected with 22 municipal and 9 rural electric cooperative systems. At December 31, 2006, PEF was providing electric services, retail and wholesale, to approximately 1.6 million customers. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., Reedy Creek Improvement District, Tampa Electric Company, and the cities of Bartow and Winter Park. PEF is subject to the rules and regulations of the FERC, the FPSC and the NRC. No single customer accounts for more than 10 percent of PEF’s revenues.

BILLED ELECTRIC REVENUES

PEF’s electric revenues, billed by customer class for the last three years, are shown as a percentage of total PEF electric revenues in the table below:

BILLED ELECTRIC REVENUE PERCENTAGES
	2006	2005	2004
Residential	53%	52%	53%
Commercial	26%	25%	25%
Industrial	8%	8%	8%
Wholesale	7%	9%	8%
Other retail	6%	6%	6%

Important industries in PEF’s territory include phosphate rock mining and processing, electronics design and manufacturing, and citrus and other food processing. Other important commercial activities are tourism, health care, construction and agriculture.

19

FUEL AND PURCHASED POWER

SOURCES OF GENERATION

PEF’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEF’s customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies. PEF’s total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table:

ENERGY MIX PERCENTAGES
	2006	2005	2004
Coal (a)	32%	33%	32%
Oil/Gas	31%	33%	32%
Nuclear	15%	13%	16%
Purchased Power	22%	21%	20%

^(a)   Amounts include synthetic fuels from unrelated third parties.

PEF is generally permitted to pass the cost of fuel and purchased power to its customers through fuel adjustment clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. See “Commodity Price Risk” under Item 7A, “Quantitative And Qualitative Disclosures About Market Risk” and Item 1A, “Risk Factors.” However, PEF believes that its fuel supply contracts, as described below and in Note 22A, will be adequate to meet its fuel supply needs.

PEF’s average fuel costs per million Btu for the last three years were as follows:

AVERAGE FUEL COST
(per million Btu)	2006	2005	2004
Coal (a)	$3.16	$2.70	$2.30
Oil	7.03	5.90	4.67
Nuclear	0.50	0.51	0.49
Gas	7.41	8.53	6.41
Weighted-average	4.21	4.15	3.21

^(a)   Amounts include synthetic fuels from unrelated third parties.

Changes in the unit price for coal, oil and gas are due to market conditions. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income.

Coal

PEF anticipates a combined requirement of approximately 6 million tons of coal in 2007. Approximately 60 percent of the coal is expected to be supplied from Appalachian coal sources in the United States and 40 percent supplied from coal sources in South America. Approximately 55 percent of the coal is expected to be delivered by rail and the remainder by water. Prior to 2006, coal for PEF was supplied by Progress Fuels, a subsidiary of Progress Energy, pursuant to contracts between PEF and Progress Fuels. Beginning in 2006, PEF began entering into coal contracts on its own behalf.

For 2007, PEF has medium-term and long-term contracts with various sources for approximately 99 percent of the estimated burn requirements of its coal units. These contracts have price adjustment provisions and have expiration dates ranging from one to four years. All the coal to be purchased for PEF is considered to be low-sulfur coal by industry standards.

20

Oil and Gas

Oil and natural gas supply for PEF’s generation fleet is purchased under term and spot contracts from several suppliers. PEF has dual-fuel generating facilities that can operate with both oil and gas. PEF’s oil and gas is either hedged at a fixed price or determined by market prices as reported in certain industry publications. PEF believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. PEF’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate pipelines. PEF purchases capacity on a seasonal basis from numerous shippers and interstate pipelines and utilizes interruptible transportation to serve its peaking load requirements.

Nuclear

Nuclear fuel is processed through four distinct stages. Stages I and II involve the mining and milling of the natural uranium ore to produce a uranium oxide concentrate and the conversion of this concentrate into uranium hexafluoride. Stages III and IV entail the enrichment of the uranium hexafluoride and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

PEF has sufficient uranium, conversion, enrichment and fabrication contracts to meet its near-term nuclear fuel requirement needs. PEF’s nuclear fuel contracts typically have terms ranging from three to ten years. For a discussion of PEF’s plans with respect to spent fuel storage, see “Nuclear Matters.”

Purchased Power

PEF purchased approximately 10.4 million MWh, 9.9 million MWh and 9.4 million MWh of its system energy requirements during 2006, 2005 and 2004 respectively, and had 2,073 MW of firm purchased capacity under contract during 2006. These agreements include approximately 943 MW of capacity under contract with certain QFs. PEF may acquire additional purchased power capacity in the future to accommodate a portion of its system load needs, and PEF believes that it can obtain enough purchased power to meet these needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected.

COAL AND SYNTHETIC FUELS

Historically, we have had substantial operations associated with the production of coal-based solid synthetic fuels. Our synthetic fuels facilities include five majority-owned synthetic fuels entities and one minority interest in a synthetic fuels entity and have the capability to produce 19 million tons per year. The production and sale of these products qualifies for federal income tax credits within the meaning of Section 29/45K so long as certain requirements are satisfied. Qualifying synthetic fuels facilities entitle their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The tax credits associated with synthetic fuels in a particular year may be phased out if annual average market prices for crude oil exceed certain prices. Synthetic fuels are generally not economical to produce and sell absent the credits. Through tax year 2005, our ability to utilize tax credits was dependent on having a sufficient tax liability. In 2005, the tax law was changed and this constraint no longer applies beginning in tax year 2006. The tax credit program for the production of qualifying synthetic fuels is scheduled to expire at the end of 2007.

In May 2006, we idled production of synthetic fuels at our synthetic fuels facilities due to the high level of oil prices. Based on significantly reduced oil prices combined with favorable oil price projections, we resumed limited production at our synthetic fuels facilities in September and October 2006, which continued through the end of 2006. For the year ended December 31, 2006, we produced approximately 3.7 million tons of synthetic fuels.

We also have five terminals on the Ohio River and its tributaries which blend and transload coal and are part of the trucking, rail and barge network for coal delivery; these terminals also support our synthetic fuel facilities.

Our coal and synthetic fuels operations and related risks are described in more detail in Item 1A, “Risk Factors” and MD&A - “Other Matters - Synthetic Fuels Tax Credits.”

21

CORPORATE AND OTHER

GENERAL

The Corporate and Other segment is comprised of nonregulated business areas that do not separately meet the disclosure requirements as a business segment. It primarily includes the activities of the Parent and PESC as well as miscellaneous nonregulated businesses. PESC provides centralized administrative, management and support services to our subsidiaries. See Note 18 for additional information about PESC services provided and costs allocated to subsidiaries.

22

ELECTRIC UTILITY REGULATED OPERATING STATISTICS - PROGRESS ENERGY
	Years Ended December 31
	2006			2005			2004		2003		2002
Energy supply (millions of kWhs)
Generated
Steam		48,770			52,306			50,782		51,501		49,734
Nuclear		30,602			30,120			30,445		30,576		30,126
Combustion Turbines/Combined Cycle		11,857			11,349			9,695		7,819		8,522
Hydro		594			749			802		955		491
Purchased		14,664			14,566			13,466		13,848		14,305
Total energy supply (Company share)		106,487			109,090			105,190		104,699		103,178
Jointly owned share (a)		5,224			5,388			5,395		5,213		5,258
Total system energy supply		111,711			114,478			110,585		109,912		108,436
Average fuel cost (per million Btu)
Fossil	$	4.17		$	4.05		$	3.17	$	2.94	$	2.62
Nuclear fuel	$	0.44		$	0.44		$	0.44	$	0.44	$	0.44
All fuels	$	2.86		$	2.83		$	2.21	$	2.05	$	1.84
Energy sales (millions of kWhs)
Retail
Residential		36,280			36,558			35,350		34,712		33,993
Commercial		25,333			25,258			24,753		24,110		23,888
Industrial		16,553			16,856			17,105		16,749		16,924
Other Retail		4,695			4,608			4,475		4,382		4,287
Wholesale		19,117			21,137			18,323		19,841		19,204
Unbilled		(371	)		(440	)		449		189		275
Total energy sales		101,607			103,977			100,455		99,983		98,571
Company uses and losses		4,880			5,113			4,735		4,716		4,607
Total energy requirements		106,487			109,090			105,190		104,699		103,178
Electric revenues (in millions)
Retail	$	7,429		$	6,607		$	6,066	$	5,620	$	5,515
Wholesale		1,039			1,103			843		914		881
Miscellaneous revenue		254			235			244		207		205
Total electric revenues	$	8,722		$	7,945		$	7,153	$	6,741	$	6,601
(a)Amounts represent joint owners’ share of the energy supplied from the six generating facilities that are jointly owned.

23

REGULATED OPERATING STATISTICS - PEC
	Years Ended December 31
	2006			2005			2004		2003			2002
Energy supply (millions of kWhs)
Generated
Steam		28,985			29,780			28,632		28,522			28,547
Nuclear		24,220			24,291			23,742		24,537			23,425
Combustion Turbines/Combined Cycle		2,106			2,475			1,926		1,344			1,934
Hydro		594			749			802		955			491
Purchased		4,229			4,656			4,023		4,467			5,213
Total energy supply (Company share)		60,134			61,951			59,125		59,825			59,610
Jointly owned share (a)		4,649			4,857			4,794		4,670			4,659
Total system energy supply		64,783			66,808			63,919		64,495			64,269
Average fuel cost (per million Btu)
Fossil	$	3.37		$	3.30		$	2.52	$	2.29		$	2.16
Nuclear fuel	$	0.43		$	0.42		$	0.42	$	0.43		$	0.43
All fuels	$	2.06		$	2.03		$	1.57	$	1.43		$	1.38
Energy sales (millions of kWhs)
Retail
Residential		16,259			16,664			16,003		15,283			15,239
Commercial		13,358			13,313			13,019		12,557			12,468
Industrial		12,393			12,716			13,036		12,749			13,089
Other Retail		1,419			1,410			1,431		1,408			1,437
Wholesale		14,584			15,673			13,222		15,518			15,024
Unbilled		(137	)		(235	)		91		(44	)		270
Total energy sales		57,876			59,541			56,802		57,471			57,527
Company uses and losses		2,258			2,410			2,323		2,354			2,083
Total energy requirements		60,134			61,951			59,125		59,825			59,610
Electric revenues (in millions)
Retail	$	3,268		$	3,133		$	2,953	$	2,824		$	2,796
Wholesale		720			759			575		687			651
Miscellaneous revenue		97			98			100		78			92
Total electric revenues	$	4,085		$	3,990		$	3,628	$	3,589		$	3,539
(a) Amounts represent joint owner’s share of the energy supplied from the four generating facilities that are jointly owned.

24

REGULATED OPERATING STATISTICS - PEF
	Years Ended December 31
	2006	2005	2004	2003	2004
Energy supply (millions of kWhs)
Generated
Steam	19,785	22,526	22,150	22,979	21,187
Nuclear	6,382	5,829	6,703	6,039	6,701
Combustion Turbines/Combined Cycle	9,751	8,874	7,769	6,475	6,588
Purchased	10,435	9,910	9,443	9,381	9,092
Total energy supply (Company share)	46,353	47,139	46,065	44,874	43,568
Jointly owned share (a)	575	531	601	543	599
Total system energy supply	46,928	47,670	46,666	45,417	44,167
Average fuel cost (per million Btu)
Fossil	$5.09	$4.88	$3.86	$3.63	$3.15
Nuclear fuel	$0.50	$0.51	$0.49	$0.50	$0.46
All fuels	$4.21	$4.15	$3.21	$3.07	$2.60
Energy sales (millions of kWhs)
Retail
Residential	20,021	19,894	19,347	19,429	18,754
Commercial	11,975	11,945	11,734	11,553	11,420
Industrial	4,160	4,140	4,069	4,000	3,835
Other Retail	3,276	3,198	3,044	2,974	2,850
Wholesale	4,533	5,464	5,101	4,323	4,180
Unbilled	(234)	(205)	358	233	5
Total energy sales	43,731	44,436	43,653	42,512	41,044
Company uses and losses	2,622	2,703	2,412	2,362	2,524
Total energy requirements	46,353	47,139	46,065	44,874	43,568
Electric revenues (in millions)
Retail	$4,161	$3,474	$3,113	$2,796	$2,719
Wholesale	319	344	268	227	230
Miscellaneous revenue	159	137	144	129	113
Total electric revenues	$4,639	$3,955	$3,525	$3,152	$3,062
(a) Amounts represent joint owners’ share of the energy supplied from the two generating facilities that are jointly owned.

25

ITEM 1A.RISK FACTORS

Investing in the securities of the Progress Registrants involves risks, including the risks described below, that could affect the Progress Registrants and their businesses, as well as the energy industry generally. Most of the business information as well as the financial and operational data contained in our risk factors are updated periodically in the reports the Progress Registrants file with the SEC. Although the Progress Registrants have discussed current material risks, please be aware that other risks may prove to be important in the future. New risks may emerge at any time and the Progress Registrants cannot predict such risks or estimate the extent to which they may affect their financial performance. Before purchasing securities of the Progress Registrants, you should carefully consider the following risks and the other information in this combined Annual Report, as well as the documents the Progress Registrants file with the SEC from time to time. Each of the risks described below could result in a decrease in the value of the securities of the Progress Registrants and your investment therein.

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

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

We are subject to comprehensive regulation by multiple federal, state and local regulatory agencies, which significantly influences our operating environment and may affect our ability to recover costs from utility customers. We are subject to regulatory oversight with respect to,among other things, rates and service for electric energy sold at retail, retail service territory, siting and construction of facilities, and issuances of securities. In addition, the Utilities are subject to federal regulation with respect to transmission and sales of wholesale power, accounting and certain other matters. We are also required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws. Laws and regulations frequently change and the ultimate costs of compliance cannot be precisely estimated. Such changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.

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

We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste production, handling and disposal. These laws and regulations can result in increased capital, operating and other costs, particularly with regard to enforcement efforts focused on existing power plants and compliance plans with regard to new power plants. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, authorizations and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable regulations might result in the imposition of fines and penalties by regulatory authorities. We cannot provide assurance that existing environmental regulations will not be revised or that new environmental regulations will not be adopted or become applicable to us. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a material adverse effect on our results of operations, particularly if those costs are not fully recoverable from our ratepayers.

In addition, we may be deemed a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs. We have been identified as a PRP at 10 former MGP sites (eight at PEC and two at PEF). We are also currently in the process of assessing potential costs and exposures at the Ward Transformer site, Carolina Transformer site and other sites. Both PEC and PEF evaluate potential claims against other potential PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. No material claims are currently pending. While we accrue for probable costs that can be

26

reasonably estimated, not all costs can be reasonably estimated or accrued and actual costs may materially exceed our accruals. Material costs in excess of our accruals could have an adverse impact on our financial condition and results of operations.

There are proposals and ongoing studies at the state and federal levels to address global climate change that would regulate carbon dioxide (CO₂) and other greenhouse gases. Any future regulatory actions taken to address global climate change represent a business risk to our operations. We have articulated principles that we believe should be incorporated into any global climate change policy. In 2005, we initiated a study to assess the impact of constraints on CO₂ and other air emissions. On March 27, 2006, we issued our report to shareholders for an assessment of global climate change and air quality risks and actions. While we participate in the development of a national climate change policy framework, we will continue to actively engage others in our region to develop consensus-based solutions, as we did with the Clean Smokestacks Act. The cost impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time.

Our compliance with environmental regulations requires significant capital expenditures that impact our financial condition. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Clean air regulations require reduction of emissions of NOx, SO₂ and mercury from coal-fired power plants. We expect that future capital expenditures required to meet the emission limits could be in excess of $1.0 billion each at PEC and PEF, respectively, through 2018, which corresponds to the latest emission reduction deadline. However, these costs could be higher than currently expected and have an adverse impact on our results of operations and financial condition.

The operation of emission control equipment to meet the emission limits will increase our operating costs, net of recovery of costs through the cost-recovery clause, and reduce the generating capacity of our coal-fired plants. O&M expenses will significantly increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation of the emission control equipment will require the procurement of significant quantities of limestone and ammonia. Future increases in demand for these items from other utility companies operating the same equipment could increase our costs associated with operating the equipment.

See Note 21 for additional discussion of environmental matters.

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

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

Furthermore, destruction caused by severe weather events, such as hurricanes, tornadoes, severe thunderstorms, snow and ice storms, can result in lost operating revenues due to outages; property damage, including downed transmission and distribution lines; and additional and unexpected expenses to mitigate storm damage.

Our ability to recover significant costs resulting from severe weather events is subject to regulatory oversight and the timing and amount of any such recovery is uncertain and may impact our financial conditions.

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

27

Under a regulatory order, PEF maintains a storm damage reserve account for major storms. Due to the significant costs incurred to recover from the damage sustained during the 2004 hurricane season, PEF’s storm damage reserve accounts were largely depleted at December 31, 2005. During 2006, the FPSC approved a modified settlement agreement that extends PEF’s current two-year storm surcharge for retail ratepayers for an additional 12-month period ending in August 2008. The extension is expected to replenish PEF’s storm reserve by an estimated additional $130 million. In the event future storms cause the reserve to be depleted, the modified settlement agreement provides for PEF to petition the FPSC for implementation of an interim retail surcharge of at least 80 percent and up to 100 percent of the claimed deficiency of its storm reserve. The intervenors to the settlement agreement agreed not to oppose recovery of 80 percent of a future claimed deficiency but reserved the right to challenge the recovery of the remaining 20 percent. The FPSC has the right to review PEF’s storm costs for prudence. Storm reserve costs attributable to wholesale customers may be amortized consistent with recovery of such amounts in wholesale rates, albeit at a specified amount per year resulting in an extended recovery period.

PEC does not maintain a storm damage reserve account and does not have an ongoing regulatory mechanism to recover storm costs. PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over five-year periods. PEC did not seek deferral of storm costs from the NCUC or SCPSC during 2006 or 2005.

Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our commercial and industrial customers as well as the demand and competitive state of the wholesale market.

The Utilities are impacted by the economic cycles of the customers we serve. For the year ended December 31, 2006, commercial and industrial customers represented approximately 43 percent and 34 percent of PEC’s and PEF’s billed electric revenues, respectively. Consequently, if our commercial and industrial customers experience economic downturns, their consumption of electricity may drop and our revenues can be negatively impacted. In recent years, in North Carolina and South Carolina, sales to industrial customers have been affected by downturns in the textile and chemical industries.

For the year ended December 31, 2006, 18 percent and seven percent of PEC’s and PEF’s billed electric revenues, respectively, were from wholesale sales. Wholesale revenues fluctuate with regional demand, fuel prices and contracted capacity. Our wholesale profitability is dependent upon our ability to renew or replace expiring wholesale contracts on favorable terms and market conditions.

In 2004, the FERC issued orders concerning utilities’ ability to sell wholesale electricity at market-based rates, including the adoption of two interim screens for assessing an applicant’s potential generation market power for determining whether the applicant should be allowed to sell wholesale electricity at market-based rates. The Utilities do not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believed it would experience in passing one of the interim screens, PEC filed revisions to its market-based rate tariffs restricting PEC to sales outside of PEC’s control area and peninsular Florida, and filed a new cost-based tariff for sales within PEC’s control area. The FERC has accepted these revised tariffs. We do not anticipate that the operations of the Utilities will be materially impacted by these market-based rates decisions.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs. Increased competition may also result from power industry consolidation. Increased competition could adversely affect the financial condition, results of operations or cash flows of us and the Utilities.

Increased competition resulting from deregulation or restructuring efforts or from industry consolidation could have a significant adverse financial impact on us and consequently, on our results of operations and cash flows. Retail competition and the unbundling of regulated energy service could have a significant adverse financial impact on us due to lower electric operating revenues, potential impairment of generation assets, loss of retail customers, or increased costs of capital. Because we have not previously operated in a competitive retail environment, we cannot predict the extent to which additional competitors would enter the market or the timing of such entry. To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give retail customers the right to choose their electricity provider or otherwise restructure or deregulate the

28

electric industry. We cannot predict when or if we will be subject to changes in legislation or regulation nor can we predict the impact of these changes on our financial condition, results of operations or cash flows.

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

We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related commodities as a result of our ownership of energy-related assets. We have hedging strategies in place to mitigate negative fluctuations in commodity supply prices, but to the extent that we do not cover our entire exposure to commodity price fluctuations, or our hedging procedures do not work as planned, there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. While the Utilities’ state utility commissions allow recovery of certain of these costs through various cost-recovery clauses, there is the potential that a portion of these future costs could be deemed imprudent by the Utilities’ respective commissions. There is also a delay between the timing of when such costs are incurred and when the costs are recovered from the ratepayers. This lag can adversely impact the cash flow of the Utilities and, consequently, our interest expense.

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

§   weather conditions;

§   seasonality;

§   power usage;

§   illiquid markets;

§   transmission or transportation constraints or inefficiencies;

§   availability of competitively priced alternative energy sources;

§   demand for energy commodities;

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

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

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

In addition, we anticipate significant capital expenditures for environmental compliance and baseload generation. The completion of these projects within established budgets is contingent upon many variables including the securing of labor and materials at estimated costs. Recently, certain construction commodities such as steel have experienced significant price increases due to worldwide demand. Also, to operate our air pollution control equipment, we use significant quantities of ammonia and limestone. With mandated compliance deadlines for air pollution controls, demand for these reagents may increase and result in higher purchase costs. Furthermore, higher worldwide demand for copper used in our transmission and distribution lines has led to significant price increases. We are subject to the risk that cost overages may not be recoverable from ratepayers and our financial condition, results of operations or cash flows may be adversely impacted.

Prices for SO₂ emission allowance credits under the EPA’s emission trading program increased significantly during 2005 and then significantly declined by the end of 2006. While SO₂ allowances are eligible for annual recovery in PEF’s jurisdictions in Florida and PEC’s in South Carolina, no such annual recovery exists in North Carolina for PEC. Future increases in the price of SO₂ allowances could have a significant adverse financial impact on us and PEC and consequently, on our results of operations and cash flows.

As a holding company with no revenue-generating operations, the Parent is dependent on upstream cash flows from its subsidiaries, primarily the Utilities. As a result, our ability to meet our ongoing and future debt service and other financial obligations and to pay dividends on our common stock is primarily dependent on the earnings and cash flows of our operating subsidiaries and their ability to pay upstream dividends or to repay funds due to us.

The Parent is a holding company and as such, has no revenue-generating operations of its own. The Parent’s ability to meet its financial obligations associated with the debt service obligations on $2.6 billion of holding company debt and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily the Utilities, and the ability of its subsidiaries to pay upstream dividends or to repay funds due the Parent. Prior to funding the Parent, its subsidiaries have financial obligations that must be satisfied,

29

including among others, their respective debt service, preferred dividends and obligations to trade creditors. Should the Utilities not be able to pay dividends or repay funds due to the Parent, the Parent’s ability to pay interest and dividends would be restricted.

Divesting of nonregulated subsidiaries may take longer than expected, may result in unexpected additional charges and may not yield the benefits that we expect.

Consistent with our announced intention to reduce holding company debt and business risk, we have divested of a number of nonregulated businesses. Certain of our divestitures announced in 2006 are expected to close during 2007. We have recognized known or estimated expenses related to these divestitures but future additional charges may be recognized depending on changes in market conditions, the transfer of existing contracts and ultimate settlement of carryover liabilities, among other factors. Such charges for the CCO divestiture could exceed $200 million. In addition, completion of these anticipated divestitures may take significantly longer than expected, thus increasing our costs and delaying our ability to benefit from such divestitures.

The rates that PEC and PEF may charge retail customers for electric power are subject to the authority of state regulators. Accordingly, our profit margins could be adversely affected if we do not control costs.

The NCUC, the SCPSC and the FPSC each exercises regulatory authority for review and approval of the retail electric power rates charged within its respective state. With the Utilities’ expected increased expenditures for environmental compliance, baseload generation and higher commodity prices, we anticipate that the Utilities’ operations will be subject to an even higher level of scrutiny from regulators, policymakers and ratepayers. State regulators may not allow PEC and PEF to increase retail rates in the manner or to the extent requested. State regulators may also seek to reduce or freeze retail rates.

Both PEC and PEF currently operate under base rate freezes, in which base rates can only be changed under certain circumstances. The costs incurred by PEC and PEF are generally not subject to being fixed or reduced by state regulators. The Utilities’ results of operations could be negatively impacted if the Utilities do not manage their costs effectively. Our ability to maintain our profit margins depends upon stable demand for electricity and management of our costs.

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

PEC (four units; 3,485 MW) and PEF (one unit; 838 MW) own and operate five nuclear units that collectively represented approximately 4,323 MW, or 20 percent, of our regulated generation capacity for the year ended December 31, 2006. In addition, we are exploring the possibility of expanding our nuclear generating capacity with two additional units at both PEC and PEF to meet future expected baseload generation needs. Our nuclear facilities are subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate capital reserves for decommissioning, limitations on amounts and types of insurance available, potential operational liabilities, and the costs of securing the facilities against possible terrorist attacks. We maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, damages from an accident or business interruption at our nuclear units could exceed the amount of our insurance coverage.

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

30

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

Meeting the anticipated growth in our service territories may require, among other things, the construction within the next decade of new coal and/or nuclear generation facilities to increase our baseload generation and the siting and construction of associated transmission facilities. We may not be able to obtain required licenses, permits and rights-of-way; successfully and timely complete construction; or recover the cost of such new generation and transmission facilities through our base rates, any of which could adversely impact our financial condition, cash flows or results of operations.

Meeting the anticipated growth within the Utilities’ service territories will require a balanced approach. The three main elements of this balanced solution are: (i) increasing energy efficiency and investing in the development of new energy resources for the future; (ii) modernizing existing plants to produce energy more efficiently using state-of-the-art technology; and (iii) investing in new generating plants and associated transmission facilities. The risks of each of these elements are discussed below:

Energy Efficiency and New Energy Resources

We are actively pursuing expansion of our energy efficiency and conservation programs through residential energy inspections, demand side management programs and providing energy conservation tips to our customers. We are subject to the risk that our customers may not participate in our conservation programs or the forecasted results from these programs may be less than anticipated requiring us to further expand our baseload generation or purchase additional power.

Current proposals at the state and federal levels for renewable energy standards could require the Utilities to produce or buy a portion of their energy from renewable energy sources. Mandated standards could result in the use of renewable fuels that are not cost-effective in order to comply with requirements to have renewable energy be a specified percentage of the Utilities’ energy mix. Currently, we partner with organizations throughout our service territories to support hydrogen, solar and other forms of renewable and alternative energy. We have invested in research for alternative energy sources that might subsequently be determined to not be cost-efficient or cost-effective, thus subjecting us to the risks of further expanding our baseload generation or purchasing additional power on the open market at then-prevailing prices.

Modernization and Construction of Generating Plants

We are currently evaluating our options for new generating plants, including coal and nuclear technologies. At this time, no definitive decision has been made regarding the construction of either coal or nuclear plants, or both. If we decide to construct new generation facilities or expand or modernize existing facilities, there is no assurance that we will be able to successfully and timely complete the projects within our projected budgets. These projects are long-term and potentially would be subject to significant cost increases for labor and materials. Should any such construction, expansion or modernization efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement. Furthermore, we have no assurance that costs incurred to construct, expand or modernize generation and associated transmission facilities will be recoverable through our base rates.

The decision to build a baseload power plant will be based on several factors including:

·   power market conditions;

·   competing fuel prices and fuel diversity;

·   the regulatory environment;

·   time required to permit and construct;

·   environmental impact;

·   both public and policymaker support;

·   siting and construction of transmission facilities;

·   cost and availability of construction materials and labor; and

31

·   the ability to obtain financing on favorable terms.

The construction of a new baseload plant and associated expansion of our transmission system will require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support the construction. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation facilities, but we cannot be certain we will be able to successfully negotiate any such arrangement. Furthermore, joint ventures or joint ownership arrangements also present risks and uncertainties, including those associated with sharing control over the construction and operation of a facility and reliance on the other party’s financial or operational strength.

Coal

In addition to the risks discussed above, the construction of a coal-fired power plant requires a number of conditions to be successful. These include, but are not limited to, consideration of emissions of NOx, SO₂ and mercury; an efficient licensing process; disposal of coal byproducts such as slag and fly ash; and anticipated regulation of carbon.

As discussed earlier, air pollution control equipment requires the use of significant amounts of ammonia and limestone which may be in high demand and have a resulting higher purchase price.

Nuclear

In addition to the risks discussed above, the successful construction of a new nuclear power plant requires a number of conditions. The conditions include, but are not limited to: the continued operation of the industry’s existing nuclear fleet in a safe, reliable, and cost-effective manner, an efficient licensing process, and a viable program for managing spent nuclear fuel. We cannot provide certainty that these conditions will exist.

We have announced that we are pursuing development of COL applications. Our announcement is not a commitment to build a nuclear plant. It is a necessary step to keep open the option of building a potential plant or plants. We have selected a site in North Carolina and a site in Florida to evaluate for possible future nuclear expansion. We currently expect to file the application for the COL for PEC’s site in 2007 and PEF’s site in 2008. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, construction activities could begin as early as 2010, and new plants could be online in late 2016.The NRC estimates that it will take approximately three to four years to review and process the COL applications.

EPACT provides for an annual tax credit of 1.8 cents/kWh for nuclear facilities for the first eight years of operation. However, the credit is limited to the first 6,000 MW of new nuclear generation in the United States that have met the permitting, construction and placed-in-service milestones specified by EPACT and has an annual cap of $125 million per unit. The credit allocation process among new nuclear plants has not been determined. Other utilities have announced plans to pursue new nuclear plants. There is no guarantee that any nuclear plant constructed by us would qualify for these additional incentives. Failure to qualify for these incentives could significantly impact the economics of building a nuclear facility.

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

Under rules recently issued by the FPSC, Florida utilities will be allowed to recover prudently incurred siting, preconstruction costs and allowance for funds used during construction (AFUDC) on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in a utility’s rate base when the plant is placed in commercial operation. In addition, the rule will require the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility.

32

While we currently estimate that we will need to increase our baseload capacity, our assumptions regarding future growth and resulting power demand in our service territories may not be realized. If anticipated growth levels are not realized, we may increase our baseload capacity and have excess capacity. This excess capacity may exceed the reserve margins established by the NCUC, SCPSC and FPSC to meet our obligation to serve retail customers and, as a result, may not be recoverable in base rates.

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

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

§   operator error and breakdown or failure of equipment or processes;

§   operational limitations imposed by environmental or other regulatory requirements;

§   inadequate or unreliable access to transmission and distribution assets;

§   labor disputes;

§   interruptions of fuel supply;

§   compliance with mandatory reliability standards for the bulk power electric system when such standards are adopted and as subsequently revised; and

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

We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity that we sell to the retail and wholesale markets. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered. Although the FERC has issued regulations designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets.

We anticipate that mandatory reliability standards will be in place by the summer of 2007. We expect these standards will become stricter over time. The financial impact of mandatory compliance cannot currently be determined. If we are unable to meet the reliability standards for the bulk power electric system in the future, it could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, failure to comply with the reliability standards could result in the imposition of fines and penalties.

A decrease in operational performance from the Utilities’ generating facilities and delivery systems or an increase in the cost of operating the facilities could have an adverse effect on our business and results of operations.

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

Our cash requirements are driven by the capital-intensive nature of our Utilities. In addition to operating cash flows, we rely heavily on commercial paper and long-term debt. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy will be adversely affected. We believe that we will continue to have sufficient access to these financial markets based upon our current credit ratings. However, market disruptions beyond our control or a downgrade of our credit ratings could increase our cost of borrowing and may adversely affect our ability to access the financial markets.

33

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

As discussed above, we rely heavily on our commercial paper and long-term debt. At December 31, 2006, we had no commercial paper outstanding or other short-term borrowings and our long-term debt balances were as follows:

(in millions)	Total Long-Term Debt, Net
Progress Energy, unconsolidated (a)	$	2,581
PEC		3,470
PEF		2,468
Other subsidiaries (b)		316
Progress Energy, consolidated (c)	$	8,835

^(a) Represents solely the outstanding indebtedness of the Parent.

^(b) Includes the following subsidiaries: Florida Progress Funding Corporation ($271 million) and Progress Capital Holdings, Inc. ($45 million).

^(c) Net of current portion, which at December 31, 2006, was $324 million on a consolidated basis.

At December 31, 2006, we had an aggregate of three committed revolving credit agreements (RCAs) that supported our commercial paper programs totaling $2.030 billion. Our internal financial policy precludes us from issuing commercial paper in excess of our revolving credit lines. At December 31, 2006, we had no outstanding borrowings under our credit facilities and had a total amount of $60 million of letters of credit issued, leaving an additional $1.970 billion available for future borrowing under our revolving credit lines.

Our revolving credit lines impose various limitations that could impact our liquidity, such as defined maximum total debt to total capital (leverage) ratios. Under these revolving credit facilities, indebtedness includes certain letters of credit and guarantees which are not recorded on the Consolidated Balance Sheets. At December 31, 2006, the required and actual ratios, pursuant to the terms of the credit agreements were as follows:

	Leverage Ratios
	Maximum Ratio	Actual Ratio (a)
Progress Energy, Inc.	68%	55.4%
PEC	65%	52.3%
PEF	65%	49.4%

 ^(a)   Indebtedness as defined by the bank agreements includes certain letters of credit and guarantees that are not recorded on the Consolidated Balance Sheets.

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 could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility. Progress Energy, Inc.’s cross-default provision applies only to Progress Energy, Inc. and its significant subsidiaries, as defined in the credit agreement, (i.e., PEC, Florida Progress, PEF, Progress Capital Holdings, Inc. and Progress Energy Ventures, Inc. (PVI)). PEC’s and PEF’s cross-default provisions apply only to 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

34

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.

As described in MD&A - “Strategy” and MD&A - “Future Liquidity and Capital Resources,” we are anticipating extensive capital needs for new generation, transmission and distribution facilities, and environmental compliance expenditures. Funding these capital needs could increase our leverage and present numerous risks including those addressed below.

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

§   increasing the cost of future debt financing;

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

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

§   limiting our ability to obtain additional financing, if needed, for working capital, acquisitions, debt service requirements or other purposes;

§   increasing our vulnerability to adverse economic and industry conditions;

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

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

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

§   causing a downgrade in our credit ratings.

Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our floating rate debt and reduce funds available to us for our current plans.

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

While the long-term target credit ratings for the Parent and the Utilities are above the minimum investment grade rating, we cannot provide certainty that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Unlike the contracts described below, our debt indentures and credit agreements do not contain any “ratings triggers,” which would cause the acceleration of interest and principal payments in the event of a ratings downgrade. Any downgrade could increase our borrowing costs and may adversely affect our access to capital, which could negatively impact our financial results and business plans. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities or those of PEC or PEF and that each agency’s rating should be evaluated independently of any other agency’s rating.

As a part of normal business, we enter into various agreements that provide future financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include performance obligations under power supply agreements, tolling 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, 2006, we have issued $1.489 billion of guarantees for future financial or performance assurance. We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

35

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below Baa3 or BBB-) by Moody’s Investors Service, Inc. (Moody’s) or Standard & Poor’s Rating Services (S&P) for the Parent’s senior unsecured debt rating, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. At December 31, 2006, the Parent’s senior unsecured debt rating was Baa2 by Moody’s and BBB- by S&P, and no guarantee obligations had been triggered. If the guarantee obligations were triggered, the maximum amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for Progress Energy’s nonregulated portfolio and power supply agreements was approximately $596 million at December 31, 2006. While we believe that we would be able to meet this obligation with cash or letters of credit, if we cannot, our financial condition, liquidity and results of operations would be materially and adversely impacted.

The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. We could recognize future financial losses on these contracts as a result of volatility in the market values of the underlying commodities.

Additionally, we are exposed to risk that our counterparties will not be able to perform their obligations. Should our counterparties fail to perform, we might be forced to replace the underlying commitment at then-current market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.

Our results of operations may be materially affected if our earnings from synthetic fuels are reduced due to the high price of oil. Our ability to utilize tax credits may be limited. This risk is not applicable to PEC and PEF.

Section 29/45K provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the Annual Average Price) exceeds a certain threshold value (the Threshold Price), the amount of Section 29/45K tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the Phase-out Price), the Section 29/45K tax credits are eliminated for that year. The Threshold Price and the Phase-out Price are adjusted annually for inflation.

In January 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 is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The contracts will be marked-to-market with changes in fair value recorded through earnings. Our synthetic fuels production levels for 2007 remain uncertain because we cannot predict with any certainty the Annual Average Price of oil for 2007. We will continue to monitor the environment surrounding synthetic fuels production and will adjust our production as warranted by changing conditions.

In accordance with the provisions of Section 29/45K, we have generated tax credits based on the content and quantity of synthetic fuels produced and sold. This tax credit program is scheduled to expire at the end of 2007. We have received favorable private letter rulings from the IRS on all of our synthetic fuels facilities. In order to claim credits under Section 29/45K, among other things, we must produce qualifying fuel and sell our production to unrelated parties. In the normal course of business, our tax returns are audited by the IRS. If our tax credits were disallowed in whole or in part as a result of an IRS audit, there could be significant additional tax liabilities and associated interest for previously recognized tax credits, which could have a material adverse impact on our earnings and cash flows. Although we are unaware of any currently proposed legislation or new IRS regulations or interpretations impacting synthetic fuels tax credits, the value of credits generated could be unfavorably impacted by such legislation or IRS regulations and interpretations.

We previously sold a portion of our interests in our synthetic fuels facilities and expect to receive cash payments from the sales through 2008, subject to production levels. We continue to operate these facilities on our own behalf and on behalf of others and consequently, continue to bear the operational risks from the synthetic fuels facilities. We also provided certain guarantees and indemnities in conjunction with our sale of interests in those synthetic fuels

36

facilities. Further, we also operate several synthetic fuels facilities for third parties and also bear operational risk for such facilities.

We are subject to risks from the operation of our nonregulated plants, including dependence on third parties and related counterparty risks, all of which may make our nonregulated generation and overall operations less profitable and more unstable. These risks are not applicable to PEC and PEF.

On December 13, 2006, Progress Energy’s board of directors approved a plan to pursue the disposition of substantially all of PVI's CCO physical and commercial assets. CCO currently owns four electricity generation facilities with approximately 1,900 MW of generation capacity, and it has contractual rights to an additional 2,500 MW of generation capacity from mixed fuel generation facilities. CCO also has forward gas and power contracts, gas transportation, storage and structured power and other contracts, including its full requirements contracts with 16 Georgia electric membership cooperatives (the Georgia Contracts). The disposition plan is expected to be completed in 2007. The operation of nonregulated generation facilities is subject to many risks, including those listed below. Until the completion of our disposition strategy, we are subject to risks, including:

·   CCO has entered into long-term agreements to sell all or a portion of their generating capacity. CCO has contracts for its combined production capacity of approximately 81 percent for 2007. We anticipate that a third party will acquire these contracts as part of our divestiture strategy. Prior to divestiture of the facilities, uncontracted generation from our facilities will generally be sold on the spot market. CCO may not be able to find adequate purchasers, attain favorable pricing, or otherwise compete effectively in the wholesale market. Additionally, numerous legal and regulatory limitations restrict our ability to operate a facility on a wholesale basis. If CCO divests of its generation facilities, but not the Georgia Contracts, CCO will continue to fulfill the contractual obligation through tolling agreements or purchases in the spot market at then-prevailing prices. If we are unable to secure favorable pricing in the spot market, our results of operations could be negatively impacted.

·   Our nonregulated generation facilities depend on third parties through agreements for fuel supply and transportation and transmission grid connection. If such third parties breach their obligations to us, our revenues, financial condition, cash flow and ability to make payments of interest and principal on our outstanding debts may be impaired. Any material breach by any of these parties of their obligations under the project contracts could adversely affect our cash flows.

·   We depend on unaffiliated transmission and distribution facilities to deliver the electricity that CCO sells to the wholesale market. If transmission is disrupted, or if capacity is inadequate, CCO’s ability to sell and deliver products and satisfy its contractual obligations may be hindered. Although the FERC has issued regulations designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets.

·   Agreements with our counterparties frequently will include the right to terminate and/or withhold payments or performance under the contracts if specific events occur. If such a contract were to be terminated due to nonperformance by us or by the other party to the contract, our ability to enter into a substitute agreement having substantially equivalent terms and conditions is uncertain.

·   Operation of our facilities could be affected by many factors, including the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency, failure to operate at design specifications, labor disputes, changes in law, failure to obtain necessary permits or to meet permit conditions, governmental exercise of eminent domain power or similar events, and catastrophic events including fires, explosions and earthquakes.

·   CCO has entered into long-term contracts that take effect at a future date based upon future expected nonregulated generation capacity. We anticipate that a third party will acquire these contracts as part of our divestiture strategy. If our generating facilities do not operate as expected prior to transfer of the contracts, we

37

may not be able to meet our obligations under the contracts and may have to purchase power in the spot market at then-prevailing prices. If we are unable to secure favorable pricing in the spot market, our results of operations could be negatively impacted. We may also become liable under any related performance guarantees then in existence.

Our nonregulated energy marketing and trading operations are subject to risks that could reduce our revenues and adversely impact our results of operations and financial condition; some of these risks, such as weather-related risks, are beyond our control. Volatile commodity prices could reduce our margins. These risks are not applicable to PEC and PEF.

As discussed above, we are pursuing the disposition of substantially all of CCO’s physical and commercial assets. Until the completion of our disposition strategy, we will actively seek to manage the market risk inherent in our nonregulated energy marketing operations. We employ risk management monitoring and control techniques to manage the risks inherent in the business. Nonetheless, adverse changes in energy and fuel prices may result in losses in our earnings or cash flows and adversely affect our financial position. Our marketing and risk management procedures do not completely eliminate risk. In addition, to the extent that we do not cover the entire exposure of our assets or our positions to market price volatility, or our hedging procedures do not work as planned, fluctuating commodity prices could cause our sales and net income to be volatile. As a result, our results of operations and financial position are sensitive to the market risk factors discussed below.

Our fleet of nonregulated power plants sells energy into the spot market, other competitive power markets or on a longer-term contractual basis. We may also enter into contracts to purchase and sell electricity and coal as part of our power marketing and energy trading operations. Our business may also include entering into tolling contracts, long-term contracts that supply customers’ full electric requirements, or other contractual structures.

The Georgia Contracts provide a fixed price for the power we supply to the cooperatives. These contracts do not provide a guaranteed rate of return on our capital investments through mandated rates. The cooperative load is dependent on the weather and economy of its service area. We use a combination of callable resources from the cooperatives, open market purchases and our own generating assets to serve this load. The risks in serving full requirements supply contracts at a fixed price include both the variability in commodity prices and the volatility of the cooperative energy demand. While these contracts are partially hedged through fixed price power and gas purchases, our revenues and results of operations from these contracts still depend to some degree upon prevailing market prices for power in our regional markets and surrounding competitive markets. These market prices can fluctuate substantially over relatively short periods of time. We anticipate transferring these contracts to a third party as part of our disposition strategy.

The FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. As discussed previously, fuel prices also may be volatile, and the price we can obtain for power sales may not change at the same rate as our fuel costs changes. These factors could reduce our margins and therefore diminish our revenues and results of operations.

Our nonregulated businesses are involved in operations that are subject to significant operational and financial risks that may reduce our revenues and adversely impact our results of operations and financial condition. These risks are not applicable to PEC and PEF.

We are exposed to operational risk resulting from our coal mining and terminal operations. Our coal mining operations are subject to conditions beyond our control that can delay deliveries or increase the cost of mining at particular locations for varying lengths of time. Such conditions include unexpected maintenance problems, key equipment failures and variations in geologic conditions. The states in which we operate coal mines have state programs for mine safety and health regulation and enforcement. Financial risks include our exposure to commodity prices, primarily fuel prices. We actively manage the operational and financial risks associated with these businesses. Nonetheless, adverse changes in fuel prices and operational issues beyond our control may result in losses in our earnings or cash flows and adversely affect our balance sheet.

38

ITEM 1B.UNRESOLVED STAFF COMMENTS

None

ITEM 2.PROPERTIES

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

ELECTRIC - PEC

PEC’s 18 generating plants represent a flexible mix of fossil, nuclear, hydroelectric, combustion turbines and combined cycle resources, with a total summer generating capacity of 12,409 MW. Of this total, Power Agency owns 699 MW. On December 31, 2006, PEC had the following generating facilities:

Facility	Location	No. of Units	In-Service Date	Fuel	PEC Ownership (in %)	Summer Net Capability (a) (in MW)
STEAM TURBINES
Asheville	Arden, N.C.	2	1964-1971	Coal	100	383
Cape Fear	Moncure, N.C.	2	1956-1958	Coal	100	317
Lee	Goldsboro, N.C.	3	1951-1962	Coal	100	406
Mayo	Roxboro, N.C.	1	1983	Coal	83.83	741	(b)
Robinson	Hartsville, S.C.	1	1960	Coal	100	180
Roxboro	Semora, N.C.	4	1966-1980	Coal	96.29 (c)	2,425	(b)
Sutton	Wilmington, N.C.	3	1954-1972	Coal	100	606
Weatherspoon	Lumberton, N.C.	3	1949-1952	Coal	100	177
	Total	19				5,235
COMBINED CYCLE
Cape Fear	Moncure, N.C.	2	1969	Oil	100	70
Richmond	Hamlet, N.C.	1	2002	Gas/Oil	100	454
	Total	3				524
COMBUSTION TURBINES
Asheville	Arden, N.C.	2	1999-2000	Gas/Oil	100	328
Blewett	Lilesville, N.C.	4	1971	Oil	100	52
Darlington	Hartsville, S.C.	13	1974-1997	Gas/Oil	100	792
Lee	Goldsboro, N.C.	4	1968-1971	Oil	100	75
Morehead City	Morehead City, N.C.	1	1968	Oil	100	12
Richmond	Hamlet, N.C.	5	2001-2002	Gas/Oil	100	777
Robinson	Hartsville, S.C.	1	1968	Gas/Oil	100	15
Roxboro	Semora, N.C.	1	1968	Oil	100	12
Sutton	Wilmington, N.C.	3	1968-1969	Gas/Oil	100	59
Wayne County	Goldsboro, N.C.	4	2000	Gas/Oil	100	686
Weatherspoon	Lumberton, N.C.	4	1970-1971	Gas/Oil	100	132
	Total	42				2,940
NUCLEAR
Brunswick	Southport, N.C.	2	1975-1977	Uranium	81.67	1,875	(b)
Harris	New Hill, N.C.	1	1987	Uranium	83.83	900	(b)
Robinson	Hartsville, S.C.	1	1971	Uranium	100	710
	Total	4				3,485
HYDRO
Blewett	Lilesville, N.C.	6	1912	Water	100	22
Marshall	Marshall, N.C.	2	1910	Water	100	5
Tillery	Mount Gilead, N.C.	4	1928-1960	Water	100	86
Walters	Waterville, N.C.	3	1930	Water	100	112
	Total	15				225
TOTAL		83				12,409

^(a)   Summer ratings reflect compliance with new NERC reliability standards and are gross of joint ownership interest.

^(b)   Facilities are jointly owned by PEC and Power Agency. The capacities shown include Power Agency’s share.

^(c)   PEC and Power Agency are joint owners of Unit 4 at the Roxboro Plant. PEC’s ownership interest in this 698 MW unit is 87.06 percent.

At December 31, 2006, including both the total generating capacity of 12,409 MW and the total firm contracts for purchased power of 1,461 MW, PEC had total capacity resources of approximately 13,870 MW.

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

At December 31, 2006, PEC had approximately 6,000 circuit miles of transmission lines including 300 miles of 500 kilovolt (kV) lines and 3,000 miles of 230 kV lines. PEC also had approximately 45,000 circuit miles of overhead distribution conductor and 19,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 12.5 million kilovolt-ampere (kVA) in approximately 2,400 transformers. Distribution line transformers numbered approximately 525,000 with an aggregate capacity of approximately 22.4 million kVA.

ELECTRIC - PEF

PEF’s 14 generating plants represent a flexible mix of fossil, nuclear, combustion turbine and combined cycle resources with a total summer generating capacity of 8,913 MW. Of this total, joint owners own 117 MW. At December 31, 2006, PEF had the following generating facilities:

Facility	Location	No. of Units	In-Service Date	Fuel	PEF Ownership (in %)	Summer Net Capability(a) (in MW)
STEAM TURBINES
Anclote	Holiday, Fla.	2	1974-1978	Gas/Oil	100	1,005
Bartow	St. Petersburg, Fla.	3	1958-1963	Gas/Oil	100	444
Crystal River	Crystal River, Fla.	4	1966-1984	Coal	100	2,313
Suwannee River	Live Oak, Fla.	3	1953-1956	Gas/Oil	100	141
	Total	12				3,903
COMBINED CYCLE
Hines	Bartow, Fla.	3	1999-2005	Gas/Oil	100	1,456
Tiger Bay	Fort Meade, Fla.	1	1997	Gas	100	203
	Total	4				1,659
COMBUSTION TURBINES
Avon Park	Avon Park, Fla.	2	1968	Gas/Oil	100	50
Bartow	St. Petersburg, Fla.	4	1972	Gas/Oil	100	176
Bayboro	St. Petersburg, Fla.	4	1973	Oil	100	177
DeBary	DeBary, Fla.	10	1975-1992	Gas/Oil	100	643
Higgins	Oldsmar, Fla.	4	1969-1971	Gas/Oil	100	110
Intercession City	Intercession City, Fla.	14	1974-2000	Gas/Oil	100 (b)	992	(c)
Rio Pinar	Rio Pinar, Fla.	1	1970	Oil	100	13
Suwannee River	Live Oak, Fla.	3	1980	Gas/Oil	100	157
Turner	Enterprise, Fla.	4	1970-1974	Oil	100	150
University of Florida Cogeneration	Gainesville, Fla.	1	1994	Gas	100	45
	Total	47				2,517
NUCLEAR
Crystal River	Crystal River, Fla.	1	1977	Uranium	91.78	838	(c)
	Total	1				838
TOTAL		64				8,913

^(a)   Summer ratings reflect compliance with new NERC reliability standards and are gross of joint ownership interest.

^(b)   PEF and Georgia Power Company (Georgia Power) are joint owners of a 143 MW advanced combustion turbine located at PEF’s Intercession City site. Georgia Power has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year.

^(c)   Facilities are jointly owned. The capacities shown include joint owners’ share.

During 2006, including both the total generating capacity of 8,913 MW and the total firm contracts for purchased power of 2,073 MW, PEF had total capacity resources of approximately 10,986 MW.

Several entities have acquired undivided ownership interests in CR3 in the aggregate amount of 8.22 percent. The joint ownership participants are: City of Alachua - 0.08 percent, City of Bushnell - 0.04 percent, City of Gainesville - 1.41 percent, Kissimmee Utility Authority - 0.68 percent, City of Leesburg - 0.82 percent, Utilities Commission of the City of New Smyrna Beach - 0.56 percent, City of Ocala - 1.33 percent, Orlando Utilities Commission - 1.60 percent and Seminole Electric Cooperative, Inc. - 1.70 percent. PEF and Georgia Power are co-owners of a 143 MW advance combustion turbine located at PEF’s Intercession City Unit P11. Georgia Power has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year. Otherwise, PEF has good and marketable title to its principal plants and units, subject to the lien of its mortgage and deed of trust, with minor exceptions, restrictions and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. PEF also owns certain easements over private property on which transmission and distribution lines are located.

At December 31, 2006, PEF had approximately 5,000 circuit miles of transmission lines including 200 miles of 500 kV lines and about 1,500 miles of 230 kV lines. PEF also had approximately 18,000 circuit miles of overhead distribution conductor and 13,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 16 million kVA in approximately 700 transformers.

Distribution line transformers numbered approximately 386,000 with an aggregate capacity of approximately 19 million kVA.

COAL AND SYNTHETIC FUELS

The Coal and Synthetic Fuels business segment has an interest in six synthetic fuels entities. Five of the entities are majority owned and one is minority owned. These facilities are in several different locations in West Virginia and Kentucky.

Through our subsidiaries, we own and operate a river terminal facility in eastern Kentucky, a railcar-to-barge loading facility in West Virginia, two bulk commodity terminals on the Kanawha River near Charleston, West Virginia, and a bulk commodity terminal on the Ohio River near Huntington, West Virginia.

In connection with our coal operations, we own and operate surface and underground mines, coal processing and loadout facilities in southeastern Kentucky and southwestern Virginia. We control either directly or through our subsidiaries, demonstrated coal reserves of approximately 76.5 million tons. The reserves controlled include substantial quantities of high quality, low-sulfur coal. Our total production of coal during 2006 was approximately 1.8 million tons. We employ both our own miners as well as contract miners in our mining activities.

COMPETITIVE COMMERICAL OPERATIONS

On December 13, 2006, our board of directors approved a plan to pursue the disposition of substantially all of CCO’s physical and commercial assets. As a result, we have classified CCO’s operations as discontinued operations in the accompanying consolidated financial statements for all periods presented (See Note 3F).

At December 31, 2006, CCO had the following nonregulated generation plants in service.

Project	Location	Commercial Operation Date	Configuration/ Number of Units	MW (a)
Monroe Units 1 and 2	Monroe, Ga.	1999-2001	Simple-Cycle, 2	315
Walton	Monroe, Ga.	2001	Simple-Cycle, 3	460
Effingham	Rincon, Ga.	2003	Combined-Cycle, 1	480
Washington	Sandersville, Ga.	2003	Simple-Cycle, 4	600
TOTAL				1,855

^(a)Amounts represent CCO’s summer rating.

ITEM 3.LEGAL PROCEEDINGS

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

During 2006, we did not have any “reportable transactions” as defined under Section 6011 of the Code nor did we incur any penalties related to failing to report such information on our tax returns.

ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

The information called for by Item 4 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

EXECUTIVE OFFICERS OF THE REGISTRANTS

AS OF FEBRUARY 28, 2007

Name	Age	Recent Business Experience
*Robert B. McGehee	63	Chairman and Chief Executive Officer, Progress Energy, May 2004 and March 2004, respectively, to present. Mr. McGehee joined Progress Energy (formerly Carolina Power & Light Company “CP&L”) in 1997 as Senior Vice President and General Counsel. Since that time, he has held several senior management positions of increasing responsibility. Most recently, Mr. McGehee served as President and Chief Operating Officer, having responsibility for the day-to-day operations of our regulated and nonregulated businesses. Prior to that, Mr. McGehee served as President and Chief Executive Officer of Progress Energy Service Company, LLC. Before joining Progress Energy, Mr. McGehee chaired the board of Wise Carter Child & Caraway, a law firm headquartered in Jackson, Miss. He primarily handled corporate, contract, nuclear regulatory and employment matters. During the 1990s, he also provided significant counsel to U.S. companies on reorganizations, business growth initiatives and preparing for deregulation and other industry changes.
William D. Johnson	53	President and Chief Operating Officer, Progress Energy, January 2005 to present; Group President, PEC, May 2004 to present; Executive Vice President, PEF, November 2000 to present; Executive Vice President, Florida Progress, May 2004 to present; Corporate Secretary, PEC, PEF, Progress Energy Service Company, LLC and Florida Progress November 2000 to December 2003. Mr. Johnson has been with Progress Energy (formerly CP&L) since 1992 and served as Group President, Energy Delivery, Progress Energy, January 2004 to December 2004. Prior to that, he was President, CEO and Corporate Secretary,Progress Energy Service Company, LLC, October 2002 to December 2003. He also served as Executive Vice President - Corporate Relations & Administrative Services, General Counsel and Secretary of Progress Energy. Mr. Johnson served as Vice President - Legal Department and Corporate Secretary, CP&L from 1997 to 1999. Before joining Progress Energy, Johnson was a partner with the Raleigh office of Hunton &

		Williams, where he specialized in the representation of utilities.
Peter M. Scott III	57	Executive Vice President and Chief Financial Officer, Progress Energy, May 2000 to present; and May 2000 to December 2003 and November 2005 to present; President and Chief Executive Officer, Progress Energy Service Company, LLC, January 2004 to present; Executive Vice President, PEC and PEF, May 2000 to present and CFO of PEC, PEF, FPC and Progress Energy Service Company, LLC, 2000 to 2003, and November 2005 to present. Mr. Scott has been with Progress Energy since May 2000. Before joining Progress Energy, Mr. Scott was the president of Scott, Madden & Associates, Inc., a general management consulting firm headquartered in Raleigh that he founded in 1983. The firm served clients in a number of industries, including energy and telecommunications. Particular practice area specialties for Mr. Scott included strategic planning and operations management.

Fred N. Day IV	63	President and Chief Executive Officer, PEC,November 2003 to present; Executive Vice President, PEF, November 2000 to present. Mr. Dayoversees all aspects of Carolinas Delivery operations, including distribution and customer service, transmission, and products and services. He previously served as Executive Vice President,PEC and PEF. During his more than 30 years with Progress Energy (formerly CP&L), Mr. Day has held several management positions of increasing responsibility. He was promoted to Vice President - Western Region in 1995.
Clayton S. Hinnant	62	Senior Vice President and Chief Nuclear Officer, PEC, June 1998 to present. Mr. Hinnant is also Senior Vice President and Chief Nuclear Officer, PEF, November 2000 and November 2005, respectively to present. Mr. Hinnant joined Progress Energy (formerly CP&L) in 1972 at the Brunswick Nuclear Plant near Southport, N.C., where he held several positions in the startup testing and operating organizations. He left Progress Energy in 1976 to work for Babcock and Wilcox in the Commercial Nuclear Power Division, returning to Progress Energy in 1977. Since that time, he has served in various management positions at three of Progress Energy’s nuclear plant sites.

*Jeffrey A. Corbett	47	Senior Vice President, PEF, June 15, 2006 to present. Mr. Corbett oversees operations and services in Florida, including engineering, distribution, construction, metering, power restoration, community relations, energy efficiency and alternative energy strategies. He previously served as vice president-Distribution for PEC from January 2005 to June 2006. He also served PEC as Vice President-Eastern Region from September 2002 to January 2005. Mr. Corbett joined Progress Energy in 1999 and has served Progress Energy in a number of roles, including General Manager of the Eastern Region and director of Distribution Power Quality and Reliability. Before joining Progress Energy, Corbett spent 17 years with Virginia Power, serving in a variety of engineering and leadership roles.
*Jeffrey J. Lyash	45	President and Chief Executive Officer, PEF, June 1, 2006 to present. Mr. Lyash oversees all aspects of PEF’s Delivery operations, including distribution and customer service, transmission, and products and services. He previously served as Senior Vice President of PEF from November 2003 through May 2006. Prior to coming to PEF, Mr. Lyash was Vice President - Transmission in Energy Delivery in the Carolinas since January 2002.

		Mr. Lyash joined Progress Energy in 1993 and spent his first eight years at the Brunswick Nuclear Plant in Southport, N.C. His last position at Brunswick was as Director of site operations.
John R. McArthur	51	Senior Vice President, General Counsel and Secretary of Progress Energy, January 2004 to present. Mr. McArthur oversees the Audit Services, Corporate Communications, Legal, Regulatory and Corporate Relations - Florida, and State Public Affairs departments, and the Environmental and Health and Safety sections. Mr. McArthur is also Senior Vice President and Corporate Secretary, FPC and PEC, and Senior Vice President, PEF and Progress Energy Service Company, LLC, January 1 2004 and December 2002, respectively to present. Previously, he served as Senior Vice President - Corporate Relations (December 2002 to December 2003) and as Vice President - Public Affairs (December 2001 to December 2002). Before joining Progress Energy in December 2001, Mr. McArthur was a member of North Carolina Governor Mike Easley’s senior management team, handling major policy initiatives as well as media and legal affairs. He also directed Governor Easley’s transition team after the election of 2000. From November of 1997 until November of 2000, Mr. McArthur handled state government affairs in 10 southeastern states for General Electric Co. Prior to joining General Electric Co., Mr. McArthur served as chief counsel in the North Carolina Attorney General’s office, where he supervised utility, consumer, health care, and environmental protection issues. Before that, he was a partner at Hunton & Williams.

*Mark F. Mulhern	47	President, Progress Energy Ventures, Inc. and Progress Fuels Corporation, March 2005 and April 2006, respectively to present. Mr. Mulhern is responsible for managing the Competitive Commercial Operations and Gas Operations groups of Progress Energy Ventures, Inc. He previously served Progress Energy Ventures, Inc. as Senior Vice President - Competitive Commercial Operations from January 2003 to March 2005. He served Progress Energy as Vice President - Strategic Planning from November 2000 to January 2003. He also served as Vice President and Treasurer of PEC from June 1997 to November 2000.
Paula J. Sims	45	Senior Vice President, PEC and PEF, April 2006 to present. Ms. Sims previously served PEC and PEF as Vice President-Fossil Generation from January 2006 to April 2006. Prior to that, she served PEC and PEF as Vice President-Regulated Fuels from December 2004 to December 2005. Ms. Sims served Progress Fuels Corporation as Chief Operating Officer from February 2002 to December 2004 and Vice President-Business Operations and Strategic Planning from June 2001 to February 2002. Prior to joining Progress Energy in 1999, Ms. Sims worked at General Electric for 15 years.
Jeffrey M. Stone	45	Chief Accounting Officer and Controller, Progress Energy and FPC, June 2005 to present; Chief Accounting Officer PEC and PEF, June 2005 and November 2005, respectively, to present; Vice President and Controller, Progress Energy Service Company, LLC, January 2005 and June 2005, respectively to present. Mr. Stone previously served as Controller of PEF and

PEC from June 2005 to November 2005. Since 1999, Mr. Stone has served Progress Energy in a number of roles in corporate support including Vice President - Capital Planning and Control; Executive Director - Financial Planning & Regulatory Services, as well as in various management positions with Energy Supply and Audit Services.

Prior to joining Progress Energy, Mr. Stone worked as an auditor with Deloitte & Touche in Charlotte, N.C.

E. Michael Williams	58	Senior Vice President, PEC and PEF, June 2000 and November 2000, respectively, to present. Before joining Progress Energy in 2000, Mr. Williams was with Central and Southwest Corp., Inc. and subsidiaries for 28 years and served in various positions prior to becoming Vice President - Fossil Generation in Dallas.
Lloyd M. Yates	46	Senior Vice President, PEC, January 2005 to present. Mr. Yates is responsible for managing the four regional vice presidents in the PEC organization. He served PEC as Vice President - Transmission from November 2003 to December 2004. Mr. Yates served as Vice President - Fossil Generation for PEC from November 1998 to November 2003. Before joining Progress Energy in 1998, Mr. Yates was with PECO Energy, where he had served in a number of engineering and management roles over 16 years. His last position with PECO was as general manager - Operations in the power operations group.

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

45

PART II

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

Progress Energy

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

	High		Low		Dividends Declared
2006
First Quarter	$	45.31	$	42.54	$	0.605
Second Quarter		45.16		40.27		0.605
Third Quarter		46.22		42.05		0.605
Fourth Quarter		49.55		44.40		0.610
2005
First Quarter	$	45.33	$	40.63	$	0.590
Second Quarter		45.83		40.61		0.590
Third Quarter		46.00		41.90		0.590
Fourth Quarter		45.50		40.19		0.605

The December 31 closing price of our Common Stock was $49.08 for 2006 and $43.92 for 2005. As of February 23, 2007, we had 61,604 holders of record of Common Stock.

Neither Progress Energy’s Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends. Our subsidiaries have provisions restricting dividends in certain limited circumstances (See Notes 10A and 12B).

Information regarding securities authorized for issuance under our equity compensation plans is included in Progress Energy’s definitive proxy statement for its 2007 Annual Meeting of Shareholders.

Issuer purchases of equity securities for fourth quarter of 2006 are as follows:

Period	(a) Total Number of Shares (or Units) Purchased (1) (2)	(b) Average Price Paid Per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (1)
October 1 - October 31	115,435	45.9573	N/A	N/A
November 1 - November 30	3	46.1800	N/A	N/A
December 1 - December 31	-	-	N/A	N/A
Total	115,438	45.9573	N/A	N/A

(1)At December 31, 2006, Progress Energy did not have any publicly announced plans or programs to purchase shares of its common stock.

(2)115,438 shares were purchased in open-market transactions by the plan administrator to satisfy share delivery requirements under the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) (See Note 10B).

46

PEC

Since 2000, the Parent has owned all of PEC’s common stock, and as a result there is no established public trading market for the stock. PEC has not issued or repurchased any equity securities since becoming a wholly owned subsidiary of the Parent. For the past three years, PEC has paid quarterly dividends to the Parent totaling the amounts shown in PEC’s Statements of Common Equity included in the financial statements in PART II, Item 8. PEC has provisions restricting dividends in certain circumstances (See Notes 10A and 12B). PEC does not have any equity compensation plans under which its equity securities are issued.

PEF

All shares of PEF’s common stock are owned by Florida Progress, and as a result there is no established public trading market for the stock. PEF did not issue or repurchase any equity securities during 2006. During 2006 and 2004, PEF paid quarterly dividends to Florida Progress totaling the amounts shown in PEF’s Statements of Common Equity included in the financial statements in PART II, Item 8. During 2005, PEF paid no dividends to Florida Progress. PEF has provisions restricting dividends in certain circumstances (See Notes 10A and 12B). PEF does not have any equity compensation plans under which its equity securities are issued.

47

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)	2006	2005 (a)	2004 (a)	2003 (a)	2002 (a)
Operating results

Operating results
Operating revenues	$	9,570	$	9,168	$	8,053	$	7,470	$	7,115
Income from continuing operations before cumulative effect of changes in accounting principles, net of tax		514		721		673		771		546
Net income		571		697		759		782		528
Per share data
Basic earnings
Income from continuing operations	$	2.05	$	2.92	$	2.78	$	3.25	$	2.51
Net income		2.28		2.82		3.13		3.30		2.43
Diluted earnings
Income from continuing operations		2.05		2.92		2.77		3.24		2.50
Net income		2.28		2.82		3.12		3.28		2.42
Assets	$	25,701	$	27,062	$	26,014	$	26,207	$	24,366
Capitalization
Common stock equity	$	8,286	$	8,038	$	7,633	$	7,444	$	6,677
Preferred stock of subsidiaries - not subject to mandatory redemption		93		93		93		93		93
Minority interest		10		36		29		24		10
Long-term debt, net (b)		8,835		10,446		9,521		9,693		9,522
Current portion of long-term debt		324		513		349		868		275
Short-term debt		-		175		684		4		695
Total capitalization	$	17,548	$	19,301	$	18,309	$	18,126	$	17,272
Dividends declared per common share	$	2.43	$	2.38	$	2.32	$	2.26	$	2.20

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

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

48

PEC

	Years Ended December 31
(in millions)	2006		2005		2004		2003		2002
Operating results
Operating revenues	$	4,086	$	3,991	$	3,629	$	3,600	$	3,554
Net income		457		493		461		482		431
Earnings for common stock		454		490		458		479		428
Assets	$	12,020	$	11,502	$	10,787	$	10,938	$	10,442
Capitalization
Common stock equity	$	3,390	$	3,118	$	3,072	$	3,237	$	3,089
Preferred stock - not subject to mandatory redemption		59		59		59		59		59
Long-term debt, net		3,470		3,667		2,750		3,086		3,048
Current portion of long-term debt		200		-		300		300		-
Short-term debt (a)		-		84		337		29		438
Total capitalization	$	7,119	$	6,928	$	6,518	$	6,711	$	6,634

^(a)   Includes notes payable to affiliated companies, related to the money pool program, of $11 million, $116 million and $25 million at December 31, 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).

49

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

The following combined Management’s Discussion and Analysis is separately filed by Progress Energy, Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF). Information contained herein relating to PEC and PEF individually is filed by such company on its own behalf. As used in this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF.

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

Management’s Discussion and Analysis should be read in conjunction with the Progress Energy Consolidated Financial Statements.

PROGRESS ENERGY

INTRODUCTION

Our reportable business segments and their primary operations include:

·   PEC - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina;

·   PEF - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida; and

·   Coal and Synthetic Fuels - primarily engaged in the production and sale of coal-based solid synthetic fuels in Kentucky and West Virginia, the operation of synthetic fuels facilities for third parties in West Virginia, and coal terminal services in Kentucky and West Virginia.

The “Corporate and Other” segment is comprised of nonregulated businesses that do not separately meet the requirements as a business segment. It primarily includes the activities of the Parent and Progress Energy Service Company, LLC (PESC), as well as other nonregulated business areas.

STRATEGY

We are an integrated energy company, with our primary focus on the end-use and wholesale electricity markets. We operate in retail utility markets in the southeastern United States and in other fuels markets in the eastern United States. Over the last several years we have reduced our business risk by exiting the majority of our nonregulated businesses. We believe that our two electric utilities, combined with our reduced nonregulated business risk, position us well for long-term growth. We are focused on the following key priorities:

·   excelling in the daily fundamentals of our utility business;

·   preparing for future baseload capacity due to high growth in our regulated service territories;

·   further strengthening our financial flexibility and growth;

·   maintaining constructive regulatory relations; and

·   executing our remaining divestiture transactions.

50

A summary of the significant financial objectives or issues impacting us, the Utilities and our remaining nonregulated operations is addressed more fully in the following discussion.

We have several key financial objectives, the first of which is to achieve sustainable earnings growth. In addition, we seek to continue our track record of dividend growth, as we have increased our dividend for 19 consecutive years, and 31 of the last 32 years. We also seek to continue our efforts to enhance balance sheet strength and flexibility so that we are positioned to accommodate the significant future growth expected at the Utilities.

In the short term, our ability to achieve these objectives will be impacted by, among other things, our ability to manage operation and maintenance (O&M) costs, the successful execution of our remaining divestiture transactions, increased environmental spending requirements, commodity price risk, and the scheduled expiration of the Internal Revenue Code (the Code) Section 29/45K (Section 29/45K) tax credit program for our synthetic fuels business at the end of 2007. Our long-term challenges include continuing our cost-management initiatives to mitigate escalating nonfuel and fuel operating costs, effectively managing capital projects, including those for environmental compliance and baseload capacity growth, achieving sufficient earnings growth to sustain our track record of dividend growth, meeting the need for future baseload capacity in our regulated service territories, achieving regulatory stability and investment recovery at the Utilities and complying with increasingly stringent environmental standards. Please review Item 1A, “Risk Factors” and “Safe Harbor for Forward-Looking Statements” for a discussion of the factors that may impact any such forward-looking statements made herein.

Our ability to meet these financial objectives is largely dependent on the earnings and cash flows of the Utilities. The Utilities contributed $780 million of our segment profit and generated substantially all of our consolidated cash flow from operations in 2006. Partially offsetting the net income contribution provided by the Utilities was a loss of $76 million recorded at our Coal and Synthetic Fuels operations, primarily related to the impairment of our synthetic fuels assets, and a loss of $190 million recorded at Corporate and Other, primarily related to interest expense on holding company debt.

While our synthetic fuels operations have historically provided significant net earnings driven by the Section 29/45K tax credit program, which is scheduled to expire at the end of 2007, the associated cash flow benefits from synthetic fuels are expected to come in the future when deferred tax credits are ultimately utilized. The total Section 29/45K credits that have been generated through December 31, 2006, but not yet utilized, are currently carried forward as deferred tax credits and will provide cash flow benefits when utilized. At December 31, 2006, the amount of these deferred tax credits was $847 million. See “Other Matters - Synthetic Fuels Tax Credits” below, Note 22D and Item 1A, “Risk Factors” for additional information on our synthetic fuels operations.

Our total debt to total capitalization ratio calculated from the Consolidated Balance Sheet is 52.2 percent at the end of 2006, a decrease from 57.7 percent at the end of 2005, primarily due to a reduction in total debt with proceeds from asset sales, recovery of storm costs incurred in Florida during 2004, fuel cost recovery, operating cash flow and growth in equity from retained earnings and limited ongoing equity issuances. We expect total capital expenditures for 2007, 2008 and 2009 to be approximately $2.4 billion, $2.5 billion and $2.4 billion, respectively, primarily related to the ongoing Utilities’ operations. We believe that operating cash flows plus availability under our credit facilities and shelf registration statements will be sufficient to fund our current business plans in the near term. In the long term, we expect to fund our business plans and any new baseload generation through operating cash flows and a combination of long-term debt, preferred stock and common equity, all of which are dependent on our ability to successfully access capital markets. We may also pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.

In 2006, the Parent’s, PEC’s, and PEF’s corporate credit ratings of BBB were affirmed and their ratings outlooks were changed to “positive” from “stable” by Standard & Poor’s (S&P). Moody’s Investors Service, Inc. (Moody’s) upgraded the Parent’s outlook to “stable” from “negative” and upgraded PEC’s outlook to “positive” from “stable.” Fitch Ratings (Fitch) upgraded the senior unsecured credit ratings of the Parent (BBB), PEC (A-) and PEF (A-), changed their ratings outlooks to “stable” and removed the Ratings Watch Positive. See “Credit Rating Matters” and “Guarantees” under “Future Liquidity and Capital Resources” below and Item 1A, “Risk Factors” for more information regarding the potential impact on our financial condition and results of operations resulting from a ratings change.

51

REGULATED UTILITIES

The Utilities’ earnings and operating cash flows are heavily influenced by weather, the economy, demand for electricity related to customer growth, actions of regulatory agencies, cost controls, the timing of recovery of fuel costs, and storm damage.

The Utilities operate in the southeastern United States, one of the fastest-growing regions of the country, and had a net increase of approximately 64,000 customers over the past year. However, lower industrial sales related mainly to weakness in the textile sector at PEC have reduced the rate of revenue growth in recent years. We do not expect any significant improvement or further degradation in industrial sales in the near term. These combined factors under normal weather conditions are expected to contribute approximately 1.5 percent to 2.0 percent annual retail kilowatt-hour (kWh) sales growth at PEC and approximately 2.5 percent to 3.0 percent annual retail kWh sales growth at PEF through at least 2008. The Utilities also seek to maintain their regulated wholesale business through targeted contract renewals and origination opportunities. The Utilities must continue to invest significant capital in additional energy conservation and efficiency programs, development and deployment of new energy technologies, and new generation, transmission and distribution facilities to support this load growth. Subject to regulatory approval, these investments are expected to increase the Utilities’ “rate base” or investment in utility plant, upon which additional return can be realized that creates the basis for long-term earnings growth in the Utilities. Through 2008, we will meet this load growth at PEC through existing resources and at PEF through the previously planned combined cycle unit of approximately 500 megawatts (MW) at PEF’s Hines Energy Complex in 2007. The Utilities expect total capital expenditures for 2007, 2008 and 2009 to be approximately $2.4 billion, $2.5 billion and $2.4 billion, respectively. The Utilities expect to fund their capital requirements primarily through a combination of internally generated funds, long-term debt, preferred stock and/or contribution of equity from the Parent.

Meeting the anticipated growth within the Utilities’ service territories will require a balanced approach. The three main elements of this balanced solution are: increasing energy efficiency and investing in the development of new energy resources for the future; modernizing existing plants to produce energy efficiently using state-of-the-art technology; and investing in new generating plants. We estimate that we will require new baseload generation facilities at both PEC and PEF by the middle of the next decade and a combined total of approximately 12,500 MW of additional capacity by 2025, and we are evaluating the best available options for this generation, including advanced design nuclear and clean coal technologies. The considerations that will factor into this decision include construction costs, fuel diversity, transmission and site availability, environmental impact, the rate impact to customers and our ability to obtain cost-effective financing. See “Other Matters - Nuclear Matters” for additional information.

We are subject to significant air quality regulations passed by the United States Environmental Protection Agency (EPA) in 2005 that affect our fossil fuel-fired generating facilities, the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule (CAMR), and the Clean Air Visibility Rule (CAVR). Additionally, at PEC’s coal-fired facilities in North Carolina, we are subject to the North Carolina Clean Smokestacks Act enacted in 2002 (Clean Smokestacks Act). Including estimated costs for CAIR, CAMR, CAVR and the Clean Smokestacks Act, we currently estimate that total future capital expenditures for the Utilities to comply with current environmental laws and regulations addressing air and water quality, which are eligible for regulatory recovery through either base rates or pass-through clauses, could be in excess of $1.0 billion each at PEC and PEF, respectively, through 2018, which is the latest compliance target date for current air and water quality regulations.

While the Utilities expect retail sales growth in the future, they are facing, and expect to continue to face, rising costs. The Utilities are committed to continuing to effectively manage costs to minimize the expected growth in O&M expenses. The Utilities are allowed to recover prudently incurred fuel costs through the fuel portion of our rates, which are adjusted annually in each state. We are focused on mitigating the impact of rising fuel prices since the under-recovery of fuel costs impacts our cash flows, interest and leverage, and rising fuel costs and higher rates also impact customer satisfaction. Our efforts to mitigate these high fuel costs include our diverse generation mix, staggered fuel contracts and hedging, and supplier and transportation diversity.

52

The Utilities successfully resolved key state regulatory issues in 2006, including fuel recovery filings in South Carolina, North Carolina and Florida and storm cost reserve replenishment in Florida. The Utilities continue to monitor progress toward a more competitive environment. No retail electric restructuring legislation has been introduced in the jurisdictions in which PEC and PEF operate. As part of the Clean Smokestacks Act, PEC is operating under a base rate freeze in North Carolina through 2007. As a result of its 2005 base rate proceeding, PEF’s base rate settlement extends through 2009. See Note 7 for further discussion of the Utilities’ retail rates.

NONREGULATED BUSINESSES

Our primary nonregulated businesses are Coal and Synthetic Fuels. Earnings of Coal and Synthetic Fuels are impacted largely by the volume of synthetic fuels produced and tax credits generated, and volumes and prices of coal terminal sales.

Through our subsidiaries, we are a majority owner in five entities and a minority owner in one entity, all of which own facilities that produce coal-based solid synthetic fuels as defined under Section 29/45K of the Code. The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied, including a requirement that the synthetic fuels differ significantly in chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced from a facility that was placed in service before July 1, 1998. Although the Section 29/45K tax credit program is expected to continue through 2007, recent market conditions, world events and catastrophic weather events have increased the volatility and level of oil prices that could limit the amount of those credits or eliminate them entirely for 2007. This possibility is due to a provision of Section 29/45K that provides that if annual average market prices for crude oil exceed certain prices, the amount of tax credits is reduced for that year. In January 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. The notional quantity of these oil price hedge instruments is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The contracts will be marked-to-market with changes in fair value recorded through earnings. Our synthetic fuels production levels for 2007 remain uncertain because we cannot predict with any certainty the price of oil for 2007. We will continue to monitor the environment surrounding synthetic fuels production and will adjust our production or consider other alternatives as warranted by changing conditions. See additional discussion of synthetic fuels tax credits in “Application of Critical Accounting Policies and Estimates - Synthetic Fuels Tax Credits,” “Other Matters - Synthetic Fuels Tax Credits” and Item 1A, “Risk Factors.”

As discussed more fully in Note 3 and “Results of Operations - Discontinued Operations,” in accordance with our business strategy to reduce our business risk and to focus on the core operations of the Utilities, many of our nonregulated business operations have been divested or are in the process of being divested. Consequently, we no longer report a Progress Ventures segment, and the composition of other continuing segments has been impacted by these divestitures. These operations have been classified as discontinued operations in the accompanying financial statements. As of December 31, 2006, the carrying value of long-lived assets of the remaining nonregulated electric generation operations and energy marketing activities and the remaining coal mining operations and other fuels businesses was $573 million.

The Progress Registrants are subject to various risks. For a discussion of their current material risks, see Item 1A, “Risk Factors.”

53

RESULTS OF OPERATIONS

In this section, earnings and the factors affecting earnings are discussed. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

OVERVIEW

FOR 2006 AS COMPARED TO 2005 AND 2005 AS COMPARED TO 2004

For the year ended December 31, 2006, our net income was $571 million or $2.28 per share compared to $697 million or $2.82 per share for the same period in 2005. For the year ended December 31, 2006, our income from continuing operations was $514 million compared to $721 million for the same period in 2005. The decrease in income from continuing operations as compared to prior year was due primarily to:

·   lower synthetic fuels earnings primarily due to lower tax credits;

·   impairment of all of our synthetic fuels assets and a portion of our coal terminal assets, primarily due to high oil prices;

·   unfavorable weather at the Utilities;

·   the cost incurred to redeem holding company debt;

·   unrealized losses recorded on contingent value obligations;

·   increased nuclear outage expenses at PEC; and

·   the prior year gain on the sale of our utility distribution assets serving the City of Winter Park, Fla. (Winter Park).

Partially offsetting these items were:

·   prior year postretirement and severance expenses related to the 2005 cost-management initiative;

·   increased retail growth and usage at the Utilities;

·   the gain on sale of Level 3 Communications, Inc. (Level 3) stock acquired as part of the divestiture of Progress Telecom, LLC (PT LLC); and

·   the prior year write-off of unrecoverable storm costs at PEF.

For the year ended December 31, 2005, our net income was $697 million or $2.82 per share compared to $759 million or $3.13 per share for the same period in 2004. For the year ended December 31, 2005, our income from continuing operations was $721 million compared to $673 million for the same period in 2004. The increase in income from continuing operations as compared to prior year was due primarily to:

·   increased synthetic fuels earnings;

·   customer growth at the Utilities;

·   favorable weather at the Utilities;

·   increased wholesale sales at the Utilities; and

·   the gain recorded on the sale of Winter Park utility distribution assets.

Partially offsetting these items were:

·   postretirement and severance charges related to the 2005 cost-management initiative;

·   the change in accounting estimates for certain capital costs in our distribution operations (Energy Delivery); and

·   the write-off of unrecoverable storm costs at PEF.

54

Our segments contributed the following profit or loss from continuing operations:

(in millions)	2006			Change			2005			Change			2004
PEC	$	454		$	(36	)	$	490		$	32		$	458
PEF		326			68			258			(75	)		333
Coal and Synthetic Fuels		(76	)		(239	)		163			73			90
Total segment profit		704			(207	)		911			30			881
Corporate and Other		(190	)		-			(190	)		18			(208	)
Total income from continuing operations		514			(207	)		721			48			673
Discontinued operations, net of tax		57			82			(25	)		(111	)		86
Cumulative effect of changes in accounting principles		-			(1	)		1			1			-
Net income	$	571		$	(126	)	$	697		$	(62	)	$	759

Cost-Management Initiative

On February 28, 2005, we approved a workforce restructuring that resulted in a reduction of approximately 450 positions. In addition to the workforce restructuring, the cost-management initiative included a voluntary enhanced retirement program. In connection with this initiative, we incurred approximately $164 million of pre-tax charges for severance and postretirement benefits during the year ended December 31, 2005. We did not incur any similar charges during 2006. The severance and postretirement charges are primarily included in O&M expense on the Consolidated Statements of Income and will be paid over time.

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $454 million, $490 million and $458 million in 2006, 2005 and 2004, respectively. The decrease in profits for 2006 as compared to 2005 is primarily due to the unfavorable impact of weather, higher O&M expense related to nuclear outages, the impact of suspending the allocation of the Parent’s income tax benefit not related to acquisition interest expense and 2006 capital project write-offs. See Corporate and Other below for additional information on the change in the tax benefit allocation in 2006. These were partially offset by postretirement and severance expenses incurred in 2005 related to the 2005 cost-management initiative and increased retail customer growth and usage.

The increase in profits for 2005 as compared to 2004 is primarily due to increased revenue from retail customer growth, the favorable impact of weather, increased wholesale margins primarily due to an increase in excess generation revenues and lower depreciation and amortization expense. These were partially offset by higher O&M charges primarily due to postretirement and severance charges related to the cost-management initiative and an increase in expenses charged to other, net.

55

REVENUES

PEC’s electric revenues and the percentage change by year and by customer class were as follows:

(in millions)
Customer Class	2006			% Change			2005			% Change		2004
Residential	$	1,462			2.8		$	1,422			7.4	$	1,324
Commercial		1,004			6.8			940			5.9		888
Industrial		711			3.9			684			3.8		659
Governmental		91			4.6			87			6.1		82
Total retail revenues		3,268			4.3			3,133			6.1		2,953
Wholesale		720			(5.1	)		759			32.0		575
Unbilled		(1	)		-			4			-		10
Miscellaneous		98			4.3			94			4.4		90
Total electric revenues		4,085			2.4			3,990			10.0		3,628
Less: Fuel revenues		(1,314	)		-			(1,186	)		-		(929	)
Revenues excluding fuel	$	2,771			(1.2	)	$	2,804			3.9	$	2,699

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

(in thousands of MWh)
Customer Class	2006			% Change			2005			% Change			2004
Residential		16,259			(2.4	)		16,664			4.1			16,003
Commercial		13,358			0.3			13,313			2.3			13,019
Industrial		12,393			(2.5	)		12,716			(2.5	)		13,036
Governmental		1,419			0.6			1,410			(1.5	)		1,431
Total retail energy sales		43,429			(1.5	)		44,103			1.4			43,489
Wholesale		14,584			(6.9	)		15,673			18.5			13,222
Unbilled		(137	)		-			(235	)		-			91
Total MWh sales		57,876			(2.8	)		59,541			4.8			56,802

PEC’s revenues, excluding fuel revenues of $1.314 billion and $1.186 billion for 2006 and 2005, respectively, decreased $33 million. The decrease in revenues was due primarily to the $67 million unfavorable impact of weather partially offset by a $24 million increase in retail customer growth and usage. Weather had an unfavorable impact as cooling degree days were 9 percent below 2005 and heating degree days were 12 percent below 2005. The increase in retail customer growth and usage was driven by an approximate increase in the average number of customers of 29,000 as of December 31, 2006, compared to December 31, 2005. Although the change in wholesale revenue less fuel did not have a material impact on the change in revenues, wholesale electric energy sales were down 6.9 percent primarily due to lower excess generation sales in 2006 compared to 2005, partially offset by an increase in contracted wholesale capacity. The decrease in excess generation sales in 2006 compared to 2005 is due to favorable market conditions during 2005 that resulted in strong sales to the mid-Atlantic United States.

PEC’s revenues, excluding fuel revenues of $1.186 billion and $929 million for 2005 and 2004, respectively, increased $105 million. The increase in revenues was primarily due to increased retail revenues of $22 million as a result of favorable weather, with cooling degree days 6 percent above prior year. Retail customer growth contributed an additional $46 million in revenues in 2005. PEC’s retail customer base increased as approximately 30,000 net new customers were added during 2005. Wholesale revenues, excluding fuel revenues, increased $37 million when compared to $311 million in 2004. The increase in PEC’s wholesale revenues in 2005 from 2004 is primarily the result of increased excess generation sales. Revenues for 2005 included strong sales to the mid-Atlantic United States as a result of favorable market conditions. In addition, higher contracted capacity compared to 2004 further increased wholesale revenues.

Industrial electric energy sales decreased in 2006 compared to 2005 primarily due to continued reduction in textile manufacturing in the Carolinas as a result of global competition and domestic consolidation. Industrial electric

56

energy sales decreased in 2005 when compared to 2004 primarily due to the reduction in textile manufacturing in the Carolinas and lower demand for both pulp and paper products. The increase in industrial revenues for 2006 compared to 2005 and 2005 compared to 2004 is due to an increase in fuel revenues as a result of higher energy costs and the recovery of prior year fuel costs.

EXPENSES

Fuel and Purchased Power

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

Fuel and purchased power expenses were $1.507 billion for 2006, which represents a $117 million increase compared to 2005. Fuel used in electric generation increased $137 million to $1.173 billion compared to 2005. This increase is due to a $141 million increase in deferred fuel expense partially offset by a $5 million decrease in fuel used in generation. Deferred fuel expense increased as a result of an increase in North Carolina and South Carolina fuel recovery rates. Fuel used in generation decreased primarily due to lower system requirements. See “Electric - PEC - Fuel and Purchased Power” in Item 1, “Business” for a summary of average fuel costs. Purchased power expenses decreased $20 million to $334 million compared to prior year. The decrease in purchased power is due primarily to a change in volume as a result of lower system requirements.

Fuel and purchased power expenses were $1.390 billion for 2005, which represents a $253 million increase compared to 2004. Fuel used in electric generation increased $200 million to $1.036 billion compared to 2004. This increase was due to a $308 million increase in fuel used in generation due to higher fuel costs, a change in generation mix and increased volume. Higher fuel costs were driven primarily by an increase in coal and natural gas prices. Outages at several facilities during 2005 resulted in increased combustion turbine generation, which had a higher average fuel cost. The increase in fuel used in generation was offset by a reduction in deferred fuel expense as a result of the under-recovery of 2005 fuel costs. Purchased power expenses increased $53 million to $354 million compared to 2004. The increase in purchased power was due primarily to a change in volume partially offset by a decrease in price.

Operation and Maintenance

O&M expenses were $930 million for 2006, which represents an $11 million decrease compared to 2005. This decrease is driven primarily by the $55 million impact of postretirement and severance expenses incurred in 2005 related to the cost-management initiative partially offset by $30 million of higher 2006 outage expenses at nuclear plants and capital project write-offs of $16 million in 2006.

O&M expenses were $941 million for 2005, which represents a $70 million increase compared to 2004. This increase was driven primarily by postretirement and severance expenses related to the 2005 cost-management initiative. Postretirement and severance expenses related to the cost-management initiative increased O&M expenses by $53 million during 2005. This increase included $55 million of charges in 2005 compared to 2004 expenses, which included $2 million related to a separate initiative. In addition, O&M expenses increased $26 million related to the change in accounting estimates for certain Energy Delivery capital costs, $25 million for higher emission allowance expenses, $16 million related to pension expenses and $6 million related to Hurricane Ophelia storm restoration costs in 2005. These unfavorable items were partially offset by decreased plant outage costs of $12 million compared to 2004, which included an additional nuclear plant outage, $8 million of lower health and life benefit expenses and a $6 million reduction of surplus inventory expense. In addition, results for 2004 included $19 million of costs associated with an ice storm that impacted the Carolinas service territory in the first quarter of 2004 and Hurricanes Charley and Ivan that impacted the Carolinas service territory in the third quarter of 2004.

57

Depreciation and Amortization

Depreciation and amortization expense was $571 million for 2006, which represents a $10 million increase compared to 2005. This increase is primarily attributable to the $12 million impact of depreciable asset base increases and $3 million of deferred environmental cost amortization partially offset by a $7 million decrease in the Clean Smokestacks Act amortization. We recorded $140 million of Clean Smokestacks Act amortization during 2006 compared to $147 million in 2005.

Depreciation and amortization expense was $561 million for 2005, which represents a $9 million decrease compared to 2004. This decrease was primarily attributable to the Clean Smokestacks Act amortization decrease of $27 million to $147 million in 2005 compared to amortization of $174 million in 2004. This was partially offset by higher depreciation expense of $17 million for increases in the depreciable asset base.

Taxes Other than on Income

Taxes other than on income were $191 million for 2006, which represents a $13 million increase compared to 2005. This increase is primarily due to a $7 million increase in property taxes and a $6 million increase in gross receipts taxes related to higher revenue. Gross receipts taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Taxes other than on income were $178 million for 2005, which represents a $5 million increase compared to 2004 primarily due to higher payroll taxes of $5 million.

Other

Other operating expenses consisted of a gain of $1 million in 2006 compared to a gain of $11 million in 2005, and a gain of $12 million in 2004. The decrease in the 2006 gain is primarily due to fewer land sales.

Total Other Income (Expense)

Total other income (expense) was $50 million of income for 2006, which represents a $57 million increase compared to 2005. This increase is primarily due to the $32 million impact of reclassifying $16 million of indemnification liability expenses incurred in 2005 for estimated capital costs associated with the Clean Smokestacks Act expected to be incurred in excess of the maximum billable costs to the joint owner. This expense was reclassified to Clean Smokestacks Act amortization and had no impact on 2006 earnings (See Note 21B). Interest income increased $17 million for 2006 compared to 2005 primarily due to investment interest and interest on under-recovered fuel costs. In addition, the change in other income (expense) includes a $4 million favorable impact related to recording an audit settlement with the Federal Energy Regulatory Commission (FERC) in 2005.

Total other income (expense) was $7 million of expense in 2005 compared to $3 million of income for 2004. The $10 million increase in expense for 2005 compared to 2004 was primarily due to the $16 million indemnification liability discussed above and $4 million related to an audit settlement with the FERC. These were partially offset by a $7 million write-off of nontrade receivables in 2004.

Total Interest Charges, Net

Total interest charges, net were $215 million for 2006, which represents a $23 million increase compared to 2005. This increase is primarily due to the $20 million impact of a net increase in average long-term debt.

Income Tax Expense

Income tax expense was $265 million, $239 million and $239 million in 2006, 2005 and 2004, respectively. The $26 million income tax expense increase in 2006 compared to 2005 is primarily due to the allocation of $23 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 that is no longer allocated in 2006. See

58

Corporate and Other below for additional information on the change in the tax benefit allocation in 2006. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $326 million, $258 million and $333 million in 2006, 2005 and 2004, respectively. The increase in profits for 2006 as compared to 2005 is primarily due to the impact of postretirement and severance costs incurred in 2005, increased retail customer growth and usage, an increase in rental and other miscellaneous service revenues and the impact of the 2005 write-off of unrecoverable storm costs. These were partially offset by the 2005 gain on the sale of the utility distribution assets serving Winter Park, the unfavorable impact of weather on revenues and the impact of suspending the allocation of the Parent’s tax benefit not related to acquisition interest expense. See Corporate and Other below for additional information on the change in the tax benefit allocation in 2006.

The decrease in 2005 profits as compared to 2004 is primarily due to higher O&M expenses (as a result of postretirement and severance costs, the change in accounting estimates for certain Energy Delivery capital costs, the write-off of unrecoverable storm costs and costs associated with outages) and lower average usage per retail customer partially offset by the favorable impact of weather, higher wholesale sales, the gain on the sale of the utility distribution assets serving Winter Park, and increased retail customer growth.

REVENUES

PEF’s electric revenues and the percentage change by year and by customer class were as follows:

(in millions)
Customer Class	2006			% Change			2005			% Change		2004
Residential	$	2,361			18.0		$	2,001			10.8	$	1,806
Commercial		1,152			21.5			948			11.1		853
Industrial		346			21.8			284			11.8		254
Governmental		301			24.4			242			14.7		211
Revenue sharing refund		1			-			(1	)		-		(11	)
Total retail revenues		4,161			19.8			3,474			11.6		3,113
Wholesale		319			(7.3	)		344			28.4		268
Unbilled		(5	)		-			(6	)		-		7
Miscellaneous		164			14.7			143			4.4		137
Total electric revenues		4,639			17.3			3,955			12.2		3,525
Less: Fuel and other pass-through revenues		(3,038	)		-			(2,385	)		-		(2,007	)
Revenues excluding fuel	$	1,601			2.0		$	1,570			3.4	$	1,518

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

(in thousands of MWh)
Customer Class	2006			% Change			2005			% Change		2004
Residential		20,021			0.6			19,894			2.8		19,347
Commercial		11,975			0.3			11,945			1.8		11,734
Industrial		4,160			0.5			4,140			1.7		4,069
Governmental		3,276			2.4			3,198			5.1		3,044
Total retail energy sales		39,432			0.7			39,177			2.6		38,194
Wholesale		4,533			(17.0	)		5,464			7.1		5,101
Unbilled		(234	)		-			(205	)		-		358
Total MWh sales		43,731			(1.6	)		44,436			1.8		43,653

59

PEF’s revenues, excluding fuel and other pass-through revenues of $3.038 billion and $2.385 billion for 2006 and 2005, respectively, increased $31 million. The increase in revenues is due to increased retail customer growth and usage of $25 million and a $21 million increase in rental and other miscellaneous service revenues partially offset by a $13 million unfavorable impact of weather. The increase in retail customer growth and usage was driven by an approximate increase in the average number of customers of 35,000 as of December 31, 2006, compared to December 31, 2005. The weather impact is primarily due to a 16 percent decrease in heating degree days compared to 2005.

PEF’s revenues, excluding fuel and other pass-through revenues of $2.385 billion and $2.007 billion for 2005 and 2004, respectively, increased $52 million. The increase in revenues was due in part to favorable weather in 2005 of $16 million with cooling degree days 11 percent higher than 2004. Retail customer growth contributed an additional $21 million as the approximate average number of customers increased 30,000 as of December 31, 2005, compared to 2004, and there was a significant reduction in hurricane-related customer outages compared to 2004. This growth in retail revenues was offset by lower retail revenues of $10 million in the Winter Park area due to the sale of the related distribution system in 2005 and an $8 million decline in average use per customer. Wholesale revenues net of fuel increased $18 million attributed to new contracts, including the service to Winter Park resulting from the switching of the sales to these customers from retail to wholesale. Revenues were also favorably impacted by a reduction in the provision for revenue sharing of $10 million and higher miscellaneous revenues of $6 million.

EXPENSES

Fuel and Purchased Power

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

Fuel and purchased power expenses were $2.601 billion in 2006, which represents a $584 million increase compared to 2005. Fuel used in electric generation increased $512 million due to a $552 million increase in deferred fuel expense resulting from an increase in the fuel recovery rates on January 1, 2006. This was partially offset by a $41 million decrease in current year fuel costs due primarily to lower system requirements. See “Electric-PEF -Fuel and Purchased Power” in Item 1, “Business” for a summary of average fuel costs. Purchased power expense increased $72 million primarily due to a $48 million increase in current year purchased power costs resulting from higher market prices and a $23 million increase in the recovery of deferred capacity costs.

Fuel and purchased power expenses were $2.017 billion in 2005, which represents a $275 million increase compared to 2004. This increase was due to increases in fuel used in electric generation and purchased power expenses of $148 million and $127 million, respectively. Higher system requirements and increased fuel costs in 2005 accounted for $342 million of the increase in fuel used in electric generation. The increase in fuel used in generation was offset by a reduction in deferred fuel expense as a result of the under-recovery of 2005 fuel costs. Purchased power increased primarily due to higher prices of purchases in 2005 as a result of increased fuel costs.

Operation and Maintenance

O&M expenses were $684 million in 2006, which represents a $168 million decrease compared to 2005. The decrease is primarily due to a $102 million impact of postretirement and severance costs associated with the cost-management initiative in 2005, $24 million of lower environmental cost-recovery expenses due to a decrease in emission allowances and lower recovery rates, $17 million related to the 2005 write-off of unrecoverable storm restoration costs (See Note 7C), a $9 million decrease in nuclear outage costs and a $6 million impact related to the 2005 write-off of GridFlorida regional transmission organization (RTO) startup costs that were previously recovered in revenues. The environmental cost-recovery expenses are recovered through an environmental cost-recovery clause and, therefore, have no material impact on earnings.

60

O&M expenses were $852 million in 2005, which represents a $222 million increase when compared to 2004. Postretirement and severance costs associated with the cost-management initiative increased O&M costs by $102 million during 2005. In addition, PEF wrote off $17 million of unrecoverable storm costs associated with the 2004 hurricanes (See Note 7C). O&M expense also increased $37 million primarily related to the change in accounting estimates for certain Energy Delivery capital costs and increased $26 million due to higher environmental cost-recovery expenses (primarily emission allowances). The remaining increase in O&M expense is attributable to $9 million of expenses related to outages in 2005, an $8 million workers’ compensation benefit adjustment recorded in 2005, $6 million related to the 2005 write-off of GridFlorida RTO startup costs that were previously recovered, and $5 million of additional bad debt expense.

Depreciation and Amortization

Depreciation and amortization expense was $404 million for 2006, which represents an increase of $70 million compared to 2005, primarily due to a $72 million increase in the amortization of storm restoration costs (See Note 7C) and a $48 million increase in utility plant depreciation partially offset by a $51 million decrease in expenses related to cost of removal primarily due to rate changes resulting from the 2005 depreciation study effective January 1, 2006 (See Note 5D). Storm restoration cost amortization is recovered in revenues through the storm recovery surcharge and, therefore, has no material impact on earnings.

Depreciation and amortization expense was $334 million for 2005, which represents an increase of $53 million compared to 2004 primarily due to the amortization of $50 million in storm restoration costs that began in August 2005 (See Note 7C).

Taxes Other than on Income

Taxes other than on income were $309 million in 2006, which represents an increase of $30 million compared to 2005. This increase is primarily due to $18 million of higher gross receipts taxes and $14 million of higher franchise taxes, related to an increase in revenues, partially offset by lower payroll taxes. Gross receipts and franchise taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Taxes other than on income were $279 million in 2005, which represents an increase of $25 million compared to 2004. This increase was due to increases in gross receipts and franchise taxes of $8 million each, related to an increase in revenues, a $5 million increase in payroll taxes and an increase in property taxes of $3 million.

Other

Other operating expenses were a gain of $2 million in 2006 compared to a gain of $26 million in 2005 and a gain of $2 million in 2004. Both the decrease in the gain for 2006 compared to 2005 and the increase in the gain from 2005 compared to 2004 are primarily due to the $24 million gain on the sale of the utility distribution assets serving Winter Park recorded in 2005.

Total Other Income

Total other income was $28 million for 2006, which represents a $20 million increase compared to 2005. This increase is primarily due to $8 million of increased investment interest income and $6 million of interest on unrecovered storm restoration costs.

Total Interest Charges, Net

Total interest charges, net were $150 million in 2006, which represents an increase of $24 million compared to 2005. The increase in interest charges is primarily due to the $20 million impact of a net increase in average long-term debt.

61

Total interest charges, net were $126 million in 2005, which represents an increase of $12 million compared to 2004. The increase in interest expense was primarily due to increased commercial paper borrowings and a net increase in average long-term debt.

Income Tax Expense

Income tax expense was $193 million, $121 million and $174 million in 2006, 2005 and 2004, respectively. The $72 million income tax expense increase in 2006 compared to 2005 is primarily due to changes in pre-tax income. In addition, 2005 income tax expense included the allocation of $13 million of the Parent’s tax benefit not related to acquisition interest expense that is no longer allocated in 2006. See Corporate and Other below for additional information on the change in the tax benefit allocation in 2006. Fluctuations in income tax expense between 2005 and 2004 are primarily due to changes in pre-tax income.

COAL AND SYNTHETIC FUELS

The operations of the Coal and Synthetic Fuels segment include synthetic fuels production and coal terminal operations. The following summarizes the Coal and Synthetic Fuels segment profits:

(in millions)	2006			2005			2004
Synthetic fuels operations	$	(44	)	$	155		$	92
Coal terminals and marketing		12			43			34
Corporate overhead and other operations		(44	)		(35	)		(36	)
Segment (loss) profits	$	(76	)	$	163		$	90

SYNTHETIC FUELS OPERATIONS

The production and sale of synthetic fuels generate operating losses, but qualify for tax credits under Section 29/45K, which generally more than offset the effect of such losses (See “Other Matters - Synthetic Fuels Tax Credits” below).

Results from the synthetic fuels operations are summarized below:

(in millions)	2006			2005			2004
Tons sold		3.7			10.1			8.3
After-tax losses (excluding impairment charge, valuation allowance and tax credits)	$	(68	)	$	(147	)	$	(128	)
After-tax gain on sale of assets		3			20			5
After-tax impairment charge		(45	)		-			-
Net operating loss (NOL) valuation allowance		(13	)		-			-
Tax credits generated		107			267			215
Tax credit inflation adjustment		10			5			-
Tax credit reserve increase due to estimated phase-out		(38	)		-			-
Tax credits previously unrecorded		-			10			-
Net (loss) profit	$	(44	)	$	155		$	92

Prior to 2006, our synthetic fuels production levels and the amount of tax credits we could claim each year were limited by our consolidated regular federal income tax liability. With the redesignation of Section 29 tax credits as Section 45K general business credits, that limitation was removed effective January 1, 2006.

Synthetic fuels operations’ net (loss) profit changed from a profit of $155 million in 2005 to a loss of $44 million in 2006 primarily due to lower synthetic fuels production as a result of high oil prices, which increased the potential phase-out of tax credits. The 6.4 million ton decrease in synthetic fuels production resulted in $79 million of lower after-tax losses. The decision to idle our synthetic fuels facilities necessitated an impairment test and resulted in the impairment of our synthetic fuels assets (See Notes 8 and 9). The lower production also resulted in a $160 million

62

reduction in generated tax credits, and as a result of the high oil prices, we recorded a $38 million tax credit reserve due to the estimated phase-out. The higher 2006 average oil prices and the uncertainty of the final phase-out percentage for 2006 resulted in a $17 million after-tax decrease in our gain on sale of assets due to recognizing a lower gain on the monetization of the Colona Synfuel Limited Partnership, LLLP (Colona) facility compared to 2005 (See Note 3J). The gain for 2006 is expected to be recorded in 2007 when the final phase-out percentage has been calculated. As of December 31, 2006, $7 million of deferred gain was recorded on the Consolidated Balance Sheet. In addition, results were unfavorably impacted by the recognition of a valuation allowance recorded against the deferred tax assets for state operating loss carry forwards. Due to the impairment of our synthetic fuels assets, the impairment charge included approximately $12 million of depreciation and amortization expense that would otherwise have been recorded in 2006, and $25 million of depreciation and amortization expense that would otherwise have been recorded during 2007.

Synthetic fuels operations’ net (loss) profits increased in 2005 as compared to 2004 due primarily to an increase in synthetic fuels production and an additional $23 million pre-tax gain recognized on the monetization of the Colona facility compared to 2004 (See Note 3J), partially offset by an increase in operating expenses. In addition, earnings in 2005 include a $10 million favorable tax credit true-up related to 2004. Our total synthetic fuels production of approximately 10 million tons in 2005 is greater than 2004 production levels of approximately eight million tons as a result of hurricane costs in 2004, which reduced our projected 2004 regular tax liability and our corresponding ability to record tax credits from synthetic fuels production.

Our future synthetic fuels production levels for 2007 remain uncertain due to the recent volatility of oil prices. See “Other Matters - Synthetic Fuels Tax Credits” below for additional information on the impact of oil prices on Section 29/45K tax credits, the results of our interim impairment review and a discussion of uncertainties surrounding our synthetic fuels production in 2007.

COAL TERMINALS AND MARKETING

Coal terminals and marketing (Coal) operations blend and transload coal as part of the trucking, rail and barge network for coal delivery. This business also has an operating fee agreement with our synthetic fuels operations for procuring and processing of coal and the transloading and marketing of synthetic fuels. As a result of the relationship with the synthetic fuels operations, fluctuations in Coal’s annual earnings are primarily related to production volumes at our synthetic fuels facilities. Coal operations contributed earnings of $12 million, $43 million and $34 million in 2006, 2005 and 2004, respectively. Coal’s 2006 results were negatively impacted by the impairment of a portion of Coal’s terminal assets, which resulted in a pre-tax charge of $17 million ($10 million after-tax) and lower revenues related to lower production at our synthetic fuels facilities and higher cost of sales due to higher coal prices (See Note 9). These were partially offset by an $11 million pre-tax reduction in expense related to a restructured coal supply contract due to 2005 coal commitments that were not delivered. During the first quarter of 2006, one of Coal’s supply contracts was restructured resulting in a payment of $103 million to Coal. These proceeds covered long-term coal supply commitments from 2005 through 2007 and will be recognized over the life of the contract as coal is received and the related inventory is utilized. Future amortization of these proceeds will be wholly offset by the increased contract price and is therefore not expected to materially impact earnings. As a result of the impairment of Coal’s terminal assets discussed above, the impairment charge included approximately $6 million of depreciation expense that would otherwise have been recorded in 2006 and approximately $11 million of depreciation expense that would otherwise have been recorded during 2007. The Coal and Synthetic Fuels segment has long-term fixed price coal purchase contracts to provide a portion of the feedstock coal required to meet 2007 solid synthetic fuels production or to resell as coal. As a result, the 2006 decline in coal prices is expected to negatively impact the financial performance of the Coal and Synthetic Fuels segment compared to previous years.

The increase in earnings for 2005 compared to 2004 was primarily due to additional revenues at the coal terminals related to increased prices and volumes and additional intersegment fees for both the coal terminals and marketing operations due to increased synthetic fuels production. These were partially offset by an increase in the cost of coal purchased by the coal terminals operations due to increased prices and larger volumes and lower third-party sales by the marketing operations.

63

CORPORATE OVERHEAD AND OTHER OPERATIONS

Corporate overhead and other operations incurred losses of $44 million, $35 million and $36 million for the years ended December 31, 2006, 2005 and 2004, respectively. The increase in losses for 2006 compared to 2005 is primarily due to the decreased allocation of interest and overheads to discontinued operations as a result of the divestitures completed during 2006.

CORPORATE AND OTHER

The Corporate and Other segment consists of the operations of the Parent, PESC and other consolidating and nonoperating entities (Corporate). Corporate and Other also includes other nonregulated business areas. Corporate and Other income (expense) is summarized below:

(in millions)	2006			Change			2005			Change			2004
Other interest expense	$	(246	)	$	(12	)	$	(234	)	$	6		$	(240	)
Contingent value obligations		(25	)		(31	)		6			(3	)		9
Tax reallocation		-			38			(38	)		(1	)		(37	)
Other income tax benefit		109			26			83			(21	)		104
Other expense		(28	)		(21	)		(7	)		37			(44	)
Corporate and Other after-tax expense	$	(190	)	$	-		$	(190	)	$	18		$	(208	)

Other interest expense, which includes elimination entries, increased $12 million for 2006 compared to 2005 primarily due to a decrease in the interest allocated to discontinued operations and a decrease in the elimination of intercompany interest expense due to lower intercompany debt balances partially offset by lower interest expense due to lower holding company debt. The decrease in interest expense allocated to discontinued operations resulted from the full year allocations of interest expense in 2005 compared to partial year allocations of interest in 2006 for operations that were sold in 2006. The decrease in other interest expense for 2005 compared to 2004 is primarily due to the increase in the interest allocated to discontinued operations partially offset by a decrease in interest rate swap activity that benefited from lower variable rates during 2004.

Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress) in 2000. Each CVO represents the right of the holder to receive contingent payments based on the performance of four synthetic fuels facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At December 31, 2006, 2005 and 2004, the CVOs had a fair market value of approximately $32 million, $7 million and $13 million, respectively. Progress Energy recorded an unrealized loss of $25 million for 2006 and unrealized gains of $6 million and $9 million for 2005 and 2004, respectively, to record the changes in fair value of CVOs, which had average unit prices of $0.33, $0.07 and $0.14 at December 31, 2006, 2005 and 2004, respectively.

For the year ended December 31, 2006, income tax expense was not increased by the allocation of the Parent’s income tax benefits not related to acquisition interest expense to profitable subsidiaries. Due to the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA 1935), beginning in 2006 we no longer allocate the Parent income tax benefits not related to acquisition interest expense to profitable subsidiaries. Since 2002, Parent income tax benefits not related to acquisition interest expense were allocated to profitable subsidiaries, in accordance with a PUHCA 1935 order. For the years ended December 31, 2005 and 2004, income tax expense was increased by $38 million and $37 million, respectively, due to the allocation of the Parent’s income tax benefit.

Other income tax benefit increased for 2006 compared to 2005 primarily due to increased pre-tax expense at the Parent. Other income tax benefit decreased for 2005 compared to 2004 due primarily to lower pre-tax expense at the Parent.

For 2006, other expense was $28 million compared to $7 million in 2005. The $21 million change is primarily due to the $59 million pre-tax ($35 million after-tax) loss on redemption of holding company debt (See Note 12) partially offset by the $17 million pre-tax gain, net of minority interest, on the sale of Level 3 stock subsequent to the sale of PT LLC (See Note 3D). In addition, other expense changed due to a $14 million increase in interest

64

income on temporary investments due to proceeds from the sale of DeSoto County Generating Co., LLC (DeSoto), Rowan County Power, LLC (Rowan) and Gas. The $37 million decrease in other expense from 2004 to 2005 was primarily due to the $43 million pre-tax ($29 million after-tax) settlement agreement in 2004 that our subsidiary Strategic Resource Solutions Corp. reached with the San Francisco United School District related to civil proceedings.

DISCONTINUED OPERATIONS

Over the last several years we have reduced our business risk by exiting the majority of our nonregulated businesses. We divested, or announced divestitures, of multiple nonregulated businesses during 2006 in accordance with our business strategy to reduce our business risk and to focus on the core operations of the Utilities. Consequently, we no longer report a Progress Ventures segment, and the composition of other continuing segments has been impacted by these divestitures.

CCO OPERATIONS

CCO - Georgia Operations

On December 13, 2006, our board of directors approved a plan to pursue the disposition of substantially all of Progress Energy Ventures, Inc.’s (PVI) Competitive Commercial Operations (CCO) physical and commercial assets, which include approximately 1,900 megawatts of power generation facilities in Georgia, as well as forward gas and power contracts, gas transportation, storage and structured power and other contracts, including full requirement contracts with 16 Georgia Electric Membership Cooperatives (the Georgia Contracts). We expect to complete the disposition plan in 2007. As a result of the disposition plan, we recorded an after-tax estimated loss on the sale of $226 million in December 2006, which includes an impairment charge related to the generation assets and intangible assets to reduce the carrying value of the assets that are expected to be sold to their estimated fair value less cost to sell (See Note 3A).

In 2007, we anticipate recording additional material charges in discontinued operations related to the disposition plan. These additional charges relate primarily to costs to be incurred to exit the Georgia Contracts. These costs could exceed $200 million after-tax. If CCO divests of its generation facilities but not the Georgia Contracts, CCO will continue to fulfill the contractual obligation through tolling agreements or purchases in the spot market.

Due to the reclassification of the remaining CCO operations to discontinued operations in December 2006, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts covering approximately 95 billion cubic feet (Bcf) of natural gas would be fulfilled. Therefore, these contracts were no longer treated as hedges and were dedesignated, and cash flow hedge accounting was discontinued. Changes in market prices since inception resulted in the recognition of unrealized mark-to-market gains of $92 million pre-tax ($60 million after-tax) for 2006. Future price volatility in the natural gas market will cause us to record mark-to-market changes through earnings of discontinued operations and will increase the volatility of future CCO operating results.

CCO’s operations generated net losses from discontinued operations of $57 million in 2006, $54 million in 2005 and $23 million in 2004. The increase in loss for 2006 compared to 2005 is primarily due to the $64 million pre-tax impairment loss ($42 million after-tax) on goodwill recognized in the first quarter of 2006 (See Note 8) and an increase in realized mark-to-market losses on gas hedges due to gas price volatility. This was partially offset by a higher gross margin related to serving the fixed price full requirements contracts that began in April 2005 and serving an increased load on a pre-existing contract in Georgia, and $66 million pre-tax of unrealized mark-to-market gains, primarily related to the dedesignated natural gas hedges discussed above.

The increase in loss for 2005 compared to 2004 is due primarily to a reduction in gross margin of $79 million pre-tax ($47 million after-tax) partially offset by favorable amortization and interest expense fluctuations. Contract margins were unfavorable in 2005 compared to 2004 due to the expiration of certain above-market tolling agreements and decreased earnings from new and existing full requirements contracts due to higher fuel and purchased power costs partially offset by net realized and unrealized mark-to-market gains. Depreciation and

65

amortization expenses decreased $6 million pre-tax ($4 million after-tax) as a result of the expiration of certain acquired contracts that were subject to amortization.

CCO - DeSoto and Rowan Generation Facilities

On May 2, 2006, our board of directors approved a plan to divest of our DeSoto and Rowan subsidiaries. DeSoto and Rowan were subsidiaries of Progress Energy Ventures, Inc. DeSoto owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Fla., and Rowan owns 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 a gross purchase price of approximately $80 million and $325 million, respectively. We used the proceeds from the sales to reduce debt and for other corporate purposes (See Note 3C).

The sale of DeSoto closed in the second quarter of 2006 and the sale of Rowan closed during the third quarter of 2006. We recorded an after-tax loss of $67 million during the year ended December 31, 2006, on the sale of DeSoto and Rowan. Discontinued DeSoto and Rowan operations had combined earnings of $10 million, $3 million and $8 million for the years ended December 31, 2006, 2005 and 2004, respectively.

GAS OPERATIONS

On July 12, 2006, our board of directors approved a plan to divest of our natural gas drilling and production business (Gas), which includes Winchester Production Company, Ltd. (Winchester Production), Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets Ltd.; all are subsidiaries of Progress Fuels Corporation (Progress Fuels). On July 22, 2006, we entered into a definitive agreement to sell Gas to EXCO Resources, Inc. for $1.2 billion in gross cash proceeds. We recorded an after-tax gain of $300 million during the year ended December 31, 2006, on the sale of Gas. Proceeds from the sale were used primarily to reduce holding company debt and for other corporate purposes (See Note 3B).

The transaction closed on October 2, 2006. Specific assets included over 325 Bcf equivalent of proved natural gas reserves, over 350 miles of pipelines, over 500 producing wells and other related assets, all of which were located in Texas and Louisiana. Discontinued Gas operations had net earnings from discontinued operations of $82 million for the year ended December 31, 2006, compared to net earnings from discontinued operations of $48 million for the same period in 2005. The increase in net earnings is primarily due to increased production, higher market prices and mark-to-market gains on gas hedges.

Gas operations generated profits of $48 million for the same period in 2005 compared to $76 million for the year ended December 31, 2004. The decrease is primarily due to the gain recognized on the sale of gas assets in 2004. In December 2004, we sold certain gas-producing properties and related assets owned by Winchester Production (North Texas gas operations). Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting the pre-tax gain of $56 million ($31 million net of taxes) was recognized in earnings rather than as a reduction of the basis of our remaining oil and gas properties. In addition, lower sales and general and administrative expense and interest expenses partially offset by lower revenues reduced the overall earnings decline from 2004 to 2005. Revenues were lower in 2005 due to the sale of the North Texas gas operations; however, the Texas/Louisiana gas operations were able to offset a majority of the lost revenue due to higher natural gas prices and increased production.

PROGRESS TELECOM, LLC

On March 20, 2006, we completed the sale of PT LLC to 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 $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 3D).

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

66

from discontinued operations for PT LLC were a loss of $2 million, earnings of $4 million and a loss of $7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

DIXIE FUELS AND OTHER FUELS BUSINESS

On March 1, 2006, we sold our 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 units under long-term contracts with PEF. 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. The other fuels business is expected to be sold in 2007 (See Note 3E).

Net earnings from discontinued operations for Dixie Fuels and other fuels business were $7 million, $5 million and $2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

COAL MINING BUSINESSES

On November 14, 2005, our board of directors approved a plan to divest of five subsidiaries of Progress Fuels engaged in the coal mining business. 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 estimated after-tax loss of $10 million for the sale of these assets. The remaining coal mining operations are expected to be sold in 2007 (See Note 3F).

Net losses from discontinued operations for the coal mining business were $4 million, $11 million and $5 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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. During the years ended December 31, 2006 and 2005, we recorded an estimated after-tax loss for the sale of these assets of $6 million and $25 million, respectively. Proceeds from the sale were used to reduce debt (See Note 3G).

Net earnings from discontinued operations for Rail were $5 million and $29 million for the years ended December 31, 2005 and 2004. Rail did not have a material impact on earnings for the year ended December 31, 2006.

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

UTILITY REGULATION

As discussed in Note 7, our regulated utilities segments are subject to regulation that sets the prices (rates) we are permitted to charge customers based on the costs that regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by a nonregulated company. This ratemaking process results in deferral of expense recognition and the recording of regulatory assets based on anticipated future cash inflows. As a result of the different ratemaking processes in each state in which we operate, a significant amount of regulatory assets has been recorded. We continually review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Additionally, the state regulatory agencies often provide flexibility in the manner and timing of the depreciation of property,

67

nuclear decommissioning costs and amortization of the regulatory assets. See Note 7 for additional information related to the impact of utility regulation on our operations.

ASSET IMPAIRMENTS

As discussed in Note 9, we evaluate the carrying value of long-lived assets and intangible assets with definite lives for impairment whenever indicators exist. Examples of these indicators include current period losses combined with a history of losses, a projection of continuing losses, a significant decrease in the market price of a long-lived asset group, or the likelihood that an asset group will be disposed of significantly prior to the end of its useful life. If an indicator exists, the asset group held and used is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows or if the asset group is to be disposed of, an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. Performing an impairment test on long-lived assets involves management’s judgment in areas such as identifying circumstances indicating an impairment may exist, identifying and grouping affected assets at the appropriate level, and developing the undiscounted cash flows associated with the asset group. Estimates of future cash flows contemplate factors such as expected use of the assets, future production and sales levels, and expected fluctuations of prices of commodities sold and consumed. Therefore, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

The carrying value of our total utility plant, net is $15.245 billion at December 31, 2006. The carrying value of our total diversified business property, net is $31 million at December 31, 2006. In addition, we have certain diversified business property with a carrying value of $573 million at December 31, 2006, included in net assets of discontinued operations (See Note 3H). Our exposure to potential impairment losses for utility plant, net is mitigated by the fact that our regulated ratemaking process generally allows for recovery of our investment in utility plant plus an allowed return on the investment, as long as the costs are prudently incurred.

Under the full-cost method of accounting for oil and gas properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future net revenues using current prices, plus the lower of cost or fair market value of unproved properties. The ceiling test takes into consideration the prices of qualifying cash flow hedges as of the balance sheet date. If the ceiling (discounted revenues) does not exceed total capitalized costs, we are required to write-down capitalized costs to the ceiling. We performed this ceiling test calculation every quarter prior to the sale of the Gas Operations (See Note 3B). No write-downs were required in 2006 or 2005.

See discussion of synthetic fuels asset impairments in “Other Matters - Synthetic Fuels Tax Credits” and in Notes 8 and 9.

GOODWILL

As discussed in Note 8, we account for goodwill in accordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), which requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist. For our utility segments, the goodwill impairment tests are performed at the utility operating segment level. We performed the annual goodwill impairment test for both the PEC and PEF segments in the second quarters of 2006 and 2005, each of which indicated no impairment. If the fair values for the utility segments were lower by five percent, there still would be no impact on the reported value of their goodwill.

The carrying amounts of goodwill at December 31, 2006 and 2005, for reportable segments PEC and PEF, were $1.922 billion and $1.733 billion, respectively. The amounts assigned to PEC and PEF are recorded in our Corporate and Other business segment.

For our former Progress Ventures segment, the goodwill impairment tests were performed at our Georgia Region reporting unit level, which was comprised of four nonregulated generation plants and was one level below the Progress Ventures segment. We performed the annual goodwill impairment test for our Georgia Region reporting unit in the first quarters of 2006 and 2005. The test in 2005 indicated no impairment. In 2006, the test indicated that

68

goodwill was fully impaired, and we recognized a pre-tax goodwill impairment charge of $64 million ($39 million after-tax) during the first quarter of 2006.

We calculated the fair value of our segments and reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow methodology and published industry valuations and market data as supporting information. These calculations are dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates, and assumptions about the timing of when unregulated energy supply and demand would reach market equilibrium. These underlying assumptions and estimates are made as of a point in time; subsequent changes, particularly changes in the discount rates, growth rates or the timing of market equilibrium, could result in a future impairment charge to goodwill.

SYNTHETIC FUELS TAX CREDITS

Our Coal and Synthetic Fuels business unit owns facilities that produce coal-based solid synthetic fuels as defined under the Internal Revenue Code. The production and sale of the synthetic fuels from these facilities qualifies for tax credits under Section 29/45K if certain requirements are satisfied, including a requirement that the synthetic fuels differ significantly in chemical composition from the coal used to produce such synthetic fuels and that the synthetic fuels were produced from a facility placed in service before July 1, 1998. For 2005 and prior years, the amount of Section 29 credits that we were allowed to generate in any calendar year was limited by the amount of our regular federal income tax liability. Section 29 tax credit amounts allowed but not utilized through December 31, 2005, are carried forward indefinitely as deferred alternative minimum tax credits on the Consolidated Balance Sheets. For 2006 and 2007, the Section 29 tax credits have been redesignated as a Section 45K general business credit, which removes the regular federal income tax liability limit on synthetic fuels production and subjects the credits to a 20-year carry forward period. This provision allows us to produce synthetic fuels at a higher level than we have historically produced, should we choose to do so. The current Section 29/45K tax credit program expires at the end of 2007.

In addition, Section 29/45K provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the Annual Average Price) exceeds a certain threshold value (the Threshold Price), the amount of tax credits is reduced for that year. Also, if the Annual Average Price increases high enough (the Phase-out Price), the Section 29/45K tax credits are eliminated for that year. The Threshold Price and the Phase-out Price are adjusted annually for inflation. We estimate that the 2006 Annual Average Price will result in an approximate 35 percent phase-out of the synthetic fuels tax credits related to synthetic fuels production in 2006. This estimate is derived from our estimates of the 2006 Threshold Price and Phase-out Price of $55 per barrel and $69 per barrel, respectively, based on an estimated inflation adjustment for 2006. For 2007 synthetic fuels production, the 2007 Annual Average Price is not known until after the end of the year; we will record the 2007 tax credits based on our estimates of what we believe the Annual Average Price will be for 2007. These estimates are based on oil prices in the futures market. Any portion of the tax credits that would be phased out based on the projected 2007 Annual Average Price exceeding the Threshold Price will not be recorded.

We estimate that the 2007 Threshold Price will be approximately $56 per barrel and the Phase-out Price will be approximately $70 per barrel, based on estimated inflation adjustments for 2006 and 2007. The monthly Domestic Crude Oil First Purchases Price published by the Energy Information Agency (EIA) has recently averaged approximately $7 lower than the corresponding daily New York Mercantile Exchange (NYMEX) prompt month settlement price for light sweet crude oil. As of January 31, 2007, the average NYMEX futures price for light sweet crude oil for calendar year 2007 was $59.50 per barrel. Based upon the estimated 2007 Threshold Price and Phase-out Price, if oil prices for the rest of 2007 remained at the January 31, 2007, average 2007 futures price level of $59.50 per barrel, we currently estimate that the synthetic fuels tax credit amount for 2007 would not be reduced. See further discussion in “Other Matters - Synthetic Fuels Tax Credits” and Item 1A, “Risk Factors.”

69

PENSION COSTS

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

Due to an increase in the market interest rates for high-quality (AAA/AA) debt securities, which are used as the benchmark for setting the discount rate used to present value future benefit payments, we increased the discount rate to approximately 5.95% at December 31, 2006, from approximately 5.65% at December 31, 2005, which will decrease the 2007 benefit costs recognized, all other factors remaining constant. Our discount rates are selected based on a plan-by-plan study by our actuary, which matches our projected benefit payments to a high-quality corporate yield curve. Plan assets performed well in 2006, with returns of approximately 14%. That positive asset performance will result in decreased pension costs in 2007, all other factors remaining constant. Evaluations of the effects of these and other factors on our 2007 pension costs have not been completed, but we estimate that the total cost recognized for pensions in 2007 will be $22 million to $30 million, compared with $32 million recognized in 2006.

We have pension plan assets with a fair value of approximately $1.8 billion at December 31, 2006. Our expected rate of return on pension plan assets is 9.0%. We review this rate on a regular basis. Under SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), the expected rate of return used in pension cost recognition is a long-term rate of return; therefore, we do not adjust that rate of return frequently. In 2005, we elected to lower our expected rate of return from 9.25% to 9.0%. The 9.0% rate of return represents the lower end of our future expected return range given our asset allocation policy. A 0.25% change in the expected rate of return for 2006 would have changed 2006 pension costs by approximately $4 million.

Another factor affecting our pension costs, and sensitivity of the costs to plan asset performance, is the method selected to determine the market-related value of assets, i.e., the asset value to which the 9.0% expected long-term rate of return is applied. SFAS No. 87 specifies that entities may use either fair value or an averaging method that recognizes changes in fair value over a period not to exceed five years, with the method selected applied on a consistent basis from year to year. We have historically used a five-year averaging method. When we acquired Florida Progress in 2000, we retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets. Changes in plan asset performance are reflected in pension costs sooner under the fair value method than the five-year averaging method, and, therefore, pension costs tend to be more volatile using the fair value method. Approximately 50 percent of our pension plan assets are subject to each of the two methods.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Progress Energy, Inc. is a holding company and, as such, has no revenue-generating operations of its own. Our primary cash needs at the Parent level are our common stock dividend and interest and principal payments on our $2.6 billion of senior unsecured debt. Our ability to meet these needs is dependent on the earnings and cash flows of the Utilities and our nonregulated subsidiaries, and the ability of our subsidiaries to pay dividends or repay funds to us. Our other significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations, including expenditures for environmental compliance. We rely upon our operating cash flow, primarily generated by the Utilities, commercial paper and bank facilities, and our ability to access the long-term debt and equity capital markets for sources of liquidity.

The majority of our operating costs are related to the Utilities. Most of these costs are recovered from ratepayers in accordance with various rate plans. We are allowed to recover certain fuel, purchased power and other costs incurred by PEC and PEF through their respective recovery clauses. The types of costs recovered through clauses vary by jurisdiction. Fuel price volatility can lead to over- or under-recovery of fuel costs, as changes in fuel prices are not

70

immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility can be both a source of and a use of liquidity resources, depending on what phase of the cycle of price volatility we are experiencing. Changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows, but not materially affect net income.

Prior to February 8, 2006, we were a registered holding company under PUHCA 1935, and therefore we obtained approval from the Securities and Exchange Commission (SEC) for the issuance and sale of securities as well as the establishment of intercompany extensions of credit (utility and nonutility money pools). PEC and PEF participate in the utility money pool, which allows the two utilities to lend to and borrow from each other. A nonutility money pool allows our nonregulated operations to lend to and borrow from each other. The Parent can lend money to the utility and nonutility money pools but cannot borrow funds. The Energy Policy Act of 2005 (EPACT) repealed PUHCA 1935 effective February 8, 2006, and transferred to the FERC certain new responsibilities with respect to the regulation of utility holding companies under the Public Utilities Holding Company Act of 2005 (PUHCA 2005). Pursuant to PUHCA 2005, utility holding companies are allowed to continue to engage in financings authorized by the SEC, provided the authorization orders have been filed with the FERC and the holding company continues to comply with such orders, terms and conditions. We have filed all such SEC orders with the FERC; therefore, we are permitted to continue all such financing transactions.

Cash from operations, asset sales, short-term and long-term debt and limited ongoing equity sales from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans are expected to fund capital expenditures and common stock dividends for 2007. For the fiscal year 2007, we expect to realize an aggregate amount of approximately $50 million from the sale of stock through these plans.

We believe our internal and external liquidity resources will be sufficient to fund our current business plans. Risk factors associated with credit facilities and credit ratings are discussed below and in Item 1A, “Risk Factors.”

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

HISTORICAL FOR 2006 AS COMPARED TO 2005 AND 2005 AS COMPARED TO 2004

CASH FLOWS FROM OPERATIONS

Cash from operations is the primary source used to meet operating requirements and capital expenditures. Net cash provided by operating activities from continuing operations for the three years ended December 31, 2006, 2005 and 2004, was $1.912 billion, $1.175 billion, and $1.409 billion, respectively.

Cash from operating activities for 2006 increased when compared with 2005. The $737 million increase in operating cash flow was primarily due to a $713 million increase in the recovery of fuel costs at the Utilities, a $201 million increase from the change in accounts receivable, approximately $103 million of proceeds received from the restructuring of a long-term coal supply contract, and $72 million related to recovery of storm restoration costs at PEF. These impacts were partially offset by a $122 million net increase in tax payments in 2006 compared to 2005, $141 million related to a wholesale customer prepayment in 2005 at PEC, as discussed below, and a $57 million decrease from the change in accounts payable. The $201 million change in accounts receivable included $147 million at PEC, principally driven by the timing of wholesale sales, and approximately $47 million at PEF, primarily related to timing of receipts.

In 2006 and 2005, the Utilities filed requests with their respective state commissions seeking rate increases for fuel cost recovery, including amounts for previous under-recoveries. In 2005, PEF also received approval from the Florida Public Service Commission (FPSC) authorizing PEF to recover $245 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004. See “Future Liquidity and Capital Resources” and Note 7 for additional information.

Cash from operating activities for 2005 decreased when compared with 2004. The $234 million decrease in operating cash flow was primarily due to a $298 million decrease in the recovery of fuel costs at the Utilities, driven

71

by rising fuel costs, and increased working capital needs of $144 million, partially offset by a $193 million reduction in storm cost spending at PEF in 2005 compared to 2004. Cash from operating activities for 2005 also includes a $141 million prepayment received from a wholesale customer. In November 2005, PEC entered into a contract with the Public Works Commission of the City of Fayetteville, North Carolina (PWC), in which the PWC prepaid $141 million in exchange for future capacity and energy power sales. The prepayment is expected to cover approximately two years of electricity service and includes a prepayment discount of approximately $16 million. In 2005, the Utilities filed requests with their respective state commissions seeking rate increases for fuel cost recovery, including amounts for previous under-recoveries. PEF also received approval from the FPSC authorizing PEF to recover $245 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004. See “Future Liquidity and Capital Resources” and Note 7 for additional information.

The increase in working capital needs for 2005 compared to 2004 was mainly driven by a $170 million increase in the change in receivables, a $97 million increase in prepayments and other current assets, and a $52 million increase in inventory purchases, primarily coal at PEC. These impacts were partially offset by a $133 million increase in the change in accounts payable and the current portion of the prepayment received from the PWC as discussed above. The increase in the change in receivables is primarily due to increased sales at the Utilities driven by weather, rising fuel costs and timing of receipts, and increased sales at our nonregulated subsidiaries, mainly driven by changes in the production level of our synthetic fuels facilities over the prior year. The change in accounts payable is primarily due to higher fuel prices at PEF and increased quantities of coal purchases at our nonregulated subsidiaries.

INVESTING ACTIVITIES

Net cash provided (used) by investing activities for the three years ended December 31, 2006, 2005 and 2004, was $271 million, $(914) million and $(649) million, respectively. Excluding proceeds from sales of discontinued operations and other assets of $1.654 billion in 2006 and $475 million in 2005, cash used in investing activities decreased slightly in 2006 when compared with 2005. The decrease in 2006 was primarily due to a $319 million increase in net proceeds from available-for-sale securities and other investments, a $12 million decrease in nuclear fuel additions, and a $14 million decrease in other investing activities, largely offset by a $343 million increase in capital expenditures for utility property. At PEC, the increase in utility property was primarily due to environmental compliance and mobile meter reading project expenditures. At PEF, the increase in utility property was primarily due to repowering the Bartow plant to more efficient natural gas-burning technology; various distribution, transmission and steam production projects; and higher spending at the Hines Unit 4 facility, partially offset by lower spending at the Hines Unit 3 facility. Available-for-sale securities and other investments include marketable debt and equity securities and investments held in nuclear decommissioning and benefit investment trusts.

Utility property additions, including nuclear fuel, for our regulated electric operations were $1.537 billion and $1.206 billion in 2006 and 2005, respectively, or approximately 100 percent of consolidated capital expenditures in both 2006 and 2005. Capital expenditures for our regulated electric operations are primarily for capacity expansion and normal construction activity and ongoing capital expenditures related to environmental compliance programs.

During 2006, proceeds from sales of discontinued operations and other assets, net of cash divested, primarily included approximately $1.1 billion from the sale of Gas (See Note 3B), $405 million from the sale of DeSoto and Rowan (See Note 3C), approximately $70 million from the sale of PT LLC (See Note 3D), approximately $27 million from the sale of certain net assets of the coal mining business (See Note 3F), and approximately $16 million from the sale of Dixie Fuels (See Note 3E).

Excluding proceeds from sales of discontinued operations and other assets, net of cash divested, cash used in investing activities increased approximately $368 million in 2005 when compared with 2004. The increase is due primarily to a $254 million decrease in net proceeds from available-for-sale securities and other investments and a $107 million increase in capital expenditures for utility property and nuclear fuel additions. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning and benefit investment trusts.

During 2005, proceeds from sales of discontinued operations and other assets, net of cash divested, primarily

72

included $405 million in base proceeds from the sale of Progress Rail in March 2005 and $42 million in proceeds from the sale of Winter Park distribution assets in June 2005 (See Notes 3G and 7C).

During 2004, proceeds from sales of discontinued operations and other assets, net of cash divested, primarily included proceeds of approximately $251 million related to the sale of natural gas assets in the Forth Worth basin of Texas and proceeds from the sale of Railcar Ltd. assets of approximately $75 million. We used the proceeds from these sales to reduce indebtedness, including $241 million to pay off a PVI bank facility.

FINANCING ACTIVITIES

Net cash (used) provided by financing activities for the three years ended December 31, 2006, 2005 and 2004, was $(2.468) billion, $229 million and $(485) million, respectively. See Note 12 for details of debt and credit facilities.

For 2006, proceeds from sales of discontinued operations and other assets, net of cash divested, were used to reduce holding company debt by $1.7 billion. The increase in cash used in financing activities was primarily related to the retirement of long-term debt in the current year, as discussed below, and a decrease in the proceeds from issuances of long-term debt. For 2005, cash provided by financing activities increased primarily due to additional issuances of long-term debt at the Utilities and an increase in common stock issuances. For 2004, cash from operations exceeded net cash used in investing activities by $760 million due primarily to asset sales, which allowed for a net decrease in cash requirements provided by financing activities.

In addition to the financing activities discussed under “Overview,” our financing activities included:

2006

·   On January 13, 2006, Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100 million of Series A Floating Rate Senior Notes due 2010. These senior notes are unsecured. Interest on the Floating Rate Senior Notes is based on three-month London Inter Bank Offering Rate (LIBOR) plus 45 basis points and resets quarterly. We used the net proceeds from the sale of these senior notes and a combination of available cash and commercial paper proceeds to retire the $800 million aggregate principal amount of our 6.75% Senior Notes on March 1, 2006. Pending the application of proceeds as described above, we invested the net proceeds in short-term, interest-bearing, investment-grade securities.

·   Progress Energy entered into a new $800 million 364-day credit agreement on November 21, 2005, which was restricted for the retirement of $800 million of 6.75% Senior Notes due March 1, 2006. On March 1, 2006, we retired $800 million of our 6.75% Senior Notes, thus effectively terminating the 364-day credit agreement.

·   On March 31, 2006, Progress Energy, as a well-known seasoned issuer, filed a shelf registration statement with the SEC. The registration statement became effective upon filing with the SEC and will allow Progress Energy to issue an indeterminate number or amount of various securities, including Senior Debt Securities, Junior Subordinated Debentures, Common Stock, Preferred Stock, Stock Purchase Contracts, Stock Purchase Units, and Trust Preferred Securities and Guarantees. The board of directors has authorized the issuance and sale of up to $1.0 billion aggregate principal amount of various securities off the new shelf registration statement, in addition to $679 million of various securities, which were not sold from our prior shelf registration statement. Accordingly, at December 31, 2006, Progress Energy had the authority to issue and sell up to $1.679 billion aggregate principal amount of various securities.

·   On May 3, 2006, Progress Energy restructured its existing $1.13 billion five-year revolving credit agreement (RCA) with a syndication of financial institutions. The new RCA is scheduled to expire on May 3, 2011, and replaced an existing $1.13 billion five-year facility, which was terminated effective May 3, 2006. The new RCA will continue to be used to provide liquidity support for Progress Energy’s issuances of commercial paper and other short-term obligations. The new RCA includes a defined maximum total debt to capital ratio of 68 percent and contains various cross-default and other acceleration provisions. The new RCA does not include a material adverse change representation for borrowings or a financial covenant for interest coverage. Fees and interest

73

rates under the RCA will continue to be determined based upon the credit rating of Progress Energy’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa2 by Moody’s and BBB- by S&P.

·   On May 3, 2006, PEC’s five-year $450 million RCA was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of PEC’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P. The amended PEC RCA is scheduled to expire on June 28, 2010.

·   On May 3, 2006, PEF’s five-year $450 million RCA was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined 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 amended PEF RCA is scheduled to expire on March 28, 2010.

·   On July 3, 2006, PEF paid at maturity $45 million of its 6.77% Medium-Term Notes, Series B with available cash on hand.

·   On November 1, 2006, Progress Capital Holdings, Inc., one of our wholly owned subsidiaries, paid at maturity $60 million of its 7.17% Medium-Term Notes with available cash on hand.

·   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, at a make-whole redemption price. The 6.05% Senior Notes were acquired at 100.274 percent of par, or approximately $351 million, plus accrued interest, and the 5.85% Senior Notes were acquired at 101.610 percent of par, or approximately $406 million, plus accrued interest. The redemptions were funded with available cash on hand and no additional debt was incurred in connection with the redemptions. See Note 20 for a discussion of losses on debt redemptions.

·   On December 6, 2006, Progress Energy repurchased, pursuant to a tender offer, $550 million, or 53.0 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. The redemption was funded with available cash on hand, and no additional debt was incurred in connection with the redemptions. See Note 20 for a discussion of losses on debt redemptions.

·   Progress Energy issued approximately 4.2 million shares of common stock resulting in approximately $185 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit and stock option plans. Included in these amounts were approximately 1.6 million shares for proceeds of approximately $70 million to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan. For 2006, the dividends paid on common stock were approximately $607 million.

2005

·   On January 31, 2005, Progress Energy entered into a new $600 million RCA, which was subsequently terminated on May 16, 2005. In March 2005, Progress Energy’s $1.1 billion five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65 percent to 68 percent. In addition to the ongoing RCAs, Progress Energy entered into a new $800 million 364-day credit agreement on November 21, 2005, which was restricted for the retirement of $800 million of 6.75% Senior Notes due March 1, 2006. On March 1, 2006, the $800 million of 6.75% Senior Notes was retired, thus effectively terminating the 364-day credit agreement.

·   PEC issued $300 million of First Mortgage Bonds, 5.15% Series due 2015; $200 million of First Mortgage Bonds, 5.70% Series due 2035; and $400 million of First Mortgage Bonds, 5.25% Series due 2015. PEC paid at

maturity $300 million in 7.50% Senior Notes. PEC also entered into a new $450 million five-year RCA with a syndication of financial institutions, which is scheduled to expire on June 28, 2010, and filed a shelf registration statement with the SEC to provide $1.0 billion of capacity, which was declared effective on December 23, 2005. The shelf registration allows PEC to issue various securities, including First Mortgage Bonds, Senior Notes, Debt Securities and Preferred Stock.

·   PEF issued $300 million in Mortgage Bonds, 4.50% Series due 2010 and $450 million in Series A Floating Rate Senior Notes due 2008. PEF paid at maturity $45 million in 6.72% Medium-Term Notes, Series B. PEF also entered into a new $450 million five-year RCA with a syndication of financial institutions, which is scheduled to expire on March 28, 2010, and filed a shelf registration statement with the SEC to provide $1.0 billion of capacity, which was declared effective on December 23, 2005. The shelf registration allows PEF to issue various securities, including First Mortgage Bonds, Debt Securities and Preferred Stock.

·   Progress Energy issued approximately 4.8 million shares of our common stock for approximately $208 million in net proceeds from its Investor Plus Stock Purchase Plan and its employee benefit and stock option plans. Included in these amounts were approximately 4.6 million shares for proceeds of approximately $199 million to meet the requirements of the 401(k) and the Investor Plus Stock Purchase Plan. For 2005, the dividends paid on common stock were approximately $582 million.

2004

·   Progress Energy paid at maturity $500 million in 6.55% Senior Notes and entered into a new $1.1 billion five-year line of credit, expiring August 5, 2009. This facility replaced Progress Energy’s $250 million 364-day line of credit and its three-year $450 million line of credit, which were both scheduled to expire in November 2004. Proceeds from the sale of natural gas assets were used to extinguish PVI's $241 million bank facility, and Progress Capital Holdings, Inc. paid at maturity $25 million of 6.48% medium-term notes.

·   PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds, $2 million of New Hanover County 6.3% Series Pollution Control Bonds, and $2 million of Chatham County 6.3% Series Pollution Control Bonds. PEC paid at maturity $150 million of 5.875% First Mortgage Bonds and $150 million of 7.875% First Mortgage Bonds. PEC extended to July 27, 2005, its $165 million 364-day line of credit, which was scheduled to expire on July 29, 2004.

·   PEF paid at maturity $40 million in 6.69% Medium-Term Notes, Series B.

·   Progress Energy issued approximately 1.7 million shares of our common stock for approximately $73 million in net proceeds from our Investor Plus Stock Purchase Plan and our employee benefit and stock option plans. Included in these amounts were approximately 1.4 million shares for proceeds of approximately $62 million to meet the requirements of the 401(k) and the Investor Plus Stock Purchase Plan. For 2004, the dividends paid on common stock were approximately $558 million.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

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

The Utilities produced substantially all of our consolidated cash from operations for the years ended December 31, 2006 and 2005. It is expected that the Utilities will continue to produce substantially all of the consolidated cash flows from operations over the next several years. Our synthetic fuels operations do not currently produce positive operating cash flow due to the difference in timing of when tax credits are recognized for financial reporting purposes and when tax credits are realized for tax purposes (See “Other Matters - Synthetic Fuels Tax Credits”).

Cash from operations plus availability under our credit facilities and shelf registration statements is expected to be sufficient to meet our requirements in the near term. To the extent necessary, we may also use limited ongoing

75

equity sales from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans to meet our liquidity requirements.

Over the long term, meeting the anticipated load growth at the Utilities will require a balanced approach, including energy conservation and efficiency programs, development and deployment of new energy technologies, and new generation, transmission and distribution facilities, potentially including new baseload generation facilities in both Florida and the Carolinas by the middle of the next decade. This approach will require the Utilities to make significant capital investments. See “Introduction - Strategy - Regulated Utilities” for additional information. These anticipated capital investments are expected to be funded through a combination of long-term debt, preferred stock and common equity, which is dependent on our ability to successfully access capital markets. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.

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

At December 31, 2006, the current portion of our long-term debt was $324 million, which we expect to fund with a combination of cash from operations, proceeds from sales of assets, commercial paper borrowings and long-term debt. See Note 3 for additional information on asset sales.

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, as discussed in “Other Matters - Regulatory Environment” and Note 7, and filings for recovery of environmental costs, as discussed in Note 21 and in “Other Matters - Environmental Matters,” may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources.

Base Rates

PEC’s base rates are subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC) and the South Carolina Public Service Commission (SCPSC). As further discussed in Note 21B, the Clean Smokestacks Act was enacted in 2002. The Clean Smokestacks Act freezes North Carolina electric utility base rates for a five-year period ending in December 2007, unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn 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. Subsequent to 2007, PEC’s current North Carolina base rates will continue subject to traditional cost-based rate regulation.

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. 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 a specified threshold and specified cap, which will be adjusted annually, and 100 percent of revenues above the specified cap. PEF’s retail base revenues did not exceed the specified 2006 threshold, and thus no revenues were subject to revenue sharing. 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. Additionally, PEF will continue to recover and collect a return on Hines Unit 2 through the fuel clause through late 2007, when it will be transferred into base rates. If PEF’s regulatory return on equity (ROE) falls below 10 percent, and for certain other events, PEF is authorized to petition the FPSC for a base rate increase.

76

PEC Fuel Cost Recovery

On June 16, 2006, the SCPSC approved a settlement agreement for an increase in the fuel rate charged to PEC’s South Carolina ratepayers for under-recovered fuel costs and to meet future expected fuel costs. The settlement agreement provided for a $23 million, or 4.6 percent, increase in rates, effective July 1, 2006. At December 31, 2006, PEC’s South Carolina deferred fuel balance was $29 million, of which $5 million is expected to be collected after 2007 in accordance with the settlement agreement and, therefore, has been classified as a long-term regulatory asset.

On September 25, 2006, the NCUC approved a settlement agreement for an increase in the fuel rate charged to PEC’s North Carolina ratepayers. The settlement agreement provided for a $177 million, or 6.7 percent, increase in rates effective October 1, 2006. The settlement agreement further provides for rate increases of $50 million in 2007 and $30 million in 2008 and for PEC to collect its existing deferred fuel balance by September 30, 2009. PEC initially sought an increase of $292 million, or 11.0 percent, but agreed to a three-year phase-in of the increase in order to address customer concerns regarding the magnitude of the proposed increase. PEC will be allowed to calculate and collect interest at 6% on the difference between its fuel factor proposed in its original request to the NCUC and the settlement agreement’s factor. At December 31, 2006, PEC’s North Carolina deferred fuel balance was $281 million, of which $109 million is expected to be collected after 2007 in accordance with the settlement agreement and, therefore, has been classified as a long-term regulatory asset. The Carolina Utility Customers Association (CUCA) has appealed the NCUC’s order on the grounds that the NCUC does not have the statutory authority to establish fuel rates for more than one year. We anticipate filing a motion to dismiss during the first quarter of 2007. We cannot predict the outcome of this matter.

PEF Pass-through Clause Cost Recovery

On November 8, 2006, the FPSC approved PEF’s supplemental filing resulting in a $40 million, or 0.7 percent, increase over 2006 rates to cover rising fuel, environmental compliance and energy conservation costs. The new charges were effective January 1, 2007. At December 31, 2006, PEF was over-recovered in fuel and capacity costs by $63 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 sulfur dioxide (SO₂) allowance costs associated with PEF’s purported failure to utilize the most economical sources of coal at Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) during the period 1996 to 2005. The OPC subsequently revised its claim to $135 million, plus interest. A hearing on the matter has been scheduled by the FPSC for April 2, 2007. PEF believes that its coal procurement practices were prudent and that it has sound legal and factual arguments to successfully defend its position. We cannot predict the outcome of this matter.

On February 8, 2007, the FPSC issued an order approving PEF’s request for a need determination to uprate Crystal River Unit No. 3 Nuclear Plant (CR3). The uprate will take place in two stages in 2009 and 2011 and is estimated to cost approximately $382 million, which includes potential transmission system improvements and modifications to comply with environmental regulations. The FPSC has scheduled a hearing on May 23, 2007, to determine whether the uprate costs should be recovered through the fuel adjustment clause. If PEF does not receive approval to recover the uprate costs through the fuel adjustment clause, these costs will be recoverable through base rates, similar to other utility plant additions. 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. We cannot predict the outcome of this matter.

PEF has received approval from the FPSC for recovery of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC), which were estimated to be $43 million at December 31, 2006. Additionally, on November 6, 2006, the FPSC approved PEF’s petition for its integrated strategy to address compliance with CAIR, CAMR and CAVR through the ECRC. The FPSC also approved cost recovery of prudently incurred costs necessary to achieve this strategy, which are currently estimated to be $900 million to $1.7 billion.

77

Storm Cost Recovery

In 2005, the FPSC issued orders authorizing PEF to recover over a two-year period, including interest, costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004, including $232 million beginning August 1, 2005, and an additional $13 million, beginning January 1, 2006.

On August 29, 2006, the FPSC approved a settlement agreement related to PEF’s storm cost-recovery docket that would allow PEF to extend its current two-year storm surcharge for an additional 12-month period to replenish its storm reserve. The requested extension, which begins in August 2007, will replenish the existing storm reserve by an estimated additional $130 million. 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. 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.

Nuclear Cost Recovery

In response to legislation passed by the Florida Legislature in 2006, the FPSC has promulgated rules that will allow PEF to recover prudently incurred siting, preconstruction costs and allowance for funds used during construction (AFUDC) on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in PEF’s rate base when the plant is placed in commercial operation. In addition, the rule will require the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility. The FPSC approved the new rules on February 13, 2007.

Other Matters

On November 3, 2004, the FPSC approved PEF’s petition for Determination of Need for the construction of a fourth unit at PEF’s Hines Energy Complex. The estimated total in-service cost of Hines Unit 4 approved as part of the Determination of Need was $286 million. The unit is planned for commercial operation in December 2007. If the actual cost is less than the original estimate, ratepayers will receive the benefit of such cost under-runs. Any costs that exceed this estimate will not be recoverable absent, among other things, extraordinary circumstances as found by the FPSC in subsequent proceedings. The current estimate of in-service cost exceeds the initial project estimate by approximately 12 percent to 15 percent due to what we believe to be extraordinary circumstances. Therefore, we believe that disallowance of these costs by the FPSC in subsequent proceedings is not probable. We cannot predict the outcome of this matter.

CAPITAL EXPENDITURES

Total cash from operations provided the funding for our capital expenditures, including property additions, nuclear fuel expenditures and diversified business property additions during 2006.

As shown in the table below, we expect the majority of our capital expenditures to be incurred at our regulated operations. We expect to fund our capital requirements primarily through a combination of internally generated funds, long-term debt, preferred stock and/or common equity. In addition, we have $2.030 billion in credit facilities that support the issuance of commercial paper. Access to the commercial paper market provides additional liquidity to help meet working capital requirements. We anticipate our regulated capital expenditures will increase in 2007 and 2008, primarily due to increased spending on environmental initiatives and current growth and maintenance projects. AFUDC represents the costs of capital funds necessary to finance the construction of new regulated assets.

78

	Actual			Forecasted
(in millions)	2006			2007			2008			2009
Regulated capital expenditures	$	1,423		$	2,250		$	2,380		$	2,180
Nuclear fuel expenditures		114			180			170			210
AFUDC - borrowed funds		(7	)		(20	)		(40	)		(40	)
Nonregulated capital and other expenditures		17			20			10			10
Total	$	1,547		$	2,430		$	2,520		$	2,360

Regulated capital expenditures for 2007, 2008 and 2009 in the table above include approximately $640 million, $610 million and $220 million, respectively, for environmental compliance capital expenditures. Forecasted environmental compliance capital expenditures for 2007, 2008 and 2009 include $320 million, $220 million and $50 million, respectively, at PEC and $320 million, $390 million and $170 million, respectively, at PEF. We currently estimate that total future capital expenditures for the Utilities to comply with current environmental laws and regulations addressing air and water quality, which are eligible for regulatory recovery through either base rates or cost-recovery clauses, could be in excess of $1.0 billion each at PEC and PEF through 2018, which is the latest compliance target date for current air and water quality regulations. See “Other Matters - Environmental Matters” for further discussion of our environmental compliance costs and related recovery of costs.

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

CREDIT FACILITIES AND REGISTRATION STATEMENTS

At December 31, 2006, we had no outstanding borrowings under our credit facilities. The following table summarizes our RCAs and available capacity at December 31, 2006:

(in millions)	Description			Total		Outstanding		Reserved (a)			Available
Progress Energy, Inc.		Five-year (expiring 5/3/11	)	$	1,130	$	-	$	(60	)	$	1,070
PEC		Five-year (expiring 6/28/10	)		450		-		-			450
PEF		Five-year (expiring 3/28/10	)		450		-		-			450
Total credit facilities				$	2,030	$	-	$	(60	)	$	1,970

^(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, 2006, Progress Energy, Inc. had a total amount of $60 million of letters of credit issued, which were supported by the RCA.

All of the revolving credit facilities supporting the credit were arranged through a syndication of financial institutions. There are no bilateral contracts associated with these facilities. See Note 12 for additional discussion of our credit facilities.

Our internal financial policy precludes issuing commercial paper in excess of the supporting lines of credit. At December 31, 2006, we had no outstanding commercial paper and a total of $60 million reserved for letters of credit issued, leaving an additional $1.970 billion available for future borrowing under our credit lines. In addition, we have requirements to pay minimal annual commitment fees to maintain our credit facilities. We expect to continue to use commercial paper issuances as a source of liquidity as long as we maintain our current short-term ratings.

All of the credit facilities include a defined maximum total debt-to-total capital ratio (leverage). We are currently in compliance with these covenants and were in compliance with these covenants at December 31, 2006. See Note 12 for a discussion of the credit facilities’ financial covenants. At December 31, 2006, the calculated ratios for the Progress Registrants, pursuant to the terms of the agreements, are as disclosed in Note 12.

79

Progress Energy, as a well-known seasoned issuer, has on file with the SEC a shelf registration statement under which Progress Energy may issue an indeterminate number or amount of various securities, including Senior Debt Securities, Junior Subordinated Debentures, Common Stock, Preferred Stock, Stock Purchase Contracts, Stock Purchase Units, and Trust Preferred Securities and Guarantees. The board of directors has authorized the issuance and sale of up to $1.0 billion aggregate principal amount of various securities off the new shelf registration statement, in addition to $679 million of various securities, which were not sold from our prior shelf registration statement. Accordingly, at December 31, 2006, Progress Energy has the authority to issue and sell up to $1.679 billion aggregate principal amount of various securities.

Both PEC and PEF currently have on file with the SEC a shelf registration statement under which each can issue up to $1.0 billion of various long-term debt securities and preferred stock.

Both PEC and PEF can issue First Mortgage Bonds under their respective First Mortgage Bond indentures. At December 31, 2006, PEC and PEF could issue up to $3.333 billion and $4.330 billion, respectively, based on property additions and $1.627 billion and $175 million, respectively, based upon retirements.

CAPITALIZATION RATIOS

The following table shows our total debt to total capitalization ratios at December 31:

	2006	2005
Common stock equity	47.2%	41.6%
Preferred stock and minority interest	0.6%	0.7%
Total debt	52.2%	57.7%

80

CREDIT RATING MATTERS

The major credit rating agencies have currently rated our securities as follows:

	Moody’s Investors Service	Standard & Poor’s	Fitch Ratings
Progress Energy, Inc.
Outlook	Stable	Positive	Stable
Corporate credit rating	n/a	BBB	n/a
Senior unsecured debt	Baa2	BBB-	BBB
Commercial paper	P-2	A-2	F-2
PEC
Outlook	Positive	Positive	Stable
Corporate credit rating	Baa1	BBB	n/a
Commercial paper	P-2	A-2	F-1
Senior secured debt	A3	BBB	A
Senior unsecured debt	Baa1	BBB-	A-
Subordinate debt	Baa2	n/a	n/a
Preferred stock	Baa3	BB+	BBB+
PEF
Outlook	Stable	Positive	Stable
Corporate credit rating	A3	BBB	n/a
Commercial paper	P-2	A-2	F-1
Senior secured debt	A2	BBB	A
Senior unsecured debt	A3	BBB-	A-
Preferred stock	Baa2	BB+	BBB+
FPC Capital I
Preferred stock (a)	Baa2	BB+	n/a
Progress Capital Holdings, Inc.
Senior unsecured debt (b)	Baa1	BBB-	n/a
(a)Guaranteed by Progress Energy, Inc. and Florida Progress. (b)Guaranteed by Florida Progress.

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

On November 3, 2006, Fitch upgraded the senior unsecured credit ratings of Progress Energy to BBB from BBB-, PEC to A- from BBB+ and PEF to A- from BBB+. The outlook at each entity was changed to stable. The short-term ratings of PEC and PEF were upgraded to F-1 from F-2. The ratings upgrades were based on our reduced business risk due to nonutility asset sales, the $1.3 billion holding company debt reduction and the successful resolution of the Internal Revenue Service (IRS) audit of the Earthco synthetic fuels facilities (Earthco).

On August 31, 2006, Moody’s upgraded Progress Energy’s outlook to stable from negative, citing expected holding company debt reduction from asset sale proceeds, successful resolution of the IRS audit of the Earthco synthetic fuels facilities, and lower business risk after divestitures of noncore assets. Moody’s also upgraded PEC’s outlook to positive from stable, citing PEC’s manageable leverage, strong cash flow coverage ratios for its current ratings category, and constructive regulatory environments in North Carolina and South Carolina. PEF’s outlook remains stable.

On July 25, 2006, S&P affirmed the corporate credit ratings of BBB at Progress Energy, Inc., PEC and PEF and revised each company's outlook to positive from stable. The outlook revision reflects the progress toward our holding company debt reduction plan and expectations of future financial performance at the BBB+ benchmark

81

levels. S&P also improved Progress Energy's business risk profile to 5 from 6 due to the sales of the DeSoto and Rowan plants and Gas, as well as anticipated cash flow benefits related to the idling of our synthetic fuels facilities.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include performance obligations under power supply agreements, tolling 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, 2006, we have issued $1.489 billion of guarantees for future financial or performance assurance, including $106 million at PEC and $2 million at PEF. Included in this amount is $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries issued by the Parent (See Note 23). We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below Baa3 or BBB-) by Moody’s or S&P for the Parent’s senior unsecured debt rating, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. At December 31, 2006, the Parent’s senior unsecured debt rating was Baa2 by Moody’s and BBB- by S&P and no guarantee obligations had been triggered. If the guarantee obligations were triggered, the approximate amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for Progress Energy’s nonregulated portfolio and power supply agreements, was $596 million at December 31, 2006. While we believe that we would be able to meet this obligation with cash or letters of credit, if we cannot, our financial condition, liquidity and results of operations will be materially and adversely impacted.

At December 31, 2006, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations as discussed in Note 22C.

MARKET RISK AND DERIVATIVES

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

CONTRACTUAL OBLIGATIONS

We are party to numerous contracts and arrangements obligating us to make cash payments in future years. These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. Amounts in the following table are estimated based upon contractual terms, and actual amounts will likely differ from amounts presented below. Further disclosure regarding our contractual obligations is included in the respective notes to the Consolidated Financial Statements. We take into consideration the future commitments when assessing our liquidity and future financing needs. The following table reflects Progress Energy’s contractual cash obligations and other commercial commitments at December 31, 2006, in the respective periods in which they are due:

82

(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (a) (See Note 12)	$	9,242	$	324	$	1,277	$	1,406	$	6,235
Interest payments on long-term debt and interest rate derivatives (b)		6,224		545		964		822		3,893
Capital lease obligations (See Note 22B)		589		29		71		68		421
Operating leases (See Note 22B)		428		79		118		59		172
Fuel and purchased power (c) (d) (See Note 22A)		13,133		2,613		3,447		1,657		5,416
Other purchase obligations (d) (See Note 22A)		892		479		299		40		74
Minimum pension funding requirements (e)		237		56		95		86		-
Other commitments (f)(g)		176		43		26		27		80
Total	$	30,921	$	4,168	$	6,297	$	4,165	$	16,291

^(a)   Our maturing debt obligations are generally expected to be repaid with asset sales and cash from operations or refinanced with new debt issuances in the capital markets.

^(b)   Interest payments on long-term debt and interest rate derivatives are based on the interest rate effective at December 31, 2006, and the LIBOR forward curve at December 31, 2006, respectively.

^(c)   Fuel and purchased power commitments represent the majority of our remaining future commitments after debt obligations. Essentially all of our fuel and purchased power costs are recovered through pass-through clauses in accordance with North Carolina, South Carolina and Florida regulations and therefore do not require separate liquidity support.

^(d)   We have additional contractual obligations associated with our discontinued CCO operations, which are not reflected in this table. They include fuel and purchased power obligations of $11 million for 2007, $1 million for 2008, $2 million each for 2009 through 2011 and $7 million thereafter. These obligations also include other purchase obligations of $15 million each for 2007 through 2009, $13 million each for 2010 and 2011 and $127 million thereafter. We anticipate transferring the obligations under these contracts to a third party as part of our disposition strategy.

^(e)   Projected pension funding status is based on current actuarial estimates and is subject to future revision.

^(f)    In 2008, PEC must begin transitioning North Carolina jurisdictional amounts currently retained internally to its external decommissioning funds. The transition of $131 million must be complete by December 31, 2017, and at least 10 percent must be transitioned each year.

^(g)   We have certain future commitments related to four synthetic fuels facilities purchased that provide for contingent payments (royalties) through 2007 (See Note 22D).

OTHER MATTERS

SYNTHETIC FUELS TAX CREDITS

Historically, we have had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Code (Section 29). The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied, including a requirement that the synthetic fuels differ significantly in chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced from a facility that was placed in service before July 1, 1998. Qualifying synthetic fuels facilities entitle their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The tax credits associated with synthetic fuels in a particular year may be phased out if annual average market prices for crude oil exceed certain prices. Synthetic fuels are generally not economical to produce and sell absent the credits. In May 2006, we idled production of synthetic fuels at our synthetic fuels facilities. As discussed below in “Impact of Crude Oil Prices,” the decision to idle production was based on the high level of oil prices. Based on significantly reduced oil prices combined with current favorable fuel price projections, we resumed limited production at our synthetic fuels facilities in September and October 2006, which continued through the end of 2006. We produced 3.7 million tons of synthetic fuels during 2006.

83

TAX CREDITS

Legislation enacted in 2005 redesignated the Section 29 tax credit as a general business credit under Section 45K of the Code (Section 45K) effective January 1, 2006. The previous amount of Section 29 tax credits that we were allowed to claim in any calendar year through December 31, 2005, was limited by the amount of our regular federal income tax liability. Section 29 tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. The redesignation of Section 29 tax credits as a Section 45K general business credit removes the regular federal income tax liability limit on synthetic fuels production and subjects the credits to a 20-year carry forward period. This provision would allow us to produce more synthetic fuels than we have historically produced, should we choose to do so.

Total Section 29/45K credits generated through December 31, 2006 (including those generated by Florida Progress prior to our acquisition), were approximately $1.9 billion, of which $974 million has been used to offset regular federal income tax liability, $847 million is being carried forward as deferred tax credits and $38 million has been reserved due to the estimated phase-out of tax credits due to high oil prices, as described below.

IMPACT OF CRUDE OIL PRICES

Although the Section 29/45K tax credit program is expected to continue through 2007, recent market conditions, world events and catastrophic weather events have increased the volatility and level of oil prices that could limit the amount of those credits or eliminate them entirely for 2007. This possibility is due to a provision of Section 29 that provides that if the Annual Average Price exceeds the Threshold Price, the amount of Section 29/45K tax credits is reduced for that year. Also, if the Annual Average Price exceeds the Phase-out Price, the Section 29/45K tax credits are eliminated for that year. The Threshold Price and the Phase-out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase-out Price for a year, the amount by which Section 29/45K tax credits are reduced will depend on where the Annual Average Price falls in that continuum. For example, for 2005, the Threshold Price was $53.20 per barrel and the Phase-out Price was $66.78 per barrel. If the Annual Average Price had been $59.99 per barrel, there would have been a 50 percent reduction in the amount of Section 29 tax credits for that year. Based on the Annual Average Price of $50.26, there was no phase-out of our synthetic fuels tax credits in 2005.

The Department of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the EIA. Because the EIA publishes its information on a three-month lag, the secretary of the Treasury finalizes the calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2006 is expected to be published in early April 2007.

We estimate that the 2006 Threshold Price will be approximately $55 per barrel and the Phase-out Price will be approximately $69 per barrel, based on an estimated inflation adjustment for 2006. The monthly Domestic Crude Oil First Purchases Price published by the EIA has recently averaged approximately $7 lower than the corresponding daily NYMEX prompt month settlement price for light sweet crude oil. Through December 31, 2006, the average daily NYMEX settlement price for light sweet crude oil was $66.25 per barrel. Based upon the estimated 2006 Threshold Price and Phase-out Price, assuming that the $7 average differential between the Domestic Crude Oil First Purchases Price published by the EIA and the NYMEX settlement price continued through December 31, 2006, we estimate that the synthetic fuels tax credit amount for 2006 will be reduced by approximately 35 percent. Therefore, we reserved 35 percent or approximately $38 million of the $107 million of tax credits generated during 2006. The final calculations of any reductions in the value of the tax credits will not be determined until April 2007 when final 2006 oil prices are published.

We estimate that the 2007 Threshold Price will be approximately $56 per barrel and the Phase-out Price will be approximately $70 per barrel, based on an estimated inflation adjustment for 2006 and 2007. The monthly Domestic Crude Oil First Purchases Price published by the EIA has recently averaged approximately $7 lower than the corresponding daily NYMEX prompt month settlement price for light sweet crude oil. As of January 31, 2007, the average NYMEX futures price for light sweet crude oil for calendar year 2007 was $59.50 per barrel. Based upon the estimated 2007 Threshold Price and Phase-out Price, if oil prices for the rest of 2007 remained at the January 31, 2007,

84

average 2007 futures price level of $59.50 per barrel, we currently estimate that the synthetic fuels tax credit amount for 2007 would not be reduced.

In January 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. These contracts will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production and will be marked-to-market with changes in fair value recorded through earnings. Our synthetic fuels production levels for 2007 remain uncertain because we cannot predict with any certainty the Annual Average Price of oil for 2007. We will continue to monitor the environment surrounding synthetic fuels production and will adjust our production as warranted by changing conditions. See Note 17 and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

IMPAIRMENT OF SYNTHETIC FUELS AND OTHER RELATED LONG-LIVED ASSETS

We monitor our long-lived assets for impairment as warranted.With the idling of our synthetic fuels facilities during the second quarter of 2006, we performed an impairment evaluation of our synthetic fuels and other related operating long-lived assets. The impairment test considered numerous factors, including, among other things, continued high oil prices and the then-current “idle” state of our synthetic fuels facilities. Based on the results of the impairment test, we recorded pre-tax impairment charges of $91 million ($55 million after-tax) during the quarter ended June 30, 2006 (See Notes 8 and 9). These charges represent the entirety of the asset carrying value of our synthetic fuels intangible assets and 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.

SALE OF PARTNERSHIP INTEREST

In June 2004, through our subsidiary Progress Fuels, we sold in two transactions a combined 49.8 percent partnership interest in Colona, one of our synthetic fuels facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gains from the sales will be recognized on a cost-recovery basis as the facility produces and sells synthetic fuels and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Gain recognition is dependent on the synthetic fuels production qualifying for Section 29/45K tax credits and the value of such tax credits as discussed above. Until the gain recognition criteria are met, gains from selling interests in Colona will be deferred. It is possible that gains will be deferred to subsequent quarters, or to a subsequent calendar year, until there is persuasive evidence that no tax credit phase-out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters in a calendar year or to a subsequent calendar year. In the event that the synthetic fuels tax credits from the Colona facility are reduced, including from an extended idling of our production due to an increase in the price of oil that could limit or eliminate synthetic fuels tax credits, the amount of proceeds realized from the sale could be significantly impacted. At December 31, 2006, a pre-tax gain on monetization of $7 million has been deferred. Based on the current level of oil prices and subject to final adjustments, we expect to recognize this gain in 2007. Beginning with the payment for the second quarter of 2006, the minority interest parties have elected to defer their cash payments in consideration of the idling of the synthetic fuels facilities at that time. In consideration of the resumption of limited synthetic fuels production in the fourth quarter of 2006, the minority interest parties made a partial payment in January 2007.

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

REGULATORY ENVIRONMENT

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

PEC and PEF continue to monitor developments impacting retail competition in their respective service territories. Movement toward deregulation throughout the nation has effectively ceased due to numerous factors including, but

85

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

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

Issues regarding the timing, creation and structure of transmission organizations are evaluated by the Utilities’ regulatory authorities. We cannot predict the outcome of these matters (See Note 7D).

On May 5, 2006, the Florida state legislature passed a comprehensive energy bill, which has been signed by the governor. The legislation creates a new energy council tasked with developing a statewide energy policy, provides incentives to renewable energy sources and fosters the construction of new nuclear power plants, including streamlining the siting of nuclear power plants and related transmission facilities, exempting new nuclear plants from the FPSC bid rule and requiring the FPSC to issue rules authorizing alternative cost-recovery mechanisms for pre-construction costs and construction cost financing. See “Nuclear” below for related FPSC rule issuances. PEF cannot determine at this time how the final rules and regulations resulting from this legislation will impact its operations and financial condition.

Due to the damage electric utility facilities suffered during recent hurricanes, during 2006 the FPSC adopted rules that require Florida’s investor-owned electric utilities, including PEF, to strengthen cost effectively, or storm harden, the state’s electric infrastructure. Storm-hardening plans are required to be filed and updated every three years for the FPSC’s approval. Each plan must address such factors as the effect of extreme wind, flooding and storm surges on electric facilities. The plans must identify critical infrastructure and the respective utilities’ deployment strategy for strengthening electric service in their service areas. In addition, state utilities are required to inspect their wooden distribution poles once every eight years. PEF does not believe that compliance with these rules will materially increase PEF’s costs due to its pole inspection and vegetation maintenance programs already in effect. Costs to comply with the storm-hardening rules are recoverable through PEF’s base rates.

The FPSC has published a proposed rule that specifies what storm costs will be recoverable and whether such recoverable costs would be offset against a utility’s storm reserve fund or recoverable through its base rates. The FPSC held a public workshop on February 21, 2007, to discuss the proposed rule with the intent to issue a final rule prior to the 2007 storm season. We cannot predict the outcome of this matter.

On April 26, 2006, PEC submitted a license renewal application with the FERC seeking a 50-year license for its Tillery and Blewett hydroelectric generating plants. The license for these plants currently expires in April 2008 and the requested renewal will allow the plants to continue operations until 2058. PEC and a key group of stakeholders have reached an agreement in principle that supports PEC’s relicensing application. The agreement in principle, which has been filed with the FERC, will establish increased water flows from both plants and will protect water supplies for local governments as well as provide enhancements for recreation, water quality and aquatic habits. The remaining phase of the application process will take approximately one year and includes review by the FERC and solicitation of public comment. We cannot predict the outcome of this matter.

In 2004, the FERC issued orders concerning utilities’ ability to sell wholesale electricity at market-based rates, including the adoption of two interim screens for assessing an applicant’s potential generation market power for determining whether the applicant should be allowed to sell wholesale electricity at market-based rates. The Utilities do not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believed it would experience in passing one of the interim screens, PEC filed revisions to its market-based rate tariffs restricting PEC to sales outside of PEC’s control area and peninsular Florida, and filed a new cost-based tariff for sales within PEC’s control area. The FERC has accepted these revised tariffs. We do not anticipate that the operations of the Utilities will be materially impacted by these market-based rates decisions.

86

LEGAL

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

NUCLEAR

Nuclear generating units are regulated by the NRC. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved.

Our nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications (See Notes 5 and 22D).

Due to the anticipated growth in our service territories, we estimate that we will require new baseload generation facilities in both Florida and the Carolinas by the middle of the next decade, and we are evaluating the best available options for this generation, including advanced design nuclear and clean coal technologies. At this time, no definitive decision has been made.

We have announced that we are pursuing development of combined license (COL) applications. Our announcement is not a commitment to build a nuclear plant. It is a necessary step to keep open the option of building a plant or plants. On January 23, 2006, we announced that PEC selected a site at the Shearon Harris Nuclear Plant (Harris) to evaluate for possible future nuclear expansion. We currently expect to file the application for the COL for PEC’s Harris site in 2007. We have selected for PEC the Westinghouse Electric AP-1000 reactor design as the technology upon which to base the potential application submission. On December 12, 2006, we announced that PEF selected a site in Levy County, Fla., to evaluate for possible future nuclear expansion, and PEF expects to file the application for the COL in 2008. We have not selected the reactor design technology upon which to base the PEF potential application submission. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, construction activities could begin as early as 2010, and new plants could be online in late 2016.The NRC estimates that it will take approximately three to four years to review and process the COL applications.

On January 16, 2007, the U.S. Supreme Court declined to hear an appeal of a Ninth Circuit U.S. Court of Appeals’ decision in which the Ninth Circuit held that the NRC is required to consider the environmental impacts of terrorist attacks under the National Environmental Policy Act in authorizing an independent spent fuel storage installation. Similar cases, including cases involving operating license renewals, are pending in seven other jurisdictions. The NRC is considering the scope and import of the Ninth Circuit’s decision in reviewing its operating license renewal program. The extent and timing of the NRC’s application of the case is unclear at this time, and the impact, if any, on PEC’s pending Harris operating license renewal application or any future PEC or PEF operating licensing proceedings cannot be predicted at this time.

A new nuclear plant may be eligible for the federal production tax credits and risk insurance provided by EPACT. EPACT provides an annual tax credit of 1.8 cents per kWh for nuclear facilities for the first eight years of operation. The credit is limited to the first 6,000 MW of new nuclear generation in the United States and has an annual cap of $125 million per 1,000 MW of national MW capacity limitation allocated to the unit. In April 2006, the IRS provided interim guidance that the 6,000 MW of production tax credits generally will be allocated to new nuclear facilities that file license applications with the NRC by December 31, 2008, had poured safety-related concrete prior to January 1, 2014, and were placed in service before January 1, 2021. There is no guarantee that the interim guidance will be incorporated into the final regulations governing the allocation of production tax credits. Multiple utilities have announced plans to pursue new nuclear plants. There is no guarantee that any nuclear plant we construct would qualify for these or other incentives. We cannot predict the outcome of this matter.

In accordance with provisions of Florida’s comprehensive energy bill discussed above, in December 2006, the FPSC ordered new rules that would allow investor-owned utilities such as PEF to request partial recovery of the planning and construction costs of a nuclear power plant prior to commercial operation. The FPSC issued a final rule on

87

February 13, 2007, under which utilities will be allowed to recover prudently incurred siting, preconstruction costs and AFUDC on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in a utility’s rate base when the plant is placed in commercial operation. In addition, the rule will require the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility. Also, on February 1, 2007, the FPSC amended its power plant bid rules to, among other things, exempt nuclear power plants from existing bid requirements.

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.

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several 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 or the state of Florida. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 7 and 21). Both PEC and PEF evaluate potential claims against other potential 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. Hazardous and solid waste management matters are discussed in detail in Note 21.

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

AIR QUALITY AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which would likely result in increased planned capital expenditures and O&M expenses. Additionally, Congress is considering legislation that would require additional reductions in air emissions of nitrogen oxide (NOx), SO₂, carbon dioxide (CO₂) and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs that could be material to our financial position or results of operations. Control equipment that will be installed pursuant to the provisions of the Clean Smokestacks Act, CAIR, CAMR and CAVR, which are discussed below, may address some of the issues outlined above. CAVR requires the installation of best available retrofit technology (BART) on certain units. However, the outcome of these matters cannot be predicted.

88

The following tables contain information about our current estimates of capital expenditures to comply with environmental laws and regulations described below. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. The outcome of future petitions for recovery cannot be predicted. Estimated expenditures for the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) include the cost to install NOx controls under North Carolina’s and South Carolina’s programs to comply with the federal eight-hour ozone standard. The air quality controls installed to comply with the NOx SIP Call and Clean Smokestacks Act will result in a reduction of the costs to meet the CAIR requirements for our North Carolina units at PEC. We review our estimates on an ongoing basis. The timing and extent of the costs for future projects will depend upon final compliance strategies.

Progress Energy

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through December 31, 2006
NOx SIP Call	2002-2007	$355	$346
Clean Smokestacks Act	2002-2013	1,000 - 1,400	562
CAIR/CAMR/CAVR	2005-2018	1,100 - 2,000	28
Total air quality		2,455 - 3,755	936
Clean Water Act Section 316(b) (a)		-	1
North Carolina Groundwater Standard(b)		-	-
Total water quality		-	1
Total air and water quality		$2,455 - $3,755	$937

PEC

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through December 31, 2006
NOx SIP Call	2002-2007	$355	$346
Clean Smokestacks Act	2002-2013	1,000 - 1,400	562
CAIR/CAMR/CAVR	2005-2018	200 - 300	1
Total air quality		1,555 - 2,055	909
Clean Water Act Section 316(b) (a)		-	-
North Carolina Groundwater Standard(b)		-	-
Total water quality		-	-
Total air and water quality		$1,555 - $2,055	$909

PEF

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through December 31, 2006
CAIR/CAMR/CAVR	2005-2018	$900 - $1,700	$27
Clean Water Act Section 316(b) (a)		-	1
Total air and water quality		$900 - $1,700	$28

^(a)   Compliance plans to meet the requirements of a revised or new implementing rule under Section 316(b) of the Clean Water Act will be determined upon finalization of the rule. See discussion under “Water Quality.”

^(b)   Compliance plans will be determined upon finalization of the changes expected to be proposed to the North Carolina groundwater quality standard for arsenic.

89

New Source Review

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether changes at those facilities were subject to New Source Review (NSR) requirements or New Source Performance Standards under the Clean Air Act. We were asked to provide information to the EPA as part of this initiative and cooperated in supplying the requested information. The outcome of this matter cannot be predicted. However, the EPA has initiated civil enforcement actions against unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements requiring expenditures by these unaffiliated utilities in excess of $1.0 billion. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related costs through rate adjustments or similar mechanisms. The U.S. Supreme Court has heard arguments, but not yet issued a ruling, related to an appeal of a decision issued by the U.S. Court of Appeals for the Fourth Circuit, in a case involving an unaffiliated utility, holding that NSR applies to projects that result in an increase in maximum hourly emissions.

On March 17, 2006, the U.S. Court of Appeals for the District of Columbia Circuit set aside the EPA’s 2003 NSR equipment replacement rule. The rule would have provided a more uniform definition of routine equipment replacement. The court had earlier set aside a provision in the NSR rule, which had exempted the installation of pollution control projects from review. The Court denied a request by the EPA for a re-hearing regarding this matter on June 30, 2006. These projects are now subject to NSR requirements, adding time and cost to the installation process. On November 27, 2006, the EPA filed a writ of certiorari petition requesting that the U.S. Supreme Court review the U.S. Court of Appeals for the District of Columbia Circuit's ruling that vacated the agency's plant renovation exemption for its NSR rule. The outcome of this matter cannot be predicted.

NOx SIP Call Rule under Section 110 of the Clean Air Act

The NOx SIP Call is an EPA rule that requires 22 states, including North Carolina, South Carolina and Georgia, to further reduce NOx emissions. The NOx SIP Call is not applicable to Florida. Further technical analysis and rulemaking may result in requirements for additional controls at some units. Increased O&M expenses relating to the NOx SIP Call are not expected to be material to our or PEC’s results of operations.

Clean Smokestacks Act

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. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by the Clean Smokestacks Act. To meet SO₂ emission targets, PEC is installing devices that neutralize sulfur compounds formed during coal combustion (scrubbers) on some of its coal-fired units. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that are then removed. In March 2006, PEC filed its annual estimate with the NCUC of the total capital expenditures to meet emission targets under the Clean Smokestacks Act by the end of 2013, which were approximately $1.1 billion to $1.4 billion at the time of the filing. Currently, the estimate is $1.0 billion to $1.4 billion. The increase in estimated total capital expenditures from the original 2002 estimate of $813 million is primarily due to the higher cost and revised quantities of construction materials, such as concrete and steel, refinement of cost and scope estimates for the current projects, and increases in the estimated inflation factor applied to future project costs. We are continuing to evaluate various design, technology, and new generation options that could further change expenditures required by the Clean Smokestacks Act. O&M expenses will significantly increase due to the additional personnel, materials and general maintenance associated with the equipment. O&M expenses are currently recoverable through base rates.

The Clean Smokestacks Act also freezes the state’s utilities' base rates for five years, which ends in 2007, unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. The Clean Smokestacks Act requires PEC to amortize $569 million, representing 70 percent of the original cost estimate of $813 million, during the five-year period ending December 31, 2007. The Clean Smokestacks Act permits PEC the flexibility to vary the amortization schedule for recording of the compliance costs from none up to $174 million per year. For the years ended December 31, 2006, 2005 and 2004, PEC recognized amortization of $140 million, $147 million and $174 million, respectively, and has recognized $535 million in

90

cumulative amortization through December 31, 2006. The remaining amortization requirement of $34 million will be recorded during the one-year period ending December 31, 2007. The NCUC will hold a hearing prior to December 31, 2007, to determine cost-recovery amounts for 2008 and 2009.

Two of PEC’s largest coal-fired generation plants (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. In 2005, PEC entered into an agreement with the joint owner 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).

Pursuant to the Clean Smokestacks Act, PEC entered into an agreement with the state of North Carolina to transfer to the state certain NOx and SO₂ emissions allowances that result from compliance with the collective NOx and SO₂ emissions limitations set in the Clean Smokestacks Act. The Clean Smokestacks Act also required the state to undertake a study of mercury and CO₂ emissions in North Carolina. The future regulatory interpretation, implementation or impact of the Clean Smokestacks Act cannot be predicted.

Clean Air Interstate Rule, Clean Air Mercury Rule and Clean Air Visibility Rule

On March 10, 2005, the EPA issued the final CAIR. The EPA’s rule requires the District of Columbia and 28 states, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and SO₂ emissions in order to reduce levels of fine particulate matter and impacts to visibility. The CAIR sets emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO₂.

PEF has joined a coalition of Florida utilities that has filed a challenge to the CAIR as it applies to Florida. A petition for reconsideration and stay and a petition for judicial review of the CAIR were filed on July 11, 2005. On October 27, 2005, the District of Columbia Circuit Court issued an order granting the motion for stay of the proceedings. On December 2, 2005, the EPA announced a reconsideration of four aspects of the CAIR, including its applicability to Florida. On March 16, 2006, the EPA denied all pending reconsiderations, allowing the challenge to proceed. While we consider it unlikely that this challenge would eliminate the compliance requirements of the CAIR, it could potentially reduce or delay our costs to comply with the CAIR. On June 29, 2006, the Florida Environmental Regulation Commission adopted the Florida CAIR, which is very similar to the EPA’s model rule. PEF and other Florida utilities are participating in an administrative review of the state-adopted rule. The outcome of these matters cannot be predicted.

On March 15, 2005, the EPA finalized two separate but related rules: the CAMR that sets emissions limits to be met in two phases beginning in 2010 and 2018, respectively, and encourages a cap-and-trade approach to achieving those caps, and a de-listing rule that eliminated any requirement to pursue a maximum achievable control technology approach for limiting mercury emissions from coal-fired power plants. NOx and SO₂ controls also are effective in reducing mercury emissions. However, according to the EPA the second phase cap reflects a level of mercury emissions reduction that exceeds the level that would be achieved solely as a co-benefit of controlling NOx and SO₂ under CAIR. The de-listing rule has been challenged by a number of parties; the resolution of the challenges could impact our final compliance plans and costs. On October 21, 2005, the EPA announced a reconsideration of the CAMR. On May 31, 2006, the EPA issued a determination confirming the de-listing. Sixteen states have subsequently petitioned for a review of this determination. The outcome of this matter cannot be predicted.

States were required to adopt mercury rules implementing the CAMR by November 17, 2006, which are subject to review and approval by the EPA. A number of states, including North Carolina, South Carolina and Florida, did not meet the deadline for submission to the EPA. The EPA has indicated it will defer action. At December 31, 2006, of the three states in which the Utilities operate, all had formally proposed mercury regulations. The North Carolina Environmental Management Commission adopted the proposed rule on November 9, 2006, which is subject to final approval by the North Carolina legislature. North Carolina's rule adopts the EPA’s cap-and-trade approach and requires the addition of mercury controls by 2018 on certain of PEC's North Carolina units that do not have scrubbers. PEC will have until 2013 to provide the agency detailed plans for the installation of controls at existing plants. South Carolina’s rule, which was proposed on October 27, 2006, adopts the EPA’s cap-and-trade approach and requires that 25 percent of the mercury allowances allocated to each unit be held in a compliance supplement set-aside pool. Allowances in the set-aside pool may be used by a unit to meet compliance requirements but cannot be

91

traded. South Carolina’s rule was adopted on January 11, 2007, and is subject to final approval by the South Carolina legislature. On June 29, 2006, the Florida Environmental Regulation Commission adopted the Florida CAMR. The Florida rule adopts the EPA’s cap-and-trade approach with changes to the EPA’s mercury allowance allocations in the rule’s first phase. The outcome of this matter cannot be predicted.

On June 15, 2005, the EPA issued the final CAVR. The EPA’s rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in 156 specially protected areas including national parks and wilderness areas. To help restore visibility in those areas, states must require the identified facilities to install BART to control their emissions. Depending on the approach taken by the states, the reductions associated with BART would begin in 2014. CAVR included the EPA’s determination that compliance with the NOx and SO₂ requirements of CAIR may be used by states as a BART substitute. Plans for compliance with CAIR and CAMR may fulfill BART obligations, but the states could require the installation of additional air quality controls if they do not achieve reasonable progress in improving visibility. PEC’s BART-eligible units are Asheville Units No. 1 and No. 2, Roxboro Units No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Units No. 1 and No. 2, Bartow Unit No. 3, and Crystal River Units No. 1 and No. 2. The outcome of this matter cannot be predicted. On December 12, 2006, the U.S. Court of Appeals for the District of Columbia Circuit decided in favor of the EPA in a case brought by the National Parks Conservation Association that alleges the EPA acted improperly by substituting the requirements of CAIR for BART for NOx and SO₂ from electric generating units in areas covered by CAIR.

PEC and PEF are each developing an integrated compliance strategy to meet all the requirements of the CAIR, CAMR and CAVR. We are evaluating various design, technology, and new generation options that could change PEC’s and PEF’s costs to meet the requirements of CAIR, CAMR and CAVR.

On October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs associated with the development and implementation of an integrated strategy to comply with the CAIR, CAMR and CAVR through the ECRC. On March 31, 2006, PEF filed a series of compliance alternatives with the FPSC to meet these federal environmental rules. At the time, PEF’s recommended proposed compliance plan included approximately $740 million of estimated capital costs expected to be spent through 2016, to plan, design, build and install pollution control equipment at our Anclote and Crystal River plants. On October 27, 2006, PEF filed supplemental testimony to inform the FPSC that estimated capital costs for the series of compliance alternatives are likely to increase by approximately 25 percent to 30 percent from the estimates filed in March 2006, primarily due to the higher cost of labor and construction materials, such as concrete and steel, and refinement of cost and scope estimates for the current projects. These costs will continue to change depending upon the results of the engineering and strategy development work and/or increases in the underlying material, labor and equipment costs. Subsequent rule interpretations, equipment availability, or the unexpected acceleration of the initial NOx or other compliance dates, among other things, could require acceleration of some projects. On November 6, 2006, the FPSC approved PEF’s petition for its integrated strategy to address compliance with CAIR, CAMR and CAVR. They also approved cost recovery of prudently incurred costs necessary to achieve this strategy.

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

In March 2004, the North Carolina attorney general filed a petition with the EPA, under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO₂ emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina’s ability to meet national air quality standards for ozone and particulate matter. On March 16, 2006, the EPA issued a final response denying the petition. The EPA's rationale for denial is that compliance with CAIR will reduce the emissions from surrounding states sufficiently to address North Carolina's concerns. On June 26, 2006, the North Carolina attorney general filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the agency’s final action on the petition.The outcome of this matter cannot be predicted.

92

National Ambient Air Quality Standards

On December 21, 2005, the EPA announced proposed changes to the National Ambient Air Quality Standards (NAAQS) for particulate matter. The EPA proposed to lower the 24-hour standard for particulate matter less than 2.5 microns in diameter (PM 2.5) from 65 micrograms per cubic meter to 35 micrograms per cubic meter. In addition, the EPA proposed to establish a new 24-hour standard of 70 micrograms per cubic meter for particulate matter that is between 2.5 and 10 microns in diameter (PM 2.5-10). The EPA also proposed to eliminate the current standards for particulate matter less than 10 microns in diameter (PM 10). On September 20, 2006, the EPA announced that it is finalizing the PM 2.5 NAAQS as proposed. In addition, the EPA decided not to establish a PM 2.5-10 NAAQS, and it is eliminating the annual PM 10 NAAQS, but the EPA is retaining the 24-hour PM 10 NAAQS. These changes are not expected to result in designation of any additional nonattainment areas in PEC’s or PEF’s service territories. On December 18, 2006, environmental groups and 13 states filed a joint petition with the U.S. Circuit Court of Appeals for the District of ColumbiaCircuit arguing that the EPA's new particulate matter rule does not adequately restrict levels of particulate matter. The outcome of this matter cannot be predicted.

Water Quality

1. General

As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on the Utilities in the immediate and extended future. The outcome of this matter cannot be predicted.

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

Section 316(b) of the Clean Water Act (Section 316(b)) requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. The EPA promulgated a rule implementing Section 316(b) in respect to existing power plants in July 2004. The July 2004 rule required assessment of the baseline environmental effect of withdrawal of cooling water and development of technologies and measures for reducing environmental effects by certain percentages. Additionally, the rule authorized establishment of alternative performance standards where the site-specific costs of achieving the otherwise applicable standards would have been substantially greater than either the benefits achieved or the costs considered by the EPA during the rulemaking.

Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued an opinion and order remanding many important provisions of the rule to the EPA. As a result of that decision, our plans and associated estimated costs to comply with Section 316(b) will need to be reassessed and determined in accordance with any revised or new implementing rule once it is established by the EPA. Costs of compliance with a new implementing rule are expected to be higher, and could be significantly higher, than estimated costs under the July 2004 rule. Our most recent cost estimates to comply with the July 2004 implementing rule were $60 million to $90 million, including $5 million to $10 million at PEC and $55 million to $80 million at PEF. The outcome of this matter cannot be predicted.

3. North Carolina Groundwater Standard

On September 14, 2006, the North Carolina Division of Water Quality (NCDWQ) appeared before the North Carolina Environmental Management Commission and recommended the state’s groundwater quality standard for arsenic be revised to 0.00002 milligrams/liter. The existing groundwater quality standard for arsenic is 0.05 milligrams/liter. The North Carolina Environmental Management Commission granted approval for NCDWQ staff to publish a notice in the North Carolina Register and schedule public hearings. The rulemaking process will require at least six months before the standard may be changed. Trace amounts of arsenic are commonly present in coal fly ash sluice water, coal pile runoff, flue gas desulphurization byproducts, and other coal combustion byproducts. The specific requirements of the rule as finally adopted and associated costs, if any, cannot be predicted.

93

OTHER ENVIRONMENTAL MATTERS

Global Climate Change

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO₂ and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration favors voluntary programs. There are proposals and ongoing studies at the state and federal levels to address global climate change that would regulate CO₂ and other greenhouse gases. Reductions in CO₂ emissions to the levels specified by the Kyoto Protocol and some additional proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from ratepayers. The cost impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time. We have articulated principles that we believe should be incorporated into any global climate change policy. While the outcome of this matter cannot be predicted, we are taking voluntary action on this important issue as part of our commitment to environmental stewardship and responsible corporate citizenship.

In a decision issued July 15, 2005, the U.S. Court of Appeals for the District of Columbia Circuit denied petitions for review filed by several states, cities and organizations seeking the regulation by the EPA of CO₂ emissions from new automobiles under the Clean Air Act, holding that the EPA administrator properly exercised his discretion in denying the request for regulation. Following denial of a request for rehearing, the petitioners filed a petition for writ of certiorari with the U.S. Supreme Court, seeking a review of the decision. On June 26, 2006, the U.S. Supreme Court agreed to review the decision. Oral argument was held on November 29, 2006. The outcome of this matter cannot be predicted.

In 2005, we initiated a study to assess the impact of constraints on CO₂ and other air emissions and on March 27, 2006, we issued our report to shareholders for an assessment of global climate change and air quality risks and actions. While we participate in the development of a national climate change policy framework, we will continue to actively engage others in our region to develop consensus-based solutions, as we did with the Clean Smokestacks Act.

NEW ACCOUNTING STANDARDS

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

94

PEC

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PEC: “Results of Operations;” “Application of Critical Accounting Policies and Estimates;” “Liquidity and Capital Resources;” “Future Outlook and Other Matters.”

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

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

PEC has primarily used a combination of debt securities, first mortgage bonds, pollution control bonds, commercial paper facilities and revolving credit agreements for liquidity needs in excess of cash provided by operations. PEC also participates in the utility money pool, which allows PEC and PEF to lend and borrow between each other.

On May 3, 2006, PEC’s five-year $450 million RCA was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of PEC’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P. The amended PEC RCA is still scheduled to expire on June 28, 2010.

PEC currently has on file with the SEC a shelf registration statement under which it can issue up to $1.0 billion of various long-term debt securities and preferred stock.

As discussed above in the Progress Energy “Credit Rating Matters,” on November 3, 2006, Fitch upgraded the senior unsecured credit rating of PEC to A- from BBB+ and revised PEC’s outlook to stable. The short-term rating of PEC was upgraded to F-1 from F-2. On August 31, 2006, Moody’s upgraded PEC’s outlook to positive from stable, citing PEC’s manageable leverage, strong cash flow coverage ratios for its current ratings category, and constructive regulatory environments in North Carolina and South Carolina. On July 25, 2006, S&P affirmed the corporate credit rating of BBB at PEC and revised PEC’s outlook to positive from stable. PEC does not expect these changes to have a material impact on its borrowing costs or overall liquidity.

PEC expects to have sufficient resources to meet its future obligations through a combination of internally generated funds, commercial paper borrowings, its credit facilities, long-term debt, preferred stock and/or contribution of equity from the Parent.

CASH FLOW DISCUSSION

HISTORICAL FOR 2006 AS COMPARED TO 2005 AND 2005 AS COMPARED TO 2004

In 2006, cash provided by operating activities increased when compared to 2005. The $62 million increase in operating cash flow was primarily due to a $136 million increase in the recovery of fuel cost, a $147 million increase from the change in accounts receivable and a $47 million increase from the change in accounts payable. In 2006 and 2005, PEC filed requests with the North Carolina and South Carolina state commissions seeking rate increases for fuel cost recovery, including amounts for previous under-recoveries. See “Future Liquidity and Capital Resources” under Progress Energy above and Note 7B. The change in accounts receivable was principally driven by the timing of wholesale sales. The change in accounts payable was largely driven by the timing of environmental compliance project payments and other vendor payments. These impacts were partially offset by a $122 million net increase in tax payments in 2006 compared to 2005 and $141 million related to a wholesale customer prepayment in 2005, as discussed below.

95

In 2005, cash provided by operating activities decreased when compared to 2004. The $44 million decrease in operating cash flow was primarily due to an $88 million increase in the under-recovery of fuel cost driven by rising fuel costs, partially offset by a $55 million improvement in working capital, including the impact of a prepayment received from a wholesale customer. In November 2005, PEC entered into a contract with the PWC in which the PWC prepaid $141 million in exchange for future capacity and energy power sales. The prepayment is expected to cover approximately two years of electricity service and includes a prepayment discount of approximately $16 million. The improvement in working capital needs for 2005 compared to 2004 was mainly driven by the current portion of the prepayment received from the PWC as discussed above and favorability from tax payments, partially offset by increases in the change in receivables and inventory purchases, primarily coal. The increase in the change in receivables is primarily due to increased sales driven by weather, timing of receipts and the impact of excess generation sales.

In 2006, cash used in investing activities decreased approximately $89 million when compared with 2005. The decrease is due primarily to a $250 million increase in net proceeds from available-for-sale securities and other investments, largely offset by $102 million in additional capital expenditures for utility property, primarily related to an increase in spending for compliance with the Clean Smokestacks Act, and $23 million in nuclear fuel additions. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

In 2005, cash used in investing activities increased when compared to 2004. The $326 million increase is due primarily to a $253 million decrease in net proceeds from available-for-sale securities and other investments and $62 million in additional capital expenditures for utility property and nuclear fuel additions, primarily related to an increase in spending for compliance with the Clean Smokestacks Act.

See the discussion above for Progress Energy under “Financing Activities” for information regarding PEC’s financing activities.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

PEC’s estimated capital requirements for 2007, 2008 and 2009 are approximately $955 million, $1.160 billion and $1.170 billion, respectively, and primarily reflect construction expenditures to support customer growth, add regulated generation, upgrade existing facilities and for environmental control facilities as discussed above in “Capital Expenditures” under Progress Energy.

PEC expects to fund its capital requirements primarily through a combination of internally generated funds, long-term debt, preferred stock and/or contribution of equity from the Parent. In addition, PEC has $450 million in credit facilities that support the issuance of commercial paper. Access to the commercial paper market and the utility money pool provide additional liquidity to help meet PEC’s working capital requirements.

Over the long-term, meeting the anticipated load growth will require a balanced approach, including energy conservation and efficiency programs, development and deployment of new energy technologies, and new generation, transmission and distribution facilities, potentially including new baseload generation facilities in the Carolinas by the middle of the next decade. This approach will require PEC to make significant capital investments. See “Introduction - Strategy - Regulated Utilities” for additional information. These anticipated capital investments are expected to be funded through a combination of long-term debt, preferred stock and common equity, which is dependent on our ability to successfully access capital markets. PEC may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.

96

CAPITALIZATION RATIOS

The following table shows PEC’s total debt to total capitalization ratios at December 31:

	2006	2005
Common stock equity	47.6%	45.0%
Preferred stock	0.8%	0.9%
Total debt	51.6%	54.1%

See the discussion above under Progress Energy and Note 12 for further discussion of PEC’s future liquidity and capital resources.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

PEC’s off-balance sheet arrangements and contractual obligations are described below.

GUARANTEES

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

MARKET RISK AND DERIVATIVES

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

97

CONTRACTUAL OBLIGATIONS

PEC is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. Amounts in the following table are estimated based upon contractual terms and will likely differ from actual amounts. Further disclosure regarding PEC’s contractual obligations is included in the respective notes to the PEC Consolidated Financial Statements. PEC takes into consideration the future commitments when assessing its liquidity and future financing needs. The following table reflects PEC’s contractual cash obligations and other commercial commitments at December 31, 2006, in the respective periods in which they are due:

(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (a) (See Note 12)	$	3,691	$	200	$	700	$	6	$	2,785
Interest payments on long-term debt and interest rate derivatives (b)		1,888		200		329		296		1,063
Capital lease obligations (See Note 22B)		24		2		5		5		12
Operating leases (See Note 22B)		269		36		60		31		142
Fuel and purchased power (c) (See Note 22A)		4,358		1,137		1,478		632		1,111
Other purchase obligations (See Note 22A)		172		120		34		6		12
Minimum pension funding requirements (d)		124		34		48		42		-
Other commitments (e)		131		-		26		26		79
Total	$	10,657	$	1,729	$	2,680	$	1,044	$	5,204

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

^(b)   Interest payments on long-term debt and interest rate derivatives are based on the interest rate effective at December 31, 2006, and the LIBOR forward curve at December 31, 2006, respectively.

^(c)   Fuel and purchased power commitments represent the majority of PEC’s remaining future commitments after its debt obligations. Essentially all of PEC’s fuel and purchased power costs are recovered through pass-through clauses in accordance with North Carolina and South Carolina regulations and therefore do not require separate liquidity support.

^(d)   Projected pension funding status is based on current actuarial estimates and is subject to future revision.

^(e)   In 2008, PEC must begin transitioning North Carolina jurisdictional amounts currently retained internally to its external decommissioning funds. The transition of $131 million must be complete by December 31, 2017, and at least 10 percent must be transitioned each year.

98

PEF

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PEF: “Results Of Operations;” “Application Of Critical Accounting Policies And Estimates;” “Liquidity And Capital Resources;” “Future Outlook” and “Other Matters.”

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

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

PEF has primarily used a combination of debt securities, first mortgage bonds, pollution control bonds, commercial paper facilities and revolving credit agreements for liquidity needs in excess of cash provided by operations. PEF also participates in the utility money pool, which allows PEC and PEF to lend and borrow between each other.

On May 3, 2006, PEF’s five-year $450 million RCA was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined 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 amended PEF RCA is still scheduled to expire on March 28, 2010. On July 3, 2006, PEF paid at maturity $45 million of its 6.77% Medium-Term Notes, Series B with available cash on hand.

PEF currently has on file with the SEC a shelf registration statement under which it can issue up to $1.0 billion of various long-term debt securities and preferred stock.

As discussed above in the Progress Energy “Credit Rating Matters,” on November 3, 2006, Fitch upgraded the senior unsecured credit rating of PEF to A- from BBB+ and revised PEF’s outlook to stable. The short-term rating of PEF was upgraded to F-1 from F-2. On August 31, 2006, Moody’s reaffirmed PEF’s credit rating with a stable outlook. On July 25, 2006, S&P affirmed the corporate credit rating of BBB at PEF and revised PEF’s outlook to positive from stable. We do not expect these changes to have a material impact on our borrowing costs or overall liquidity.

PEF expects to have sufficient resources to meet its future obligations through a combination of internally generated funds, commercial paper borrowings, its credit facilities, long-term debt, preferred stock and/or contribution of equity from the Parent.

CASH FLOW DISCUSSION

HISTORICAL FOR 2006 AS COMPARED TO 2005 AND 2005 AS COMPARED TO 2004

Cash from operating activities for 2006 increased when compared with 2005. The $463 million increase in operating cash flow was primarily due to a $577 million improvement from the recovery of fuel costs and $72 million related to recovery of storm restoration costs. In 2005, PEF filed requests with the Florida state commission seeking rate increases for fuel cost recovery, including amounts for previous under-recoveries. PEF also received approval from the FPSC authorizing PEF to recover $245 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004. See “Future Liquidity and Capital Resources” under Progress Energy above and Note 7C. These impacts were partially offset by a $94 million increase in inventory levels, primarily related to coal, a $49 million decrease from the change in accounts payable, and a $40 million decrease in derivative premiums received.

99

Cash from operating activities for 2005 decreased when compared with 2004. The $103 million decrease in operating cash flow was primarily due to a $210 million increase in the under-recovery of fuel costs driven by rising fuel costs and a $32 million increase in working capital needs, partially offset by a $193 million reduction in storm cost spending at PEF in 2005 compared to 2004. The increase in working capital needs for 2005 compared to 2004 was mainly driven by a $50 million increase in the change in receivables, primarily due to increased sales largely driven by rising fuel prices and timing of receipts.

In 2006, cash used in investing activities increased approximately $229 million when compared with 2005. The increase in cash used in investing activities was primarily due to a $231 million increase in capital expenditures for utility property additions. The increase in utility property was primarily due to repowering the Bartow plant to more efficient natural gas-burning technology, various distribution, transmission and steam production projects, and higher spending at the Hines Unit 4 facility, partially offset by lower spending at the Hines Unit 3 facility. Additionally, proceeds from sales of assets were lower in 2006 as compared to 2005 due to the sale of distribution assets to Winter Park in 2005 (See Note 7C). These impacts were partially offset by a $35 million decrease in nuclear fuel additions related to the nuclear facility refueling outage in 2005.

In 2005, cash used in investing activities increased when compared to 2004. The $10 million increase is due primarily to $47 million in nuclear fuel additions, partially offset by $42 million in proceeds from the sale of Winter Park distribution assets in 2005.

In planning for its future generation needs, PEF develops a forecast of annual demand for electricity, including a forecast of the level and duration of peak demands during the year. The reserve margin is the difference between a company’s net system generating capacity and the maximum demand on the system. In December 1999, the FPSC approved a joint proposal by PEF, Florida Power & Light and Tampa Electric Company to increase the reserve margin to 20 percent from 15 percent. In response, PEF constructed additional generating units at the Hines site. Hines Unit 2 was placed into service in December 2003 and Hines Unit 3 was placed into service in November 2005. PEF is currently constructing Hines Unit 4, which is expected to be completed in December 2007.

See the discussion above for Progress Energy under “Financing Activities” for information regarding PEF’s financing activities.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

PEF’s estimated capital requirements for 2007, 2008 and 2009 are approximately $1.455 billion, $1.350 billion and $1.180 billion, respectively, and primarily reflect construction expenditures to support customer growth, add regulated generation, upgrade existing facilities and add environmental control facilities as discussed above in “Capital Expenditures” under Progress Energy.

PEF expects to fund its capital requirements primarily through a combination of internally generated funds, long-term debt, preferred stock and/or contribution of equity from the Parent. In addition, PEF has $450 million in credit facilities that support the issuance of commercial paper. Access to the commercial paper market and the utility money pool provide additional liquidity to help meet PEF’s working capital requirements.

Over the long-term, meeting the anticipated load growth will require a balanced approach, including energy conservation and efficiency programs, development and deployment of new energy technologies, and new generation, transmission and distribution facilities, potentially including new baseload generation facilities in Florida by the middle of the next decade. This approach will require PEF to make significant capital investments. See “Introduction - Strategy - Regulated Utilities” for additional information. These anticipated capital investments are expected to be funded through a combination of long-term debt, preferred stock and common equity, which is dependent on our ability to successfully access capital markets. PEF may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.

100

CAPITALIZATION RATIOS

The following table shows PEF’s total debt to total capitalization ratios at December 31:

	2006	2005
Common stock equity	50.5%	48.6%
Preferred stock	0.6%	0.6%
Total debt	48.9%	50.8%

See the discussion above under Progress Energy and Note 12 for further discussion of PEF’s future liquidity and capital resources.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

See discussion under Progress Energy and Notes 22A, 22B and 22C for information on PEF’s off-balance sheet arrangements and contractual obligations at December 31, 2006.

MARKET RISK AND DERIVATIVES

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

101

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, “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.

PROGRESS ENERGY, INC.

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.

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, 2006 and 2005, 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 2007 to 2011 and thereafter and the fair value of the related hedges. Notional amounts are used to calculate the contractual cash flows

102

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, 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 mature on October 1, 2017, and require 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 53.0 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.

103

December 31, 2005 (dollars in millions)	2006			2007			2008			2009			2010			Thereafter			Total			Fair Value December 31, 2005
Fixed-rate long-term debt(a)	$	513		$	674		$	827		$	401		$	306		$	6,611		$	9,332		$	9,768
Average interest rate		6.79	%		6.41	%		6.27	%		5.95	%		4.53	%		6.34	%		6.29	%
Variable-rate long-term debt		-			-		$	450			-		$	100		$	861		$	1,411		$	1,411
Average interest rate		-			-			4.88	%		-			5.03	%		3.05	%		3.77	%
Debt to affiliated trust(b)		-			-			-			-			-		$	309		$	309		$	312
Interest rate		-			-			-			-			-			7.10	%		7.10	%
Interest rate derivatives
Pay variable/receive fixed		-			-		$	(100	)		-			-		$	(50	)	$	(150	)	$	(2	)
Average pay rate		-			-			(c	)		-			-			(c	)		(c	)
Average receive rate		-			-			4.10	%		-			-			4.65	%		4.28	%
Interest rate forward contracts(d)	$	100			-			-			-			-			-		$	100		$	1
Average pay rate		4.87	%		-			-			-			-			-			4.87	%
Average receive rate		(c	)		-			-			-			-			-			(c	)

^(a)   Excludes $397 million in 2006 classified as long-term debt at December 31, 2005.

^(b)   FPC Capital I - Quarterly Income Preferred Securities.

^(c)   Rate is 3-month LIBOR, which was 4.54% at December 31, 2005.

^(d)   Anticipated 10-year debt issue hedges mature on March 1, 2016, and required mandatory cash settlement on March 1, 2006.

At December 31, 2005, we classified $397 million related to the retirement of $800 million of Progress Energy, Inc. 6.75% Senior Notes on March 1, 2006, as long-term debt. Settlement of this obligation did not require the use of working capital in 2006 as we had the intent and ability to refinance this debt on a long-term basis. On January 13, 2006, Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100 million of Series A Floating Rate Senior Notes due 2010, receiving net proceeds of $397 million. These senior notes are unsecured.

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, 2006 and 2005, the fair value of these funds was $1.287 billion and $1.133 billion, respectively, including $735 million and $640 million, respectively, for PEC and $552 million and $493 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, if any, are based on the net after-tax cash flows the facilities generate. These CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At December 31, 2006 and 2005, the fair value of these CVOs was $32 million and $7 million, respectively. A hypothetical 10 percent decrease in the December 31, 2006, market price would result in a $3 million decrease in the fair value of the CVOs.

104

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.”

Most of our 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.

As discussed in Note 3, on December 13, 2006, our board of directors approved a plan to pursue the disposition of substantially all of PVI’s remaining CCO physical and commercial assets, and on July 12, 2006, our board of directors approved a plan to divest of Gas. The transaction to sell Gas closed on October 2, 2006. We expect to complete the disposition plan for CCO in 2007.

Due to the reclassification of the remaining CCO operations to discontinued operations in December 2006, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts covering approximately 95 Bcf of natural gas would be fulfilled. Therefore, these contracts were no longer treated as cash flow hedges and were dedesignated, and cash flow hedge accounting was discontinued.

At December 31, 2006, derivative assets and derivative liabilities related to CCO are included in assets of discontinued operations and liabilities of discontinued operations, respectively, on the Consolidated Balance Sheet. At December 31, 2005, derivative assets and derivative liabilities related to Gas and CCO are included in assets of discontinued operations and liabilities of discontinued operations, respectively, on the Consolidated Balance Sheet. For the years ending December 31, 2006, 2005 and 2004, 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 ending 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 ending December 31, 2005, there were no reclassifications to earnings due to discontinuance of the related cash flow hedges. For the year ending December 31, 2004, discontinued operations, net of tax includes $10 million in after-tax deferred losses, which were reclassified to earnings due to discontinuance of the related cash flow hedges.

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments, which are not eligible for recovery from ratepayers. At December 31, 2006, as described above, these derivative commodity instruments are included in discontinued operations. 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. A decrease of 10 percent in the market prices of energy commodities from their December 31, 2006, levels would decrease after-tax earnings of discontinued operations by approximately $55 million. A hypothetical 10 percent increase or decrease in commodity market prices in the near term on our derivative commodity instruments would not have had a material effect on our financial position, results of operations or cash flows at December 31, 2005. As discussed above, certain derivative contracts were dedesignated during 2006 and cash flow hedge accounting was discontinued, which increased the exposure to potential earnings impacts in the near term from changes in commodity market prices.

The above analysis of our derivative commodity instruments used for hedging purposes does not include the

105

potential favorable impact of the same hypothetical price movement on the physical purchases of natural gas and power to which the hedges relate. Additionally, our derivative commodity portfolio is managed to complement the physical transaction portfolio, reducing overall risk within set limits. Therefore, the potential impact to earnings of discontinued operations from a hypothetical 10 percent adverse change in commodity market prices would be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity positions are not closed out in advance of their expected term, continue to function effectively as hedges of the underlying risk, and the anticipated underlying transactions settle, as applicable. If any of these assumptions ceases to be true, a loss on the derivative instruments may occur.

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

ECONOMIC DERIVATIVES

Derivative products, primarily electricity and natural gas 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. Gains and losses from such contracts were not material to our or the Utilities’ results of operations during the years ended December 31, 2006, 2005 and 2004. Excluding $107 million of derivative assets, which are included in assets of discontinued operations on the Consolidated Balance Sheet and $31 million of derivative liabilities, which are included in liabilities of discontinued operations on the Consolidated Balance Sheet at December 31, 2006, we did not have material outstanding positions in such contracts at December 31, 2006 and 2005, other than those receiving regulatory accounting treatment at PEF, as discussed below. Our discontinued operations did not have material outstanding positions in such contracts at December 31, 2005.

PEC did not have material outstanding positions in such contracts at December 31, 2006 and 2005. PEF did not have material outstanding positions in such contracts at December 31, 2006 and 2005, other than those receiving regulatory accounting treatment, as discussed below.

PEF has derivative instruments related to its 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. Once settled, any realized gains or losses are passed through the fuel clause. At December 31, 2006, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits, an $87 million short-term derivative liability position included in other current liabilities and a $36 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheet. At December 31, 2005, the fair values of the instruments were a $77 million short-term derivative asset position included in other current assets, a $45 million long-term derivative asset position included in other assets and deferred debits and a $49 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheet.

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 NYMEX basis. The notional quantity of these oil price hedge instruments is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts will be marked-to-market with changes in fair value recorded through earnings from synthetic fuels production.

CASH FLOW HEDGES

Our subsidiaries designate 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 natural gas and power for our forecasted purchases and sales. Realized gains and losses are recorded net in

106

operating revenues or operating expenses, as appropriate. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for 2006, 2005 and 2004.

The fair values of commodity cash flow hedges at December 31 were as follows:

	Progress Energy					PEC					PEF
(in millions)	2006		2005			2006		2005			2006		2005
Fair value of assets	$	2	$	7		$	2	$	7		$	-	$	-
Fair value of liabilities		-		(4	)		-		(4	)		-		-
Fair value, net	$	2	$	3		$	2	$	3		$	-	$	-

Our discontinued operations did not have material outstanding positions in commodity cash flow hedges at December 31, 2006. Excluded from the table above are $163 million of derivative assets, which are included in assets of discontinued operations, and $54 million of derivative liabilities, which are included in liabilities of discontinued operations on the Consolidated Balance Sheet at December 31, 2005.

At December 31, 2006, the amount recorded in our, PEC’s or PEF’s accumulated other comprehensive income (AOCI) related to commodity cash flow hedges was not material. At December 31, 2005, we had $69 million of after-tax deferred income and PEC had $2 million of after-tax deferred income recorded in AOCI related to commodity cash flow hedges. PEF had no amount recorded in AOCI related to commodity cash flow hedges at December 31, 2006 or 2005.

107

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, 2006 and 2005, about PEC’s interest rate risk sensitive instruments:

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 matures on October 1, 2017, and requires mandatory cash settlement on October 1, 2007.

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

December 31, 2005 (dollars in millions)	2006		2007			2008			2009			2010			Thereafter			Total			Fair Value December 31, 2005
Fixed-rate long-term debt	$	-	$	200		$	300		$	400		$	6		$	2,165		$	3,071		$	3,169
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		-		-			-			-			-			3.04	%		3.04	%

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 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.

108

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, 2006 and 2005, about PEF’s interest rate risk sensitive instruments:

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 matures on October 1, 2017, and requires mandatory cash settlement on October 1, 2007.

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

December 31, 2005 (dollars in millions)	2006			2007			2008			2009		2010			Thereafter			Total			Fair Value December 31, 2005
Fixed-rate long-term debt	$	48		$	89		$	82			-	$	300		$	1,400		$	1,919		$	1,944
Average interest rate		6.76	%		6.80	%		6.87	%		-		4.50	%		5.65	%		5.60	%
Variable-rate long-term debt		-			-		$	450			-		-		$	241		$	691		$	691
Average interest rate		-			-			4.88	%		-		-			3.07	%		4.25	%

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 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.

109

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	113
Consolidated Statements of Income for the Years Ended December 31, 2006, 2005 and 2004	114
Consolidated Balance Sheets at December 31, 2006 and 2005	115
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	116
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2006, 2005 and 2004	118
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004	118

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

Report of Independent Registered Public Accounting Firm	119
Consolidated Statements of Income for the Years Ended December 31, 2006, 2005 and 2004	120
Consolidated Balance Sheets at December 31, 2006 and 2005	121
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	122
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2006, 2005 and 2004	123
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004	123

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

Report of Independent Registered Public Accounting Firm	124
Statements of Income for the Years Ended December 31, 2006, 2005 and 2004	125
Balance Sheets at December 31, 2006 and 2005	126
Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	127
Statements of Changes in Common Stock Equity for the Years Ended December 31, 2006, 2005 and 2004	129
Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004	129

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	130
Note 2 - New Accounting Standards	137
Note 3 - Divestitures	139
Note 4 - Acquisitions	144
Note 5 - Property, Plant and Equipment	145
Note 6 - Current Assets	150
Note 7 - Regulatory Matters	151
Note 8 - Goodwill and Other Intangible Assets	157
Note 9 - Impairments of Long-Lived Assets and Investments	158
Note 10 - Equity	159
Note 11 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption	166
Note 12 - Debt and Credit Facilities	167
Note 13 - Investments and Fair Value of Financial Instruments	171
Note 14 - Income Taxes	176

110

	Page
Note 15 - Contingent Value Obligations	182
Note 16 - Benefit Plans	183
Note 17 - Risk Management Activities and Derivatives Transactions	191
Note 18 - Related Party Transactions	195
Note 19 - Financial Information by Business Segment	196
Note 20 - Other Income and Other Expense	198
Note 21 - Environmental Matters	200
Note 22 - Commitments and Contingencies	203
Note 23 - Condensed Consolidating Statements	211
Note 24 - Quarterly Financial Data (Unaudited)	220

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, 2006, 2005 and 2004:

Report of Independent Registered Public Accounting Firm on Financial Statement Schedule - Progress Energy, Inc.	222
Schedule II - Valuation and Qualifying Accounts - Progress Energy, Inc.	223
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.	224
Schedule II - Valuation and Qualifying Accounts - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.	225
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule - Florida Power Corporation d/b/a Progress Energy Florida, Inc.	226
Schedule II - Valuation and Qualifying Accounts - Florida Power Corporation d/b/a Progress Energy Florida, Inc.	227

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.

111

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, 2006 and 2005, 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, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 158, and in 2005 the Company adopted Statement of Financial Accounting Standards No. 123R and Financial Accounting Standards Board Interpretation No. 47.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting at December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2007, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

112

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of INCOME
(in millions except per share data)
Years ended December 31	2006			2005			2004
Operating revenues
Electric	$	8,722		$	7,945		$	7,153
Diversified business		848			1,223			900
Total operating revenues		9,570			9,168			8,053
Operating expenses
Utility
Fuel used in electric generation		3,008			2,359			2,011
Purchased power		1,100			1,048			868
Operation and maintenance		1,583			1,770			1,475
Depreciation and amortization		1,009			922			878
Taxes other than on income		500			460			425
Other		(3	)		(37	)		(13	)
Diversified business
Cost of sales		898			1,353			992
Depreciation and amortization		23			41			41
Impairments of assets		91			-			-
Gain on the sales of assets		(4	)		(30	)		(8	)
Other		56			62			112
Total operating expenses		8,261			7,948			6,781
Operating income		1,309			1,220			1,272
Other income (expense)
Interest income		61			16			11
Other, net		(18	)		(7	)		4
Total other income		43			9			15
Interest charges
Net interest charges		632			587			572
Allowance for borrowed funds used during construction		(7	)		(13	)		(6	)
Total interest charges, net		625			574			566
Income from continuing operations before income tax and minority interest		727			655			721
Income tax expense (benefit)		204			(37	)		67
Income from continuing operations before minority interest		523			692			654
Minority interest in subsidiaries’ (income) loss, net of tax		(9	)		29			19
Income from continuing operations		514			721			673
Discontinued operations, net of tax		57			(25	)		86
Cumulative effect of change in accounting principle, net of tax		-			1			-
Net income	$	571		$	697		$	759
Average common shares outstanding - basic		250			247			242
Basic earnings per common share
Income from continuing operations	$	2.05		$	2.92		$	2.78
Discontinued operations, net of tax		0.23			(0.10	)		0.35
Net income	$	2.28		$	2.82		$	3.13
Diluted earnings per common share
Income from continuing operations	$	2.05		$	2.92		$	2.77
Discontinued operations, net of tax		0.23			(0.10	)		0.35
Net income	$	2.28		$	2.82		$	3.12
Dividends declared per common share	$	2.43		$	2.38		$	2.32

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

113

PROGRESS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(in millions)

December 31	2006			2005
ASSETS
Utility plant
Utility plant in service	$	23,743		$	22,940
Accumulated depreciation		(10,064	)		(9,602	)
Utility plant in service, net		13,679			13,338
Held for future use		10			12
Construction work in progress		1,289			813
Nuclear fuel, net of amortization		267			279
Total utility plant, net		15,245			14,442
Current assets
Cash and cash equivalents		265			605
Short-term investments		71			191
Receivables, net		930			997
Inventory		969			823
Deferred fuel cost		196			602
Deferred income taxes		159			37
Assets of discontinued operations		887			2,566
Prepayments and other current assets		108			186
Total current assets		3,585			6,007
Deferred debits and other assets
Regulatory assets		1,231			854
Nuclear decommissioning trust funds		1,287			1,133
Diversified business property, net		31			78
Miscellaneous other property and investments		456			476
Goodwill		3,655			3,655
Intangibles, net		-			59
Other assets and deferred debits		211			358
Total deferred debits and other assets		6,871			6,613
Total assets	$	25,701		$	27,062
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 256 and 252 million shares issued and outstanding, respectively	$	5,791		$	5,571
Unearned ESOP shares (2 and 3 million shares, respectively)		(50	)		(63	)
Accumulated other comprehensive loss		(49	)		(104	)
Retained earnings		2,594			2,634
Total common stock equity		8,286			8,038
Preferred stock of subsidiaries - not subject to mandatory redemption		93			93
Minority interest		10			36
Long-term debt, affiliate		271			270
Long-term debt, net		8,564			10,176
Total capitalization		17,224			18,613
Current liabilities
Current portion of long-term debt		324			513
Accounts payable		712			601
Interest accrued		171			208
Dividends declared		156			152
Short-term debt		-			175
Customer deposits		227			200
Liabilities of discontinued operations		189			542
Income taxes accrued		284			116
Other current liabilities		755			542
Total current liabilities		2,818			3,049
Deferred credits and other liabilities
Noncurrent income tax liabilities		306			198
Accumulated deferred investment tax credits		151			163
Regulatory liabilities		2,543			2,527
Asset retirement obligations		1,306			1,242
Accrued pension and other benefits		957			865
Other liabilities and deferred credits		396			405
Total deferred credits and other liabilities		5,659			5,400
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	25,701		$	27,062

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

114

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CASH FLOWS

(in millions)
Years ended December 31	2006	2005	2004
Operating activities
Net income	$571	$697	$759
Adjustments to reconcile net income to net cash provided by operating activities
(Income) loss from discontinued operations, net of tax	(57)	25	(86)
Gain on sales of operating assets	(7)	(67)	(21)
Impairment of long-lived assets and investments	92	-	-
Charges for voluntary enhanced retirement program	-	159	-
Depreciation and amortization	1,119	1,083	1,037
Deferred income taxes	(72)	(379)	(118)
Investment tax credit	(12)	(13)	(14)
Deferred fuel cost (credit)	396	(317)	(19)
Other adjustments to net income	85	157	113
Cash provided (used) by changes in operating assets and liabilities
Receivables	47	(154)	16
Inventory	(171)	(136)	(84)
Prepayments and other current assets	(71)	(78)	19
Accounts payable	46	103	(30)
Other current liabilities	(70)	109	67
Regulatory assets and liabilities	11	(74)	(234)
Other liabilities and deferred credits	(44)	101	(60)
Other assets and deferred debits	49	(41)	64
Net cash provided by operating activities	1,912	1,175	1,409
Investing activities
Gross utility property additions	(1,423)	(1,080)	(998)
Diversified business property additions	(2)	(6)	(6)
Nuclear fuel additions	(114)	(126)	(101)
Proceeds from sales of discontinued operations and other assets, net of cash divested	1,654	475	372
Purchases of available-for-sale securities and other investments	(2,452)	(3,985)	(3,134)
Proceeds from sales of available-for-sale securities and other investments	2,631	3,845	3,248
Other investing activities	(23)	(37)	(30)
Net cash provided (used) by investing activities	271	(914)	(649)
Financing activities
Issuance of common stock	185	208	73
Proceeds from issuance of long-term debt, net	397	1,642	421
Net (decrease) increase in short-term debt	(175)	(509)	680
Retirement of long-term debt	(2,200)	(564)	(1,112)
Dividends paid on common stock	(607)	(582)	(558)
Cash distributions to minority interests of consolidated subsidiary	(79)	-	-
Other financing activities	11	34	11
Net cash (used) provided by financing activities	(2,468)	229	(485)
Cash provided (used) by discontinued operations
Operating activities	86	294	191
Investing activities	(141)	(232)	(199)
Financing activities	-	(2)	(246)
Net (decrease) increase in cash and cash equivalents	(340)	550	21
Cash and cash equivalents at beginning of year	605	55	34
Cash and cash equivalents at end of year	$265	$605	$55
Supplemental disclosures of cash flow information
Cash paid during the year - interest (net of amount capitalized)	$692	$643	$639
income taxes (net of refunds)	$311	$168	$189

115

Noncash activities

·In addition to normal and recurring accruals for capital additions, Progress Energy Florida recorded purchases and construction costs for utility plant and equipment and a

corresponding liability for $47 million related to additions at an electric generation facility in 2006. Actual cash expenditures will not occur until 2007.

·In 2005, Progress Energy Florida entered into a capital lease agreement for a building that was completed in 2006, at which point Progress Energy Florida recorded a capital lease

asset and obligation for $54 million.

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

116

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
(in millions except per share data)	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, 2003		246	$	5,270		$	(17	)	$	(89	)	$	(50	)	$	2,330		$	7,444
Net income				-			-			-			-			759			759
Other comprehensive loss				-			-			-			(114	)		-			(114	)
Comprehensive income																			645
Issuance of shares		1		62			-			-			-			-			62
Stock options exercised				18			-			-			-			-			18
Purchase of restricted stock				-			(7	)		-			-			-			(7	)
Restricted stock expense recognition				-			7			-			-			-			7
Cancellation of restricted shares				(4	)		4			-			-			-			-
Allocation of ESOP shares				14			-			13			-			-			27
Dividends ($2.32 per share)				-			-			-			-			(563	)		(563	)
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	)
Restricted stock expense recognition				3			-			-			-			-			3
Allocation of ESOP shares				12			-			13			-			-			25
Stock-based compensation expense				10			-			-			-			-			10
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	)
Restricted stock expense recognition				5			-			-			-			-			5
Allocation of ESOP shares				13			-			13			-			-			26
Stock-based compensation expense				25			-			-			-			-			25
Dividends ($2.43 per share)				-			-			-			-			(611	)		(611	)
Balance, December 31, 2006		256	$	5,791		$	-		$	(50	)	$	(49	)	$	2,594		$	8,286

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31	2006			2005			2004
Net income	$	571		$	697		$	759
Other comprehensive (loss) income
Reclassification adjustment for amounts included in net income:
Cash flow hedges (net of tax benefit (expense) of $28, $(26) and $(16), respectively)		(46	)		46			26
Foreign currency translation adjustments included in discontinued operations		-			(6	)		-
Minimum pension liability adjustment included in discontinued operations (net of tax expense of $1)		-			1			-
Changes in net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $16, ($26) and $10, respectively)		(23	)		37			(18	)
Reclassification of minimum pension liability to regulatory assets (net of tax expense of $2)		-			-			4
Minimum pension liability adjustment (net of tax (expense) benefit of $(30), $22 and $78, respectively)		48			(19	)		(130	)
Foreign currency translation and other (net of tax expense of $-, $1 and $-, respectively)		3			1			4
Other comprehensive (loss) income		(18	)		60			(114	)
Comprehensive income	$	553		$	757		$	645

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

117

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, 2006 and 2005, and the related consolidated statements of income, changes in common stock equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of PEC’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. PEC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, in 2006 PEC adopted Statement of Financial Accounting Standards No. 158, and in 2005 PEC adopted Statement of Financial Accounting Standards No. 123R and Financial Accounting Standards Board Interpretation No. 47.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

118

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

CONSOLIDATED STATEMENTS of INCOME
(in millions)
Years ended December 31	2006			2005			2004
Operating revenues
Electric	$	4,085		$	3,990		$	3,628
Diversified business		1			1			1
Total operating revenues		4,086			3,991			3,629
Operating expenses
Fuel used in electric generation		1,173			1,036			836
Purchased power		334			354			301
Operation and maintenance		930			941			871
Depreciation and amortization		571			561			570
Taxes other than on income		191			178			173
Other		(1	)		(11	)		(12	)
Diversified business		1			1			1
Total operating expenses		3,199			3,060			2,740
Operating income		887			931			889
Other income (expense)
Interest income		25			8			4
Other, net		25			(15	)		(1	)
Total other income (expense)		50			(7	)		3
Interest charges
Interest charges		217			197			195
Allowance for borrowed funds used during construction		(2	)		(5	)		(3	)
Total interest charges, net		215			192			192
Income before income taxes		722			732			700
Income tax expense		265			239			239
Net income		457			493			461
Preferred stock dividend requirement		3			3			3
Earnings for common stock	$	454		$	490		$	458

See Notes to PEC Consolidated Financial Statements.

119

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

CONSOLIDATED BALANCE SHEETS
(in millions)
December 31	2006			2005
ASSETS
Utility plant
Utility plant in service	$	14,356		$	13,994
Accumulated depreciation		(6,408	)		(6,120	)
Utility plant in service, net		7,948			7,874
Held for future use		3			3
Construction work in progress		617			399
Nuclear fuel, net of amortization		209			203
Total utility plant, net		8,777			8,479
Current assets
Cash and cash equivalents		71			125
Short-term investments		50			191
Receivables, net		473			518
Receivables from affiliated companies		27			24
Note receivable from affiliated company		24			-
Inventory		497			451
Deferred fuel cost		196			261
Prepayments and other current assets		45			20
Total current assets		1,383			1,590
Deferred debits and other assets
Regulatory assets		777			421
Nuclear decommissioning trust funds		735			640
Miscellaneous other property and investments		193			188
Other assets and deferred debits		155			184
Total deferred debits and other assets		1,860			1,433
Total assets	$	12,020		$	11,502
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, authorized 200 million shares, 160 million shares issued and outstanding at December 31	$	2,010		$	1,981
Unearned ESOP common stock		(50	)		(63	)
Accumulated other comprehensive loss		(1	)		(120	)
Retained earnings		1,431			1,320
Total common stock equity		3,390			3,118
Preferred stock - not subject to mandatory redemption		59			59
Long-term debt, net		3,470			3,667
Total capitalization		6,919			6,844
Current liabilities
Current portion of long-term debt		200			-
Accounts payable		310			247
Payables to affiliated companies		108			73
Notes payable to affiliated companies		-			11
Interest accrued		69			73
Short-term debt		-			73
Customer deposits		59			52
Income taxes accrued		68			100
Current portion of unearned revenue		71			70
Other current liabilities		154			185
Total current liabilities		1,039			884
Deferred credits and other liabilities
Noncurrent income tax liabilities		909			814
Accumulated deferred investment tax credits		128			133
Regulatory liabilities		1,320			1,196
Asset retirement obligations		1,004			949
Accrued pension and other benefits		581			511
Other liabilities and deferred credits		120			171
Total deferred credits and other liabilities		4,062			3,774
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	12,020		$	11,502

See Notes to PEC Consolidated Financial Statements.

120

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

CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2006	2005	2004
Operating activities
Net income	$457	$493	$461
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program	-	42	-
Depreciation and amortization	656	644	658
Deferred income taxes and investment tax credits, net	(59)	(150)	(26)
Deferred fuel credit	(8)	(144)	(56)
Other adjustments to net income	(23)	69	50
Cash provided (used) by changes in operating assets and liabilities
Receivables	36	(111)	(4)
Receivables from affiliated companies	9	11	15
Inventory	(69)	(91)	(22)
Prepayments and other current assets	10	9	17
Accounts payable	56	9	34
Payables to affiliated companies	32	(13)	(53)
Other current liabilities	(40)	239	11
Regulatory assets and liabilities	1	2	9
Other liabilities and deferred credits	(2)	42	(63)
Other assets and deferred debits	38	(19)	45
Net cash provided by operating activities	1,094	1,032	1,076
Investing activities
Gross utility property additions	(705)	(603)	(519)
Proceeds from sales of assets	5	14	25
Nuclear fuel additions	(102)	(79)	(101)
Purchases of available-for-sale securities and other investments	(896)	(1,832)	(2,479)
Proceeds from sales of available-for-sale securities and other investments	1,006	1,692	2,592
Other investing activities	(30)	(3)	(3)
Net cash used in investing activities	(722)	(811)	(485)
Financing activities
Proceeds from issuance of long-term debt, net	-	898	-
Net (decrease) increase in short-term debt	(73)	(148)	217
Changes in advances from affiliates	(11)	(105)	91
Retirement of long-term debt	-	(300)	(339)
Dividends paid to parent	(339)	(457)	(551)
Dividends paid on preferred stock	(3)	(3)	(3)
Other financing activities	-	1	-
Net cash used in financing activities	(426)	(114)	(585)
Net (decrease) increase in cash and cash equivalents	(54)	107	6
Cash and cash equivalents at beginning of year	125	18	12
Cash and cash equivalents at end of year	$71	$125	$18
Supplemental disclosures of cash flow information
Cash paid during the year - interest (net of amount capitalized)	$210	$187	$185
income taxes (net of refunds)	$347	$222	$286

See Notes to PEC Consolidated Financial Statements.

121

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

CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
(in millions except shares outstanding)	Common Stock      Outstanding Shares                 Amount					Unearned ESOP Shares			Accumulated Other Comprehensive (Loss) Income			Retained Earnings			Total Common Stock Equity
Balance, December 31, 2003		160	$	1,953		$	(89	)	$	(7	)	$	1,380		$	3,237
Net income				-			-			-			461			461
Other comprehensive loss				-			-			(107	)		-			(107	)
Comprehensive income																354
Allocation of ESOP shares				22			13			-			-			35
Preferred stock dividends at stated rates				-			-			-			(3	)		(3	)
Dividends paid to parent				-			-			-			(551	)		(551	)
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

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

CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31	2006			2005			2004
Net income	$	457		$	493		$	461
Other comprehensive (loss) income
Changes in net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $2, ($2), and $1, respectively)		(2	)		3			(1	)
Reclassification adjustment for amounts included in net income (net of tax expense of $-)		-			1			-
Minimum pension liability adjustment (net of tax (expense) benefit of $(23), $7, and $68, respectively)		36			(12	)		(106	)
Other (net of tax benefit (expense) of $1, $(1), and $-, respectively)		2			2			-
Other comprehensive income (loss)		36			(6	)		(107	)
Comprehensive income	$	493		$	487		$	354

See Notes to PEC Consolidated Financial Statements.

122

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, 2006 and 2005, and the related statements of income, changes in common stock equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of PEF’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. PEF is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, in 2006 PEF adopted Statement of Financial Accounting Standards No. 158, and in 2005 PEF adopted Statement of Financial Accounting Standards No. 123R and Financial Accounting Standards Board Interpretation No. 47.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

123

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

STATEMENTS of INCOME
(in millions)
Years ended December 31	2006			2005			2004
Operating revenues	$	4,639		$	3,955		$	3,525
Operating expenses
Fuel used in electric generation		1,835			1,323			1,175
Purchased power		766			694			567
Operation and maintenance		684			852			630
Depreciation and amortization		404			334			281
Taxes other than on income		309			279			254
Other		(2	)		(26	)		(2	)
Total operating expenses		3,996			3,456			2,905
Operating income		643			499			620
Other income
Interest income		15			1			-
Other, net		13			7			3
Total other income		28			8			3
Interest charges
Interest charges		155			134			117
Allowance for borrowed funds used during construction		(5	)		(8	)		(3	)
Total interest charges, net		150			126			114
Income before income taxes		521			381			509
Income tax expense		193			121			174
Net income		328			260			335
Preferred stock dividend requirement		2			2			2
Earnings for common stock	$	326		$	258		$	333

See Notes to PEF Financial Statements.

124

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

BALANCE SHEETS
(in millions)
December 31	2006			2005
ASSETS
Utility plant
Utility plant in service	$	9,202		$	8,756
Accumulated depreciation		(3,602	)		(3,434	)
Utility plant in service, net		5,600			5,322
Held for future use		7			9
Construction work in progress		672			414
Nuclear fuel, net of amortization		58			76
Total utility plant, net		6,337			5,821
Current assets
Cash and cash equivalents		23			218
Receivables, net		340			331
Receivables from affiliated companies		11			11
Deferred income taxes		86			12
Inventory		436			311
Deferred fuel cost		-			341
Income taxes receivable		47			-
Derivative assets		-			77
Prepayments and other current assets		62			23
Total current assets		1,005			1,324
Deferred debits and other assets
Regulatory assets		454			351
Nuclear decommissioning trust funds		552			493
Miscellaneous other property and investments		45			47
Prepaid pension cost		174			200
Other assets and deferred debits		26			82
Total deferred debits and other assets		1,251			1,173
Total assets	$	8,593		$	8,318
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,100		$	1,097
Accumulated other comprehensive loss		(1	)		-
Retained earnings		1,588			1,498
Total common stock equity		2,687			2,595
Preferred stock - not subject to mandatory redemption		34			34
Long-term debt, net		2,468			2,554
Total capitalization		5,189			5,183
Current liabilities
Current portion of long-term debt		89			48
Accounts payable		292			237
Payables to affiliated companies		116			101
Notes payable to affiliated companies		47			13
Short-term debt		-			102
Customer deposits		168			148
Interest accrued		38			42
Derivative liabilities		89			-
Current regulatory liabilities		76			10
Other current liabilities		89			91
Total current liabilities		1,004			792
Deferred credits and other liabilities
Noncurrent income tax liabilities		466			433
Accumulated deferred investment tax credits		23			30
Regulatory liabilities		1,091			1,189
Asset retirement obligations		299			290
Accrued pension and other benefits		332			257
Other liabilities and deferred credits		189			144
Total deferred credits and other liabilities		2,400			2,343
Commitments and contingencies (Notes 21 and 22)
Total capitalization and liabilities	$	8,593		$	8,318

See Notes to PEF Financial Statements.

125

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

STATEMENTS of CASH FLOWS
(in millions)
Years ended December 31	2006			2005			2004
Operating activities
Net income	$	328		$	260		$	335
Adjustments to reconcile net income to net cash provided by operating activities
Gain on sales of operating assets		(2	)		(26	)		(1	)
Charges for voluntary enhanced retirement program		-			92			-
Depreciation and amortization		433			367			310
Deferred income taxes and investment tax credits, net		(48	)		(50	)		110
Deferred fuel cost (credit)		404			(173	)		37
Other adjustments to net income		21			45			(13	)
Cash (used) provided by changes in operating assets and liabilities
Receivables		(23	)		(70	)		(20	)
Receivables from affiliated companies		-			4			(8	)
Inventory		(128	)		(34	)		(36	)
Prepayments and other current assets		(37	)		(22	)		2
Accounts payable		3			52			13
Payables to affiliated companies		15			21			14
Other current liabilities		(35	)		(7	)		11
Regulatory assets and liabilities		10			(76	)		(243	)
Other liabilities and deferred credits		(52	)		50			14
Other assets and deferred debits		4			(3	)		8
Net cash provided by operating activities		893			430			533
Investing activities
Gross utility property additions		(727	)		(496	)		(492	)
Nuclear fuel additions		(12	)		(47	)		-
Proceeds from sales of assets		3			43			-
Purchases of available-for-sale securities and other investments		(625	)		(405	)		(569	)
Proceeds from sales of available-for-sale securities and other investments		625			405			569
Other investing activities		1			(6	)		(4	)
Net cash used in investing activities		(735	)		(506	)		(496	)
Financing activities
Proceeds from issuance of long-term debt, net		-			744			56
Net (decrease) increase in short-term debt		(102	)		(191	)		293
Retirement of long-term debt		(48	)		(102	)		(43	)
Changes in advances from affiliates		34			(165	)		(185	)
Dividends paid to parent		(234	)		-			(155	)
Dividends paid on preferred stock		(2	)		(2	)		(2	)
Other financing activities		(1	)		(2	)		1
Net cash (used) provided by financing activities		(353	)		282			(35	)
Net (decrease) increase in cash and cash equivalents		(195	)		206			2
Cash and cash equivalents at beginning of year		218			12			10
Cash and cash equivalents at end of year	$	23		$	218		$	12
Supplemental disclosures of cash flow information
Cash paid during the year- interest (net of amount capitalized)	$	152		$	131		$	118
income taxes (net of refunds)	$	296		$	185		$	57

126

Noncash activities

·In addition to normal and recurring accruals for capital additions, Progress Energy Florida recorded purchases and construction costs for utility plant and equipment and a

corresponding liability for $47 million related to additions at an electric generation facility in 2006. Actual cash expenditures will not occur until 2007.

·In 2005, Progress Energy Florida entered into a capital lease agreement for a building that was completed in 2006, at which point Progress Energy Florida recorded a capital lease

asset and obligation for $54 million.

See Notes to PEF Financial Statements.

127

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) Income			Retained Earnings			Total Common Stock Equity
Balance, December 31, 2003		100	$	1,081	$	(4	)	$	1,062		$	2,139
Net income				-		-			335			335
Other comprehensive income				-		4			-			4
Comprehensive income												339
Preferred stock dividends at stated rates				-		-			(2	)		(2	)
Dividends paid to parent				-		-			(155	)		(155	)
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

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
STATEMENTS of COMPREHENSIVE INCOME
(in millions)
Years ended December 31	2006			2005		2004
Net income	$	328		$	260	$	335
Other comprehensive (loss) income
Changes in net unrealized losses on cash flow hedges (net of tax benefit of $1)		(1	)		-		-
Reclassification of minimum pension liability to regulatory assets (net of tax expense of $2)		-			-		4
Other comprehensive (loss) income		(1	)		-		4
Comprehensive income	$	327		$	260	$	339

See Notes to PEF Financial Statements.

128

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). Prior to February 8, 2006, the Parent was subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA 1935), as amended.

Our reportable segments are: PEC, PEF and Coal and Synthetic Fuels. Our PEC and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity. Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuels as defined under the Internal Revenue Code (the Code), the operation of synthetic fuels facilities for third parties, and coal terminal services. Our Corporate and Other segment (Corporate and Other) is comprised of the activities of the Parent and Progress Energy Service Company (PESC) as well as nonregulated businesses, which do not separately meet the disclosure requirements as a 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

129

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.

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.

Diversified business revenues and expenses represent the operating activities of our consolidated nonregulated operations, primarily the Coal and Synthetic Fuels segment. These operations are separate and distinct businesses from the Utilities.

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 2005 and 2004 have been reclassified to conform to the 2006 presentation.

C. Consolidation of Variable Interest Entities

We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities 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, 2006, the aggregate additional maximum loss exposure that we could be required to record in our income statement as a result of these arrangements was $7 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 Code. At December 31, 2006, 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

130

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.

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 $45 million, $44 million and $42 million in 2006, 2005 and 2004, respectively. The generation capacity of the entity’s power plant is approximately 835 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 20 limited liability partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. At December 31, 2006, the aggregate maximum loss exposure that PEC could be required to record on its income statement as a result of these arrangements totals $21 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 three variable interest entities for which PEF is not the primary beneficiary. These arrangements include investments in one venture capital fund, one building lease with a special-purpose entity and one operating lease with a special-purpose entity. At December 31, 2006, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was $57 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. Diversified business revenues are generally recognized at the time products are shipped or as services are rendered. Leasing activities are accounted for in accordance with SFAS No. 13, “Accounting for Leases.” Revenues related to design and construction of wireless infrastructure are recognized upon completion of services for each completed phase of design and construction. Revenues from the sale of oil and gas production are recognized when title passes, net of royalties. Customer prepayments are recorded as deferred revenue and recognized as revenues as the services are provided.

131

FUEL COST DEFERRALS

Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by the Utilities’ regulators. These clauses allow the Utilities to recover fuel costs and portions of purchased power costs through surcharges on customer rates. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers.

EXCISE TAXES

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in electric operating revenues and taxes other than on income in the statements of income for the years ended December 31 were as follows:

(in millions)	2006		2005		2004
Progress Energy	$	293	$	258	$	240
PEC		94		91		89
PEF		199		167		151

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 agreements approved by the SEC pursuant to Section 13(b) of PUHCA 1935. 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. The repeal of PUHCA 1935 and subsequent regulation by the FERC did not change our current intercompany services.

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 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,

132

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.

ASSET RETIREMENT OBLIGATIONS

We account for asset retirement obligations (ARO), 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

For financial reporting purposes, 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 5).

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 freezes North Carolina electric utility base rates for a five-year period ending in December 2007, unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn 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. During the rate freeze period, the legislation provides for the amortization and recovery of 70 percent of the original estimated compliance costs while providing significant flexibility in the amount of annual amortization recorded from none up to $174 million per 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 a maturity of three months or less.

INVENTORY

We account for inventory, including emission allowances, using the average cost method. Inventories are valued at the lower of average cost or market.

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.

DIVERSIFIED BUSINESS PROPERTY

Diversified business property is stated at cost less accumulated depreciation. If an impairment is recognized on an asset, the fair value becomes its new cost basis. The costs of renewals and betterments are capitalized. The costs of repairs and maintenance are charged to expense as incurred. For properties other than oil and gas properties, depreciation is computed on a straight-line basis using the estimated useful lives disclosed in Note 5B. Depletion of mineral rights is provided on the units-of-production method based upon the estimates of recoverable amounts of clean mineral.

We use the full-cost method to account for our oil and gas properties. Under the full-cost method, substantially all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. These capitalized costs include the costs of all unproved properties and internal costs directly related to acquisition and exploration activities. The amortization base also includes the estimated future cost to develop proved reserves. Except for costs of unproved properties and major development projects in progress, all costs are amortized using the units-of-production method on a country-by-country basis over the life of our proved reserves. Accordingly, all property acquisition, exploration, and development costs of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals, are capitalized as incurred, including internal costs directly attributable to such activities. Related interest expense incurred during property development activities is capitalized as a cost of such activity. Net capitalized costs of unproved property are reclassified as proved property and well costs when related proved reserves are found. Costs to operate and maintain wells and field equipment are expensed as incurred. In accordance with Rule 4-10 of Regulation S-X, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless certain significance tests are met. During 2006, we sold our natural gas drilling and production business, and we met the significance tests necessary to recognize a gain on the transaction (See Note 3B).

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 being 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 have been allocated to profitable subsidiaries in accordance with a PUHCA 1935 order. 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) in the Consolidated Statements of Income. Interest expense on tax deficiencies 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 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, including uncertain tax benefits, 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. Tax reserves are recorded for uncertain tax benefits when it is probable that the tax position will be disallowed and the amount of the disallowance 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. 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 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 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.

Under the full-cost method of accounting for oil and gas properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future net revenues using current prices, plus the lower of cost or fair market value of unproved properties. The ceiling test takes into consideration the prices of qualifying cash flow hedges as of the balance sheet date. If the ceiling (discounted revenues) is not equal to or greater than total capitalized costs, we are required to write-down capitalized costs to this level. We performed this ceiling test calculation every quarter prior to the sale of our natural gas drilling and production business (See Note 3B). No write-downs were required in 2006, 2005 or 2004.

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

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)”

In September 2006, the FASB issued 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). SFAS No. 158 requires an entity to recognize in its statement of financial condition the funded status of its 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 employer’s fiscal year (with limited exceptions). SFAS No. 158 also requires an entity to recognize changes in the funded status of a pension or other postretirement benefit plan within accumulated other comprehensive income (AOCI), net of tax, to the extent such changes are not recognized in earnings as components of net periodic cost. SFAS No. 158 does not permit retrospective application of its provisions. The recognition and disclosure provisions of SFAS No. 158 were implemented by us as of December 31, 2006. The implementation of SFAS No. 158 had no impact on reported net income.

The following is a summary of the incremental effect of applying the provisions of SFAS No. 158 on individual line items of the Balance Sheets of the Progress Registrants at December 31, 2006.

Progress Energy

(in millions)	Before Application of SFAS No. 158			Adjustments			After Application of SFAS No. 158
Regulatory assets	$	892		$	339		$	1,231
Intangibles, net		39			(39	)		-
Total assets		25,401			300			25,701
Liabilities of discontinued operations		185			4			189
Income taxes accrued		287			(3	)		284
Other current liabilities		746			9			755
Noncurrent income tax liabilities		255			51			306
Accrued pension and other benefits		791			166			957
Accumulated other comprehensive loss		(122	)		73			(49	)
Total capitalization and liabilities		25,401			300			25,701

PEC

(in millions)	Before Application of SFAS No. 158			Adjustments			After Application of SFAS No. 158
Regulatory assets	$	534		$	243		$	777
Other assets and deferred debits		180			(25	)		155
Total assets		11,802			218			12,020
Income taxes accrued		69			(1	)		68
Other current liabilities		152			2			154
Noncurrent income tax liabilities		855			54			909
Accrued pension and other benefits		501			80			581
Accumulated other comprehensive loss		(84	)		83			(1	)
Total capitalization and liabilities		11,802		$	218			12,020

PEF

(in millions)	Before Application of SFAS No. 158		Adjustments			After Application of SFAS No. 158
Regulatory assets	$	330	$	124		$	454
Prepaid pension cost		221		(47	)		174
Total assets		8,516		77			8,593
Other current liabilities		87		2			89
Noncurrent income tax liabilities		465		1			466
Accrued pension and other benefits		258		74			332
Total capitalization and liabilities		8,516	$	77			8,593

Amounts for PEC and PEF that would otherwise be recorded in AOCI pursuant to SFAS No. 158 are recorded as regulatory assets consistent with the recovery of the related costs through the ratemaking process.

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

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). Enterprises must adopt FIN 48 through a cumulative effect adjustment to retained earnings at the beginning of their first fiscal year that begins after December 15, 2006, which for us was January 1, 2007. FIN 48 applies to all tax positions within the scope of SFAS No. 109, “Accounting for Income Taxes,” and includes tax positions taken and tax positions expected to be taken. 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. FIN 48 also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. We are still in the process of assessing the impact of FIN 48 on our various income tax positions. The cumulative effect adjustment to retained earnings upon adoption of FIN 48 could have a material impact on our financial statements.

SFAS No. 157, “Fair Value Measurements”

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 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 fair value hierarchy that categorizes and prioritizes the inputs that should be used to estimate fair value. We will implement SFAS No. 157 as of January 1, 2008, applying the provisions retrospectively for derivative accounting and prospectively for all other valuations. We are currently evaluating the impact adoption may have on our financial condition, results of operations and cash flows.

Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”(SAB 108). In practice, some companies currently use the “rollover” method, which focuses on the impact of a misstatement on the income statement. Other companies use the “iron curtain” method, which focuses on the impact of a misstatement on the balance sheet. SAB 108 requires companies to use a “dual approach” in quantifying financial statement misstatements. If an error is determined to be material under either approach, the financial statements must be adjusted. SAB 108 also provides transition guidance for correcting errors existing in prior years.

The SEC permits two methods for the initial application of SAB 108. A company can elect to restate prior financial statements as if the “dual approach” had always been used, or it can record a cumulative effect, with any correcting adjustments recorded to the carrying values of assets and liabilities as of the beginning of the implementation year with the offsetting adjustment recorded to the opening balance of retained earnings. Companies using the “cumulative effect” transition method must disclose the nature and amount of each individual error, including when and how each error being corrected arose. They must also disclose the fact that the errors had previously been considered immaterial. Companies do not have to restate prior period financial statements at initial application so long as management properly applied its previous approach.

SAB 108 is effective for us at December 31, 2006. The implementation of SAB 108 did not have a material effect on our financial position or results of operations, and we did not record an adjustment to beginning retained earnings as permitted by SAB 108.

3.DIVESTITURES

A.   CCO - Georgia Operations

On December 13, 2006, our board of directors approved a plan to pursue the disposition of substantially all of Progress Ventures, Inc.’s (PVI) Competitive Commercial Operations (CCO) physical and commercial assets, which include approximately 1,900 MW of power generation facilities in Georgia, as well as forward gas and power contracts, gas transportation, storage and structured power and other contracts, including the full requirements contracts with 16 Georgia Electric Membership Cooperatives (the Georgia Contracts). The operations of CCO were previously included in the former Progress Ventures segment. We expect to complete the disposition plan in 2007. As a result of the disposition plan, we recorded an after-tax estimated loss of $226 million in December 2006. In 2007, we anticipate recording additional material charges in discontinued operations related to the disposition plan. These additional charges relate primarily to costs to be incurred to exit the Georgia Contracts under SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” These costs could exceed $200 million after-tax.

138

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. Interest expense allocated for the years ended December 31, 2006, 2005 and 2004 was $36 million, $39 million and $40 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in December 2006. After-tax depreciation expense during the years ended December 31, 2006, 2005 and 2004 was $14 million, $14 million and $15 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

(in millions)	2006			2005			2004
Revenues	$	754		$	627		$	168
Loss before income taxes	$	(92	)	$	(93	)	$	(39	)
Income tax benefit		35			39			16
Net loss from discontinued operations		(57	)		(54	)		(23	)
Estimated loss on disposal of discontinued operations, including income tax benefit of $123		(226	)		-			-
Loss from discontinued operations	$	(283	)	$	(54	)	$	(23	)

B.Natural Gas Drilling and Production

On October 2, 2006, we sold our natural gas drilling and production business (Gas) to EXCO Resources, Inc. 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 Corporation (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.

In December 2004, we sold certain gas-producing properties and related assets owned by Winchester Production, which were previously included in the former Progress Ventures segment. Net proceeds of approximately $251 million were used to reduce debt. Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting, the pre-tax gain of $56 million was recognized in earnings rather than as a reduction of the basis of our remaining oil and gas properties. Upon the sale of Gas, the gain was reclassed from continuing operations to earnings from discontinued operations.

The accompanying consolidated financial statements have been restated for all periods presented to reflect all 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. Interest expense allocated for the years ended December 31, 2006, 2005 and 2004 was $13 million, $13 million and $14 million, respectively. 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, 2005 and 2004 was $16 million, $26 million and $27 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

(in millions)	2006			2005			2004
Revenues	$	192		$	159		$	162
Earnings before income taxes	$	135		$	73		$	127
Income tax expense		(53	)		(25	)		(51	)
Net earnings from discontinued operations		82			48			76
Gain on disposal of discontinued operations, including income tax expense of $188		300			-			-
Earnings from discontinued operations	$	382		$	48		$	76

139

C.    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 owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Fla., and Rowan owns 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.

The accompanying consolidated financial statements have been restated for all periods presented to 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. Interest expense allocated for the years ended December 31, 2006, 2005 and 2004 was $6 million, $13 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, 2005 and 2004 was $3 million, $8 million and $8 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

(in millions)	2006			2005			2004
Revenues	$	64		$	67		$	72
Earnings before income taxes	$	15		$	5		$	13
Income tax expense		(5	)		(2	)		(5	)
Net earnings from discontinued operations		10			3			8
Loss on disposal of discontinued operations, including income tax benefit of $37		(67	)		-			-
(Loss) earnings from discontinued operations	$	(57	)	$	3		$	8

D.    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.

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 have been restated for all periods presented to 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. Interest expense allocated was $1 million for each of the years ended December 31, 2005 and 2004. 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, 2005 and 2004 was $1 million, $8 million and $6 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

140

(in millions)	2006			2005			2004
Revenues	$	18		$	76		$	69
Earnings (loss) before income taxes and minority interest	$	7		$	11		$	(9	)
Income tax (expense) benefit		(4	)		(3	)		2
Minority interest		(5	)		(4	)		-
Net (loss) earnings from discontinued operations		(2	)		4			(7	)
Gain on disposal of discontinued operations, including income tax expense of $8 and minority interest of $35		28			-			-
Earnings (loss) from discontinued operations	$	26		$	4		$	(7	)

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.

E.    Dixie Fuels and Other Fuels Business

On March 1, 2006, we sold our 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 units operating under long-term contracts with PEF. 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. The other fuels business is Progress Materials, Inc. and is expected to be sold in 2007.

The accompanying consolidated financial statements have been restated for all periods presented to 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. Interest expense allocated was $1 million for each of the years ended December 31, 2006, 2005 and 2004. We ceased recording depreciation upon classification of the assets as discontinued operations. After-tax depreciation expense during the years ended December 31, 2006, 2005 and 2004 was $1 million, $2 million and $3 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

(in millions)	2006			2005			2004
Revenues	$	20		$	32		$	25
Earnings before income taxes	$	11		$	8		$	3
Income tax expense		(4	)		(3	)		(1	)
Net earnings from discontinued operations		7			5			2
Gain on disposal of discontinued operations, including income tax expense of $1		2			-			-
Earnings from discontinued operations	$	9		$	5		$	2

F.    Coal Mining Businesses

On November 14, 2005, our board of directors approved a plan to divest of five subsidiaries of Progress Fuels engaged in the coal mining business. 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. The remaining coal mining operations are expected to be sold in 2007.

The accompanying consolidated financial statements have been restated for all periods presented to 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. Interest expense allocated for the years ended December 31, 2006, 2005 and 2004 was $1 million, $3 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 years ended December 31,

141

2005 and 2004 was $10 million and $9 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

(in millions)	2006			2005			2004
Revenues	$	84		$	184		$	160
Loss before income taxes	$	(11	)	$	(16	)	$	(17	)
Income tax benefit		7			5			12
Net loss from discontinued operations		(4	)		(11	)		(5	)
Loss on disposal of discontinued operations, including income tax benefit of $16		(10	)		-			-
Loss from discontinued operations	$	(14	)	$	(11	)	$	(5	)

G.    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 have been restated for all periods presented to 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. Interest expense allocated for the years ended December 31, 2005 and 2004 was $4 million and $16 million, respectively. We ceased recording depreciation upon classification of Progress Rail as discontinued operations in February 2005. After-tax depreciation expense during the years ended December 31, 2005 and 2004 was $3 million and $10 million, respectively. Results of discontinued operations for the years ended December 31 were as follows:

(in millions)	2006			2005			2004
Revenues	$	-		$	358		$	1,127
Earnings before income taxes	$	-		$	8		$	50
Income tax expense		-			(3	)		(21	)
Net earnings from discontinued operations		-			5			29
Loss on disposal of discontinued operations, including income tax (expense) benefit of $(6) and $15, respectively		(6	)		(25	)		-
(Loss) earnings from discontinued operations	$	(6	)	$	(20	)	$	29

In February 2004, we sold the majority of the assets of Railcar Ltd., a subsidiary of Progress Rail, to The Andersons, Inc. for proceeds of approximately $82 million before transaction costs and taxes of approximately $13 million. In 2002, we had recognized pre-tax impairment of $59 million to write-down the assets to our estimated fair value less costs to sell. In July 2004, we sold the remaining assets, which had been classified as held for sale, to a third party for net proceeds of $6 million.

H.    Net Assets of Discontinued Operations

Included in net assets of discontinued operations are the assets and liabilities of CCO, the remaining coal mining operations and other fuels business at December 31, 2006, and the assets and liabilities of CCO, Gas, DeSoto and Rowan, PT LLC, Dixie Fuels, the five coal mining businesses and other fuels business at December 31, 2005. The

142

major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets were as follows:

(in millions)	December 31, 2006		December 31, 2005
Accounts receivable	$	45	$	115
Inventory		24		50
Other current assets		28		47
Total property, plant and equipment, net		573		1,899
Total other assets		217		455
Assets of discontinued operations	$	887	$	2,566
Accounts payable	$	43	$	87
Accrued expenses		122		233
Long-term liabilities		24		222
Liabilities of discontinued operations	$	189	$	542

I.    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.

J.    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 will be received over time, which is typical of such sales in the industry. Gains from the sales will be 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, $30 million and $8 million in the years ended December 31, 2006, 2005 and 2004, respectively. In the event that the synthetic fuels tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuels tax credits, the amount of proceeds realized from the sale could be significantly impacted.

K. North Carolina Natural Gas Corporation

On September 30, 2003, we sold North Carolina Natural Gas Corporation (NCNG) and our equity investment in Eastern North Carolina Natural Gas Company to Piedmont Natural Gas Company, Inc. During 2004, we recorded an additional tax gain of approximately $6 million due to final tax adjustments related to the divestiture of NCNG.

4.ACQUISITIONS

In May 2005, Winchester Production, an indirectly wholly owned subsidiary of Progress Fuels, acquired a 50 percent interest in approximately 11 natural gas producing wells and proven reserves of approximately 25 billion cubic feet equivalent (Bcf) 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 or 2004. 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 3B).

143

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		2006		2005		2006		2005		2006		2005
Production plant		7-43	$	12,685	$	12,489	$	8,422	$	8,260	$	4,078	$	4,039
Transmission plant		17-75		2,509		2,353		1,300		1,264		1,209		1,089
Distribution plant		13-55		7,351		7,015		3,992		3,838		3,359		3,177
General plant and other		5-35		1,198		1,083		642		632		556		451
Utility plant in service			$	23,743	$	22,940	$	14,356	$	13,994	$	9,202	$	8,756

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. 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 8.7%, 5.6% and 7.2% in 2006, 2005 and 2004, respectively. The composite AFUDC rate for PEF’s electric utility plant was 8.8% in 2006 and 7.8% in 2005 and 2004.

Our depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.7%, 2.5% and 2.2% in 2006, 2005 and 2004, respectively. The depreciation provisions related to utility plant were $628 million, $556 million and $463 million in 2006, 2005 and 2004, 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 21B).

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, 2006, 2005 and 2004 was $140 million, $136 million and $137 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 2.8%, 2.7% and 2.1% in 2006, 2005 and 2004, respectively. The depreciation provisions related to utility plant were $389 million, $365 million and $275 million in 2006, 2005 and 2004, 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 7A) and Clean Smokestacks Act amortization (See Note 21B).

During 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of two depreciation studies that allowed the utility to reduce the rates used to calculate depreciation expense. The reduction was primarily due to extended lives at each of PEC’s nuclear units. The reduced depreciation rates were effective January 1, 2004.

144

PEF’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.7% in 2006 and 2.3% in 2005 and 2004. The depreciation provisions related to utility plant were $239 million, $191 million and $188 million in 2006, 2005 and 2004, 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, 2006, 2005 and 2004 was $109 million, $107 million and $105 million, respectively, for PEC and $31 million, $29 million and $32 million, respectively, for PEF. These costs were included in fuel used for electric generation in the Statements of Income.

B.Diversified Business Property

Progress Energy

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

(in millions)	2006			2005
Equipment (3-25 years)	$	66		$	79
Land and mineral rights		16			17
Buildings and plants (5-40 years)		54			66
Rail equipment (3-20 years)		-			37
Computers, office equipment and software (3-10 years)		2			2
Construction work in progress		1			2
Accumulated depreciation		(108	)		(125	)
Diversified business property, net	$	31		$	78

Diversified business depreciation expense was $13 million for December 31, 2006, and $22 million for December 31, 2005 and 2004.

PEC

Net diversified business property was $7 million at both December 31, 2006 and 2005. 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, 2006 and 2005. Diversified business depreciation expense was less than $1 million each in 2006, 2005 and 2004. Net diversified business property is included in miscellaneous other property and investments on the Consolidated Balance Sheets.

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). 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:

145

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		-

2005 (in millions) Subsidiary	Facility		Company Ownership Interest			Plant Investment		Accumulated Depreciation		Construction Work in Progress
PEC		Mayo		83.83	%	$	518	$	255	$	1
PEC		Harris		83.83	%		3,146		1,459		17
PEC		Brunswick		81.67	%		1,623		921		23
PEC		Roxboro Unit 4		87.06	%		355		153		10
PEF		Crystal River Unit 3		91.78	%		808		493		48
PEF		Intercession City Unit P11		66.67	%		24		4		-

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, 2006 and 2005, the asset retirement costs, included in utility plant, related to nuclear decommissioning of irradiated plant, net of accumulated depreciation for PEC, totaled $30 million and $31 million, respectively. No costs related to nuclear decommissioning of irradiated plant were recorded at December 31, 2006 and 2005 at PEF. At December 31, 2006 and 2005, additional PEF-related asset retirement costs, net of accumulated depreciation, of $126 million and $137 million, respectively, were recorded at Progress Energy. The fair value of funds set aside in the Utilities’ nuclear decommissioning trust funds for the nuclear decommissioning liability totaled $735 million and $640 million at December 31, 2006 and 2005, respectively, for PEC and $552 million and $493 million, respectively, for PEF. Net nuclear decommissioning trust unrealized gains are included in regulatory liabilities (See Note 7A).

PEC’s decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million each in 2006, 2005 and 2004. Management believes that 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 asset retirement obligations, which are included in depreciation and amortization expense, were $96 million, $90 million and $83 million in 2006, 2005 and 2004, respectively, for PEC and $27 million, $78 million and $77 million in 2006, 2005 and 2004, 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.

146

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)	2006		2005		2006		2005		2006		2005
Removal costs	$	1,341	$	1,316	$	727	$	661	$	614	$	655
Nonirradiated decommissioning costs		137		132		76		71		61		61
Dismantlement costs		124		123		-		-		124		123
Non-ARO cost of removal	$	1,602	$	1,571	$	803	$	732	$	799	$	839

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 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. Extended 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. An application to extend the licenses 20 years for the Brunswick units was approved in June 2006. 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. An application to extend this license 20 years is expected to be submitted 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 $145 million at December 31, 2006 and 2005, 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).

147

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 the synthetic fuels operations. The related asset retirement costs, net of accumulated depreciation, totaled $3 million at December 31, 2006 and 2005.

The following table presents the changes to the AROs during the years ended December 31, 2006 and 2005. Additions relate primarily to asbestos abatement at the Utilities. 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.

	Progress Energy
(in millions)	Regulated			Nonregulated		PEC			PEF
Asset retirement obligations at January 1, 2005	$	1,261		$	2	$	924		$	337
Additions		50			-		23			27
Accretion expense		65			1		51			14
Revisions to prior estimates		(137	)		-		(49	)		(88	)
Asset retirement obligations at December 31, 2005		1,239			3		949			290
Accretion expense		72			-		57			15
Revisions to prior estimates		(8	)		-		(2	)		(6	)
Asset retirement obligations at December 31, 2006	$	1,303		$	3	$	1,004		$	299

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 $33 million with respect to the primary coverage, $36 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

148

from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $300 million (currently available through commercial insurers), each company would be subject to pro rata assessments of up to $100 million for each reactor owned per occurrence. 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.

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, 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. For nuclear liability claims arising out of terrorist acts, the primary level available through commercial insurers is now subject to an industry aggregate limit of $300 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $300 million and would provide coverage in excess of any diminished primary limits due to terrorist acts.

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).

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)	2006			2005			2006			2005			2006			2005
Trade accounts receivable	$	628		$	661		$	285		$	336		$	288		$	263
Unbilled accounts receivable		227			227			157			158			55			60
Notes receivable		57			83			-			-			-			-
Other receivables		46			45			36			28			5			14
Allowance for doubtful accounts receivable		(28	)		(19	)		(5	)		(4	)		(8	)		(6	)
Total receivables	$	930		$	997		$	473		$	518		$	340		$	331

B.  Inventory

At December 31 inventory was comprised of:

	Progress Energy				PEC				PEF
(in millions)	2006		2005		2006		2005		2006		2005
Fuel for production	$	470	$	321	$	230	$	185	$	240	$	136
Inventory for sale		34		61		-		-		-		-
Materials and supplies		443		406		247		240		194		166
Emission allowances		22		35		20		26		2		9
Total current inventory	$	969	$	823	$	497	$	451	$	436	$	311

Materials and supplies amounts above exclude long-term combustion turbine inventory amounts included in other assets and deferred debits for Progress Energy and PEC of $44 million at December 31, 2006 and 2005.

Emission allowances above exclude long-term emission allowances included in other assets and deferred debits for Progress Energy, PEC and PEF of $14 million, $13 million and $1 million, respectively, at December 31, 2005. Progress Energy, PEC and PEF did not have any long-term emission allowance amounts at December 31, 2006.

149

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.

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

Progress Energy

(in millions)	2006			2005
Deferred fuel cost - current (Note 7B)	$	196		$	602
Deferred fuel cost - long-term (Note 7B)		114			31
Deferred impact of ARO - PEC (Note 1D)		282			281
Income taxes recoverable through future rates (Note 14)		114			81
Loss on reacquired debt (Note 1D)		46			50
Storm deferral (Notes 7B and 7C)		102			227
Postretirement benefits (Note 16)		373			88
Derivative mark-to-market adjustment (Note 17)		78			6
Environmental (Notes 7B, 7C and 21A)		72			26
Other		50			64
Total long-term regulatory assets		1,231			854
Deferred fuel cost - current (Note 7C)		(63	)		-
Deferred energy conservation cost and other current regulatory liabilities		(13	)		(10	)
Total current regulatory liabilities		(76	)		(10	)
Non-ARO cost of removal (Note 5D)		(1,602	)		(1,571	)
Deferred impact of ARO - PEF (Note 1D)		(221	)		(225	)
Net nuclear decommissioning trust unrealized gains (Note 5D)		(330	)		(251	)
Clean Smokestacks Act compliance (Note 21B)		(333	)		(317	)
Derivative mark-to-market adjustment (Note 17A)		-			(122	)
Other		(57	)		(41	)
Total long-term regulatory liabilities		(2,543	)		(2,527	)
Net regulatory liabilities	$	(1,192	)	$	(1,081	)

150

PEC

(in millions)	2006			2005
Deferred fuel cost - current (Note 7B)	$	196		$	261
Deferred fuel cost - long-term (Note 7B)		114			31
Deferred impact of ARO (Note 1D)		282			281
Income taxes recoverable through future rates (Note 14)		50			22
Loss on reacquired debt (Note 1D)		19			21
Storm deferral (Note 7B)		12			19
Postretirement benefits (Note 16)		243			-
Environmental (Note 7B)		15			-
Other		42			47
Total long-term regulatory assets		777			421
Non-ARO cost of removal (Note 5D)		(803	)		(732	)
Net nuclear decommissioning trust unrealized gains (Note 5D)		(171	)		(135	)
Clean Smokestacks Act compliance (Note 21B)		(333	)		(317	)
Other		(13	)		(12	)
Total long-term regulatory liabilities		(1,320	)		(1,196	)
Net regulatory liabilities	$	(347	)	$	(514	)

PEF

(in millions)	2006			2005
Deferred fuel cost - current (Note 7C)	$	-		$	341
Storm deferral (Note 7C)		90			208
Income taxes recoverable through future rates (Note 14)		64			59
Loss on reacquired debt (Note 1D)		27			29
Postretirement benefits (Note 16)		130			7
Derivative mark-to-market adjustment (Note 17A)		78			6
Environmental (Notes 7C and 21A)		57			26
Other		8			16
Total long-term regulatory assets		454			351
Deferred fuel cost - current (Note 7C)		(63	)		-
Deferred energy conservation cost and other current regulatory liabilities		(13	)		(10	)
Total current regulatory liabilities		(76	)		(10	)
Non-ARO cost of removal (Note 5D)		(799	)		(839	)
Deferred impact of ARO (Note 1D)		(88	)		(80	)
Net nuclear decommissioning trust unrealized gains (Note 5D)		(159	)		(116	)
Derivative mark-to-market adjustment (Note 17A)		-			(122	)
Other		(45	)		(32	)
Total long-term regulatory liabilities		(1,091	)		(1,189	)
Net regulatory liabilities	$	(713	)	$	(507	)

Except for portions of deferred fuel costs and loss on reacquired debt, all regulatory assets earn a return or the cash has not yet been expended, in which case the assets are offset by liabilities that do not incur a carrying cost. We expect to fully recover these assets and refund these liabilities through customer rates under current regulatory practice.

151

B.  PEC Retail Rate Matters

BASE RATES

PEC’s base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC. As further discussed in Note 21B, the Clean Smokestacks Act was enacted in 2002. The Clean Smokestacks Act freezes North Carolina electric utility base rates for a five-year period ending in December 2007, unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn 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. During the rate freeze period, the legislation provides for the amortization and recovery of 70 percent of the original estimated compliance costs while providing significant flexibility in the amount of annual amortization recorded from none up to $174 million per year. Subsequent to 2007, PEC’s current North Carolina base rates will continue subject to traditional cost-based rate regulation.

FUEL COST RECOVERY

On May 3, 2006, PEC filed with the SCPSC for an increase in the fuel rate charged to its South Carolina ratepayers for under-recovered fuel costs and to meet future expected fuel costs. On June 16, 2006, the SCPSC approved a settlement agreement filed jointly by PEC and all other parties to the proceeding. The settlement agreement provided for a $23 million, or 4.6 percent, increase in rates. The increase was $4 million less than PEC originally requested due to adjustment of future fuel cost estimates agreed upon during settlement. Effective July 1, 2006, residential electric bills increased by $3.01 per 1,000 kWhs for fuel cost recovery. At December 31, 2006, PEC’s South Carolina deferred fuel balance was $29 million, of which $5 million is expected to be collected after 2007 in accordance with the settlement agreement and, therefore, has been classified as a long-term regulatory asset.

On June 2, 2006, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. On September 25, 2006, the NCUC approved a settlement agreement filed jointly by PEC, the NCUC Public Staff and the Carolinas Industrial Group for Fair Utility Rates II. The settlement agreement provided for a $177 million, or 6.7 percent increase in rates effective October 1, 2006. The settlement agreement further provides for rate increases of $50 million in 2007 and $30 million in 2008 and for PEC to collect its existing deferred fuel balance by September 30, 2009. PEC initially sought an increase of $292 million, or 11.0 percent, but agreed to a three-year phase-in of the increase in order to address concerns regarding the magnitude of the proposed increase. PEC will be allowed to calculate and collect interest at 6% on the difference between its fuel factor proposed in its original request to the NCUC and the settlement agreement’s factor. Effective October 1, 2006, residential electric bills increased by $4.87 per 1,000 kWhs for fuel cost recovery. At December 31, 2006, PEC’s North Carolina deferred fuel balance was $281 million, of which $109 million is expected to be collected after 2007 in accordance with the settlement agreement and, therefore, has been classified as a long-term regulatory asset.

The Carolina Utility Customers Association (CUCA) appealed the NCUC’s order on November 21, 2006 on the grounds that the NCUC does not have the statutory authority to establish fuel rates for more than one year. We anticipate filing a motion to dismiss during the first quarter of 2007. We cannot predict the outcome of this matter.

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. During each of 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. During each of 2006, 2005 and 2004, PEC recognized $5 million of North Carolina storm amortization.

152

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 $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 the fourth quarter of 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.

As discussed in Note 21B, PEC reclassified $29 million of expense from other, net to depreciation and amortization expense on the Consolidated Statements of Income for Clean Smokestacks Act amortization recognized during 2006.

The NCUC and SCPSC have 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. Accelerated cost recovery of these assets resulted in no additional expense in 2006, 2005 or 2004. Through December 31, 2006, PEC recorded total accelerated depreciation of $403 million.

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. Additionally, PEF will continue to recover and collect a return on Hines Unit 2 through the fuel clause through late 2007, when it will be transferred into base rates. This transfer will correspond with the in-service dates of Hines Unit 4, which will also be recovered through a base rate increase. 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 2006 threshold of $1.499 billion and thus no revenues were subject to revenue sharing. Both the 2006 base threshold of $1.499 billion and the 2006 cap of $1.549 billion will be adjusted annually for rolling average 10-year retail kWh sales growth. 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 return on equity (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 1 and September 15, 2006, PEF filed requests with the FPSC seeking increases to cover rising fuel, environmental compliance and energy conservation costs. PEF asked the FPSC to approve a $171 million, or 3.7 percent, increase in rates. Subsequently, on October 25 and October 31, 2006, PEF supplemented its September filings to reflect lower projected fuel costs for PEF. PEF’s revised forecasts resulted in a $40 million, or 0.7 percent, increase in rates over 2006. On November 8, 2006, the FPSC approved PEF’s supplemental filing. The new charges

153

were effective January 1, 2007, and increased residential bills $0.78 for the first 1,000 kWhs. At December 31, 2006, PEF was over-recovered in fuel and capacity costs by $63 million and under-recovered in environmental compliance by $14 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 sulfur dioxide (SO₂) allowance costs associated with PEF’s purported failure to utilize the most economical sources of coal at Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) during the period 1996 to 2005. The OPC subsequently revised its claim to $135 million, plus interest. The OPC claims that although 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 August 30, 2006, PEF filed a motion with the FPSC to dismiss the petition on the grounds that the OPC petition would require the FPSC to engage in retroactive ratemaking for rates previously approved under the fuel recovery clause. On September 13, 2006, the OPC filed a memorandum in opposition to PEF’s motion to dismiss the petition. PEF’s motion to dismiss was denied by the FPSC on December 19, 2006. A hearing on the matter has been scheduled by the FPSC for April 2, 2007. PEF believes that its coal procurement practices were prudent and that it has sound legal and factual arguments to successfully defend its position. 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 costs through PEF’s fuel recovery clause. The uprate will increase CR3’s gross output by approximately 180 MW. The uprate will take place in two stages: approximately 40 MW will be added through equipment modifications during the 2009 refueling outage and approximately 140 MW will be added by modifying the design of the plant during the 2011 refueling outage to use more highly enriched fuel. The design modifications will require a license amendment approved by the NRC. The project is estimated to cost approximately $382 million, which includes potential transmission system improvements and modifications to comply with environmental regulations. The costs 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 of uprate costs through PEF’s fuel recovery clause was transferred to a separate docket filed on January 16, 2007. The FPSC has scheduled a hearing to be held May 23, 2007, to determine whether the uprate costs should be recovered through the fuel adjustment clause. If PEF does not receive approval to recover the uprate costs through the fuel adjustment clause, these costs will be recoverable through base rates, similar to other utility plant additions. 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. 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 kWhs 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 the FPSC staff. The net impact was included in customer bills beginning January 1, 2006. In 2006 and 2005, PEF recorded amortization of $122 million and $50 million, respectively, associated with the recovery of these storm costs.

154

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 current two-year storm surcharge, which equals approximately $3.61 on the average residential monthly customer bill of 1,000 kWhs, for an additional 12-month period to replenish its storm reserve. The requested extension, which would begin August 2007, would replenish the existing storm reserve by an estimated additional $130 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.

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 November 3, 2004, the FPSC approved PEF’s petition for Determination of Need for the construction of a fourth unit at PEF’s Hines Energy Complex. Hines Unit 4 is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to its ratepayers at a reasonable cost. The unit is planned for commercial operation in December 2007. Hines Unit 4 will be a combined cycle unit with a generating capacity of 461 MW (summer rating). The estimated total in-service cost of Hines Unit 4 approved as part of the Determination of Need was $286 million. If the actual cost is less than the original estimate, ratepayers will receive the benefit of such cost under-runs. Any costs that exceed this estimate will not be recoverable absent, among other things, extraordinary circumstances as found by the FPSC in subsequent proceedings. The current estimate of in-service cost exceeds the initial project estimate by approximately 12 percent to 15 percent due to what we believe to be extraordinary circumstances. Therefore, we believe that disallowance of these costs by the FPSC in subsequent proceedings is not probable. We cannot predict the outcome of this matter.

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. 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. PEC’s investment in GridSouth totaled $33 million at December 31, 2006 and 2005. PEC expects to recover its investment.

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 startup costs in GridFlorida from retail ratepayers through base rates.

E. Nuclear License Renewals

On June 26, 2006, Brunswick received 20-year extensions from the NRC on the operating licenses for its two nuclear reactors. The operating licenses have been extended to 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.

F. FERC Market Power Mitigation

In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant did not pass one of the interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believed it would experience in passing one of the interim screens, on September 6, 2005, PEC filed revisions to its market-based rate tariffs restricting them to sales outside PEC’s control area and peninsular Florida and a new cost-based tariff for sales within PEC’s control area. The FERC has accepted these revised tariffs.

8.   GOODWILL AND OTHER 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 2005 and 2006; 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, 2006 and 2005, 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 2006 or 2005.

Included in the assets of discontinued operations at December 31, 2005, is the goodwill related to CCO. For CCO, the goodwill impairment tests were performed at the reporting unit level of our Effingham, Monroe, Walton and Washington nonregulated generating plants (Georgia Region), which is one level below CCO. As a result of our evaluation of certain business opportunities that impacted the future cash flows of our Georgia Region operations, we performed an interim 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 was previously reported within impairment of assets on the Consolidated Statements of Income. This impairment was reclassed to discontinued operations on the Consolidated Statements of Income during the fourth quarter of 2006 (See Note 3A).

The gross carrying amount and accumulated amortization of the intangible assets at December 31 were as follows:

	2006					2005
(in millions)	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Synthetic fuels intangibles	$	107	$	(107	)	$	134	$	(98	)
Other		6		(6	)		29		(6	)
Total	$	113	$	(113	)	$	163	$	(104	)

156

All of our intangibles, except minimum pension liability adjustments, are subject to amortization. Synthetic fuels intangibles represent intangibles for synthetic fuels technology. Other intangibles are primarily acquired customer contracts, permits that are amortized over their respective lives and minimum pension liability adjustments.

PEC had intangible assets related to minimum pension liability adjustments of $17 million at December 31, 2005. PEF had intangible assets related to minimum pension liability adjustments of $2 million at December 31, 2005. Due to the adoption of SFAS No. 158 in 2006, minimum pension liability adjustments and related intangible assets are no longer recorded (See Note 2).

Amortization expense recorded on intangible assets was $9 million for the year ended December 31, 2006, and $19 million for both years ended December 31, 2005 and 2004. No amortization expense on intangible assets was recorded at PEC and PEF for each of the years ended December 31, 2006, 2005 and 2004. No annual amortization expense for intangible assets is expected for 2007 through 2011.

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 “idle” 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 is reported within impairment of assets on the Consolidated Statements of Income. This charge represents the entirety of the synthetic fuels intangible assets; these assets had been reported within the Coal and Synthetic Fuels segment. Following a significant decrease in oil prices, our synthetic fuels facilities resumed limited production of synthetic fuels in September and October 2006, which continued through the end of 2006.

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 and 2005, we recorded pre-tax long-lived asset and investment impairments and other charges of $65 million and $1 million, respectively. PEC recorded pre-tax long-lived asset and investment impairments and other charges of $1 million in both 2006 and 2005. No impairments were recorded in 2004.

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 is reported within impairment of assets on the Consolidated Statements of Income. 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 the Coal and Synthetic Fuels segment. As discussed in Note 8, our synthetic fuels facilities resumed limited production of synthetic fuels in September and October 2006, which continued through the end of 2006.

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).

157

Declines in fair value to below the cost basis judged to be other than temporary on available-for-sale securities are included in 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. 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. No impairments were recorded in 2004.

10.   EQUITY

A. Common Stock

Progress Energy

At December 31, 2006 and 2005, we had 500 million shares of common stock authorized under our charter, of which 256 million shares and 252 million shares, respectively, were outstanding. During 2006, 2005 and 2004, respectively, we issued approximately 4.2 million, 4.8 million and 1.7 million shares of common stock, resulting in approximately $185 million, $208 million and $73 million in proceeds. Included in these amounts for 2006, 2005 and 2004, respectively, were approximately 1.6 million, 4.6 million and 1.4 million shares for proceeds of approximately $70 million, $199 million and $62 million, to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan.

At December 31, 2006 and 2005, we had approximately 54 million shares and 58 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, 2006, there were no significant restrictions on the use of retained earnings (See Note 12).

PEC

At December 31, 2006 and 2005, 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, 2006, 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, 2006 and 2005, 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, 2006, there were no significant restrictions on the use of retained earnings. See Note 12 for additional dividend restrictions related to PEF.

158

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, 2006 and 2005, 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 2.3 million and 2.9 million ESOP suspense shares at December 31, 2006 and 2005, respectively, with a fair value of $112 million and $126 million, respectively. ESOP shares allocated to plan participants totaled 10.9 million and 11.4 million at December 31, 2006 and 2005, 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 were met and will be met with shares released from the suspense account, totaled approximately $14 million, $18 million and $21 million for the years ended December 31, 2006, 2005 and 2004, respectively. Total matching and incentive costs were approximately $23 million, $30 million and $32 million for the years ended December 31, 2006, 2005 and 2004, 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.

PEC

PEC’s matching and incentive costs, which were met and will be met with shares released from the suspense account, totaled approximately $8 million, $11 million and $12 million for the years ended December 31, 2006, 2005 and 2004, respectively. Total matching and incentive costs were approximately $13 million, $17 million and $18 million for the years ended December 31, 2006, 2005 and 2004, respectively.

PEF

PEF’s matching and incentive costs, which were met and will be met with shares released from the suspense account, totaled approximately $2 million, $4 million and $5 million for the years ended December 31, 2006, 2005 and 2004, respectively. Total matching and incentive costs were approximately $4 million, $6 million and $7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

159

STOCK OPTIONS

Pursuant to our 1997 Equity Incentive Plan and 2002 Equity Incentive Plan, 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. An immaterial number of stock options were granted in 2004 and no stock options have been granted in 2005 or 2006. 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, 2006, 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		7.0		$	43.58
Granted		-			-
Forfeited		(0.1	)		44.75
Canceled		(0.2	)		43.74
Exercised		(2.7	)		43.37
Options outstanding, December 31		4.0			43.70
Options exercisable, December 31		4.0			43.70

The options outstanding and exercisable at December 31, 2006, had a weighted-average remaining contractual life of 5.8 years and an aggregate intrinsic value of $22 million. Total intrinsic value of options exercised during the year ended December 31, 2006, was $10 million. Total intrinsic value of options exercised during the year ended December 31, 2005, was less than $1 million. The total intrinsic value of options exercised during the year ended December 31, 2004, was $1 million.

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 with the following weighted-average assumptions:

	2004
Risk-free interest rate	4.22%
Dividend yield	5.19%
Volatility factor	20.30%
Weighted-average expected life of the options (in years)	10

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.

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.

160

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		2004
Net income, as reported	$	697	$	759
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		2		10
Pro forma net income	$	695	$	749
Earnings per share
Basic - as reported	$	2.82	$	3.13
Basic - pro forma		2.81		3.09
Diluted - as reported		2.82		3.12
Diluted - pro forma		2.81		3.08

As of December 31, 2006, all options were fully vested and no compensation expense related to stock options is expected in future periods.

Cash received from the exercise of stock options totaled $115 million, $8 million and $18 million, respectively, during the years ended December 31, 2006, 2005 and 2004. The actual tax benefit for tax deductions from stock option exercises for the year ended December 31, 2006, was $4 million. The actual tax benefit for tax deductions from stock option exercises for the years ended December 31, 2005 and 2004 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 are fully vested and no compensation expense related to stock options is expected in future periods.

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		2004
Net income, as reported	$	493	$	461
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		2		7
Pro forma net income	$	491	$	454

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 are fully vested and no compensation expense related to stock options is expected in future periods.

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.

161

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		2004
Net income, as reported	$	260	$	335
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1		2
Pro forma net income	$	259	$	333

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. The two primary active stock-based compensation programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards (RSA) program, both of which were established pursuant to our 1997 Equity Incentive Plan and were continued under our 2002 Equity Incentive Plan, as amended and restated from time to time.

We granted cash-settled PSSP awards prior to 2005. Beginning in 2005, we are granting stock-settled PSSP awards. Under the terms of the cash-settled 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, the performance shares. The PSSP has two equally weighted performance measures, both of which are based on our results as compared to a peer group of utilities. The outcome of the performance measures can result in an increase or decrease from the target number of performance shares granted. Compensation expense is recognized over the vesting period based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. 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 certain subsequent adjustments related to our results as compared to the peer group of utilities. PSSP cash-settled liabilities totaling $4 million, $5 million and $7 million were paid in the years ended December 31, 2006, 2005 and 2004, respectively. A summary of the status of the target performance shares under the stock-settled PSSP plan at December 31, 2006, 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		540,588		$	44.24
Granted		556,431			44.27
Paid		(54	)		44.27
Vested		-			-
Forfeited		( 52,382	)		44.25
Ending balance		1,044,583		$	44.26

^(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.

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

The 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,

162

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, 2006, and changes during the year then ended, is presented below:

	Number of Restricted Shares			Weighted-Average Grant Date Fair Value
Beginning balance		588,308		$	43.27
Granted		168,800			44.51
Vested		(102,836	)		41.87
Forfeited		(50,034	)		43.68
Ending balance		604,238		$	43.82

For the years ended December 31, 2005 and 2004, the weighted-average grant date fair value of restricted stock granted was $42.56 and $46.95, respectively.

The total fair value of restricted stock vested during the years ended December 31, 2006, 2005 and 2004 was $4 million, $7 million and $16 million, respectively. Cash expended to purchase shares for the restricted stock program totaled $8 million, $8 million and $7 million during the years ended December 31, 2006, 2005 and 2004, respectively.

Our Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $25 million for the year ended December 31, 2006, with a recognized tax benefit of $10 million. The total expense recognized on our Consolidated Statements of Income for other stock-based compensation plans was $10 million, with a recognized tax benefit of $4 million, for each of the years ended December 31, 2005 and 2004. No compensation cost related to other stock-based compensation plans was capitalized.

At December 31, 2006, there was $33 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 2.1 years.

PEC

Our Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $14 million for the year ended December 31, 2006, with a recognized tax benefit of $6 million. The total expense recognized on our Consolidated Statements of Income for other stock-based compensation plans was $7 million, with a recognized tax benefit of $3 million, for each of the years ended December 31, 2005 and 2004. No compensation cost related to other stock-based compensation plans was capitalized.

PEF

Our Statements of Income included total recognized expense for other stock-based compensation plans of $7 million for the year ended December 31, 2006, with a recognized tax benefit of $3 million. The total expense recognized on our 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. The total expense recognized on our Statements of Income for other stock-based compensation plans was $2 million for the year ended December 31, 2004, 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 effect of the nonvested portion of restricted stock awards and the effect of stock options outstanding.

163

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)	2006	2005	2004
Weighted-average common shares - basic	250.4	246.6	242.2
Net effect of dilutive stock-based compensation plans	0.4	0.4	0.9
Weighted-average shares - fully diluted	250.8	247.0	243.1

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 2.4 million, 3.0 million and 3.6 million for the years ended December 31, 2006, 2005 and 2004, respectively. There were 1.8 million, 2.9 million and 3.0 million stock options outstanding at December 31, 2006, 2005 and 2004, 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)	2006			2005			2006			2005			2006			2005
(Loss) gain on cash flow hedges	$	(14	)	$	55		$	(5	)	$	(3	)	$	(1	)	$	-
Minimum pension liability adjustments		-			(160	)		-			(119	)		-			-
SFAS No. 158 benefits adjustment		(39	)		-			-			-			-			-
Other		4			1			4			2			-			-
Total accumulated other comprehensive loss	$	(49	)	$	(104	)	$	(1	)	$	(120	)	$	(1	)	$	-

164

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, 2006 and 2005, preferred stock outstanding consisted of the following:

(dollars in millions, except share and per share data)	Shares Authorized                      Outstanding			Redemption 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

165

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, 2006):

(in millions)			2006			2005
Progress Energy, Inc.
Senior unsecured notes, maturing 2010-2031	6.98	%	$	2,600		$	4,300
Unamortized fair value hedge gain, net				(1	)		(3	)
Unamortized premium and discount, net				(18	)		(19	)
Current portion of long-term debt				-			(404	)
Long-term debt, net				2,581			3,874
PEC
First mortgage bonds, maturing 2007-2033	5.76	%		2,200			2,200
Pollution control obligations, maturing 2017-2024	3.74	%		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				(21	)		(24	)
Current portion of long-term debt				(200	)		-
Long-term debt, net				3,470			3,667
PEF
First mortgage bonds, maturing 2008-2033	5.39	%		1,630			1,630
Pollution control obligations, maturing 2018-2027	3.66	%		241			241
Senior unsecured notes, maturing 2008	5.77	%		450			450
Medium-term notes, maturing 2007-2028	6.77	%		241			289
Unamortized premium and discount, net				(5	)		(8	)
Current portion of long-term debt				(89	)		(48	)
Long-term debt, net				2,468			2,554
Florida Progress Funding Corporation (See Note 23)
Debt to affiliated trust, maturing 2039	7.10	%		309			309
Unamortized premium and discount, net				(38	)		(39	)
Long-term debt, net				271			270
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2007-2008	6.59	%		80			140
Miscellaneous notes				-			2
Current portion of long-term debt				(35	)		(61	)
Long-term debt, net				45			81
Progress Energy consolidated long-term debt, net			$	8,835		$	10,446

At December 31, 2005, we classified $397 million, related to the retirement of $800 million in Progress Energy, Inc. 6.75% Senior Notes on March 1, 2006, as long-term debt. Settlement of this obligation was not expected to require the use of working capital in 2006 as we had the intent and ability to refinance this debt on a long-term basis.

On January 13, 2006, Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100 million of Series A Floating Rate Senior Notes due 2010, receiving net proceeds of $397 million. These senior notes are unsecured. Interest on the Floating Rate Senior Notes is based on three-month London Inter Bank Offering Rate

166

(LIBOR) plus 45 basis points and resets quarterly. We used the net proceeds from the sale of these senior notes and a combination of available cash and commercial paper proceeds to retire the $800 million aggregate principal amount of our 6.75% Senior Notes on March 1, 2006. Pending the application of the proceeds described above, we invested the net proceeds in short-term, interest-bearing, investment-grade securities.

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, at a make-whole redemption price. The 6.05% Senior Notes were acquired at 100.274 percent of par, or approximately $351 million plus accrued interest, and the 5.85% Senior Notes were acquired at 101.610 percent of par, or approximately $406 million, plus accrued interest. The redemptions were funded with available cash on hand and no additional debt was incurred in connection with the redemptions. On December 6, 2006, Progress Energy repurchased, pursuant to a tender offer, $550 million, or 53.0 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. The redemption was funded with available cash on hand and no additional debt was incurred in connection with the redemption. See Note 20 for a discussion of losses on debt redemptions.

At December 31, 2006 and 2005, we had committed lines of credit used to support our commercial paper borrowings. At December 31, 2006 and 2005, we had no outstanding borrowings under our credit facilities. We are required to pay minimal annual commitment fees to maintain our credit facilities.

The following table summarizes our revolving credit agreements (RCAs) and available capacity at December 31, 2006:

(in millions)	Description		Total		Outstanding		Reserved(a)			Available
Progress Energy, Inc.		Five-year (expiring 5/3/11)	$	1,130	$	-	$	(60	)	$	1,070
PEC		Five-year (expiring 6/28/10)		450		-		-			450
PEF		Five-year (expiring 3/28/10)		450		-		-			450
Total credit facilities			$	2,030	$	-	$	(60	)	$	1,970

^(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, 2006, Progress Energy, Inc. had a total amount of $60 million of letters of credit issued, which were supported by the RCA.

In addition to the committed RCAs at December 31, 2005, we had an $800 million 364-day credit agreement, which was restricted for the retirement of $800 million of 6.75% Senior Notes due March 1, 2006. On March 1, 2006, Progress Energy, Inc. retired $800 million of its 6.75% Senior Notes, thus effectively terminating the 364-day credit agreement.

On May 3, 2006, Progress Energy restructured its existing $1.13 billion five-year RCA with a syndication of financial institutions. The new RCA replaced an existing $1.13 billion five-year facility, which was terminated effective May 3, 2006. The new RCA will continue to be used to provide liquidity support for Progress Energy’s issuances of commercial paper and other short-term obligations. The new RCA no longer includes a material adverse change representation for borrowings or a financial covenant for interest coverage. Fees and interest rates under the new RCA will continue to be determined 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.

On May 3, 2006, PEC’s five-year $450 million RCA was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of PEC’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P.

On May 3, 2006, PEF’s five-year $450 million RCA was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be

167

determined 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.

We had no commercial paper outstanding or other short-term debt at December 31, 2006. The following table summarizes our outstanding commercial paper and other short-term debt and related weighted-average interest rates at December 31, 2005:

(in millions)
PEC	4.65	%	$	73
PEF	4.75	%		102
Total	4.71	%	$	175

The following table presents the aggregate maturities of long-term debt at December 31, 2006:

(in millions)	Progress Energy Consolidated		PEC		PEF
2007	$	324	$	200	$	89
2008		877		300		532
2009		400		400		-
2010		406		6		300
2011		1,000		-		300
Thereafter		6,235		2,785		1,341
Total	$	9,242	$	3,691	$	2,562

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, 2006, 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	%		55.4	%
PEC		65	%		52.3	%
PEF		65	%		49.4	%

^(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 could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility. Progress Energy, Inc.’s cross-default provision applies only to Progress Energy, Inc. and its significant subsidiaries, as defined in the credit agreement, (i.e., PEC, Florida Progress Corporation (Florida Progress), PEF, Progress Capital Holdings, Inc. and PVI). PEC’s and PEF’s cross-default provisions apply only to defaults of indebtedness by PEC and its subsidiaries and PEF, respectively, not each other or other affiliates of PEC and PEF.

168

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, 2006, 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, 2006, none of PEC’s cash dividends or distributions on common stock was restricted.

In addition, PEC’s Articles of Incorporation provide that so long as any shares of preferred stock are outstanding, the aggregate amount of cash dividends or distributions on common stock since December 31, 1945, including the amount then proposed to be expended, shall be limited to 75 percent of the aggregate net income available for common stock if common stock equity falls below 25 percent of total capitalization, and to 50 percent if common 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, 2006, PEC’s common stock equity was approximately 49.0 percent of total capitalization. At December 31, 2006, 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, 2006, 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, 2006, PEF’s common stock equity was approximately 51.8 percent of total capitalization. At December 31, 2006, none of PEF’s cash dividends or distributions on common stock was restricted.

169

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, 2006, PEC and PEF had a total of $2.869 billion and $1.871 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.

13.   INVESTMENTS AND FAIR VALUE OF FINANCIAL INSTRUMENTS

A.  Investments

At December 31, 2006 and 2005, 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)	2006		2005		2006		2005		2006		2005
Nuclear decommissioning trust (See Note 5D)	$	1,287	$	1,133	$	735	$	640	$	552	$	493
Investments in equity securities (a)		6		7		4		6		1		1
Equity method investments (b)		23		27		13		15		-		-
Cost investments (c)		8		13		2		1		-		-
Benefit investment trusts (d)		80		77		2		1		-		-
Company-owned life insurance (d)		161		153		99		97		39		39
Marketable debt securities (e)		71		191		50		191		-		-
Total	$	1,636	$	1,601	$	905	$	951	$	592	$	533

^(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 the Consolidated Balance Sheets in miscellaneous other property and investments 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 $9.159 billion and $10.959 billion at December 31, 2006 and 2005, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $9.543 billion and $11.491 billion at December 31, 2006 and 2005, 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 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, 2006 and 2005 are summarized below. Net nuclear decommissioning trust fund unrealized gains are included in regulatory liabilities (See Note 7A).

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
2005
(in millions)		Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	406	$	257	$	663
Debt securities		673		7		680
Cash equivalents		18		-		18
Total	$	1,097	$	264	$	1,361

At December 31, 2006, the fair value of available-for-sale debt securities by contractual maturity was (in millions):

Due in one year or less	$	28
Due after one through five years		116
Due after five through 10 years		196
Due after 10 years		279
Total	$	619

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)	2006		2005		2004
Proceeds	$	2,547	$	3,755	$	3,200
Realized gains		33		26		55
Realized losses		24		31		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, 2006 and 2005 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, 2006 and 2005 our other securities had no investments in a continuous loss position for greater than 12 months.

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $3.670 billion and $3.667 billion at December 31, 2006 and 2005, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3.732 billion and $3.789 billion at December 31, 2006 and 2005, 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, 2006 and 2005 are summarized below. Net nuclear decommissioning trust fund unrealized gains are included in regulatory liabilities (See Note 7A).

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
2005
(in millions)		Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	218	$	141	$	359
Debt securities		461		4		465
Cash equivalents		10		-		10
Total	$	689	$	145	$	834

At December 31, 2006, the fair value of available-for-sale debt securities by contractual maturity was (in millions):

Due in one year or less	$	18
Due after one through five years		80
Due after five through 10 years		76
Due after 10 years		197
Total	$	371

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)	2006		2005		2004
Proceeds	$	995	$	1,678	$	2,584
Realized gains		21		13		24
Realized losses		14		16		25

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 the carrying value is other-than-temporary (See Note 1D). At December 31, 2006 and 2005 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 $2.557 billion and $2.602 billion at December 31, 2006 and 2005, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $2.567 and $2.635 billion at December 31, 2006 and 2005, 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, 2006 and 2005 are summarized below. Net nuclear decommissioning trust fund unrealized gains are included in regulatory liabilities (See Note 7A).

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
2005
(in millions)		Book Value		Unrealized Gains		Estimated Fair Value
Equity securities	$	188	$	116	$	304
Debt securities		180		3		183
Cash equivalents		5		-		5
Total	$	373	$	119	$	492

At December 31, 2006, the fair value of available-for-sale debt securities by contractual maturity was (in millions):

Due in one year or less	$	3
Due after one through five years		26
Due after five through 10 years		100
Due after 10 years		61
Total	$	190

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)	2006		2005		2004
Proceeds	$	509	$	330	$	529
Realized gains		12		13		30
Realized losses		9		13		5

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, 2006 and 2005 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.

Progress Energy

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

(in millions)	2006			2005
Deferred income tax assets
Asset retirement obligation liability	$	141		$	155
Compensation accruals		99			99
Deferred revenue		28			55
Derivative instruments		42			-
Environmental remediation liability		36			27
Income taxes refundable through future rates		216			234
Investments		5			-
SFAS No. 158, postretirement and pension benefits		351			274
Unbilled revenue		36			30
Other		125			108
Federal income tax credit carry forward		851			957
State net operating loss carry forward (net of federal expense)		54			44
Valuation allowance		(71	)		(39	)
Total deferred income tax assets		1,913			1,944
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(1,349	)		(1,396	)
Deferred fuel recovery		(60	)		(89	)
Deferred storm costs		(51	)		(94	)
Derivative instruments		-			(32	)
Income taxes recoverable through future rates		(436	)		(202	)
Investments		-			(35	)
Other		(70	)		(64	)
Total deferred income tax liabilities		(1,966	)		(1,912	)
Total net deferred income tax (liabilities) assets	$	(53	)	$	32

175

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

(in millions)	2006			2005
Current deferred income tax assets	$	159		$	37
Noncurrent deferred income tax assets, included in other assets and deferred debits		19			79
Current deferred income tax liabilities, included in other current liabilities		(1	)		(1	)
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(230	)		(83	)
Total net deferred income tax (liabilities) assets	$	(53	)	$	32

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.

At December 31, 2006, the federal income tax credit carry forward includes $850 million of alternative minimum tax credits that do not expire and $1 million of general business credits that will expire during the period 2023 through 2025.

At December 31, 2006, we had gross state net operating loss carry forwards of $1.1 billion that will expire during the period 2009 through 2026.

Valuation allowances have been established due to the uncertainty of realizing certain future state tax benefits. We established additional valuation allowances of $32 million during 2006. 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.

We establish accruals for certain tax contingencies when, despite our belief that our tax return positions are fully supported, we believe that certain positions may be challenged and that it is probable our positions may not be fully sustained. We are under continuous examination by the IRS and other tax authorities, and we account 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, excluding accrued interest and penalties, which were included in taxes accrued on the Consolidated Balance Sheets.

Considering all tax contingency reserves, we do not expect the resolution of these matters to have a material impact on our financial position or results of operations. The tax contingency reserves relate primarily to capitalization and basis issues.

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

	2006			2005			2004
Effective income tax rate		28.1	%		(5.9	)%		9.3	%
State income taxes, net of federal benefit		(6.5	)		(3.7	)		(7.7	)
Minority interest		0.2			(2.3	)		(1.2	)
Federal tax credits		11.3			43.7			30.2
Investment tax credit amortization		1.7			2.0			1.9
Employee stock ownership plan dividends		1.7			1.9			2.1
Domestic manufacturing deduction		0.5			1.3			-
Other differences, net		(2.0	)		(2.0	)		0.4
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

176

Our effective income tax rate is favorably impacted by federal tax credits resulting from synthetic fuels production.

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

(in millions)	2006			2005			2004
Current - federal	$	377		$	382		$	249
- state		69			78			71
Deferred - federal		(136	)		(163	)		(33	)
- state		(26	)		(36	)		10
Valuation allowance		14			-			-
State net operating loss carry forward		(3	)		(3	)		(1	)
Synthetic fuels tax credit		(79	)		(282	)		(215	)
Investment tax credit		(12	)		(13	)		(14	)
Total income tax expense (benefit)	$	204		$	(37	)	$	67

Total income tax expense (benefit) 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 2006 or 2004.

·   Taxes related to discontinued operations recorded net of tax for 2006, 2005 and 2004, which are presented separately in Notes 3A through 3G.

·   Taxes related to other comprehensive income recorded net of tax for 2006, 2005 and 2004, which are presented separately in the Consolidated Statements of Comprehensive Income.

·   Current tax benefit of $3 million related to excess tax deductions resulting from vesting of restricted stock, interim period vesting of stock-settled PSSP awards and exercises of nonqualified stock options, which was recorded in common stock during 2006. Current tax benefit of $2 million related to excess tax deductions resulting from vesting of restricted stock and exercises of nonqualified stock options, which was recorded in common stock during 2005. Less than $1 million was recorded in common stock for excess tax deductions during 2004.

Through our subsidiaries, we are a majority owner in five entities and a minority owner in one entity that own facilities that produce synthetic fuels as defined under the Code. The production and sale of the synthetic fuels from these facilities qualifies for tax credits under Section 29/45K, if certain requirements are satisfied.

177

PEC

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

(in millions)	2006			2005
Deferred income tax assets:
Asset retirement obligation liability	$	132		$	131
Compensation accruals		47			46
Deferred revenue		28			55
Income taxes refundable through future rates		68			54
SFAS No. 158, postretirement and pension benefits		200			155
Other		37			49
Federal income tax credit carry forward		1			20
Total deferred income tax assets		513			510
Deferred income tax liabilities:
Accumulated depreciation and property cost differences		(930	)		(952	)
Deferred fuel recovery		(55	)		(67	)
Income taxes recoverable through future rates		(317	)		(129	)
Investments		(10	)		(61	)
Other		(27	)		(27	)
Total deferred income tax liabilities		(1,339	)		(1,236	)
Total net deferred income tax liabilities	$	(826	)	$	(726	)

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

(in millions)	2006			2005
Current deferred income tax assets, included in prepayments and other current assets	$	34		$	-
Current deferred income tax liabilities, included in other current liabilities		-			(4	)
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(860	)		(722	)
Total net deferred income tax liabilities	$	(826	)	$	(726	)

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, the federal income tax credit carry forward includes $1 million of general business credits that will expire during the period 2023 through 2025.

At December 31, 2006 and 2005, PEC had recorded $5 million and $2 million, respectively, of tax contingency reserves, excluding accrued interest and penalties, which were included in taxes accrued on the Consolidated Balance Sheets.

Considering all tax contingency reserves, PEC does not expect the resolution of these matters to have a material impact on its financial position or results of operations. The tax contingency reserves relate primarily to capitalization and basis issues.

178

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

	2006			2005			2004
Effective income tax rate		36.7	%		32.7	%		34.1	%
State income taxes, net of federal benefit		(2.3	)		(2.1	)		(2.9	)
Investment tax credit amortization		0.8			1.1			1.1
Domestic manufacturing deduction		0.6			0.7			-
Progress Energy tax benefit allocation		-			2.9			3.0
Other differences, net		(0.8	)		(0.3	)		(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)	2006			2005			2004
Current   - federal	$	285		$	343		$	232
- state		39			45			33
Deferred - federal		(42	)		(120	)		(18	)
- state		(11	)		(21	)		(1	)
Investment tax credit		(6	)		(8	)		(7	)
Total income tax expense	$	265		$	239		$	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 2006 or 2004.

·   Taxes related to other comprehensive income recorded net of tax for 2006, 2005 and 2004, which are presented separately in the Consolidated Statements of Comprehensive Income.

·   Current tax benefit of $1 million related to excess tax deductions resulting from vesting of restricted stock, interim period vesting of stock-settled PSSP awards and exercises of nonqualified stock options, which was recorded in common stock during 2006. Current tax benefit of $1 million related to excess tax deductions resulting from vesting of restricted stock and exercises of nonqualified stock options, which was recorded in common stock during 2005. Less than $1 million was recorded in common stock for excess tax deductions during 2004.

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 $51 million and $74 million at December 31, 2006 and 2005, respectively.

179

PEF

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

(in millions)	2006			2005
Deferred income tax assets
Asset retirement obligation liability	$	9		$	3
Derivative instruments		30			-
Environmental remediation liability		24			15
Income taxes refundable through future rates		95			123
SFAS No. 158, postretirement and pension benefits		150			85
Unbilled revenue		36			30
Other		61			53
Total deferred income tax assets		405			309
Deferred income tax liabilities
Accumulated depreciation and property cost differences		(429	)		(401	)
Deferred fuel recovery		(5	)		(21	)
Deferred storm costs		(45	)		(87	)
Derivative instruments		-			(45	)
Income taxes recoverable through future rates		(119	)		(28	)
Investments		(61	)		(45	)
Prepaid pension costs		(67	)		(61	)
Other		(33	)		(25	)
Total deferred income tax liabilities		(759	)		(713	)
Total net deferred income tax liabilities	$	(354	)	$	(404	)

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

(in millions)	2006			2005
Current deferred income tax assets	$	86		$	12
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(440	)		(416	)
Total net deferred income tax liabilities	$	(354	)	$	(404	)

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, excluding accrued interest and penalties, which were included in other current liabilities on the Balance Sheets.

Considering all tax contingency reserves, PEF does not expect the resolution of these matters to have a material impact on its financial position or results of operations. The tax contingency reserves relate primarily to capitalization and basis issues.

180

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

	2006			2005			2004
Effective income tax rate		37.0	%		31.8	%		34.2	%
State income taxes, net of federal benefit		(3.6	)		(3.3	)		(3.5	)
Investment tax credit amortization		1.2			1.4			1.2
Domestic manufacturing deduction		0.3			0.9			-
Progress Energy tax allocation benefit		-			3.2			2.5
Other differences, net		0.1			1.0			0.6
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)	2006			2005			2004
Current - federal	$	207		$	146		$	55
- state		34			25			9
Deferred - federal		(36	)		(39	)		98
- state		(6	)		(6	)		18
Investment tax credit		(6	)		(5	)		(6	)
Total income tax expense	$	193		$	121		$	174

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 2006 or 2004.

·   Taxes related to other comprehensive income recorded net of tax for 2006, 2005 and 2004, which are presented separately in the Statements of Comprehensive Income.

·   Less than $1 million of current tax benefit related to excess tax deductions resulting from vesting of restricted stock and exercises of nonqualified stock options, which was recorded in common stock during 2006, 2005 and 2004.

PEF has entered into the Tax Agreement with Progress Energy (See Note 1D). PEF’s intercompany tax receivable was approximately $47 million at December 31, 2006. PEF’s intercompany tax payable was approximately $7 million at December 31, 2005.

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 synthetic fuels facilities purchased by subsidiaries of Florida Progress in October 1999. The payments, if any, would be based on the net after-tax cash flows the facilities generate. The CVO liability is adjusted to reflect market price fluctuations. The unrealized loss/gain recognized due to these market fluctuations is recorded in other, net on the Consolidated Statements of Income (See Note 20). The liability, included in other liabilities and deferred credits on the Consolidated Balance Sheets, at December 31, 2006 and 2005, was $32 million and $7 million, respectively.

181

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.

See Note 2 for information related to the implementation of SFAS No. 158 as of December 31, 2006.

COSTS OF BENEFIT PLANS

Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

To determine the market-related value of assets, we use a five-year averaging method for a portion of the pension assets and fair value for the remaining portion. We have historically used the five-year averaging method. When we acquired Florida Progress in 2000, we retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets.

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

Progress Energy

	Pension Benefits									Other Postretirement Benefits
(in millions)	2006			2005			2004			2006			2005			2004
Service cost	$	45		$	47		$	54		$	9		$	9		$	12
Interest cost		117			117			110			33			33			31
Expected return on plan assets		(148	)		(147	)		(155	)		(6	)		(5	)		(5	)
Amortization of actuarial loss(a)		18			21			6			4			6			4
Other amortization, net (a)		-			-			(1	)		5			5			3
Net periodic cost	$	32		$	38		$	14		$	45		$	48		$	45

(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.

No amounts related to our OPEB plans were recognized as a component of other comprehensive income (OCI) for the years ended December 31, 2006, 2005 and 2004. Pre-tax amounts related to our pension plans recognized as a component of OCI for the years ended December 31, 2006, 2005 and 2004 were net actuarial gains (losses) of $78 million, $(41) million and $(202) million, respectively.

182

PEC

	Pension Benefits									Other Postretirement Benefits
(in millions)	2006			2005			2004			2006			2005			2004
Service cost	$	22		$	22		$	24		$	4		$	4		$	6
Interest cost		52			53			52			17			17			15
Expected return on plan assets		(59	)		(62	)		(69	)		(4	)		(4	)		(4	)
Amortization of actuarial loss		11			10			1			2			5			2
Other amortization, net		1			1			-			1			1			1
Net periodic cost	$	27		$	24		$	8		$	20		$	23		$	20

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 plan were recognized as a component of OCI for the years ended December 31, 2006, 2005 and 2004. Pre-tax amounts related to PEC’s pension plans recognized as a component of OCI for the years ended December 31, 2006, 2005 and 2004, were net actuarial gains (losses) of $59 million, $(19) million and $(174) million, respectively.

PEF

	Pension Benefits									Other Postretirement Benefits
(in millions)	2006			2005			2004			2006			2005			2004
Service cost	$	16		$	16		$	21		$	3		$	3		$	4
Interest cost		49			48			43			14			13			13
Expected return on plan assets		(78	)		(73	)		(73	)		(1	)		(1	)		(1	)
Amortization of actuarial loss		3			8			2			1			2			1
Other amortization, net		(1	)		(1	)		(1	)		4			4			4
Net periodic (benefit) cost	$	(11	)	$	(2	)	$	(8	)	$	21		$	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 plans were recognized as a component of OCI for the years ended December 31, 2006, 2005 and 2004. No amounts related to PEF’s pension plans were recognized as a component of OCI for the years ended December 31, 2006 and 2005. For the year ended December 31, 2004, a pre-tax net actuarial gain of $6 million was recognized as a component of OCI.

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

	Pension Benefits									Other Postretirement Benefits
	2006			2005			2004			2006			2005			2004
Discount rate		5.65	%		5.70	%		6.30	%		5.65	%		5.70	%		6.30	%
Rate of increase in future compensation
Bargaining		3.50	%		3.50	%		3.50	%		-			-			-
Supplementary plans		5.25	%		5.25	%		5.00	%		-			-			-
Expected long-term rate of return on
plan assets		9.00	%		9.00	%		9.25	%		8.30	%		8.25	%		8.50	%

183

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 PEF’s OPEB plan assets was 5.0% 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 have chosen to use an expected long-term rate of 9.0%, the low end of the range, beginning in 2005.

BENEFIT OBLIGATIONS AND ACCRUED COSTS

Reconciliations of the changes in the Progress Registrants’ benefit obligations and the funded status as of December 31, 2006 and 2005 are presented in the tables below, with each table followed by related supplementary information.

Progress Energy

	Pension Benefits						Other Postretirement Benefits
(in millions)	2006			2005			2006			2005
Projected benefit obligation at January 1	$	2,164		$	1,961		$	650		$	538
Service cost		45			47			9			9
Interest cost		117			117			33			33
Benefit payments		(174	)		(182	)		(29	)		(33	)
Plan amendment		18			-			(4	)		-
Special termination benefits		-			123			-			19
Actuarial (gain) loss		(47	)		98			(31	)		84
Obligation at December 31		2,123			2,164			628			650
Fair value of plan assets at December 31		1,836			1,770			74			76
Funded status	$	(287	)	$	(394	)	$	(554	)	$	(574	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $2.123 billion and $2.164 billion at December 31, 2006 and 2005, respectively. Those plans had accumulated benefit obligations totaling $2.083 billion and $2.117 billion at December 31, 2006 and 2005, respectively, and plan assets of $1.836 billion and $1.770 billion at December 31, 2006 and 2005, respectively.

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

	Pension Benefits				Other Postretirement Benefits
(in millions)	2006		2005		2006		2005
Current liabilities	$	14	$	-	$	1	$	-
Noncurrent liabilities		273		347		553		390

184

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)	2006		2005		2006		2005
Recognized in accumulated other comprehensive loss
Net actuarial loss	$	49	$	260	$	7	$	-
Other, net		5		-		1		-
Recognized in regulatory assets, net
Net actuarial loss (gain)		215		83		108		(19	)
Other, net		22		-		28		24
Recognized as an intangible asset
Prior service cost		-		23		-		-
Not recognized in the Consolidated Balance Sheets
Net actuarial loss		-		47		-		170
Other, net		-		-		-		14
Total not yet recognized as a component of net periodic cost(a)	$	291	$	413	$	144	$	189

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

The following table presents the amounts we expect to recognize as components of net periodic cost in 2007.

(in millions)	Pension Benefits		Other Postretirement Benefits
Amortization of actuarial loss (a)	$	15	$	6
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)	2006			2005			2006			2005
Projected benefit obligation at January 1	$	969		$	928		$	333		$	262
Service cost		22			22			4			4
Interest cost		52			53			17			17
Plan amendment		9			-			-			-
Benefit payments		(83	)		(94	)		(11	)		(14	)
Actuarial (gain) loss		(17	)		39			(13	)		56
Special termination benefits		-			21			-			8
Obligation at December 31		952			969			330			333
Fair value of plan assets at December 31		741			731			45			49
Funded status	$	(211	)	$	(238	)	$	(285	)	$	(284	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $952 million and $969 million at December 31, 2006 and 2005, respectively. Those plans had accumulated benefit obligations totaling $946 million and $963 million at December 31, 2006 and 2005, respectively, and plan assets of $741 million and $731 million at December 31, 2006 and 2005, respectively.

185

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

	Pension Benefits				Other Postretirement Benefits
(in millions)	2006		2005		2006		2005
Current liabilities	$	2	$	-	$	-	$	-
Noncurrent liabilities		209		232		285		189

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)	2006		2005		2006		2005
Recognized in accumulated other comprehensive loss
Net actuarial loss	$	-	$	195	$	-	$	-
Recognized as an intangible asset
Prior service cost		-		17		-		-
Recognized in regulatory assets
Net actuarial loss		142		-		69		-
Other, net		25		-		7		-
Not recognized in the Consolidated Balance Sheets
Net actuarial loss		-		6		-		87
Other, net		-		-		-		8
Total not yet recognized as a component of net periodic cost	$	167	$	218	$	76	$	95

The following table presents the amounts PEC expects to recognize as components of net periodic cost in 2007.

(in millions)	Pension Benefits		Other Postretirement Benefits
Amortization of actuarial loss	$	11	$	4
Amortization of other, net		2		1

PEF

	Pension Benefits						Other Postretirement Benefits
(in millions)	2006			2005			2006			2005
Projected benefit obligation at January 1	$	896		$	767		$	259		$	232
Service cost		16			16			3			3
Interest cost		49			48			14			13
Plan amendment		8			-			(4	)		-
Benefit payments		(69	)		(61	)		(17	)		(18	)
Special termination benefits		-			85			-			7
Actuarial (gain) loss		(20	)		41			(9	)		22
Obligation at December 31		880			896			246			259
Fair value of plan assets at December 31		952			895			24			22
Funded status	$	72		$	(1	)	$	(222	)	$	(237	)

The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $342 million and $341 million at December 31, 2006 and 2005, respectively. Those plans had accumulated benefit obligations totaling $311 million and $306 million at December 31, 2006 and 2005,

186

respectively, and plan assets of $240 million and $217 million at December 31, 2006 and 2005, respectively. The total accumulated benefit obligation for pension plans was $849 million and $860 million at December 31, 2006 and 2005, respectively.

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

	Pension Benefits				Other Postretirement Benefits
(in millions)	2006		2005		2006		2005
Noncurrent assets	$	174	$	200	$	-	$	-
Current liabilities		3		-		-		-
Noncurrent liabilities		99		89		222		159

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)	2006			2005			2006		2005
Recognized as an intangible asset
Prior service cost	$	-		$	1		$	-	$	-
Recognized in regulatory assets, net
Net actuarial loss		72			7			39		-
Other, net		(2	)		-			21		-
Not recognized in the Balance Sheets
Net actuarial loss		-			125			-		49
Other, net		-			(13	)		-		29
Total not yet recognized as a component of net periodic cost	$	70		$	120		$	60	$	78

The following table presents the amounts PEF expects to recognize as components of net periodic cost in 2007.

(in millions)	Pension Benefits			Other Postretirement Benefits
Amortization of actuarial loss	$	1		$	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
	2006			2005			2006			2005
Discount rate		5.95	%		5.65	%		5.95	%		5.65	%
Rate of increase in future compensation
Bargaining		4.25	%		3.50	%		-			-
Supplementary plans		5.25	%		5.25	%		-			-
Initial medical cost trend rate for pre-Medicare Act benefits		-			-			9.00	%		8.25	%
Initial medical cost trend rate for post-Medicare Act benefits		-			-			9.00	%		8.25	%
Ultimate medical cost trend rate		-			-			5.00	%		5.00	%
Year ultimate medical cost trend rate is achieved		-			-			2014			2013

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.

187

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		29			15			11
1 percent decrease in medical cost trend rate
Effect on total of service and interest cost		(1	)		(1	)		(1	)
Effect on postretirement benefit obligation		(22	)		(12	)		(9	)

ASSETS OF BENEFIT PLANS

In the plan asset reconciliation tables that follow, substantially all employer contributions represent benefit payments made directly from the Progress Registrants’ assets. The OPEB benefit payments presented in the plan asset reconciliation tables that follow represent the cost after participant contributions. Participant contributions represent approximately 20 percent of gross benefit payments for Progress Energy, 30 percent for PEC and 10 percent for PEF. The OPEB benefits payments for 2006 are also reduced by prescription drug-related federal subsidies received, which 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)	2006			2005			2006			2005
Fair value of plan assets at January 1	$	1,770		$	1,774		$	76		$	70
Actual return on plan assets		222			170			8			5
Benefit payments		(174	)		(182	)		(29	)		(33	)
Employer contributions		18			8			19			34
Fair value of plan assets at December 31	$	1,836		$	1,770		$	74		$	76
PEC	Pension Benefits						Other Postretirement Benefits
(in millions)		2006			2005			2006			2005
Fair value of plan assets at January 1	$	731		$	753		$	49		$	45
Actual return on plan assets		91			71			6			4
Benefit payments		(83	)		(94	)		(11	)		(14	)
Employer contributions		2			1			1			14
Fair value of plan assets at December 31	$	741		$	731		$	45		$	49

188

PEF	Pension Benefits						Other Postretirement Benefits
(in millions)	2006			2005			2006			2005
Fair value of plan assets at January 1	$	895		$	868		$	22		$	20
Actual return on plan assets		114			85			1			-
Benefit payments		(69	)		(61	)		(17	)		(18	)
Employer contributions		12			3			18			20
Fair value of plan assets at December 31	$	952		$	895		$	24		$	22

The asset allocation for the benefit plans at the end of 2006 and 2005 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	2007			2006			2005
Equity - domestic		40	%		44	%		44	%
Equity - international		15	%		23	%		22	%
Debt - domestic		20	%		12	%		13	%
Debt - international		10	%		9	%		8	%
Other		15	%		12	%		13	%
Total		100	%		100	%		100	%

   

	Other Postretirement Benefits
Progress Energy	Target Allocations			Percentage of Plan Assets at Year End
Asset Category	2007			2006			2005
Equity - domestic		27	%		30	%		32	%
Equity - international		10	%		15	%		16	%
Debt - domestic		46	%		40	%		37	%
Debt - international		7	%		7	%		6	%
Other		10	%		8	%		9	%
Total		100	%		100	%		100	%

PEC	Target Allocations			Percentage of Plan Assets at Year End
Asset Category	2007			2006			2005
Equity - domestic		40	%		44	%		44	%
Equity - international		15	%		23	%		22	%
Debt - domestic		20	%		12	%		13	%
Debt - international		10	%		9	%		8	%
Other		15	%		12	%		13	%
Total		100	%		100	%		100	%

PEF	Target Allocations			Percentage of Plan Assets at Year End
Asset Category		2007			2006		2005
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

189

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 five 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 2007, we expect to make $60 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 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $143, $147, $151, $154, $154 and $838, respectively. The expected benefit payments for the OPEB plan for 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $41, $45, $48, $51, $53 and $284, 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 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $3, $4, $4, $5, $5 and $38, respectively.

In 2007, PEC expects to make $35 million in contributions directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $69, $72, $74, $76, $75 and $399, respectively. The expected benefit payments for the OPEB plan for 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $19, $21, $23, $25, $27, and $148, 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 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $1, $2, $2, $2, $3 and $19, respectively.

In 2007, PEF expects to make $10 million of contributions directly to pension plan assets and $1 million of discretionary contributions to OPEB plan assets. The expected benefit payments for the pension benefit plan for 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $56, $56, $57, $57, $59 and $316, respectively. The expected benefit payments for the OPEB plan for 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $19, $20, $21, $22, $22 and $113, 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 2007 through 2011 and in total for 2012 through 2016, in millions, are approximately $2, $2, $2, $2, $2 and $16, 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.

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

190

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 3, on December 13, 2006, our board of directors approved a plan to pursue the disposition of substantially all of PVI’s remaining CCO physical and commercial assets and on July 12, 2006, our board of directors approved a plan to divest of Gas. The transaction to sell Gas closed on October 2, 2006. We expect to complete the disposition plan for CCO in 2007.

Due to the reclassification of the remaining CCO operations to discontinued operations in December 2006, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts covering approximately 95 Bcf of natural gas would be fulfilled. Therefore, these contracts were no longer treated as cash flow hedges, and were dedesignated and cash flow hedge accounting was discontinued.

At December 31, 2006, derivative assets and derivative liabilities related to CCO are included in assets of discontinued operations and liabilities of discontinued operations, respectively, on the Consolidated Balance Sheet. At December 31, 2005, derivative assets and derivative liabilities related to Gas and CCO are included in assets of discontinued operations and liabilities of discontinued operations, respectively, on the Consolidated Balance Sheet. For the years ending December 31, 2006, 2005 and 2004, 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 ending 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 ending December 31, 2005, there were no reclassifications to earnings due to discontinuance of the related cash flow hedges. For the year ending December 31, 2004, discontinued operations, net of tax includes $10 million in after-tax deferred losses, which were reclassified to earnings due to discontinuance of the related cash flow hedges.

A. Commodity Derivatives

GENERAL

Most of our 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, 2006 and 2005, the remaining liability was $14 million and $19 million, respectively.

ECONOMIC DERIVATIVES

Derivative products, primarily electricity and natural gas 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. Gains and losses from such contracts were not material to our or the Utilities’ results of operations during the years ended December 31, 2006, 2005 and 2004. Excluding $107 million of derivative assets, which are included in assets of discontinued operations on the Consolidated Balance Sheet and $31 million of derivative liabilities, which are included in liabilities of discontinued operations on the Consolidated Balance Sheet at December 31, 2006, we did not have material outstanding positions in such contracts at December 31, 2006 and 2005, other than those receiving regulatory accounting treatment at PEF, as discussed below. Our discontinued operations did not have material outstanding positions in such contracts at December 31, 2005.

191

PEC did not have material outstanding positions in such contracts at December 31, 2006 and 2005. PEF did not have material outstanding positions in such contracts at December 31, 2006 and 2005, other than those receiving regulatory accounting treatment, as discussed below.

PEF has derivative instruments related to its 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. Once settled, any realized gains or losses are passed through the fuel clause. At December 31, 2006, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits, an $87 million short-term derivative liability position included in other current liabilities and a $36 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheet. At December 31, 2005, the fair values of the instruments were a $77 million short-term derivative asset position included in other current assets, a $45 million long-term derivative asset position included in other assets and deferred debits and a $49 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheet.

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 is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts will be marked-to-market with changes in fair value recorded through earnings from synthetic fuels production.

CASH FLOW HEDGES

Our subsidiaries designate 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 natural gas and power for our forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for 2006, 2005 and 2004.

The fair values of commodity cash flow hedges at December 31 were as follows:

	Progress Energy					PEC					PEF
(in millions)	2006		2005			2006		2005			2006		2005
Fair value of assets	$	2	$	7		$	2	$	7		$	-	$	-
Fair value of liabilities		-		(4	)		-		(4	)		-		-
Fair value, net	$	2	$	3		$	2	$	3		$	-	$	-

Our discontinued operations did not have material outstanding positions in commodity cash flow hedges at December 31, 2006. Excluded from the table above are $163 million of derivative assets, which are included in assets of discontinued operations, and $54 million of derivative liabilities, which are included in liabilities of discontinued operations on the Consolidated Balance Sheet at December 31, 2005.

At December 31, 2006, the amount recorded in our, PEC’s or PEF’s AOCI related to commodity cash flow hedges was not material. At December 31, 2005, we had $69 million of after-tax deferred income and PEC had $2 million of after-tax deferred income recorded in AOCI related to commodity cash flow hedges. PEF had no amount recorded in AOCI related to commodity cash flow hedges at December 31, 2006 or 2005.

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

192

event of default by the counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

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 53.0 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.

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

	Progress Energy						PEC					PEF
(in millions)	2006			2005			2006			2005		2006			2005
Interest rate cash flow hedges	$	(2	)	$	1		$	(1	)	$	-	$	(1	)	$	-
Interest rate fair value hedges		(1	)		(2	)		-			-		-			-

CASH FLOW HEDGES

Gains and losses from cash flow hedges are recorded in AOCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in AOCI 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 2006, 2005 and 2004.

The following table presents selected information related to interest rate cash flow hedges included in AOCI at December 31, 2006:

	Maximum Term						Accumulated Other Comprehensive Loss, net of Tax(a)									Portion Expected to be Reclassified to Earnings during the Next 12 Months(b)
(term in years/ dollars in millions)	Progress Energy		PEC		PEF		Progress Energy			PEC			PEF			Progress Energy			PEC			PEF
Interest rate cash flow hedges		1		1		1	$	(14	)	$	(5	)	$	(1	)	$	(2	)	$	(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.

PEC entered into a $50 million forward starting swap on June 2, 2006, and PEF entered into a $50 million forward starting swap on June 6, 2006, to mitigate exposure to interest rate risk on their respective anticipated debt issuances in 2007. These swaps were designated as cash flow hedges as of July 1, 2006.

At December 31, 2005, including amounts related to terminated hedges, we had $13 million of after-tax deferred losses and PEC had $5 million of after-tax deferred losses recorded in AOCI related to interest rate cash flow hedges. PEF had no amount recorded in AOCI related to interest rate cash flow hedges.

At December 31, 2005, we had $100 million notional of interest rate cash flow hedges, which were settled in the first quarter of 2006. The Utilities had no open interest rate cash flow hedges at December 31, 2005.

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, 2006 and 2005, we had

193

$50 million notional and $150 million notional, respectively, of interest rate fair value hedges. At December 31, 2006 and 2005, 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, tolling 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, 2006, the Parent had issued $1.34 billion 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 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 2006, 2005 and 2004 to PEC amounted to $188 million, $202 million and $209 million, respectively, and services provided to PEF were $165 million, $169 million and $165 million, respectively.

PEC and PEF also provide and receive services at cost. Services provided by PEC to PEF during 2006, 2005 and 2004 amounted to $34 million, $54 million and $52 million, respectively. Services provided by PEF to PEC during 2006, 2005 and 2004 amounted to $8 million, $14 million and $16 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 5.17%, 3.77% and 1.72% at December 31, 2006, 2005 and 2004, 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 2006 andfor an insignificant profit in 2005 and 2004. 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 $321 million, $402 million and $331 million for the years ended December 31, 2006, 2005 and 2004, 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).

194

19.   FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are: PEC, PEF, and Coal and Synthetic Fuels.

Our 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.

Our Coal and Synthetic Fuels segment is 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. On May 22, 2006, we idled our synthetic fuels facilities due to significant uncertainty surrounding synthetic fuels production. During September and October 2006, we resumed limited synthetic fuels production at our facilities, which continued through the end of 2006. See Notes 8 and 9 for additional information.

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and PESC as well as other nonregulated businesses. These nonregulated businesses do not separately meet the disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” Included in the 2004 losses is a $43 million pre-tax ($29 million after-tax) settlement agreement that our subsidiary Strategic Resource Solutions Corp. reached with the San Francisco United School District related to civil proceedings. The profit or loss of our reportable segments plus the profit or loss of Corporate and Other represents our total income from continuing operations.

As discussed in Note 3, prior to 2006, our former Progress Ventures segment was engaged in nonregulated electric generation and energy marketing activities and natural gas drilling and production. Also, prior to 2006, PT LLC was included within the Corporate and Other segment, and Dixie Fuels and other fuels business were included within the Coal and Synthetic Fuels segment. In connection with their respective divestitures, certain of which are expected to close in 2007, these operations were reclassified to discontinued operations in 2006 and therefore are not included in the results from continuing operations during the periods reported. 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.

Products and services are sold between the various reportable segments. All intersegment transactions are at cost except for transactions between PEF and the 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 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 2006, 2005 and 2004 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 of discontinued operations are not included in the table presented below.

195

(in millions)	PEC		PEF		Coal and Synthetic Fuels			Corporate and Other			Eliminations			Totals
As of and for the year ended December 31, 2006
Revenues
Unaffiliated	$	4,086	$	4,639	$	845		$	-		$	-		$	9,570
Intersegment		-		-		321			408			(729	)		-
Total revenues		4,086		4,639		1,166			408			(729	)		9,570
Depreciation and amortization		571		404		19			38			-			1,032
Interest income		25		15		2			85			(66	)		61
Total interest charges, net		215		150		15			312			(67	)		625
Impairment of long-lived assets and investments		-		-		91			-			-			91
Income tax expense (benefit)		265		193		(145	)		(109	)		-			204
Segment profit (loss)		454		326		(76	)		(190	)		-			514
Total assets		12,020		8,593		268			15,204			(11,271	)		24,814
Capital and investment expenditures		808		741		3			12			(9	)		1,555

As of and for the year ended December 31, 2005
Revenues
Unaffiliated	$	3,991	$	3,955	$	1,222		$	-		$	-		$	9,168
Intersegment		-		-		402			437			(839	)		-
Total revenues		3,991		3,955		1,624			437			(839	)		9,168
Depreciation and amortization		561		334		34			34			-			963
Interest income		8		1		3			94			(90	)		16
Total interest charges, net		192		126		23			318			(85	)		574
Postretirement and severance charges		55		102		5			1			-			163
Income tax expense (benefit)		239		121		(354	)		(43	)		-			(37	)
Segment profit (loss)		490		258		163			(190	)		-			721
Total assets		11,502		8,318		450			17,898			(13,672	)		24,496
Capital and investment expenditures		682		543		5			19			(19	)		1,230

196

(in millions)	PEC		PEF		Coal and Synthetic Fuels			Corporate and Other			Eliminations			Totals
As of and for the year ended December 31, 2004
Revenues
Unaffiliated	$	3,629	$	3,525	$	886		$	13		$	-		$	8,053
Intersegment		-		-		333			430			(763	)		-
Total revenues		3,629		3,525		1,219			443			(763	)		8,053
Depreciation and amortization		570		281		34			34			-			919
Interest income		4		-		6			90			(89	)		11
Total interest charges, net		192		114		23			322			(85	)		566
Postretirement and severance charges		2		-		1			-			-			3
Income tax expense (benefit)		239		174		(280	)		(66	)		-			67
Segment profit (loss)		458		333		90			(208	)		-			673
Total assets		10,787		7,924		540			17,465			(13,550	)		23,166
Capital and investment expenditures		620		492		6			20			(12	)		1,126

20.OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income, impairment of investments, 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:

197

Progress Energy

(in millions)	2006			2005			2004
Other income
Nonregulated energy and delivery services income	$	41		$	32		$	28
DIG Issue C20 amortization (Note 17A)		5			7			9
Contingent value obligation unrealized gain (Note 15)		-			6			9
Gain on sale of Level 3 stock (a)		32			-			-
Investment gains		4			4			2
Income from equity investments		1			1			3
AFUDC equity		21			16			12
Reversal of indemnification liability (Note 21B)		29			-			-
Other		16			16			14
Total other income		149			82			77
Other expense
Nonregulated energy and delivery services expenses		27			23			21
Donations		20			18			15
Contingent value obligation unrealized loss (Note 15)		25			-			-
Loss from equity investments		8			13			8
Loss on debt redemption(b)		59			-			-
FERC audit settlement		-			7			-
Indemnification liability (Note 21B)		13			16			-
Other		15			12			29
Total other expense		167			89			73
Other, net - Progress Energy	$	(18	)	$	(7	)	$	4

PEC

(in millions)	2006		2005			2004
Other income
Nonregulated energy and delivery services income	$	15	$	12		$	11
DIG Issue C20 amortization (Note 17A)		5		7			9
Income from equity investments		-		1			3
AFUDC equity		4		3			4
Reversal of indemnification liability (Note 21B)		29		-			-
Other		10		9			13
Total other income		63		32			40
Other expense
Nonregulated energy and delivery services expenses		7		9			9
Donations		10		8			7
Losses from equity investments		1		-			3
FERC audit settlement		-		4			-
Indemnification liability (Note 21B)		13		16			-
Other		7		10			22
Total other expense		38		47			41
Other, net - PEC	$	25	$	(15	)	$	(1	)

198

PEF

(in millions)	2006		2005		2004
Other income
Nonregulated energy and delivery services income	$	26	$	20	$	17
Investment gains		2		2		1
AFUDC equity		17		13		7
Other		1		-		-
Total other income		46		35		25
Other expense
Nonregulated energy and delivery services expenses		20		14		12
Donations		10		10		9
Losses from equity investments		1		-		-
FERC audit settlement		-		3		-
Other		2		1		1
Total other expense		33		28		22
Other, net - PEF	$	13	$	7	$	3

^(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 3D). 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 53.0 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.

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 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 or the state of Florida, 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 potentially responsible parties (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 potential 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

199

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)	2006		2005
PEC
MGP and other sites(a)	$	22	$	7
PEF
Remediation of distribution and substation transformers		43		20
MGP and other sites		18		18
Total PEF environmental remediation accruals(b)		61		38
Progress Energy nonregulated operations		3		3
Total Progress Energy environmental remediation accruals	$	86	$	48

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

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

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 and 2005, the remaining accrual balance was approximately $3 million. Expenditures related to this liability were not material during 2006 and 2005.

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, 2006, including the Ward Transformer site and MGP sites discussed below, PEC accrued approximately $21 million and spent approximately $6 million. For the year ended December 31, 2005, PEC accrued approximately $4 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 (See Note 7B).

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 $32 million. In May 2006, a meeting was called by the EPA to discuss a settlement proposal among the PRPs. An agreement among PRPs has not been reached; consequently, it is not possible at this time to

200

reasonably estimate the amount of PEC’s share of the reimbursement for remediation of the Carolina Transformer site. The outcome of this matter cannot be predicted.

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 EPA’s past expenditures in addressing conditions at the site. In September 2005, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the site. For the year ended December 31, 2005, PEC accrued approximately $3 million for its portion of the EPA’s estimated remediation costs and the EPA's past costs. 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. 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.

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. However, 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.

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 years ended December 31, 2006 and 2005, PEF accrued approximately $42 million and $2 million, respectively, due to additional sites expected to require remediation and spent approximately $19 million and $9 million, respectively, related to the remediation of transformers. At December 31, 2006, 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, 2006, PEF made no accruals and PEF’s expenditures and insurance proceeds were not material to our or PEF’s results of operations or financial condition. For the year ended December 31, 2005, PEF made no material accruals, spent approximately $1 million and received approximately $1 million of additional insurance proceeds.

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 Mercury Rule (CAMR), the Clean Air Visibility Rule (CAVR), the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) and the Clean Smokestacks Act. At December 31, 2006, cumulative capital expenditures to date to comply with these environmental laws and regulations were $937 million, including $909 million and $28 million at PEC and PEF, respectively.

In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxide (NOx) and SO₂ from their North Carolina coal-fired power plants in phases

by 2013. The Clean Smokestacks Act requires PEC to amortize $569 million, representing 70 percent of the original cost estimate of $813 million, during the five-year period ending December 31, 2007. The Clean Smokestacks Act permits PEC the flexibility to vary the amortization schedule for recording of the compliance costs from none up to $174 million per year. For the years ended December 31, 2006, 2005 and 2004, PEC recognized amortization of $140 million, $147 million and $174 million, respectively, and has recognized $535 million in cumulative amortization through December 31, 2006. The remaining amortization requirement of $34 million will be recorded during the one-year period ending December 31, 2007. The NCUC will hold a hearing prior to December 31, 2007, to determine cost-recovery amounts for 2008 and 2009.

Two of PEC’s largest coal-fired generation plants (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 on 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, 2006, the amount of the liability was $29 million and had increased from $16 million at December 31, 2005, based upon the respective current estimates for Clean Smokestacks Act compliance. Because PEC has taken a systemwide compliance approach, its North Carolina retail customers 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 customers, consistent with other capital expenditures associated with PEC’s compliance with the Clean Smokestacks Act. On November 2, 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 subsequently reclassified $29 million of indemnification expense to Clean Smokestacks Act amortization (See Note 20).

22.COMMITMENTS AND CONTINGENCIES

A.    Purchase Obligations

At December 31, 2006, the following table reflects contractual cash obligations and other commercial commitments in the respective periods in which they are due:

Progress Energy

(in millions)	2007		2008		2009		2010		2011		Thereafter
Fuel	$	2,128	$	1,514	$	1,057	$	509	$	390	$	1,251
Purchased power		485		454		422		377		381		4,165
Construction obligations		393		197		8		3		-		-
Other purchase obligations		86		71		23		22		15		74
Total	$	3,092	$	2,236	$	1,510	$	911	$	786	$	5,490

PEC

(in millions)	2007		2008		2009		2010		2011		Thereafter
Fuel	$	1,008	$	759	$	547	$	314	$	231	$	647
Purchased power		129		87		85		43		44		464
Construction obligations		99		9		-		-		-		-
Other purchase obligations		21		22		3		3		3		12
Total	$	1,257	$	877	$	635	$	360	$	278	$	1,123

202

PEF

(in millions)	2007		2008		2009		2010		2011		Thereafter
Fuel	$	931	$	682	$	511	$	194	$	160	$	605
Purchased power		356		366		336		334		337		3,701
Construction obligations		294		188		8		3		-		-
Other purchase obligations		46		46		20		19		12		62
Total	$	1,627	$	1,282	$	875	$	550	$	509	$	4,368

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 $3.168 billion, $3.071 billion and $2.033 billion for 2006, 2005 and 2004, respectively. PEC’s total payments under these commitments for its generating plants were $1.051 billion, $964 million and $477 million in 2006, 2005 and 2004, respectively. PEF’s payments totaled $577 million, $506 million and $375 million in 2006, 2005 and 2004, respectively.

Both PEC and PEF have ongoing purchased power contracts with certain cogenerators (primarily QFs) with expiration dates ranging from 2007 to 2033. These purchased power contracts generally provide for capacity and energy payments.

Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between PEC and Power Agency, PEC is obligated to purchase a percentage of Power Agency’s ownership capacity of, and energy from, Harris. In 1993, PEC and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly owned units. Under the terms of the 1993 agreement, PEC increased the amount of capacity and energy purchased from Power Agency’s ownership interest in Harris, and the buyback period was extended six years through 2007. The estimated minimum annual payments for these purchases, which reflect capacity and energy costs, total approximately $34 million. These contractual purchases totaled $38 million, $37 million and $39 million for 2006, 2005 and 2004, respectively.

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 $80 million, $71 million and $62 million for 2006, 2005 and 2004, respectively.

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 $40 million, $44 million and $42 million in 2006, 2005 and 2004, respectively.

PEC has various pay-for-performance contracts with QFs for approximately 327 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 $182 million, $112 million and $90 million in 2006, 2005 and 2004, 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 $162 million, $175 million and $128 million for 2006, 2005 and 2004, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $65 million annually through 2009, $54 million for 2010 and $38 million annually thereafter through 2016.

203

PEF has ongoing purchased power contracts with certain QFs for 943 MW of capacity with expiration dates ranging from 2007 to 2033. 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 have been approved by the FPSC. Total capacity purchases under these contracts amounted to $277 million, $262 million and $247 million for 2006, 2005 and 2004, respectively. At December 31, 2006, minimum expected future capacity payments under these contracts were $289 million, $300 million, $271 million, $274 million and $288 million for 2007 through 2011, respectively, and $3.508 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.

On December 2, 2004, PEF entered into precedent and related agreements with Southern Natural Gas Company (SNG), Florida Gas Transmission Company (FGT), and BG LNG Services, LLC for the supply of natural gas and associated firm pipeline transportation to augment PEF’s gas supply needs for the period from May 1, 2007, to April 30, 2027. The total cost to PEF associated with the agreements is approximately $3.9 billion. The transactions are subject to several conditions precedent, some of which have been satisfied, which include obtaining the FPSC’s approval of the agreements, the completion and commencement of operation of the necessary related expansions to SNG’s and FGT’s respective natural gas pipeline systems, and other standard closing conditions. Due to the conditions in the agreements, the estimated costs associated with these agreements are not included in the contractual cash obligations table above.

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 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 $877 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 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 Florida Public Service Commission 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 May 31, 2013. The total cost to PEF associated with this agreement is approximately $128 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.

204

CONSTRUCTION OBLIGATIONS

We have purchase obligations related to various capital construction projects. Our total payments under these contracts were $365 million, $91 million and $108 million for 2006, 2005 and 2004, respectively. At December 31, 2006, PEC had construction obligations related to Clean Smokestacks Act capital projects of $99 million and $9 million for 2007 and 2008, respectively, and none thereafter. Total purchases by PEC under various capital projects related to Clean Smokestacks Act were $225 million for 2006 and purchases under various combustion turbine construction obligations were $5 million for 2004. PEC did not have any purchases related to construction obligations in 2005. PEF has purchase obligations related to various plant capital projects related to new generation and Florida CAIR. Total payments under PEF’s contracts were $140 million, $91 million and $102 million for 2006, 2005 and 2004, respectively. PEF’s future obligations under these contracts are $294 million, $188 million, $8 million and $3 million for 2007 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 $91 million, $82 million and $44 million for 2006, 2005 and 2004, 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 $18 million, $17 million and $15 million for 2006, 2005 and 2004, respectively. Estimated future payments under these contracts of $198 million are not reflected in the table presented at the beginning of this footnote. Included in these contracts are purchase obligations with two counterparties for pipeline capacity through 2018 and 2028. Payments under these agreements were $16 million, $15 million and $13 million for 2006, 2005 and 2004, respectively. Future obligations under these contracts are approximately $13 million for 2007, $12 million for 2008 through 2011 and approximately $76 million payable thereafter. We anticipate transferring the obligations under these contracts to a third party as part of our disposition strategy.

PEC has various purchase obligations for emission obligations, limestone supply and the purchase of capital parts. Total purchases under these contracts were $2 million, $10 million and $2 million for 2006, 2005 and 2004, respectively. Future obligations under these contracts are $21 million each for 2007 and 2008, $3 million each for 2009 through 2011 and $12 million thereafter.

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, $13 million for 2005 and $17 million for 2004. We do not have any future purchase obligations under these contracts.

PEF has long-term service agreements for the Hines Energy Complex. Total payments under these contracts were $12 million, $8 million and $11 million for 2006, 2005 and 2004, respectively. Future obligations under these contracts are $11 million, $16 million, $14 million, $19 million and $12 million for 2007 through 2011, respectively, with approximately $62 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 $21 million for 2006 and $34 million for 2005. There were no payments under these contracts during 2004. Future obligations under these contracts are $22 million, $8 million and $6 million for 2007 through 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 $42 million for 2006 and $38 million each for 2005 and 2004. Our purchased power expense under

205

agreements classified as operating leases was approximately $60 million, $14 million and $25 million in 2006, 2005 and 2004, respectively.

PEC’s rent expense under operating leases totaled $25 million for 2006, $24 million for 2005 and $20 million for 2004. These amounts include rent expense allocated from PESC of $8 million, $7 million and $10 million for 2006, 2005 and 2004, respectively. Purchased power expense under agreements classified as operating leases were approximately $10 million, $11 million and $25 million in 2006, 2005 and 2004, respectively.

PEF’s rent expense under operating leases totaled $16 million, $11 million and $14 million during 2006, 2005 and 2004, respectively. These amounts include rent expense allocated from PESC to PEF of $7 million each for 2006 and 2005 and $10 million for 2004. Purchased power expense under agreements classified as operating leases was approximately $49 million and $3 million in 2006 and 2005, respectively, and none in 2004.

Assets recorded under capital leases at December 31 consisted of:

	Progress Energy						PEC						PEF
(in millions)	2006			2005			2006			2005			2006		2005
Buildings	$	84		$	30		$	30		$	30		$	54	$	-
Less: Accumulated amortization		(12	)		(12	)		(12	)		(12	)		-		-
Total	$	72		$	18		$	18		$	18		$	54	$	-

At December 31, 2006, 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
2007	$	6		$	79	$	2		$	36	$	4		$	39
2008		8			63		3			30		5			29
2009		7			55		2			30		5			22
2010		8			40		3			18		5			20
2011		7			19		2			13		5			4
Thereafter		91			172		12			142		79			26
Minimum annual payments		127		$	428		24		$	269		103		$	140
Less amount representing imputed
interest		(55	)				(6	)				(49	)
Present value of net minimum lease payments under capital leases	$	72				$	18				$	54

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 2005, PEF entered into an agreement for a new 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. Due to the conditions of the agreement, the capital lease will not be recorded on PEF’s Balance Sheet until 2007. Therefore this capital lease is not included in the table above. The agreement calls for annual payments of approximately $27 million from 2007 through 2024 for a total of approximately $460 million.

206

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 $9 million, $7 million, $6 million, $4 million and $2 million for 2007 through 2011, respectively. Rents received under these operating leases totaled $9 million, $8 million and $6 million for 2006, 2005 and 2004, respectively.

The Utilities are lessors of electric poles, streetlights and other facilities. PEC’s minimum rentals under noncancelable leases are $10 million for 2007 and none thereafter. PEC’s rents received are contingent upon usage and totaled $31 million each for 2006 and 2005 and $32 million for 2004. PEF’s rents received are based on a fixed minimum rental where price varies by type of equipment or contingent usage and totaled $72 million for 2006 and $63 million each for 2005 and 2004. PEF’s minimum rentals under noncancelable leases are not material for 2007 and thereafter.

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.” These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes (See Note 18). Our guarantees include performance obligations under power supply agreements, tolling 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, 2006, 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, 2006, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations. 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 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, 2006, the maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $208 million, including $32 million at PEF. At December 31, 2006 and 2005, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $60 million and $41 million, respectively. These amounts include $29 million and $16 million, respectively, for PEC at December 31, 2006 and 2005, and $8 million for PEF at December 31, 2006. PEF had no liabilities related to guarantees and indemnifications to third parties at December 31, 2005. 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).

207

D. Other Commitments and Contingencies

1. 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 or are expected to be presented in the trials or appeals that are currently scheduled to occur 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. Subsequently, the trial court continued the stay until March 17, 2006. The trial court lifted the stay on March 22, 2006, and discovery has commenced. The trial court’s scheduling order, issued on March 23, 2006, included an anticipated trial date in late 2007.

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 EPA is expected to issue a new safety standard for the repository in early 2007. 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 has since reported that the license application will be submitted by June 2008. Congress approved $450 million for fiscal year 2006 for the Yucca Mountain project, approximately $201 million less than requested by the DOE. The DOE requested $545 million for fiscal year 2007. The request has not been approved at this time and the DOE is operating under a continuing resolution that limits spending to the level of fiscal year 2006.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 onsite 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.

208

2. 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 that (1) 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 and (2) it is entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities.

The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al., asserts the above claims in a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), 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. 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, 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 (the North Carolina Global Case). 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 during the course of the Internal Revenue Service (IRS) audit of the Earthco synthetic fuels facilities. The audit was successfully resolved in 2006 and the escrow, which totaled $42 million at December 31, 2006, was paid to Global in January 2007. The remainder of the suit continues. We cannot predict the outcome of this matter.

3. 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.

209

23.CONDENSED CONSOLIDATING STATEMENTS

Presented below are the condensed consolidating Statements of Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In September 2005, we issued our guarantee of certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are in addition to the previously issued guarantees of our wholly owned subsidiary, Florida Progress.

The Trust, a finance subsidiary, was established in 1999 for the sole purpose of issuing $300 million of 7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A (Preferred Securities) and using the proceeds thereof to purchase from Funding Corp. $300 million of 7.10% Junior Subordinated Deferrable Interest Notes due 2039 (Subordinated Notes). The Trust has no other operations and its sole assets are the Subordinated Notes and Notes Guarantee (as discussed below). Funding Corp. is a wholly owned subsidiary of Florida Progress and was formed for the sole purpose of providing financing to Florida Progress and its subsidiaries. Funding Corp. does not engage in business activities other than such financing and has no independent operations. Since 1999, Florida Progress has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes (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.

We have guaranteed the payment of all distributions related to the Trust's Preferred Securities. As of December 31, 2006, 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 the following tables, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the financial results of Florida Progress. The Other column includes the consolidated financial results of all other nonguarantor subsidiaries and elimination entries for all intercompany transactions. All applicable corporate expenses have been allocated appropriately among the guarantor and nonguarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other nonguarantor subsidiaries operated as independent entities. The accompanying condensed consolidating financial statements have been restated for all periods presented to reflect the operations of CCO, Gas, PT LLC, DeSoto, Rowan, Dixie Fuels and other fuels businesses as discontinued operations as described in Note 3.

210

Condensed Consolidating Statement of Income Year ended December 31, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	-		$	4,637		$	4,085		$	8,722
Diversified business		-			839			9			848
Total operating revenues		-			5,476			4,094			9,570
Operating expenses
Utility
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		-			404			605			1,009
Taxes other than on income		-			309			191			500
Other		-			(2	)		(1	)		(3	)
Diversified business
Cost of sales		-			854			44			898
Depreciation and amortization		-			13			10			23
Impairment of assets		-			44			47			91
Other		-			36			16			52
Total operating expenses		14			4,943			3,304			8,261
Operating (loss) income		(14	)		533			790			1,309
Other (expense) income, net		(33	)		55			21			43
Interest charges, net		276			184			165			625
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(323	)		404			646			727
Income tax (benefit) expense		(123	)		90			237			204
Equity in earnings of consolidated subsidiaries		779			-			(779	)		-
Minority interest in subsidiaries’ income, net of tax		-			(9	)		-			(9	)
Income (loss) from continuing operations		579			305			(370	)		514
Discontinued operations, net of tax		(8	)		392			(327	)		57
Net income (loss)	$	571		$	697		$	(697	)	$	571

211

Condensed Consolidating Statement of Income Year ended December 31, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	-		$	3,955		$	3,990		$	7,945
Diversified business		-			1,244			(21	)		1,223
Total operating revenues		-			5,199			3,969			9,168
Operating expenses
Utility
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		-			334			588			922
Taxes other than on income		4			279			177			460
Other		-			(26	)		(11	)		(37	)
Diversified business
Cost of sales		-			1,267			86			1,353
Depreciation and amortization		-			21			20			41
Other		-			19			13			32
Total operating expenses		16			4,763			3,169			7,948
Operating (loss) income		(16	)		436			800			1,220
Other income (expense), net		66			(5	)		(52	)		9
Interest charges, net		300			166			108			574
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(250	)		265			640			655
Income tax (benefit) expense		(63	)		(70	)		96			(37	)
Equity in earnings of consolidated subsidiaries		884			-			(884	)		-
Minority interest in subsidiaries’ loss, net of tax		-			29			-			29
Income (loss) from continuing operations		697			364			(340	)		721
Discontinued operations, net of tax		-			10			(35	)		(25	)
Cumulative effect of change in accounting principle, net of tax		-			-			1			1
Net income (loss)	$	697		$	374		$	(374	)	$	697

212

Condensed Consolidating Statement of Income Year ended December 31, 2004
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	-		$	3,525		$	3,628		$	7,153
Diversified business		-			895			5			900
Total operating revenues		-			4,420			3,633			8,053
Operating expenses
Utility
Fuel used in electric generation		-			1,175			836			2,011
Purchased power		-			567			301			868
Operation and maintenance		10			630			835			1,475
Depreciation and amortization		-			281			597			878
Taxes other than on income		(2	)		254			173			425
Other		-			(2	)		(11	)		(13	)
Diversified business
Cost of sales		-			911			81			992
Depreciation and amortization		-			21			20			41
Other		-			46			58			104
Total operating expenses		8			3,883			2,890			6,781
Operating (loss) income		(8	)		537			743			1,272
Other income (expense), net		65			(4	)		(46	)		15
Interest charges, net		295			152			119			566
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(238	)		381			578			721
Income tax (benefit) expense		(57	)		12			112			67
Equity in earnings of consolidated subsidiaries		940			-			(940	)		-
Minority interest in subsidiaries’ loss, net of tax		-			19			-			19
Income (loss) from continuing operations		759			388			(474	)		673
Discontinued operations, net of tax		-			86			-			86
Net income (loss)	$	759		$	474		$	(474	)	$	759

Condensed Consolidating Balance Sheet December 31, 2006
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
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 of discontinued operations		-		45		842			887
Other current assets		27		1,109		1,030			2,166
Total current assets		259		1,231		2,095			3,585
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		1,583		1,507			3,216
Total deferred debits and other assets		10,866		1,584		(5,579	)		6,871
Total assets	$	11,125	$	9,152	$	5,424		$	25,701
Capitalization
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 of discontinued operations		-		13		176			189
Other current liabilities		210		1,281		814			2,305
Total current liabilities		210		1,495		1,113			2,818
Deferred credits and other liabilities
Noncurrent income tax liabilities		-		61		245			306
Regulatory liabilities		-		1,091		1,452			2,543
Accrued pension and other benefits		14		377		566			957
Other liabilities and deferred credits		33		559		1,261			1,853
Total deferred credits and other liabilities		47		2,088		3,524			5,659
Total capitalization and liabilities	$	11,125	$	9,152	$	5,424		$	25,701

214

Condensed Consolidating Balance Sheet December 31, 2005
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	-	$	5,821	$	8,621		$	14,442
Current assets
Cash and cash equivalents		239		239		127			605
Short-term investments		-		-		191			191
Notes receivable from affiliated companies		467		-		(467	)		-
Deferred fuel cost		-		341		261			602
Assets of discontinued operations		-		757		1,809			2,566
Other current assets		22		992		1,029			2,043
Total current assets		728		2,329		2,950			6,007
Deferred debits and other assets
Investment in consolidated subsidiaries		11,594		-		(11,594	)		-
Goodwill		-		2		3,653			3,655
Other assets and deferred debits		259		1,561		1,138			2,958
Total deferred debits and other assets		11,853		1,563		(6,803	)		6,613
Total assets	$	12,581	$	9,713	$	4,768		$	27,062
Capitalization
Common stock equity	$	8,038	$	3,039	$	(3,039	)	$	8,038
Preferred stock of subsidiaries - not subject to mandatory redemption		-		34		59			93
Minority interest		-		31		5			36
Long-term debt, affiliate		-		440		(170	)		270
Long-term debt, net		3,873		2,636		3,667			10,176
Total capitalization		11,911		6,180		522			18,613
Current liabilities
Current portion of long-term debt		404		109		-			513
Notes payable to affiliated companies		-		315		(315	)		-
Short-term debt		-		102		73			175
Liabilities of discontinued operations		-		226		316			542
Other current liabilities		245		762		812			1,819
Total current liabilities		649		1,514		886			3,049
Deferred credits and other liabilities
Noncurrent income tax liabilities		-		-		198			198
Regulatory liabilities		-		1,189		1,338			2,527
Accrued pension and other benefits		12		307		546			865
Other liabilities and deferred credits		9		523		1,278			1,810
Total deferred credits and other liabilities		21		2,019		3,360			5,400
Total capitalization and liabilities	$	12,581	$	9,713	$	4,768		$	27,062

215

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		$	1,015		$	(398	)	$	1,912
Investing activities
Gross utility property additions		-			(718	)		(705	)		(1,423	)
Diversified business property additions		-			(2	)		-			(2	)
Nuclear fuel additions		-			(12	)		(102	)		(114	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		-			1,239			415			1,654
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			561			(1,033	)		271
Financing activities
Issuance of common stock		185			-			-			185
Proceeds from issuance of long-term debt, net		397			-			-			397
Net decrease in short-term debt		-			(102	)		(73	)		(175	)
Retirement of long-term debt		(2,091	)		(109	)		-			(2,200	)
Retirement of long-term affiliate debt		-			(131	)		131			-
Dividends paid on common stock		(607	)		-			-			(607	)
Dividends paid to parent		-			(1,135	)		1,135			-
Changes in advances from affiliates		-			(243	)		243			-
Cash distributions to minority interests of consolidated subsidiary		-			(79	)		-			(79	)
Other financing activities		(8	)		71			(52	)		11
Net cash (used) provided by financing activities		(2,124	)		(1,728	)		1,384			(2,468	)
Cash provided (used) by discontinued operations
Operating activities		-			92			(6	)		86
Investing activities		-			(139	)		(2	)		(141	)
Financing activities		-			-			-			-
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

216

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		$	409		$	509		$	1,175
Investing activities
Gross utility property additions		-			(496	)		(584	)		(1,080	)
Diversified business property additions		-			(6	)		-			(6	)
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	)		1			(37	)
Net cash provided (used) by investing activities		690			(108	)		(1,496	)		(914	)
Financing activities
Issuance of common stock		208			-			-			208
Proceeds from issuance of long-term debt, net		-			744			898			1,642
Net increase in short-term debt		(170	)		(191	)		(148	)		(509	)
Retirement of long-term debt		(160	)		(104	)		(300	)		(564	)
Retirement of long-term affiliate debt		-			(369	)		369			-
Dividends paid on common stock		(582	)		-			-			(582	)
Dividends paid to parent		-			(2	)		2			-
Changes in advances from affiliates		-			(101	)		101			-
Other financing activities		(9	)		53			(10	)		34
Net cash (used) provided by financing activities		(713	)		30			912			229
Cash provided (used) by discontinued operations
Operating activities		-			93			201			294
Investing activities		-			(206	)		(26	)		(232	)
Financing activities		-			(2	)		-			(2	)
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

217

Condensed Consolidating Statement of Cash Flows Year ended December 31, 2004
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	653		$	469		$	287		$	1,409
Investing activities
Gross utility property additions		-			(482	)		(516	)		(998	)
Diversified business property additions		-			(6	)		-			(6	)
Nuclear fuel additions		-			-			(101	)		(101	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		-			343			29			372
Purchases of available-for-sale securities and other investments		-			(569	)		(2,565	)		(3,134	)
Proceeds from sales of available-for-sale securities and other investments		-			569			2,679			3,248
Changes in advances to affiliates		27			(5	)		(22	)		-
Contributions to consolidated subsidiaries		(15	)		-			15			-
Other investing activities		-			(23	)		(7	)		(30	)
Net cash provided (used) by investing activities		12			(173	)		(488	)		(649	)
Financing activities
Issuance of common stock		73			-			-			73
Proceeds from issuance of long-term debt, net		365			56			-			421
Net increase in short-term debt		170			293			217			680
Retirement of long-term debt		(705	)		(68	)		(339	)		(1,112	)
Dividends paid on common stock		(558	)		-			-			(558	)
Dividends paid to parent		-			(340	)		340			-
Changes in advances from affiliates		-			(205	)		205			-
Contributions from parent		-			12			(12	)		-
Other financing activities		(5	)		15			1			11
Net cash (used) provided by financing activities		(660	)		(237	)		412			(485	)
Cash provided (used) by discontinued operations
Operating activities		-			145			46			191
Investing activities		-			(190	)		(9	)		(199	)
Financing activities		-			(5	)		(241	)		(246	)
Net increase in cash and cash equivalents		5			9			7			21
Cash and cash equivalents at beginning of year		-			14			20			34
Cash and cash equivalents at end of year	$	5		$	23		$	27		$	55

218

24.QUARTERLY FINANCIAL DATA (UNAUDITED)

Results of operations for an interim period may not give a true indication of results for the year. In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Summarized quarterly financial data was as follows:

Progress Energy

(in millions except per share data)	First (a)(b)		Second (a)(b)			Third (a)(b)		Fourth (a)(b)
2006
Operating revenues	$	2,223	$	2,298		$	2,776	$	2,273
Operating income		268		210			557		274
Income from continuing operations		85		19			283		127
Net income (loss)		45		(47	)		319		254
Common stock data
Basic earnings per common share
Income from continuing operations		0.34		0.08			1.13		0.51
Net income (loss)		0.18		(0.19	)		1.27		1.01
Diluted earnings per common share
Income from continuing operations		0.34		0.08			1.12		0.51
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
2005
Operating revenues	$	2,051	$	2,079		$	2,743	$	2,295
Operating income		237		119			539		325
Income from continuing operations before cumulative effect of change in accounting principle		103		2			457		159
Net income (loss)		93		(1	)		450		155
Common stock data
Basic earnings per common share
Income from continuing operations before cumulative effect of change in accounting principle		0.42		0.01			1.84		0.64
Net income (loss)		0.38		(0.01	)		1.82		0.62
Diluted earnings per common share
Income from continuing operations before cumulative effect of change in accounting principle		0.42		0.01			1.84		0.64
Net income (loss)		0.38		(0.01	)		1.81		0.62
Dividends declared per common share		0.590		0.590			0.590		0.605
Market price per share -High		45.33		45.83			46.00		45.50
- Low		40.63		40.61			41.90		40.19
(a) Operating results have been restated for discontinued operations.
(b) Certain amounts have been reclassified to conform to current period presentation.

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. The first quarter of 2005 included $31 million recorded for estimated severance expense for workforce restructuring and implementation of an automated meter reading initiative at PEF; the second and fourth quarters of 2005 included reversals of estimated severance expense of $13 million each quarter. The second quarter of 2005 included a $141 million charge related to postretirement benefits for employees participating in the voluntary enhanced retirement program (See Note 16A). The second quarter of 2006 includes a $91 million

219

impairment charge to our synthetic fuels assets and a portion of our coal terminal assets (See Notes 8 and 9). The 2006 and 2005 amounts were restated for discontinued operations (See Note 3).

PEC

Summarized quarterly financial data was as follows:

(in millions)	First (a)		Second (a)		Third (a)		Fourth (a)
2006
Operating revenues	$	978	$	936	$	1,200	$	972
Operating income		189		174		346		178
Net income		86		76		189		106
2005
Operating revenues	$	935	$	861	$	1,185	$	1,010
Operating income		221		140		343		227
Net income		116		67		184		126
(a) Certain amounts have been reclassified to conform to current period presentation.

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. The first quarter of 2005 included $14 million recorded for estimated severance expense for workforce restructuring; the second and fourth quarters of 2005 included reversals of estimated severance expense of $6 million and $5 million, respectively. The second quarter of 2005 included a $29 million charge related to postretirement benefits for employees participating in the voluntary enhanced retirement program (See Note 16A).

PEF

Summarized quarterly financial data was as follows:

(in millions)	First (a)		Second (a)		Third (a)		Fourth (a)
2006
Operating revenues	$	1,007	$	1,147	$	1,399	$	1,086
Operating income		117		167		237		122
Net income		53		87		125		63
2005
Operating revenues	$	848	$	908	$	1,227	$	972
Operating income		89		51		247		112
Net income		44		10		151		55
(a) Certain amounts have been reclassified to conform to current period presentation.

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. The first quarter of 2005 included $14 million recorded for estimated severance expense for workforce restructuring and implementation of an automated meter reading initiative; the second and fourth quarters of 2005 included reversals of estimated severance expense of $5 million and $6 million, respectively. The second quarter of 2005 included a $90 million charge related to postretirement benefits for employees participating in the voluntary enhanced retirement program (See Note 16A).

220

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.:

We have audited the consolidated financial statements of Progress Energy, Inc., and its subsidiaries (the Company) at December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, management’s assessment of the effectiveness of the Company’s internal control over financial reporting at December 31, 2006, and the effectiveness of the Company’s internal control over financial reporting at December 31, 2006, and have issued our reports thereon dated February 28, 2007 (which reports on the consolidated financial statements express an unqualified opinion and include an explanatory paragraph concerning the adoption of new accounting principles in 2006 and 2005); such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company listed in Item 15. This consolidated financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

221

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, 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
DECEMBER 31, 2004
Uncollectible accounts	$	28	$	14	$	(4	)	$	(16	)	$	22
Fossil fuel plants dismantlement reserve		143		1		-			-			144
Nuclear refueling outage reserve		2		10		-			-			12
(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.

222

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 consolidated financial statements of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc., and its subsidiaries (PEC) at December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, and have issued our report thereon dated February 28, 2007 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2006 and 2005); such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of PEC listed in Item 15. This consolidated financial statement schedule is the responsibility of PEC’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

223

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, 2006
Uncollectible accounts	$	4	$	9	$	-		$	(8	)	$	5
DECEMBER 31, 2005
Uncollectible accounts	$	10	$	5	$	-		$	(11	)	$	4
DECEMBER 31, 2004
Uncollectible accounts	$	17	$	7	$	(4	)	$	(10	)	$	10
(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.

224

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 financial statements of Florida Power Corporation d/b/a Progress Energy Florida, Inc., (PEF) at December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, and have issued our report thereon dated February 28, 2007 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2006 and 2005); such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of PEF listed in Item 15. This financial statement schedule is the responsibility of PEF’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

225

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, 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
DECEMBER 31, 2004
Uncollectible accounts	$	2	$	5	$	-	$	(5	)	$	2
Fossil fuel plants dismantlement reserve		143		1		-		-			144
Nuclear refueling outage reserve		2		10		-		-			12
(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.

226

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

None

ITEM 9A.CONTROLS AND PROCEDURES

Progress Energy, Inc.

DISCLOSURE CONTROLS AND PROCEDURES

Pursuant to Rule 13a-15(b) under 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 Rule 13a-15(e) 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 15(d)-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, 2006. 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, 2006, Progress Energy maintained effective internal control over financial reporting.

Management’s assessment of the effectiveness of Progress Energy’s internal control over financial reporting at December 31, 2006, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included below.

227

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, 2006 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.

We have audited management’s assessment, included in the accompanying Management’s Report of Internal Controls, that Progress Energy, Inc., and its subsidiaries (the “Company”) maintained effective internal control over financial reporting at December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting at December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting at December 31, 2006, 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, 2006, of the Company and

228

our report dated February 28, 2007, expressedan unqualified opinion on those consolidated financial statements and included an explanatory paragraph concerning the adoption of new accounting principles.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

PEC

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.

There has been no change in PEC’s internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

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.

There has been no change in PEF’s internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

ITEM 9B.OTHER INFORMATION

None

229

PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

a)   Information on Progress Energy, Inc.’s directors is set forth in Progress Energy’s definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated by reference herein. Information on PEC’s directors is set forth in PEC’s definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

b)   Information on both Progress Energy’s and PEC’s executive officers is set forth in PART I and incorporated by reference herein.

c)   We have adopted a Code of Ethics that applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller (or persons performing similar functions). Our board of directors has adopted our Code of Ethics as its own standard. Board members, Progress Energy officers and Progress Energy employees certify their compliance with the Code of Ethics on an annual basis. Our Code of Ethics is posted on our Web site at www.progress-energy.com and is available in print to any shareholder upon written request.

We intend to satisfy the disclosure requirement under Item 10 of Form 8-K relating to amendments to or waivers from any provision of the Code of Ethics applicable to our

Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller by posting such information on our Web site cited above.

d)   The board of directors has determined that Carlos A. Saladrigas and Theresa M. Stone are the “Audit Committee Financial Experts,” as that term is defined in the rules promulgated by the SEC pursuant to the Sarbanes-Oxley Act of 2002, and have designated them as such. Both Mr. Saladrigas and Ms. Stone are “independent,” as that term is defined in the general independence standards of the New York Stock Exchange listing standards.

e)   Information regarding our compliance with Section 16(a) of the Securities Exchange Act of 1934 and certain corporate governance matters is set forth in Progress Energy's and PEC's definitive proxy statements for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

f)   The following are available on our Web site cited above and in print at no cost:

·    Audit and Corporate Performance Committee Charter

·    Corporate Governance Committee Charter

·   Organization and Compensation Committee Charter

·   Corporate Governance Guidelines

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

ITEM 11.EXECUTIVE COMPENSATION

Information on Progress Energy’s executive compensation is set forth in Progress Energy’s definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated by reference herein. Information on PEC’s executive compensation is set forth in PEC’s definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

The information called for by Item 11 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

230

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

a)   Information regarding any person Progress Energy knows to be the beneficial owner of more than five (5%) percent of any class of its voting securities is set forth in its definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated herein by reference.

Information regarding any person PEC knows to be the beneficial owner of more than five percent of any class of its voting securities is set forth in its definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated herein by reference.

b)   Information on security ownership of Progress Energy’s and PEC’s management is set forth, respectively, in Progress Energy’s and PEC’s definitive proxy statements for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

c)   Information on the equity compensation plans of Progress Energy is set forth under the heading “Equity Compensation Plan Information” in Progress Energy’s definitive proxy statement for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

The information called for by Item 12 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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

Information on certain relationships and related transactions is set forth, respectively, in Progress Energy’s and PEC’s definitive proxy statements for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

The information called for by Item 13 is omitted for PEF pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

The Audit and Corporate Performance Committee of Progress Energy’s board of directors (“Audit Committee”) has actively monitored all services provided by its independent registered public accounting firm, Deloitte & Touche LLP, the member firms of Deloitte & Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte”) and the relationship between audit and nonaudit services provided by Deloitte. Progress Energy has adopted policies and procedures for approving all audit and permissible nonaudit services rendered by Deloitte, and the fees billed for those services. The Controller is responsible to the Audit Committee for enforcement of this procedure, and for reporting noncompliance. The Audit Committee specifically preapproved the use of Deloitte for audit, audit-related, tax and nonaudit services, subject to the limitations of our preapproval policy. Audit and audit-related services include assurance and related activities; assurance services associated with internal control over financial reporting; review of reports for regulatory filings, releases containing financial information and financing-related materials; consultations on dispositions and discontinued operations; audits of employee benefit plan; and consultation on accounting issues. The preapproval policy provides that any audit and audit-related services with projected expenditure of over $50,000 and not previously preapproved, will require individual approval by the Audit Committee in advance of Deloitte being engaged to render such services. Once the cumulative total of those projects less than $50,000, plus projected overruns in excess of previously approved amounts, exceeds $500,000 for the year, each subsequent project, regardless of amount, must be approved individually in advance by the Audit Committee.

The preapproval policy requires management to obtain specific preapproval from the Audit Committee for the use of Deloitte for any permissible nonaudit services, which, generally, are limited to tax services, including tax compliance, tax planning, and tax advice services such as return review and consultation and assistance. Other types

231

of permissible nonaudit services will not be considered for approval except in limited instances, which may include proposed services that provide significant economic or other benefits. In determining whether to approve these services, the Audit Committee will assess whether these services adversely impair the independence of Deloitte. Any permissible nonaudit services provided during a fiscal year that (i) do not aggregate more than five percent of the total fees paid to Deloitte for all services rendered during that fiscal year and (ii) were not recognized as nonaudit services at the time of the engagement must be brought to the attention of the Controller for prompt submission to the Audit Committee for approval. These “de minimis” nonaudit services must be approved by the Audit Committee or its designated representative before the completion of the services. The policy also requires the Controller to update the Audit Committee throughout the year as to the services provided by Deloitte and the costs of those services. The policy also requires Deloitte to annually confirm its independence in accordance with SEC and New York Stock Exchange standards. The Audit Committee will assess the adequacy of this policy and related procedure as it deems necessary and revise accordingly.

Information regarding principal accountant fees and services is set forth, respectively, in Progress Energy’s and PEC’s definitive proxy statements for the 2007 Annual Meeting of Shareholders and incorporated by reference herein.

PEF

Set forth in the table below is certain information relating to the aggregate fees billed by Deloitte for professional services rendered to PEF for the fiscal years ended December 31.

	2006		2005
Audit fees	$	906,000	$	1,282,000
Audit-related fees		44,000		18,000
Tax fees		103,000		179,000
All other fees		4,000		-
Total	$	1,057,000	$	1,479,000

Audit fees include fees billed for services rendered in connection with (i) the audits of the annual financial statements of PEF (ii) the audit of management’s assessment of internal control over financial reporting; (iii) the reviews of the financial statements included in the Quarterly Reports on Form 10-Q of PEF, (iv) SEC filings, (v) accounting consultations arising as part of the audits and (vi) comfort letters.

Audit-related fees include fees billed for (i) special procedures and letter reports, (ii) benefit plan audits when fees are paid by PEF rather than directly by the plan; and (iii) accounting consultations for prospective transactions not arising directly from the audits.

Tax fees include fees billed for tax compliance matters and tax planning and advisory services.

All other fees include fees billed for utility accounting training.

The Audit Committee has concluded that the provision of the nonaudit services listed above as “All other fees” is compatible with maintaining Deloitte’s independence.

None of the services provided were approved by the Audit Committee pursuant to the “de minimis” waiver provisions described above.

232

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

3.Exhibits Filed:

See EXHIBIT INDEX

233

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY
Date: February 26, 2007	(Registrants)
	By: /s/ Robert B. McGehee
	Robert B. McGehee
	Chairman and Chief Executive Officer
	Progress Energy, Inc.
	Chairman
	Carolina Power & Light Company
	By: /s/ Fred N. Day IV
	Fred N. Day IV
	President and Chief Executive Officer
	Carolina Power & Light Company
	By: /s/ Peter M. Scott III
	Peter M. Scott III Executive Vice President and Chief Financial Officer Progress Energy, Inc. Carolina Power & Light Company
	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone Chief Accounting Officer and Controller Progress Energy, Inc. Chief Accounting Officer Carolina Power & Light Company

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Signature	Title	Date
/s/ Robert B. McGehee	Chairman	February 26, 2007
(Robert B. McGehee)
/s/ Edwin B. Borden	Director	February 26, 2007
(Edwin B. Borden)
/s/ James E. Bostic, Jr.	Director	February 26, 2007
(James E. Bostic, Jr.)

234

/s/ David L. Burner	Director	February 26, 2007
(David L. Burner)

/s/ Richard L. Daugherty	Director	February 26, 2007
(Richard L. Daugherty)
/s/ Harris E. DeLoach, Jr.	Director	February 26, 2007
(Harris E. DeLoach, Jr.)
/s/ W. D. Frederick, Jr.	Director	February 26, 2007
(W. D. Frederick, Jr.)
/s/ W. Steven Jones	Director	February 26, 2007
(W. Steven Jones)
/s/ E. Marie McKee	Director	February 26, 2007
(E. Marie McKee)
/s/ John H. Mullin, III	Director	February 26, 2007
(John H. Mullin, III)
/s/ Carlos A. Saladrigas	Director	February 26, 2007
(Carlos A. Saladrigas)
/s/ Theresa M. Stone	Director	February 26, 2007
(Theresa M. Stone)
/s/ Alfred C. Tollison, Jr.	Director	February 26, 2007
(Alfred C. Tollison, Jr.)
/s/ Jean Giles Wittner	Director	February 26, 2007
(Jean Giles Wittner)

235

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

	FLORIDA POWER CORPORATION
	(Registrant)
Date: February 26, 2007
	By: /s/ Jeffrey J. Lyash
	Jeffrey J. Lyash
	President and Chief Executive Officer
	By: /s/ Peter M. Scott III
	Peter M. Scott III
	Executive Vice President and Chief Financial Officer
	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Signature	Title	Date
/s/ Robert B. McGehee	Chairman	February 26, 2007
(Robert B. McGehee)
/s/ Jeffrey A. Corbett	Director	February 26, 2007
(Jeffrey A. Corbett)
/s/ Fred N. Day IV	Director	February 26, 2007
(Fred N. Day IV)
/s/ William D. Johnson	Director	February 26, 2007
(William D. Johnson)
/s/ Jeffrey J. Lyash	Director	February 26, 2007
(Jeffrey J. Lyash)
/s/ John R. McArthur	Director	February 26, 2007
(John R. McArthur)
/s/ Peter M. Scott III	Director	February 26, 2007
(Peter M. Scott III)

236

EXHIBIT INDEX

Number	Exhibit	Progress Energy, Inc.	PEC	PEF
*3a(1)	Restated Charter of Carolina Power & Light Company, as amended May 10, 1995 (filed as Exhibit No. 3(i) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1995, File No. 1-3382).		X
*3a(2)	Restated Charter of Carolina Power & Light Company as amended on May 10, 1996 (filed as Exhibit No. 3(i) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-3382).		X
*3a(3)	Amended and Restated Articles of Incorporation of Progress Energy, Inc. (f/k/a CP&L Energy, Inc.), as amended and restated on June 15, 2000 (filed as Exhibit No. 3a(1) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15929 and No. 1-3382).	X
*3a(4)	Amended and Restated Articles of Incorporation of Progress Energy, Inc. (f/k/a CP&L Energy, Inc.), as amended and restated on December 4, 2000 (filed as Exhibit 3b(1) to Annual Report on Form 10-K for the year ended December 31, 2001, as filed with the SEC on March 28, 2002, File No. 1-15929).	X
*3a(5)	Amended Articles of Incorporation of Progress Energy, Inc., as amended on May 10, 2006 (filed as Exhibit 3.A to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006, File No. 1-15929, 1-3382 and 1-3274. )	X
*3a(6)	Amended Articles of Incorporation of Florida Power Corporation (filed as Exhibit 3(a) to the Progress Energy Florida Annual Report on Form 10-K for the year ended December 31, 1991, as filed with the SEC on March 30, 1992, File No. 1-3274).			X
*3b(1)	By-Laws of Progress Energy, Inc., as amended on May 10, 2006 (filed as Exhibit 3.B to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006, File No. 1-15929, 1-3382 and 1-3274).	X
*3b(2)	By-Laws of Carolina Power & Light Company, as amended on March 17, 2004 (filed as Exhibit No. 3(ii)(b) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, File No. 1-3382 and 1-15929).		X
*3b(3)	Bylaws of Progress Energy Florida, as amended October 1, 2001 (filed as Exhibit 3.(d) to the Progress Energy Florida Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the SEC on March 16, 2005, File No. 1-8349 and 1-3274).			X
*4a(1)	Description of Preferred Stock and the rights of the holders thereof (as set forth in Article Fourth of the		X

237

	Restated Charter of Carolina Power & Light Company, as amended, and Sections 1-9, 15, 16, 22-27, and 31 of the By-Laws of Carolina Power & Light Company, as amended (filed as Exhibit 4(f), File No.33-25560).
*4a(2)	Statement of Classification of Shares dated January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company’s Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560).	X
*4a(3)	Statement of Classification of Shares dated September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company’s Serial Preferred Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560).	X
*4b(1)	Mortgage and Deed of Trust dated as of May 1, 1940 between Carolina Power & Light Company and The Bank of New York (formerly, Irving Trust Company) and Frederick G. Herbst (Douglas J. MacInnes, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); the Sixth through Sixty-sixth Supplemental Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No. 2-19118; Exhibit 4(b)-2, File No. 2-22439; Exhibit 4(b)-2, File No. 2-24624; Exhibit 2(c), File No. 2-27297; Exhibit 2(c), File No. 2-30172; Exhibit 2(c), File No. 2-35694; Exhibit 2(c), File No. 2-37505; Exhibit 2(c), File No. 2-39002; Exhibit 2(c), File No. 2-41738; Exhibit 2(c), File No. 2-43439; Exhibit 2(c), File No. 2-47751; Exhibit 2(c), File No. 2-49347; Exhibit 2(c), File No. 2-53113; Exhibit 2(d), File No. 2-53113; Exhibit 2(c), File No. 2-59511; Exhibit 2(c), File No. 2-61611; Exhibit 2(d), File No. 2-64189; Exhibit 2(c), File No. 2-65514; Exhibits 2(c) and 2(d), File No. 2-66851; Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File No. 2-81299; Exhibits 4(c)-1 through 4(c)-8, File No. 2-95505; Exhibits 4(b) through 4(h), File No. 33-25560; Exhibits 4(b) and 4(c), File No. 33-33431; Exhibits 4(b) and 4(c), File No. 33-38298; Exhibits 4(h) and 4(i), File No. 33-42869; Exhibits 4(e)-(g), File No. 33-48607; Exhibits 4(e) and 4(f), File No. 33-55060; Exhibits 4(e) and 4(f), File No. 33-60014; Exhibits 4(a) and 4(b) to Post-Effective Amendment No. 1, File No. 33-38349; Exhibit 4(e), File No. 33-50597; Exhibit 4(e) and 4(f), File No. 33-57835; Exhibit to Current Report on Form 8-K dated August 28, 1997, File No. 1-3382; Form of Carolina Power & Light Company First Mortgage Bond, 6.80% Series Due August 15, 2007 filed as Exhibit 4 to Form 10-Q for the period ended September 30, 1998, File No. 1-3382; Exhibit 4(b), File No. 333-69237; and Exhibit 4(c) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382.); and the Sixty-eighth Supplemental Indenture (Exhibit No. 4(b) to Current Report on Form 8-K dated April 20, 2000, File No. 1-3382; and the Sixty-ninth Supplemental Indenture (Exhibit No. 4b(2) to Annual Report on Form 10-K dated	X

238

	March 29, 2001, File No. 1-3382); and the Seventieth Supplemental Indenture, (Exhibit 4b(3) to Annual Report on Form 10-K dated March 29, 2001, File No. 1-3382); and the Seventy-first Supplemental Indenture (Exhibit 4b(2) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3382 and 1-15929); and the Seventy-second Supplemental Indenture (Exhibit 4 to PEC Report on Form 8-K dated September 12, 2003, File No. 1-3382); and the Seventy-third Supplemental Indenture (Exhibit 4 to PEC Report on Form 8-K dated March 22, 2005, File No. 1-3382); and the Seventy-fourth Supplemental Indenture (Exhibit 4 to PEC Report on Form 8-K dated November 30, 2005, File No. 1-3382).
*4b(2)	Indenture, dated as of January 1, 1944 (the "Indenture"), between Florida Power Corporation and Guaranty Trust Company of New York and The Florida National Bank of Jacksonville, as Trustees (filed as Exhibit B-18 to Florida Power's Registration Statement on Form A-2) (No. 2-5293) filed with the SEC on January 24, 1944).	X
*4b(3)	Seventh Supplemental Indenture (filed as Exhibit 4(b) to Florida Power Corporation's Registration Statement on Form S-3 (No. 33-16788) filed with the SEC on September 27, 1991); and the Eighth Supplemental Indenture (filed as Exhibit 4(c) to Florida Power Corporation's Registration Statement on Form S-3 (No. 33-16788) filed with the SEC on September 27, 1991); and the Sixteenth Supplemental Indenture (filed as Exhibit 4(d) to Florida Power Corporation's Registration Statement on Form S-3 (No. 33-16788) filed with the SEC on September 27, 1991); and the Twenty-ninth Supplemental Indenture (filed as Exhibit 4(c) to Florida Power Corporation's Registration Statement on Form S-3 (No. 2-79832) filed with the SEC on September 17, 1982); and the Thirty-eighth Supplemental Indenture (filed as exhibit 4(f) to Florida Power's Registration Statement on Form S-3 (No. 33-55273) as filed with the SEC on August 29, 1994); and the Thirty-ninth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on July 23, 2001); and the Fortieth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on February 18, 2003); and the Forty-first Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on February 21, 2003); and the Forty-second Supplemental Indenture (filed as Exhibit 4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 filed with the SEC on September 11, 2003); and the Forty-third Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K filed with the SEC on November 21, 2003); and the Forty-fourth Supplemental Indenture (filed as Exhibit 4.(m) to the Progress Energy Florida Annual Report on Form 10-K dated March 16, 2005); and the Forty- fifth Supplemental Indenture (filed as Exhibit 4 to Current Report on Form 8-K, filed on May 16, 2005).	X
*4b(4)	Indenture, dated as of December 7, 2005, between Progress Energy Florida, Inc. and J.P. Morgan Trust	X

239

	Company, National Association, as Trustee with respect to Senior Notes, (filed as Exhibit 4(a) to Current Report on Form 8-K dated December 13, 2005, File No. 1-3274).
*4b(5)	Indenture, dated as of March 1, 1995, between Carolina Power & Light Company and Bankers Trust Company, as Trustee, with respect to Unsecured Subordinated Debt Securities (filed as Exhibit No. 4(c) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382).		X
*4b(6)	Indenture, dated as of February 15, 2001, between Progress Energy, Inc. and Bank One Trust Company, N.A., as Trustee, with respect to Senior Notes (filed as Exhibit 4(a) to Form 8-K dated February 27, 2001, File No. 1-15929).	X
*4c	Resolutions adopted by the Executive Committee of the Board of Directors at a meeting held on April 13, 1995, establishing the terms of the 8.55% Quarterly Income Capital Securities (Series A Subordinated Deferrable Interest Debentures) (filed as Exhibit 4(b) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382).		X
*4d	Indenture (for Senior Notes), dated as of March 1, 1999 between Carolina Power & Light Company and The Bank of New York, as Trustee, (filed as Exhibit No. 4(a) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382), and the First and Second Supplemental Senior Note Indentures thereto (Exhibit No. 4(b) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382); Exhibit No. 4(a) to Current Report on Form 8-K dated April 20, 2000, File No. 1-3382).		X
*4e	Indenture (For Debt Securities), dated as of October 28, 1999 between Carolina Power & Light Company and The Chase Manhattan Bank, as Trustee (filed as Exhibit 4(a) to Current Report on Form 8-K dated November 5, 1999, File No. 1-3382), (Exhibit 4(b) to Current Report on Form 8-K dated November 5, 1999, File No. 1-3382).		X
*4f	Contingent Value Obligation Agreement, dated as of November 30, 2000, between CP&L Energy, Inc. and The Chase Manhattan Bank, as Trustee (Exhibit 4.1 to Current Report on Form 8-K dated December 12, 2000, File No. 1-3382).	X
*10a(1)	Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560).		X
*10a(2)	Operating and Fuel Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3		X

240

	and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560).
*10a(3)	Power Coordination Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and		X
*10a(4)	Amendment dated December 16, 1982 to Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560).		X
*10b(1)	Progress Energy, Inc. $1,130,000,000 5-Year Revolving Credit Agreement dated as of May 3, 2006 (filed as Exhibit 10(c) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, File No. 1-15929, 1-3274 and 1-3382).	X
*10b(2)	PEF 5-Year $450,000,000 Credit Agreement, dated as of March 28, 2005 (filed as Exhibit 10(ii) to Current Report on Form 8-K filed April 1, 2005, File No. 1-3274).			X
*10b(3)	Amendment dated as of May 3, 2006, to the 5-Year $450,000,000 Credit Agreement among PEF and certain lenders, dated March 28, 2005 (filed as Exhibit 10(e) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, File No. 1-15929, 1-3274 and 1-3382).			X
*10b(4)	PEC 5-¼-Year $450,000,000 Credit Agreement dated as of March 28, 2005 (filed as Exhibit 10(i) to Current Report on Form 8-K filed April 1, 2005, File No. 1-3382).		X
*10b(5)	Amendment dated as of May 3, 2006, to the 5-¼-Year $450,000,000 Credit Agreement among PEC and certain lenders, dated March 28, 2005 (filed as Exhibit 10(d) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, File No. 1-15929, 1-3274 and 1-3382).		X
-+*10c(1)	Retirement Plan for Outside Directors (filed as Exhibit 10(i), File No. 33-25560).		X
+*10c(2)	Resolutions of Board of Directors dated July 9, 1997, amending the Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company.		X
+*10c(3)	Progress Energy, Inc. Form of Stock Option Agreement (filed as Exhibit 4.4 to Form S-8 dated September 27, 2001, File No. 333-70332).	X	X	X

241

+*10c(4)	Progress Energy, Inc. Form of Stock Option Award (filed as Exhibit 4.5 to Form S-8 dated September 27, 2001, File No. 333-70332).	X	X	X
+10c(5)	2002 Progress Energy, Inc. Equity Incentive Plan, Amended and Restated effective January 1, 2007.	X	X	X
+10c(6)	Amended and Restated Broad-Based Performance Share Sub-Plan, Exhibit B to the 2002 Progress Energy, Inc. Equity Incentive Plan, effective January 1, 2007.	X	X	X
+10c(7)	Amended and Restated Executive and Key Manager Performance Share Sub-Plan, Exhibit A to the 2002 Progress Energy, Inc. Equity Incentive Plan (effective January 1, 2007).	X	X	X
+10c (8)	Amended and Restated Management Incentive Compensation Plan of Progress Energy, Inc., effective January 1, 2007.	X	X	X
+10c(9)	Amended and Restated Management Deferred Compensation Plan of Progress Energy, Inc., effective as of January 1, 2007.	X	X	X
+10c(10)	Amended and Restated Management Change-in-Control Plan of Progress Energy, Inc., effective as of January 1, 2007.	X	X	X
+10c(11)	Amended and Restated Non-Employee Director Deferred Compensation Plan of Progress Energy, Inc., effective January 1, 2007.	X	X	X
+10c(12)	Amended and Restated Restoration Retirement Plan of Progress Energy, Inc., effective January 1, 2007.	X	X	X
+10c(13)	Amended and Restated Supplemental Senior Executive Retirement Plan of Progress Energy, Inc., effective January 1, 2007.	X	X	X
+10c(14)	Amended and Restated Non-Employee Director Stock Unit Plan of Progress Energy, Inc., effective January 1, 2007.	X	X	X
+*10c(15)	Form of Progress Energy, Inc. Restricted Stock Agreement pursuant to the 2002 Progress Energy Inc. Equity Incentive Plan, as amended July 2002 (filed as Exhibit 10c(18) to Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the SEC on March 16, 2005, File No. 1-3382 and 1-15929).	X	X	X
+*10c(16)	Employment Agreement dated August 1, 2000 between CP&L Service Company LLC and Robert McGehee (filed as Exhibit 10(iv) to Quarterly Report on Form 10-Q for the period ended September 30, 2000, File No. 1-15929 and No. 1-3382).	X

242

+*10c(17)	Form of Employment Agreement dated August 1, 2000 between CP&L Service Company LLC and Peter M. Scott III (filed as Exhibit 10(v) to Quarterly Report on Form 10-Q for the period ended September 30, 2000, File No. 1-15929 and No. 1-3382).	X	X	X
+*10c(18)	Amendment, dated August 5, 2005, to Employment Agreement dated between Progress Energy Service Company, LLC and Peter M. Scott III (filed as Exhibit 10 to Quarterly Report on Form 10-Q for the period ended June 30, 2005, File No. 1-15929, 1-3382 and 1-3274).	X	X	X
+*10c(19)	Form of Employment Agreement dated August 1, 2000 between Carolina Power & Light Company and Fred Day IV and C.S. “Scotty” Hinnant (filed as Exhibit 10(vi) to Quarterly Report on Form 10-Q for the period ended September 30, 2000, File No. 1-15929 and No. 1-3382).	X	X
+*10c(20)	Form of Employment Agreement between Progress Energy Service Company and John R. McArthur, effective January 2003 (filed as Exhibit 10c(27) to Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the SEC on March 21, 2003, File No. 1-3382 and 1-15929).	X	X	X
+*10c(21)	Employment Agreement dated January 1, 2005 between Progress Energy Carolinas, Inc. and William D. Johnson (filed as Exhibit 10c(29) to Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the SEC on March 16, 2005, File No. 1-3382 and 1-15929).	X	X	X
+10c(22)	Selected Executives Supplemental Deferred Compensation Program Agreement, dated August, 1996, between CP&L and C. S. Hinnant.		X
+10c(23)	Form of Executive Permanent Life Insurance Agreement.
*10d(1)	Agreement dated November 18, 2004 between Winchester Production Company, Ltd., TGG Pipeline Ltd., Progress Energy, Inc. and EnCana Oil & Gas (USA), Inc. (filed as Exhibit 10d(1) to Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the SEC on March 16, 2005, File No. 1-3382 and 1-15929).	X		X
*10d(2)	Precedent and Related Agreements among Florida Power Corporation d/b/a Progress Energy Florida, Inc. (“PEF”), Southern Natural Gas Company (“SNG”), Florida Gas Transmission Company (“FGT”), and BG LNG Services, LLC (“BG”), including: a)Precedent Agreement by and between SNG and PEF, dated December 2, 2004; b)Gas Sale and Purchase Contract between BG and PEF, dated December 1, 2004; c)Interim Firm Transportation Service Agreement by and between FGT and PEF,dated December 2, 2004; d)Letter Agreement between FGT and PEF, dated	X		X

243

	December 2, 2004 and Firm Transportation Service Agreement by and between FGT and PEF to be entered into upon satisfaction of certain conditions precedent; e)Discount Agreement between FGT and PEF, dated December 2, 2004; f)Amendment to Gas Sale and Purchase Contract between BG and PEF, dated January 28, 2005; and g)Letter Agreement between FGT and PEF, dated January 31, 2005, (filed as Exhibit 10.1 to Current Report on Form 8-K/A filed March 15, 2005). (Confidential treatment has been requested for portions of this exhibit. These portions have been omitted from the above-referenced Current Report and submitted separately to the SEC.)
12(a)	Computation of Ratio of Earnings to Fixed Charges.	X
12(b)	Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends Combined.		X
12(c)	Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends Combined.			X
21	Subsidiaries of Progress Energy, Inc.	X
23(a)	Consent of Deloitte & Touche LLP.	X
23(b)	Consent of Deloitte & Touche LLP.		X
31(a)	302 Certification of Chief Executive Officer	X
31(b)	302 Certification of Chief Financial Officer	X
31(c)	302 Certification of Chief Executive Officer		X
31(d)	302 Certification of Chief Financial Officer		X
31(e)	302 Certification of Chief Executive Officer			X
31(f)	302 Certification of Chief Financial Officer			X
32(a)	906 Certification of Chief Executive Officer	X
32(b)	906 Certification of Chief Financial Officer	X
32(c)	906 Certification of Chief Executive Officer		X
32(d)	906 Certification of Chief Financial Officer		X

244

32(e)	906 Certification of Chief Executive Officer	X
32(f)	906 Certification of Chief Financial Officer	X

*Incorporated herein by reference as indicated.

+Management contract or compensatory plan or arrangement required to be filed as an exhibit to this form pursuant to Item 15 (b) of this report.

-Sponsorship of this management contract or compensation plan or arrangement was transferred from Carolina Power & Light Company to Progress Energy, Inc., effective August 1, 2000.

EX-10.C5

Exhibit 10c(5)

Progress Energy, Inc. 2002 Equity Incentive Plan

(Amended and Restated Effective January 1, 2007)

Section 1.Purpose

Progress Energy, Inc. (hereinafter referred to as the "Sponsor"), a North Carolina corporation, hereby establishes the 2002 Equity Incentive Plan (the "Plan") to promote the interests of the Sponsor and its shareholders through the (i) attraction and retention of executive officers, directors and other key employees essential to the success of Sponsor and its Affiliates; (ii) motivation of executive officers, directors and other key employees using performance-related and stock-based incentives linked to the interests of the Sponsor's shareholders; and (iii) enabling of such executive officers, directors and other key employees to share in the long-term growth and success of the Sponsor and its Affiliates. The Plan permits the grant of Nonqualified Stock Options, Incentive Stock Options (intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended), Stock Appreciation Rights, Restricted Stock, Performance Shares, Performance Units, and any other Stock Unit Awards or stock-based forms of Awards as the Committee may determine under its sole and complete discretion at the time of grant, subject to the provisions of this Plan document and applicable law. The 1997 Equity Incentive Plan of Progress Energy, Inc. (the "1997 Plan") shall remain effective with regard to all Awards made thereunder, but shall be superseded by this Plan with regard to all Awards after the Effective Date.

Section 2.Effective Date and Duration

The Plan was approved by the Board of Directors on March 20, 2002, subject to approval by the shareholders of the Sponsor. The Plan became effective on the date of approval of the Plan by the Sponsor's shareholders (the "Effective Date"). The Plan was further amended and restated effective July 10, 2002, and amended and restated effective January 1, 2007. The Plan shall expire on the tenth anniversary of the Effective Date; however, all Awards made prior to, and outstanding on such date, shall remain valid in accordance with their terms and conditions.

Section 3.Definitions

Except as otherwise defined in the Plan, the following terms shall have the meanings set forth below:

3.1"Affiliate" means, with respect to Sponsor, any entity that directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with Sponsor.

3.2"Award" means individually or collectively, a grant under the Plan of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Units, Performance Shares, or other Stock Unit Awards.

3.3"Award Date" or "Grant Date" means the date on which an Award is made by the Committee under this Plan.

3.4"Award Agreement" or "Agreement" means a written agreement implementing the grant of each Award signed by an authorized officer of the Sponsor and by the Participant.

3.5"Beneficial Owner" shall have the meaning ascribed to such term in Rule 13d-3 under the Exchange Act.

3.6"Board" or "Board of Directors" means the Board of Directors of the Sponsor.

3.7"Cashless Exercise" means the exercise of an Option by the Participant in compliance with Section 13(k) of the Exchange Act and with the Federal Reserve Board's Regulation T (or any successor provision) or as otherwise permitted by the Committee through the use of a brokerage firm to make payment to the Sponsor of the exercise price either from the proceeds of a loan to the Participant from the brokerage firm or from the proceeds of the sale of Stock issued pursuant to the exercise of the Option, and upon receipt of such payment, the Sponsor delivers the exercised Stock to the brokerage firm. The date of exercise of a Cashless Exercise shall be the date the broker executes the sale of exercised Stock, or if no sale is made, the date the broker receives the exercise loan notice from the Participant to pay the Sponsor for the exercised Stock.

3.8"Cause" means:

(a)embezzlement or theft from the Company, or other acts of dishonesty, disloyalty or otherwise injurious to the Company;

(b)disclosing without authorization proprietary or confidential information of the Company;

(c)committing any act of negligence or malfeasance causing injury to the Company;

(d)conviction of a crime amounting to a felony under the laws of the United States or any of the several states;

(e)any violation of the Company’s Code of Ethics; or

(f)unacceptable job performance which has been substantiated in accordance with the normal practices and procedures of the Company.

3.9"Change in Control" means the earliest of the following dates:

(a)the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or

(b)the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or

(c)the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or

(d)the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or

(e)the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor’s assets; or

(f)the date of any event which the Board determines should constitute a Change in Control.

A Change in Control shall not be deemed to have occurred on account of an event described in paragraphs (a), (b), (c), (d) or (e) of this Section 3.9 until a majority of the members of the Board receive written certification from the Committee that such event has occurred. Any determination that an event described in this Section 3.9 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Committee, the Sponsor, the Participants and their beneficiaries for all purposes of the Plan.

3.10"CEO" means the chief executive officer of the Sponsor.

3.11"Code" means the Internal Revenue Code of 1986, as amended from time to time.

3.12"Committee" means the Organization and Compensation Committee of the Board, comprised solely of Outside Directors, which will administer the Plan pursuant to Section 4 herein.

3.13"Company" means Progress Energy, Inc., including all Affiliates, or any successor thereto.

3.14"Continuing Director" means the members of the Board as of January 1, 2007; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of thedirectors who then comprised Continuing Directors shall be considered to be a Continuing Director.

3.15"Covered Participant" means a Participant who is a "covered employee" as defined in Section 162(m)(3) of the Code, and the regulations promulgated thereunder.

3.16"Department" means the Human Resources Department of Progress Energy Service Company, LLC.

3.17"Designated Beneficiary" means the beneficiary designated by the Participant, pursuant to procedures established by the Department, to receive amounts due to the Participant or to exercise any rights of the Participant to the extent permitted hereunder in the event of the Participant's death. If the Participant does not make an effective designation, then the Designated Beneficiary will be deemed to be the Participant's estate.

3.18"Disability" means (i) the mental or physical disability, either occupational or non-occupational in origin, of the Participant defined as "total disability" in the Long-term Disability Plan of the Sponsor currently in effect and as amended from time to time; or (ii) a determination by the Committee of "Total Disability" based on medical evidence that precludes the Participant from engaging in any occupation or employment for wage or profit for at least twelve months and appears to be permanent. In the case of Awards of Incentive Stock Options, "Disability" shall have the meaning set forth in Section 22(e)(3) of the Code.

3.19"Divestiture" means the sale (including the spin-off) of, or closing by, the Company of the business operations in which the Participant is employed.

3.20"Early Retirement" means retirement of a Participant from employment with the Company after age 55, but prior to age 65 under the provisions of the Sponsor's Pension Plan or the Sponsor's Supplemental Senior Executive Retirement Plan. In the event of a change in the Sponsor's Pension Plan such that there is no longer a definition of "Early Retirement" or the Participant is not a participant in the Sponsor's Pension Plan for purposes of this plan, "Early Retirement" shall mean retirement before age 65 after reaching the 55th birthday together with completion of 15 years of Vesting Service, or after completion of 35 years of Vesting Service with no age limitation.

3.21"Exchange Act" means the Securities Exchange Act of 1934, as amended.

3.22"Executive Officer" means an individual designated as an "officer" for purposes of Section 16 of the Securities Exchange Act of 1934 and as an "executive officer" for Item 401(b) of Regulation S-K by the Board pursuant to resolutions adopted by the Board from time to time.

3.23"Fair Market Value" means, on any given date, the closing price of Stock as reported on the New York Stock Exchange composite tape on such day or, if no shares of Stock were traded on the New York Stock Exchange on such day, then on the next preceding day that Stock was traded on such exchange, all as reported by such source as the Committee may select. In the case of a Cashless Exercise, Fair Market Value means the price of the Stock at the date and time the broker executes the sale of exercised Stock.

3.24"Full-time Employee" means an employee of the Company designated by the Department as being a "regular, full-time employee" who is eligible for all plans and programs of the Company set forth for such employees. This designation excludes all part-time, temporary, leased or contract employees and consultants to the Company.

3.25"Incentive Stock Option" means an option to purchase Stock, granted under Section 7 herein, which is designated as an incentive stock option by the Committee and is intended to meet the requirements of Section 422 of the Code.

3.26"Key Employee" means an officer or other employee of the Company who is selected for participation in the Plan in accordance with Section 4.2.

3.27"Nonqualified Stock Option" means an Option to purchase Stock, granted under Section 7 herein, which is not intended to be an Incentive Stock Option.

3.28"Normal Retirement" means the retirement of any Participant under the Sponsor's Pension Plan at age 65. In the event of a change in the Sponsor's Pension Plan such that there is no longer a definition of "Normal Retirement" or the Participant is not a participant in the Sponsor's Pension Plan, for purposes of the Plan "Normal Retirement" shall mean retirement upon attaining the age of 65 years and completing five years of Vesting Service.

3.29"Option" means an Incentive Stock Option or a Nonqualified Stock Option.

3.30"Other Stock Unit Award" means Awards of Stock or other Awards that are valued in whole or in part by reference to, or are otherwise based on, shares of Stock or other securities of the Sponsor.

3.31"Outside Director" means a member of the Board of Directors of the Sponsor who is not an employee of the Company.

3.32"Participant" means a Key Employee or Outside Director who has been granted an Award under the Plan.

3.33"Performance-Based Exception" means the performance-based exception from the tax deductibility limitations of Code Section 162(m).

3.34"Performance Measures" mean, unless and until the Committee proposes for shareholder approval and the Sponsor's shareholders approve a change in the general performance measures set forth in this article, the attainment of which may determine the degree of payout and/or vesting with respect to Awards which are designed to qualify for the Performance-Based Exception, measure(s) chosen from among the following alternatives:

(a)Total shareholder return (absolute or peer-group comparative)

(b)Stock price increase (absolute or peer-group comparative)

(c)Dividend payout as a percentage of net income (absolute or peer-group comparative)

(d)Return on equity (absolute or peer-group comparative)

(e)Return on capital employed (absolute or peer-group comparative)

(f)Cash flow, including operating cash flow, free cash flow, discounted cash flow return on investment, and cash flow in excess of cost of capital

(g)Economic value added (income in excess of capital costs)

(h)Cost per KWH (absolute or peer-group comparative)

(i)Revenue per KWH (absolute or peer-group comparative)

(j)Market share

(k)Customer satisfaction as measured by survey instruments (absolute or peer-group comparative)

(l)Earnings before interest, and taxes (absolute or peer-group comparative)

(m)Earnings before interest, taxes, depreciation, and amortization (absolute or peer-group comparative)

The Committee shall have the discretion to adjust the determinations of the degree of attainment of the pre-established Performance Measures; provided, however, that Awards which are designed to qualify for the Performance-Based Exception may not be adjusted upward (the Committee shall retain the discretion to adjust such Awards downward), except to the extent permitted under Code Section 162(m) and the regulations thereunder to reflect corporate reorganizations or other events.

3.35"Performance Award" means a performance-based Award, which may be in the form of either Performance Shares or Performance Units.

3.36"Performance Period" means the time period designated by the Committee during which performance goals must be met.

3.37"Performance Share" means an Award, designated as a Performance Share, granted to a Participant pursuant to Section 10 herein, the value of which is determined, in whole or in part, by the value of Stock in a manner deemed appropriate by the Committee and described in the Agreement or Sub-Plan.

3.38"Performance Unit" means an Award, designated as a Performance Unit, granted to a Participant pursuant to Section 10 herein, the value of which is determined, in whole or in part, by the attainment of pre-established goals relating to Sponsor's or Company's financial or operating performance as deemed appropriate by the Committee and described in the Agreement or Sub-Plan.

3.39"Period of Restriction" means the period during which the transfer of shares of Restricted Stock is restricted, pursuant to Section 9 of the Plan.

3.40"Person" shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a "group" as defined in Section 13(d).

3.41"Plan" means the Progress Energy, Inc. 2002 Equity Incentive Plan as herein described and as hereafter from time to time amended.

3.42"Restricted Stock" means an Award of Stock granted to a Participant pursuant to Section 9 of the Plan.

3.43"Rule 16b-3" means Rule 16b-3 under Section 16(b) of the Exchange Act or any successor rule as amended from time to time.

3.44“Section 409A” means Section 409A of the Code, or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time and by related guidance.

3.45"Section 162(m)" means Section 162(m) of the Code, or any successor section under the Code, as amended from time to time and as interpreted by final or proposed regulations promulgated thereunder from time to time.

3.46"Securities Act" means the Securities Act of 1933 and the rules and regulations promulgated thereunder, or any successor law, as amended from time to time.

3.47"Secretary" means the corporate secretary of the Sponsor.

3.48"Sponsor" means Progress Energy, Inc., or any successor thereto.

3.49"Sponsor's Pension Plan" means the Progress Energy Pension Plan, as amended from time to time, and any successor thereto.

3.50"Stock" means the common stock of the Sponsor.

3.51"Stock Appreciation Right" means the right to receive an amount equal to the excess of the Fair Market Value of a share of Stock (as determined on the date of exercise) over the Fair Market Value of the Stock on the Award Date of the Stock Appreciation Right.

3.52"Stock Unit Award" means an Award of Stock or units granted under Section 11 of the Plan.

3.53"Sub-Plan" means a written document that permits the grant of Awards consistent with the provisions of this Plan.

3.54"Vesting Service" means each year of employment with the Company in which a Participant works one thousand (1,000) hours.

Section 4.Administration

4.1The Committee. The Plan shall be administered and interpreted by the Committee which shall have full authority and all powers necessary or desirable for such administration. The express grant in this Plan of any specific power to the Committee shall not be construed as limiting any power or authority of the Committee. In its sole and complete discretion the Committee may adopt, alter, suspend and repeal any such administrative rules, regulations, guidelines, and practices governing the operation of the Plan as it shall from time to time deem advisable. In addition to any other powers and, subject to the provisions of the Plan, the Committee shall have the following specific powers: (i) to determine the terms and conditions upon which the Awards may be made and exercised; (ii) to determine all terms and provisions of each Agreement and/or Sub-Plan, which need not be identical for types of Awards nor for the same type of Award to different Participants; (iii) to construe and interpret the Agreements, Sub-Plans and the Plan; (iv) to establish, amend, or waive rules or regulations for the Plan's administration; (v) to accelerate the exercisability of any Award, the length of a Performance Period or the termination of any Period of Restriction except for Awards to Covered Participants that are intended to qualify for the Performance-Based Exception, other than as may be otherwise provided under the terms of such an Award in the event of a Change in Control or as hereinafter specified; and (vi) to make all other determinations and take all other actions necessary or advisable for the administration of the Plan, including a determination of a Change in Control under Section 3.9. The Committee may take action by a meeting in person, by unanimous written consent, or by meeting with the assistance of communications equipment which allows all Committee members participating in the meeting to communicate in either oral or written form. The Committee may seek the assistance or advice of any persons it deems necessary to the proper administration of the Plan.

4.2Selection of Participants Other Than Outside Directors. Subject to Section 5 of the Plan, the Committee shall have sole and complete discretion in determining Key Employees who shall participate in the Plan; provided, however, the Committee may delegate to the CEO the authority to designate Key Employees and/or Awards to be made to Key Employees who are not Executive Officers, subject to any limitations imposed by the Committee on the designation of Key Employees including a fixed maximum Award amount for any group of Key Employees and/or a maximum Award amount for any one Key Employee, as determined by the Committee. Awards made to the Executive Officers shall be determined by the Committee.

4.3Awards to Outside Directors. Awards to Outside Directors shall be made in the sole discretion of the full Board of Directors; provided, however, that Awards of Options to Outside Directors shall be limited to Nonqualified Stock Options.

4.4Award Agreements and Sub-Plans. Each Award granted under the Plan shall be granted either under the terms of an Award Agreement and/or a Sub-Plan. Award Agreements and Sub-Plans shall specify the terms, conditions and any rules applicable to the Award, including but not limited to the effect of transferability, a Change in Control, or death, Disability, Divestiture, Early Retirement, Normal Retirement or other termination of employment of the Participant on the Award. If the Award is granted under the terms of an Award Agreement, the Award Agreement shall be signed by an authorized representative of the Sponsor and the Participant, and a copy of the signed Award Agreement shall be provided to the Participant. If the Award is granted under the terms and conditions of a Sub-Plan, the Sub-Plan shall be approved by the Committee as an Exhibit to the Plan, and a copy of the Sub-Plan or a summary description thereof shall be provided to each Participant.

4.5Committee Decisions. All determinations and decisions made by the Committee pursuant to the provisions of the Plan shall be final, conclusive, and binding upon all persons, including the Company, its employees, Participants, and Designated Beneficiaries, and the Sponsor's shareholders, except when the terms of any sale or award of shares of Stock or any grant of rights or Options under the Plan are required by law or by the Articles of Incorporation or Bylaws of the Sponsor to be approved by the Sponsor's Board of Directors or shareholders prior to any such sale, award or grant.

4.6Rule 16b-3, Section 162(m) and Section 409A. Notwithstanding any other provision of the Plan, the Committee may impose such conditions on any Award, and the Board may amend the Plan in any such respects, as may be required to satisfy the requirements of Rule 16b-3, Section 162(m) and Section 409A.

4.7Indemnification of Committee. In addition to such other rights of indemnification as they may have as Outside Directors or as members of the Committee, the members of the Committee shall be indemnified by the Sponsor against reasonable expenses incurred from their administration of the Plan. Such reasonable expenses include, but are not limited to, attorneys' fees actually and reasonably incurred in connection with the defense of any action, suit or proceeding, or in connection with any appeal therein, to which they or any of them may be a party by reason of any action taken or failure to act under or in connection with the Plan or any Award granted or made hereunder, and all amounts reasonably paid by them in settlement thereof or paid by them in satisfaction of a judgment in any such action, suit or proceeding, if such members acted in good faith and in a manner which they believed to be in, and not opposed to, the best interests of the Company.

Section 5.Eligibility

Selection of Participants by the Committee or the CEO under Section 4.2 shall be subject to the following limitations: (i) no person owning, directly or indirectly, more than five percent (5%) of the total combined voting power of all classes of Stock shall be eligible to participate under the Plan; and (ii) only Full-time Employees shall be eligible to participate under the Plan, except that Outside Directors may be granted Nonqualified Stock Options or Restricted Stock Awards in accordance with Section 4.3.

Section 6.Shares of Stock Subject to the Plan

6.1Number of Shares. Subject to adjustment as provided below and except as otherwise provided in Section 6.4 and Section 6.5 herein, the maximum aggregate number of shares of Stock that may be issued pursuant to Awards made under the Plan shall not exceed fifteen million (15,000,000) shares of Stock, which may be in any combination of Options, Restricted Stock, Performance Shares or any other right or Option which is payable in the form of Stock. Additionally, shares of Stock available for issuance on the Effective Date under the 1997 Plan shall be transferred to the Plan and added to the shares available for the grant of Awards under this Plan. The maximum aggregate number of shares that may be granted in the form of Incentive Stock Options shall be ten million (10,000,000). The maximum aggregate number of shares of Stock that may be granted in the form of Restricted Stock shall be three million (3,000,000) and the maximum aggregate number of shares of Stock (or derivatives of shares of Stock) that may be granted in the form of Performance Shares, Performance Units or other Stock Unit Awards shall be four million (4,000,000). Shares of Stock may be available from the authorized but unissued shares of Stock. Except as provided in Sections 6.2 and 6.3 herein, the issuance of shares of Stock in connection with the exercise of, or as other payment for, Awards under the Plan shall reduce the number of shares of Stock available for future Awards under the Plan.

6.2Lapsed Awards of Forfeited Shares of Stock. In the event that (i) any Option or other Award granted under the Plan or the 1997 Plan terminates, expires, or lapses for any reason other than exercise of the Award, or (ii) if shares of Stock issued pursuant to the Awards are canceled or forfeited for any reason, the number of shares of Stock available for Awards under the Plan shall be increased by the number of shares of Stock that were subject to such Award; provided, however, that this provision shall not be construed to allow for the issuance of treasury stock.

6.3Delivery of Shares of Stock as Payment. In the event a Participant pays for any Option or other Award granted under the Plan through the delivery of previously acquired shares of Stock, the number of shares of Stock available for Awards under the Plan shall be increased by the number of shares of Stock surrendered by the Participant, subject to Rule 16b-3 as interpreted by the Securities and Exchange Commission or its staff; provided, however, that this provision shall not be construed to allow for the issuance of treasury stock.

6.4Capital Adjustments. The number and class of shares of Stock subject to each outstanding Award, the maximum number of shares of Stock that may be subject to an Award under Sections 7.7, 8.5, 9.6, 10.6, and 11.1, the Option Price (as hereinafter defined) and the aggregate number, type and class of shares of Stock for which Awards thereafter may be made shall be adjusted in the case of an event described in subsection (a) or (b) below; provided, however, that with respect to Incentive Stock Options such adjustment shall be made in a manner consistent with Section 424(a) of the Code and, with respect to Awards to Executive Officers, in a manner consistent with the requirements of Section 162(m) of the Code and the regulations promulgated thereunder. Such events include but are not limited to the following:

(a)If the outstanding shares of Stock of the Sponsor are increased, decreased or exchanged through merger, consolidation, sale of all or substantially all of the property of the Sponsor, reorganization, recapitalization, reclassification, stock dividend, stock split or other distribution in respect to such shares of Stock, for a different number or type of shares of Stock, or if additional shares of Stock or new or different shares of Stock are distributed with respect to such shares of Stock, an appropriate and proportionate adjustment shall be made in: (i) the maximum number of shares of Stock available for the Plan as provided in Section 6.1 herein, (ii) the type of shares of Stock or other securities available for the Plan, (iii) the number of shares of Stock subject to any then outstanding Awards under the Plan, and (iv) the price (including exercise price) for each share of Stock (or other kind of shares or securities) subject to then outstanding Awards, but without change in the aggregate purchase price as to which such Options remain exercisable or Restricted Stock releasable.

(b)If other events not specified above in this Section 6.4, such as any extraordinary cash dividend, split-up, spin-off, combination, exchange of shares, warrants or rights offering to purchase Stock, or other similar corporate event affect the Stock such that an adjustment is necessary to maintain the benefits or potential benefits intended to be provided under this Plan, then the Committee shall make adjustments to any or all of (i) the number and type of shares of Stock which thereafter may be optioned and sold or awarded or made subject to Stock Appreciation Rights under the Plan, (ii) the grant, exercise or conversion price of any Award made under the Plan thereafter, and (iii) the number and price (including Exercise Price) of each share of Stock (or other kind of shares or securities) subject to then outstanding Awards, but without change in the aggregate purchase price as to which such Options remain exercisable or Restricted Stock releasable. Any adjustment as provided above for Awards that are intended to qualify for the Performance-Based Exception shall be subject to any applicable restrictions set forth in Section 12 or in Section 162(m).

Any adjustment made by the Committee pursuant to the provisions of this Section 6.4 shall be final, binding and conclusive. A notice of such adjustment, including identification of the event causing such an adjustment, the calculation method of such adjustment, and the change in price and the number of shares of Stock, or securities, cash or property purchasable subject to each Award shall be sent to each affected Participant. No fractional interests shall be issued under the Plan based on such adjustments, and shall be forfeited.

6.5Acquisitions. In connection with the acquisition of any business by the Company or any of its Affiliates, any outstanding grants, awards or sales of options or other similar rights pertaining to such business may be assumed or replaced by grants or awards under the Plan upon such terms and conditions as the Committee determines. The date of any such grant or award shall relate back to the date of the initial grant or award being assumed or replaced, and service with the acquired business shall constitute service with the Company for purposes of such grant or award. Any shares of Stock underlying any grant or award or sale pursuant to any such acquisition shall be disregarded for purposes of applying the limitations, and shall not reduce the number of shares of Stock available, under Section 6.1 above. Notwithstanding any provision in this Plan to the contrary, the exercise price of any such Award may be below Fair Market Value in order to replace the value of another award in the sole discretion of the Committee.

Section 7.Stock Options

7.1Grant of Stock Options. Subject to the terms and provisions of the Plan and applicable law, the Committee, at any time and from time to time, may grant Options to Key Employees, and with respect to Outside Directors pursuant to approval by the Board, as it shall determine. Except with respect to Outside Directors, the Committee shall have sole and complete discretion in determining the type of Option granted, the Option Price (as hereinafter defined), the duration of the Option, the number of shares of Stock to which an Option pertains, any conditions imposed upon the exercisability of the Options, the conditions under which the Option may be terminated and any such other provisions as may be warranted to comply with the law or rules of any securities trading system or stock exchange. Notwithstanding the preceding, the Committee may delegate to the CEO authority to grant options in accordance with Section 4.2. Each Option grant shall have such specified terms and conditions detailed in an Award Agreement. The Agreement shall specify whether the Option is intended to be an Incentive Stock Option within the meaning of Section 422 of the Code, or a Nonqualified Stock Option.

7.2Option Price. The exercise price per share of Stock covered by an Option ("Option Price") shall be determined at the time of grant by the Committee, subject to Section 6.5 hereof and the limitation that the Option Price shall not be less than one hundred percent (100%) of the Fair Market Value of the Stock on the Grant Date.

7.3Exercisability. Options granted under the Plan shall be exercisable at such times and be subject to such restrictions and conditions as the Committee or the CEO, as the case may be, shall determine, which will be specified in the Award Agreement and need not be the same for each Participant. However, no Option may be exercisable within the first year following the Grant Date, except in the event of a Change in Control, or after the expiration of ten (10) years from the Grant Date.

7.4Limitations on Incentive Stock Options. Incentive Stock Options may be granted only to Participants who are employees of the Sponsor or of a "Parent Corporation" or "Subsidiary Corporation" (as defined in Sections 424(e) and (f) of the Code, respectively) at the Grant Date. The aggregate Fair Market Value (determined as of the time the Stock Option is granted) of the Stock with respect to which Incentive Stock Options are exercisable for the first time by a Participant during any calendar year (under all option plans of the Company and of any Parent Corporation or Subsidiary Corporation) shall not exceed one hundred thousand dollars ($100,000). For purposes of the preceding sentence, Incentive Stock Options will be taken into account in the order in which they are granted. The per-share exercise price of an Incentive Stock Option shall not be less than one hundred percent (100%) of the Fair Market Value of the Stock on the Grant Date, and no Incentive Stock Option may be exercised later than ten (10) years after the date it is granted. In addition, no Incentive Stock Option may be issued to a Participant in tandem with a Nonqualified Stock Option. Further, Incentive Stock Options may not be granted to any Participant who, at the time of grant, owns stock possessing (after the application of the attribution rules of Section 424(d) of the Code) more than ten percent (10%) of the total combined voting power of all classes of stock of the Company or any Parent Corporation or Subsidiary Corporation, unless the exercise price of the option is fixed at not less than one hundred ten percent (110%) of the Fair Market Value of the Stock on the Grant Date and the exercise of such Option is prohibited by its terms after the expiration of five (5) years from the Grant Date of such Option.

7.5Method of Exercise. Options shall be exercised by the delivery of a notice from the Participant to the Secretary (or his or her designee) in the form prescribed by the Committee setting forth the number of shares of Stock with respect to which the Option is to be exercised, accompanied by full payment for the shares of Stock. The Option Price shall be payable to the Sponsor in full in cash, or its equivalent, or by delivery of shares of Stock (not subject to any security interest or pledge) valued at Fair Market Value at the time of exercise or by a combination of the foregoing. In addition, the Committee may permit the Cashless Exercise of the Option. As soon as practicable after receipt of notice and payment, the Sponsor shall deliver to the Participant Stock certificates in an appropriate amount based upon the number of shares of Stock with respect to which the Option is exercised, issued in the Participant's name.

7.6Notice. Each Participant shall give prompt notice to the Sponsor of any disposition of shares of Stock acquired upon exercise of an Incentive Stock Option if such disposition occurs within either two (2) years after the Grant Date or one (1) year after the date of transfer of such shares of Stock to the Participant upon the exercise of such Incentive Stock Option.

7.7Maximum Award. The maximum number of shares of Stock that may be granted in the form of Options pursuant to any Award granted in a single calendar year to any one Participant shall be two million (2,000,000).

7.8Limitation on Transferability. Solely to the extent permitted by the Committee in an Award Agreement and subject to the terms and conditions as the Committee shall specify, a Nonqualified Stock Option (but not an Incentive Stock Option) may be transferred to members of the Participant's immediate family (as determined by the Committee) or to trusts, partnerships or corporations whose beneficiaries, members or owners are members of the Participant's immediate family, and/or to such other persons or entities as may be approved by the Committee in advance and set forth in an Award Agreement, in each case subject to the condition that the Committee be satisfied that such transfer is being made for estate or tax planning purposes or for gratuitous or donative purposes, without consideration (other than nominal consideration) being received therefor. Except to the extent permitted by the Committee in accordance with the foregoing, an Option shall be nontransferable otherwise than by will or by the laws of descent and distribution, and shall be exercisable during the lifetime of the Participant only by such Participant.

Section 8.Stock Appreciation Rights

8.1Grant of Stock Appreciation Rights. Subject to the terms and provisions of the Plan and applicable law, the Committee, at any time and from time to time, may grant freestanding Stock Appreciation Rights, Stock Appreciation Rights in tandem with an Option, or Stock Appreciation Rights in addition to an Option. Stock Appreciation Rights granted in tandem with an Option or in addition to an Option may be granted at the time of the Option or at a later time.

8.2Price. The exercise price of each Stock Appreciation Right shall be determined at the time of grant by the Committee, subject to the limitation that the grant price shall not be less than one hundred percent (100%) of Fair Market Value of the Stock on the Grant Date.

8.3Exercise. The Participant shall be entitled to receive payment upon exercise of a Stock Appreciation Right in accordance with Section 8.4.

8.4Payment. Upon exercise of the Stock Appreciation Right, the Participant shall be entitled to receive payment from the Company in an amount determined by multiplying (a) the difference between the Fair Market Value of a share of Stock on the date of Exercise of the Stock Appreciation Right over the grant price specified in the Award Agreement by (b) the number of shares of Stock with respect to which the Stock Appreciation Right is exercised.

8.5Maximum Award. The maximum number of shares of Stock that may be subject to Stock Appreciation Rights granted to any Participant during a single calendar year shall be two million (2,000,000).

Section 9.Restricted Stock

9.1Grant of Restricted Stock. Subject to the terms and provisions of the Plan and applicable law, the Committee, at any time and from time to time, may grant shares of Restricted Stock under the Plan to such Participants, and in such amounts and for such duration and/or consideration as it shall determine. Participants receiving Restricted Stock Awards are not required to pay the Sponsor or the Company therefor (except for applicable tax withholding) other than the rendering of services and/or other consideration as determined by the Committee at its sole discretion.

9.2Restricted Stock Agreement. Each Restricted Stock grant shall be evidenced by an Agreement that shall specify the Period of Restriction; the conditions which must be satisfied prior to removal of the restriction; the number of shares of Restricted Stock granted; and such other provisions as the Committee shall determine. The Committee may specify, but is not limited to, the following types of restrictions in the Award Agreement: (i) restrictions on acceleration or achievement of terms or vesting based an any business or financial goals of the Company, including, but not limited to the Performance Measures set out in Section 3.33, and (ii) any further restrictions that may be advisable under the law, including requirements set forth by the Securities Act, any securities trading system or stock exchange upon which such shares under the Plan are listed.

9.3Removal of Restrictions. Except as otherwise noted in this Section 9, Restricted Stock covered by each Award made under the Plan shall be provided to and become freely transferable by the Participant after the last day of the Period of Restriction and/or upon the satisfaction of other conditions as determined by the Committee. Except as specifically provided in this Section 9, the Committee shall have no authority to reduce or remove the restrictions or to reduce or remove the Period of Restriction without the express consent of the shareholders of the Sponsor. If the grant of Restricted Stock is performance-based, the total Restricted Period for any or all shares or units of Restricted Stock so granted shall be no less than one (1) year. Any other shares of Restricted Stock issued pursuant to this Section 9 shall provide that the minimum Period of Restrictions shall be three (3) years, which Period of Restriction may permit the removal of restrictions on no more than one-third (1/3) of the shares of Restricted Stock at the end of the first year following the Grant Date, and the removal of the restrictions on an additional one-third (1/3) of the shares at the end of each subsequent year. Notwithstanding the previous sentence, if a Participant terminates employment from the Company at or following Early Retirement or Normal Retirement, any time-based Period of Restriction may be removed at the discretion of the Committee. In no event shall any restrictions be removed from shares of Restricted Stock during the first year following the Grant Date, except due to retirement as described in the preceding sentence or in the event of a Change in Control.

9.4Voting Rights. During the Period of Restriction, Participants in whose name Restricted Stock is granted under the Plan may exercise full voting rights with respect to those shares.

9.5Dividends and Other Distributions. During the Period of Restriction, Participants in whose name Restricted Stock is granted under the Plan shall be entitled to receive all dividends and other distributions paid with respect to those shares. If any such dividends or distributions are paid in shares, the shares shall be subject to the same restrictions on transferability as the Restricted Stock with respect to which they were distributed.

9.6Maximum Award. The maximum number of shares of Stock that may be granted in the form of Restricted Stock pursuant to an Award granted to a Participant during a single calendar year shall be two hundred fifty thousand (250,000).

Section 10.Performance-Based Awards

10.1Grant of Performance Awards. Subject to the terms and provisions of the Plan and applicable law, the Committee, at any time and from time to time, may issue Performance Awards in the form of either Performance Units or Performance Shares to Participants subject to the Performance Measures and Performance Period as it shall determine. The Committee shall have complete discretion in determining the number and value of Performance Units or Performance Shares granted to each Participant. Participants receiving Performance Awards are not required to pay the Sponsor or a Subsidiary or Affiliate therefor (except for applicable tax withholding) other than the rendering of services.

10.2Value of Performance Awards. The Committee shall determine the number and value of Performance Units or Performance Shares granted to each Participant as a Performance Award. The Committee shall set Performance Measures in its discretion for each Participant who is granted a Performance Award. The extent to which such Performance Measures are met will determine the value of the Performance Unit to the Participant or the number of Performance Shares earned by the Participant. Such Performance Measures may be particular to a Participant, may relate to the performance of the Affiliate which employs him or her, may be based on the division which employs him or her, may be based on the performance of the Company generally, or a combination of the foregoing. The terms and conditions of each Performance Award will be set forth in an Agreement and/or a Sub-Plan.

10.3Settlement of Performance Awards. After a Performance Period has ended, the holder of a Performance Unit or Performance Share shall be entitled to receive the value thereof based on the degree to which the Performance Measures established by the Committee and set forth in the Agreement and/or Sub-Plan have been satisfied.

10.4Form of Payment. Payment of the amount to which a Participant shall be entitled upon the settlement of a Performance Award shall be made in cash, Stock, or a combination thereof as determined by the Committee. Payment may be made in a lump sum or installments as prescribed by the Committee.

10.5Deferral of Performance Awards. The Committee may permit a Participant to elect, in accordance with Section 409A and rules prescribed by the Committee, not to receive a distribution upon the vesting of such Performance Award and instead have the Company continue to maintain the Performance Award on its books of account.

10.6Maximum Award. The maximum number of shares of Stock that may be the subject of a Performance Share Award granted to a Participant in a single calendar year shall be two hundred fifty thousand (250,000) shares or if less, ten million dollars ($10,000,000) of Stock (rounded to the nearest whole share). The maximum amount of compensation payable, without regard to any deferred amounts, to a Participant pursuant to the grant of Performance Unit Awards in any calendar year shall be ten million dollars ($10,000,000).

Section 11.Other Stock-Based Awards

11.1Grant of Other Stock-Based Awards. Subject to the terms and provisions of the Plan and applicable law, the Committee, at any time and from time to time, may issue to Participants, either alone or in addition to other Awards made under the Plan, Stock Unit Awards which may be in the form of or based on Stock or other securities. The maximum number of shares of Stock that may be granted in any calendar year to a Participant as part of a Stock Unit Award shall be two hundred fifty thousand (250,000). If the value of any Stock Unit Award is not based entirely on the value of the underlying Stock, the maximum amount of compensation payable, without regard to any deferred amounts, to a Participant pursuant to the grant of all such Stock Unit Awards in any calendar year shall be two million five hundred thousand dollars ($2,500,000). The Committee, in its sole and complete discretion, may determine that an Award, either in the form of a Stock Unit Award under this Section 11 or as an Award granted pursuant to Sections 7 through 10, may provide to the Participant (i) dividends or dividend equivalents (payable on a current or deferred basis) and (ii) cash payments in lieu of or in addition to an Award. Subject to the provisions of the Plan, the Committee in its sole and complete discretion, shall determine the terms, restrictions, conditions, vesting requirements, and payment rules (all of which are sometimes hereinafter collectively referred to as "rules") of the Award. The Award Agreement and/or Sub-Plan shall specify the rules of each Award as determined by the Committee. However, each Stock Unit Award need not be subject to identical rules.

11.2Rules. The Committee, in its sole and complete discretion, may grant a Stock Unit Award subject to the following rules:

(a)Stock or other securities issued pursuant to Stock Unit Awards may not be sold, transferred, pledged, assigned or otherwise alienated or hypothecated by a Participant until the expiration of at least six months from the Award Date, except that such limitation shall not apply in the case of death or Disability of the Participant. All rights with respect to such other Stock Unit Awards granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant or his or her guardian or legal representative.

(b)Stock Unit Awards may require the payment of cash consideration by the Participant in receipt of the Award or provide that the Award, and any Stock or other securities issued in conjunction with the Award be delivered without the payment of cash consideration.

(c)The Committee, in its sole and complete discretion, may establish certain Performance Measures that may relate in whole or in part to receipt of the Stock Unit Awards.

(d)Stock Unit Awards may be subject to a deferred payment schedule and/or vesting over a specified employment period.

(e)The Committee, in its sole and complete discretion, as a result of certain circumstances, may waive or otherwise remove, in whole or in part, any restriction or condition imposed on a Stock Unit Award at the time of grant.

11.3Deferral of Stock Unit Awards. The Committee may permit a Participant to elect, in accordance with Section 409A and rules prescribed by the Committee, not to receive a distribution upon the vesting of a Stock Unit Award and instead have the Company continue to maintain the Stock Unit on its books of account.

Section 12.Special Provisions Applicable to Covered Participants.

Unless the Committee in its sole discretion determines that any Award made to a Covered Employee is not intended to qualify for the Performance-Based Exception under Section 162(m), Awards subject to Performance Measures that are granted to Covered Participants under this Plan shall be governed by the conditions of this Section 12, in addition to the requirements of Sections 9, 10, and 11 above. Should conditions set forth under this Section 12 (when applicable) conflict with the requirements of Sections 9, 10, and 11, the conditions of this Section 12 shall prevail.

(a)Performance Measures for Covered Participants shall be established by the Committee in writing prior to the beginning of the Performance Period, or by such other later date during the Performance Period as may be permitted under Section 162(m). Performance Measures for Covered Participants may include alternative and multiple Performance Measures and may be based on one or more business criteria.

(b)All Performance Measures must be objective and must satisfy third party "objectivity" standards under Section 162(m).

(c)The Performance Measures shall not allow for any discretion by the Committee as to an increase in any Award, but discretion to lower an Award is permissible.

(d)The Award and payment of any Award under this Plan to a Covered Participant with respect to relevant Performance Period shall be contingent upon the attainment of the Performance Measures that are applicable to such Covered Participant. The Committee shall certify in writing prior to payment of any such Award that such applicable Performance Measures relating to the Award are satisfied. Approved minutes of the Committee may be used for this purpose.

(e)All Awards to Covered Participants under this Plan shall be further subject to such other conditions, restrictions, and requirements as the Committee may determine to be necessary to carry out the purpose of this Section 12.

Section 13.General Provisions

13.1Withholding. The Company shall have the right to deduct or withhold, or require a Participant to remit to the Company, any taxes, including employment taxes, required by law to be withheld with respect to the Awards made under this Plan. In the event an Award is paid in the form of Stock, the Committee may require the Participant to remit to the Company the amount of any taxes required to be withheld from such payment in Stock, or, in lieu thereof the Company may withhold (or the Participant may be provided the opportunity to elect to tender) the number of shares of Stock equal in Fair Market Value to the amount required to be withheld.

13.2No Right to Employment. No granting of an Award shall be construed as a right to employment with the Company.

13.3Rights as Shareholder. Subject to the Award provisions, no Participant or Designated Beneficiary shall be deemed a shareholder of the Sponsor nor have any rights as such with respect to any shares of Stock to be provided under the Plan until he or she has become the holder of such shares. Notwithstanding the aforementioned, with respect to Stock granted under a Restricted Stock Agreement under this Plan, the Participant or Designated Beneficiary of such Award shall be deemed the owner of such shares. As such, unless contrary to the provisions herein or in any such related Award Agreement, such shareholder shall be entitled to full voting, dividend and distribution rights as provided any other Sponsor shareholder.

13.4Construction of the Plan. The Plan, and its rules, rights, Agreements, Sub-Plans and regulations, shall be governed, construed, interpreted and administered in accordance with applicable Federal laws, or to the extent that Federal laws do not apply, the laws of the State of North Carolina. In the event any provision of the Plan shall be held invalid, illegal or unenforceable, in whole or in part, for any reason, such determination shall not affect the validity, legality or enforceability of any remaining provision, or portion of provision, of the Plan overall, which shall remain in full force and effect.

13.5Amendment of Plan. The Committee or the Board of Directors may amend, suspend, or terminate the Plan or any portion thereof at any time, provided (a) such amendment is made with shareholder approval if such approval is necessary to comply with any tax or regulatory requirement, including for these purposes any approval requirement for the Performance-Based Exception under Section 162(m), and (b) such amendment may not adjust or amend the exercise price of Options previously granted to a Participant without further shareholder approval except as provided in Sections 6.4 and 6.5 hereof. The Committee in its discretion may amend the Plan so as to conform with any applicable regulatory requirements subject to any provisions to the contrary specified herein.

13.6Amendment of Award. At any time and in its sole and complete discretion, the Committee may amend any Award for the following reasons: (i) additions and/or changes are made to the Code, any federal or state securities law, or other law or regulations subsequent to the Grant Date, and have an impact on the Award; or (ii) for any other reason not described in clause (i), provided (a) such amendment does not adversely affect a Participant or, if it does, provided the Participant gives his or her consent to such amendment, and (b) such amendment may not adjust or amend the exercise price of Options previously granted to a Participant without further shareholder approval except as provided in Sections 6.4 and 6.5 hereof.

13.7Exemption from Computation of Compensation for Other Purposes. By accepting an Award under this Plan, each Participant agrees that such Award shall be considered special incentive compensation and will be exempt from inclusion as "wages" or "salary" for purposes of calculating benefits under pension, profit sharing, disability, severance, life insurance, and other employee benefit plans of the Company, except as otherwise provided in those benefit plans.

13.8Legend. In its sole and complete discretion, the Committee may elect to legend certificates representing shares of Stock sold or awarded under the Plan, to make appropriate references to the restrictions imposed on such shares.

13.9Executive Officers and Covered Participants. All Award Agreements and/or Sub-Plans for Participants subject to Section 16(b) shall be deemed to include any such additional terms, conditions, limitations and provisions as Rule 16b-3 requires, unless the Committee in its discretion determines that any such Award should not be governed by Rule 16b3. All Awards subject to the Performance-Based Exception shall be deemed to include any such additional terms, conditions, limitations and provisions as are necessary to comply with the Performance-Based Compensation exemption of Section 162(m), unless the Committee, in its sole discretion, determines that an Award to a Covered Participant is not intended to qualify for the Performance-Based Exception.

13.10Change in Control. In the event of a Change in Control, the Committee may provide, in its sole and complete discretion, either within the terms of the Award Agreement or subsequently, for the acceleration of the payment and/or vesting of any Award, the extension of the time during which an Award is exercisable to its full term regardless of a Participant's termination of employment with the Company and/or the release of any restrictions on any Award.

13.11Divestiture. In the event of a Divestiture, the Committee may provide, in its sole and complete discretion, either within the terms of the Award Agreement or subsequently, for the acceleration of the payment and/or vesting of any Award, the extension of the time during which an Award is exercisable to its full term regardless of a Participant's termination of employment with the Company and/or the release of any restrictions on any Award or the assumption of an Award as contemplated in Section 13.14.

13.12Unfunded Obligation. Nothing in this Plan shall be interpreted or construed to require the Company in any manner to fund any obligation to the Participants or any Designated Beneficiary. Nothing contained in this Plan nor any action taken hereunder shall create, or be construed to create a trust of any kind, or a fiduciary relationship between the Company and/or the Committee, and the Participants and/or any Designated Beneficiary. To the extent that any Participant or Designated Beneficiary acquires a right to receive payments under this Plan, such rights shall be no greater than the rights of any unsecured general creditor of the Sponsor.

13.13Plan Expenses. All reasonable expenses of the Plan shall be paid by the Company.

13.14Transfer. The sponsorship of this Plan may be assumed by any Affiliate of the Sponsor in the case of a reorganization of the Sponsor and its Affiliates, or by any successor in interest of the Sponsor. Further, in the event any Award under the Plan is assumed by an Affiliate or another entity in connection with the disposition or sale of any business of the Sponsor and its Affiliates, the Award so assumed shall be cancelled under the Plan.

13.15Deferred Compensation. In the event an Award is considered “deferred compensation,” as defined for purposes of Section 409A, such Award shall be deemed to include such additional terms, conditions, limitations and provisions as may be required for it not to be subject to excise tax under Section 409A. In no event may the time or schedule of any payment of deferred compensation under the Plan be accelerated except as provided under Section 409A.

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006

     PROGRESS ENERGY, INC.

      By: /s/ Robert B. McGehee

            < font id="TAB2" style="LETTER-SPACING: 9pt">         Robert B. McGehee

                                                               Chief Executive Officer

239485 Legal

EX-10.C6

Exhibit 10c(6)

EXHIBIT B

TO

2002 EQUITY INCENTIVE PLAN

BROAD-BASED PERFORMANCE SHARE SUB-PLAN

(As amended effective January 1, 2007)

This Broad-Based Performance Share Sub-Plan (“Sub-Plan”) sets forth the rules and regulations adopted by the Committee for issuance of Performance Share Awards under Section 10 of the 2002 Equity Incentive Plan (“Plan”). These rules and regulations shall apply to Awards granted effective on and after January 1, 2005. Capitalized terms used in this Sub-Plan that are not defined herein shall have the meaning given in the Plan. In the event of any conflict between this Sub-Plan and the Plan, the terms and conditions of the Plan shall control. No award Agreement shall be required for participation in this Sub-Plan.

Section 1. Definitions

When used in this Sub-Plan, the following terms shall have the meanings as set forth below, and are in addition to the definitions set forth in the Plan.

1.1 “Account” means the account used to record and track the number of Performance Shares granted to each Participant as provided in Section 2.4.

1.2 “Award” as used in this Sub-Plan means each aggregate award of Performance Shares as provided in Section 2.2.

1.3 “EBITDA” means earnings before interest, taxes, depreciation, and amortization as determined from time to time by the Committee.

1.4 “EBITDA Growth” means the percentage increase (if any) in EBITDA for any Year, as compared to the previous Year as determined from time to time by the Committee.

1.5 “Peer Group” means the peer group of utilities designated by the Committee prior to the beginning of the Performance Period for which an Award is granted.

1.6 “Performance Period” for purposes of this Sub-Plan means three consecutive Years beginning with the Year in which an Award is granted.

1.7 “Performance Schedule” means Attachment 1 to this Sub-Plan, which sets forth the Performance Measures applicable to this Sub-Plan.

1.8 “Performance Share” for purposes of this Sub-Plan means each unit of an Award granted to a Participant, the value of which is equal to the value of Company Stock as hereinafter provided.

1.9 “Retire” or “Retirement” means termination of employment on or after:

(a)becoming 65 years old with at least 5 years of service;

(b)becoming 55 years old with at least 15 years of service; or

(c)achieving at least 35 years of service, regardless of age.

1.10 “Salary” means the regular base rate of compensation payable by the Company to a Participant on an annual basis. Salary does not include bonuses, if any, or incentive compensation, if any. Such compensation shall not be reduced by any deferrals made under any other plans or programs maintained by the Company.

1.11 “Total Shareholder Return” means the total percentage return realized by the owner of a share of stock during a relevant Year or any part thereof. Total Shareholder Return is equal to the appreciation or depreciation in value of the stock (which is equal to the closing value of the stock on the last trading day of the relevant period minus the closing value of the stock on the last trading day of the preceding Year) plus the dividends declared during the relevant period, divided by the closing value of the stock on the last trading day of the preceding Year.

1.12 “Year” means a calendar year.

Section 2. Sub-Plan Participation and Awards

2.1Participation Selection. Participants under this Sub-Plan shall be recommended by the Chief Executive Officer of the Sponsor and approved by the Committee in its sole discretion as provided in Section 4.2 of the Sponsor of the Plan.

2.2Awards. Subject to any adjustments to be made under Section 2.5, the Committee may, in its sole discretion, grant Awards to some or all of the Participants in the form of a specific number of Performance Shares. The target and maximum value of any Award granted to any Participant in any calendar Year will be based upon the following:

Participant	Target Award	Maximum Award
Key Managers
Level I	25% of Salary	31.25% of Salary
Level II	15% of Salary	18.75% of Salary

2.3Award Valuation at Grant. In calculating the value of an Award for purposes of Section 2.2, the value of each Performance Share shall be equal to the closing price of a share of Stock on the last trading day of the Year before the Performance Period begins. The Participant’s Salary shall be determined as of the January 1 preceding the date the Award is granted, or such other time as is determined in the discretion of the Committee. Each Award is deemed to be granted on the day that it is approved by the Committee.

2.4Accounting and Adjustment of Awards. The number of Performance Shares awarded to a Participant shall be recorded in a separate Account for each Participant. The number of Performance Shares recorded in a Participant’s Account shall be adjusted to reflect any splits or other adjustments in the Stock. If any cash dividends are paid on the Stock, the number of Performance Shares in each Participant’s Account shall be increased by a number equal to (i) the dividend multiplied by the number of Performance Shares in each Participant’s Account, divided by (ii) the closing price of a share of Stock on the payment date of the dividend. No adjustment shall be made to any outstanding Awards of a Retired Participant for cash dividends paid on Stock during the Performance Period following the Retirement of the Participant.

2.5Performance Schedule and Calculation of Awards. Except as otherwise provided, each Award shall become vested on January 1 immediately following the end of the applicable Performance Period, subject to adjustment in accordance with the following procedure. In no event shall such date be construed to be earlier than January 1 immediately following the end of the applicable Performance Period:

(a)One-half of the Award shall be adjusted as follows:

(i)The Total Shareholder Return for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the “Company TSR”).

(ii)The average Total Shareholder Return for the Peer Group utilities shall be determined for each Year during the Performance Period, and shall then be averaged (the “Peer Group TSR”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group TSR.

(iii)The Peer Group TSR for the Performance Period shall be subtracted from the Company TSR for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(b)The other one-half of the Award shall be adjusted as follows:

(i)The EBITDA Growth for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the “Company EBITDA Growth”).

(ii)The average EBITDA Growth for the Peer Group utilities shall be determined for each Year during the Performance period, and shall be averaged (the “Peer Group EBITDA Growth”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group EBITDA Growth.

(iii)The Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(c)Except as provided in Section 3, the total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above.

(d)The Performance Measures and the Performance Schedule will not change during any Performance Period with regard to any Awards that have already been granted. The Committee reserves the right to modify or adjust the Performance Measures and/or the Performance Schedule in the Committee’s sole discretion with regard to future grants.

2.6Payment of Awards. Except as provided in Section 3, Awards shall be paid after expiration of the Performance Period. The Company will issue one share of Stock in payment for each vested Performance Share (rounded to the nearest whole Performance Share) credited to the Account of the Participant. Payment shall be made during the month of April of the Year immediately following expiration of the Performance Period, or as soon as practicable thereafter.

Section 3. Vesting and Forfeiture

3.1Retirement. In the event of the Retirement of the Participant, any outstanding Awards of the Participant for any unexpired Performance Period shall immediately vest on a prorated basis, beginning with January 1 of the Performance Period and ending with the month prior to the Retirement date. The vested portion of the Participant’s outstanding Awards shall be adjusted in accordance with Section 2.5 and paid in accordance with Section 2.6 following the end of the Performance Period for the Award. If the Participant dies following Retirement but prior to the expiration of the Performance Period, the Participant’s outstanding Awards shall be adjusted and paid in accordance with Section 3.4.

3.2Death or Divestiture. If the Participant dies prior to expiration of the Performance Period, or terminates employment as the result of a Divestiture during a Performance Period, any outstanding Awards of the Participant for any unexpired Performance Period shall vest on a prorated basis beginning with January 1 of the Performance Period and ending with the last month completed prior to the date the participant dies or the date of the termination as a result of the Divestiture. The Participant’s outstanding Awards shall be adjusted and paid in accordance with Section 3.4.

3.3Change in Control. In the event of a Change in Control prior to the expiration of the Performance Period, any outstanding Award of the Participant for any unexpired Performance Period shall be treated as follows:

(a)If the Award is assumed by the successor to the Sponsor as of the date of the Change in Control, each outstanding Award not previously forfeited shall continue to vest and shall be paid pursuant to the terms of this Sub-Plan; provided, however, that in the event the employment of the Participant is terminated by the Company without Cause following the Change in Control, any outstanding Award shall become fully vested as of the termination date, and the aggregate value of the Award shall be paid after being adjusted in accordance with Section 3.4.

 (b)If the Award is not assumed by the successor to the Sponsor as of the date of the Change in Control, any outstanding Award shall become vested as of the date of the Change in Control, and the aggregate value of the Award shall be paid after being adjusted in accordance with Section 3.4.

3.4Adjustment and Payment of Awards. Any Award which is vested prior to the end of the Performance Period due to the death of the Participant, termination of employment as a result of a Divestiture, or Change in Control during the Performance Period, or becomes payable upon death following Retirement pursuant to Section 3.1 above shall be adjusted and paid pursuant to the following procedure:

(a)One-half of the Award shall be adjusted as follows:

(i)The Company TSR shall be determined for each Year or partial Year, and a weighted average Company TSR shall be calculated for the period between the first day of the Performance Period and the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.3 (the “Prorated Company TSR”).

(ii)The average Peer Group TSR shall be determined for each Year or partial Year, and a weighted average Peer Group TSR shall be calculated for the period between the first day of the Performance Period and the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.3 (the “Prorated Peer Group TSR”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group TSR.

(iii)The Prorated Peer Group TSR for the Performance Period shall be subtracted from the Prorated Company TSR for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(b)The other one-half of the Award shall be adjusted as follows:

(i)The Company EBITDA Growth shall be determined for each Year or partial Year, and a weighted average Company EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.3 (the “Prorated Company EBITDA Growth”).

(ii)The average Peer Group EBITDA Growth shall be determined for each Year or partial Year, and a weighted average Peer Group EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.3 (the “Prorated Peer Group EBITDA Growth”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group EBITDA Growth.

(iii) The Prorated Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Prorated Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(c)The total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above.

(d)In the event of the death of the Participant, payment shall be made within a reasonable time after the Participant dies to the Participant’s Designated Beneficiary. In the event of the termination of employment of the Participant as a result of a Divestiture, payment shall be made within a reasonable time after the date of termination. If the Award vests pursuant to Section 3.3, the Award shall be paid within a reasonable time after the date of vesting. The Company will issue one share of Stock in payment for each Performance Share (rounded to the nearest whole Performance Share) credited to the Account of the Participant.

3.5Termination of Employment. In the event that a Participant’s employment with the Company terminates for any reason other than as provided in this Section 3, any Award made to the Participant which has not vested as provided in Section 2 or Section 3 shall be forfeited.

Section 4. Non-Assignability of Awards

The Awards and any right to receive payment under the Plan and this Sub-Plan may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a Participant becomes bankrupt, then in the sole discretion of the Committee, any Award made to the Participant which has not vested as provided in Sections 2 and 3 shall be forfeited.

Section 5. Amendment and Termination

This Sub-Plan shall be subject to amendment, suspension, or termination as provided in the Plan.

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

     PROGRESS ENERGY, INC.

            ;  By: /s/ Robert B. McGehee

            < font id="TAB2" style="LETTER-SPACING: 9pt">    Robert B. McGehee

            ;                   Chief Executive Officer

ATTACHMENT 1

PERFORMANCE SCHEDULE

PERFORMANCE SHARE CALCULATION¹

The following table shall be used to adjust one half of the Participant’s Award in accordance with Section 2.5(a) or Section 3.4(a) of the Plan.

If the Company TSR2 minus the Peer Group TSR2 is:	Then the 50% of the vested Performance Share Award shall be multiplied by:
5% or better	2.00
4.0 - 4.99	1.75
3.0 - 3.99	1.50
2.0 - 2.99	1.25
1.0 - 1.99	1.00
(0.99) - 0.99	.50
(1.0) - (1.99)	.25
(2.0) or less	0.00

The following table shall be used to adjust one half of the Participant’s Award in accordance with Section 2.5(b) or Section 3.4(b) of the Plan:

If the Company EBITDA Growth2 minus the Peer Group EBITDA Growth2 is:	Then the 50% of the vested Performance Share Award shall be multiplied by:
5% or better	2.00
4.0 - 4.99	1.75
3.0 - 3.99	1.50
2.0 - 2.99	1.25
1.0 - 1.99	1.00
0.00 - 0.99	.50
Less than 0	0

¹The number of Performance Shares as calculated above shall be paid in accordance with the provisions of Section 2.5 and 2.6 of this Sub-Plan.

² For purposes of Section 3, the Prorated Company TSR and EBITDA Growth and Prorated Peer Group TSR and EBITDA Growth shall be used, and the number of Performance Shares as calculated above shall be paid in accordance with the provisions of this Sub-Plan.

EX-10.C7

Exhibit 10c(7)

EXHIBIT A

TO

2002 EQUITY INCENTIVE PLAN

EXECUTIVE AND KEY MANAGER PERFORMANCE SHARE SUB-PLAN

(As amended effective January 1, 2007)

This Executive and Key Manager Performance Share Sub-Plan (“Sub-Plan”) sets forth the rules and regulations adopted by the Committee for issuance of Performance Share Awards under Section 10 of the 2002 Equity Incentive Plan (“Plan”). These rules and regulations shall apply to Awards granted effective on and after January 1, 2005. In addition, the rules and regulations relating to the deferral of Awards set forth in this Sub-Plan shall apply to any Awards which become vested on or after January 1, 2005. Capitalized terms used in this Sub-Plan that are not defined herein shall have the meaning given in the Plan. In the event of any conflict between this Sub-Plan and the Plan, the terms and conditions of the Plan shall control. No Award Agreement shall be required for participation in this Sub-Plan.

Section 1. Definitions

When used in this Sub-Plan, the following terms shall have the meanings as set forth below, and are in addition to the definitions set forth in the Plan.

1.1 “Account” means the account used to record and track the number of Performance Shares granted to each Participant as provided in Section 2.4.

1.2 “Award” as used in this Sub-Plan means each aggregate award of Performance Shares as provided in Section 2.2.

1.3 “EBITDA” means earnings before interest, taxes, depreciation, and amortization as determined from time to time by the Committee.

1.4 “EBITDA Growth” means the percentage increase (if any) in EBITDA for any Year, as compared to the previous Year as determined from time to time by the Committee.

1.5 “Peer Group” means the peer group of utilities designated by the Committee prior to the beginning of the Performance Period for which an Award is granted.

1.6 “Performance Period” for purposes of this Sub-Plan means three consecutive Years beginning with the Year in which an Award is granted.

1.7 “Performance Schedule” means Attachment 1 to this Sub-Plan, which sets forth the Performance Measures applicable to this Sub-Plan.  

1.8 “Performance Share” for purposes of this Sub-Plan means each unit of an Award granted to a Participant, the value of which is equal to the value of Company Stock as hereinafter provided.

1.9 “Retire” or “Retirement” means Separation from Service on or after:

(a) becoming 65 years old with at least 5 years of service;

(b) becoming 55 years old with at least 15 years of service; or

(c) achieving at least 35 years of service, regardless of age.

1.10 “Salary” means the regular base rate of compensation payable by the Company to a Participant on an annual basis. Salary does not include bonuses, if any, or incentive compensation, if any. Such compensation shall not be reduced by any deferrals made under any other plans or programs maintained by the Company.

1.11 “Section 409A” means Section 409A of the Code, or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time.

1.12 “Separation from Service” means the death, Retirement or other termination of employment with the Company as defined for purposes of Section 409A of the Code.

1.13 “Total Shareholder Return” means the total percentage return realized by the owner of a share of stock during a relevant Year or any part thereof. Total Shareholder Return is equal to the appreciation or depreciation in value of the stock (which is equal to the closing value of the stock on the last trading day of the relevant period minus the closing value of the stock on the last trading day of the preceding Year) plus the dividends declared during the relevant period, divided by the closing value of the stock on the last trading day of the preceding Year.

1.14 “Year” means a calendar year.

Section 2. Sub-Plan Participation and Awards

2.1Participant Selection. Participants under this Sub-Plan shall be selected by the Committee in its sole discretion as provided in Section 4.2 of the Sponsor of the Plan.

2.2Awards. Subject to any adjustments to be made under Section 2.5, the Compensation Committee may, in its sole discretion, grant Awards to some or all of the Participants in the form of a specific number of Performance Shares. The target and maximum value of any Award granted to any Participant in any calendar Year will be based upon the following:

Participant	Target Award	Maximum Award
CEO*	290% of Salary	362.5% of Salary
COO*	200% of Salary	250% of Salary
Presidents*/Executive VPs*	133% of Salary	166.25% of Salary
Senior VPs*	110% of Salary	137.5% of Salary
VP/Department Heads** Level I Level II Level III	100% of Salary 80% of Salary 60% of Salary	125% of Salary 100% of Salary 75% of Salary
Key Managers	55% of Salary	68.75% of Salary

* Senior Management Committee level position

**Levels shall be determined in the sole discretion of the Committee

2.3Award Valuation at Grant. In calculating the value of an Award for purposes of Section 2.2, the value of each Performance Share shall be equal to the closing price of a share of Stock on the last trading day of the Year before the Performance Period begins. The Participant’s Salary shall be determined as of the January 1 preceding the date the Award is granted, or such other time as is determined in the discretion of the Committee. Each Award is deemed to be granted on the day that it is approved by the Committee.

2.4Accounting and Adjustment of Awards. The number of Performance Shares awarded to a Participant shall be recorded in a separate Account for each Participant. The number of Performance Shares recorded in a Participant’s Account shall be adjusted to reflect any splits or other adjustments in the Stock. If any cash dividends are paid on the Stock, the number of Performance Shares in each Participant’s Account shall be increased by a number equal to (i) the dividend multiplied by the number of Performance Shares in each Participant’s Account, divided by (ii) the closing price of a share of Stock on the payment date of the dividend. No adjustment shall be made to any outstanding Awards of a Retired Participant for cash dividends paid on Stock during the Performance Period following the Retirement of the Participant.

2.5Performance Schedule and Calculation of Awards. Except as otherwise provided, each Award shall become vested on January 1 immediately following the end of the applicable Performance Period, subject to adjustment in accordance with the following procedure. In no event shall such date be construed to be earlier than January 1 immediately following the end of the applicable Performance Period:

(a)One-half of the Award shall be adjusted as follows:

(i)The Total Shareholder Return for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the “Company TSR”).

(ii)The average Total Shareholder Return for the Peer Group utilities shall be determined for each Year during the Performance Period, and shall then be averaged ( the “Peer Group TSR”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group TSR.

(iii)The Peer Group TSR for the Performance Period shall be subtracted from the Company TSR for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(b)The other one-half of the Award shall be adjusted as follows:

(i)The EBITDA Growth for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the “Company EBITDA Growth”).

(ii)The average EBITDA Growth for the Peer Group utilities shall be determined for each Year during the Performance period, and shall be averaged (the “Peer Group EBITDA Growth”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group EBITDA Growth.

(iii)The Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(c)Except as provided in Section 3, the total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above.

(d)The Performance Measures and the Performance Schedule will not change during any Performance Period with regard to any Awards that have already been granted. The Committee reserves the right to modify or adjust the Performance Measures and/or the Performance Schedule in the Committee’s sole discretion with regard to future grants.

2.6Payment Options. Except as provided in Section 3, Awards shall be paid after expiration of the Performance Period. The Company will issue one share of Stock in payment for each vested Performance Share (rounded to the nearest whole Performance Share) credited to the Account of the Participant. Payment shall be made as follows:

(a)100% during the month of April of the Year immediately following expiration of the Performance Period, or as soon as practicable thereafter; or

(b)in accordance with an alternative payment election made by Participant substantially in the form attached hereto as Attachment 2, provided that such election is executed by the Participant and returned to the Vice President, Human Resources Department no later than the end of the first Year of the Performance Period. Once made, this election shall be irrevocable except as may be permitted by rules promulgated under Section 409A and allowed by the Committee. A deferral election may only be made by a Participant who is employed as a Department Head or in a higher position on the date the deferral election is solicited. Awards that are deferred pursuant to this Section 2.6(b) are referred to herein as “Deferred Awards.”

2.7Grantor Trust. In the case of a Change in Control, the Company shall, subject to the restrictions in this Section 2.7 and Section 13.12 of the Plan, irrevocably set aside shares of Stock or cash in one or more such grantor trusts in an amount that is sufficient to pay each Participant employed by such Company (or Designated Beneficiary), the net present value as of the date on which the Change in Control occurs, of the earned benefits to which Participants (or their Designated Beneficiaries) would be entitled pursuant to the terms of the Plan if the value of their deferral account (if any) established pursuant to section 2.6(b) would be paid in a lump sum upon the Change in Control. Any such trust shall be subject to the claims of the general creditors of the Sponsor or Company in the event of bankruptcy or insolvency of the Sponsor or Company. Notwithstanding the foregoing provisions of this Section 2.7, the Company shall establish no such trust if the assets thereof shall be includable in the income of Participants thereby pursuant to Section 409A(b).

Section 3. Early Vesting and Forfeiture

3.1Retirement, Death or Divestiture. If the Participant Retires or dies prior to expiration of the Performance Period, or terminates employment as the result of a Divestiture during a Performance Period, any outstanding Awards of the Participant for any unexpired Performance Period shall immediately become vested. Payment of the outstanding Awards of such Participant shall be subject to the following special provisions:

(a)In the event of the Retirement of the Participant, the Participant’s outstanding Awards shall be adjusted in accordance with Section 2.5 and paid in accordance with Section 2.6 following the end of the Performance Period for the Award; provided, that if the Participant has elected to defer payment until a specified date certain and Retires before the date specified in the deferral election, the Company will commence distribution of the Deferred Award as soon as practicable on or after the later of: (i) the April 1 following the first anniversary of the date of Retirement, or (ii) the April 1 of the year following the end of the Performance Period, even though said date is earlier than the date specified in the deferral election. If the Participant dies following Retirement but prior to the expiration of the Performance Period, the Participant’s outstanding Awards shall be adjusted and paid in accordance with Section 3.3.

(b)In the event of the death of the Participant, or termination of employment as the result of a Divestiture during a Performance Period, the Participant’s outstanding Awards shall be adjusted and paid in accordance with Section 3.3.

3.2  Change in Control. In the event of a Change in Control prior to the expiration of the Performance Period, any outstanding Award of the Participant for any unexpired Performance Period shall be treated as follows:

     (a)If the Award is assumed by the successor to the Sponsor as of the date of the Change in Control, each outstanding Award not previously forfeited shall continue to vest and shall be paid pursuant to the terms of this Sub-Plan; provided, however, that in the event the employment of the Participant is terminated by the Company without Cause following the Change in Control, any outstanding Award shall become vested as of the termination date, and the aggregate value of the Award shall be paid after being adjusted in accordance with Section 3.3.

(b)If the Award is not assumed by the successor to the Sponsor as of the date of the Change in Control, any outstanding Award shall become vested as of the date of the Change in Control, and the aggregate value of the Award shall be paid after being adjusted in accordance with Section 3.3.

3.3Adjustment and Payment of Awards. Any Award which is vested prior to the end of the Performance Period due to the death of the Participant, termination of employment as a result of a Divestiture a Change in Control during the Performance Period, or becomes payable upon death following Retirement pursuant to Section 3.1(a) above shall be adjusted and paid pursuant to the following procedure:

(a)One-half of the Award shall be adjusted as follows:

(i)The Company TSR shall be determined for each Year or partial Year, and a weighted average Company TSR shall be calculated for the period between the first day of the Performance Period and the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the “Prorated Company TSR”).

(ii)The average Peer Group TSR shall be determined for each Year or partial Year, and a weighted average Peer Group TSR shall be calculated for the period between the first day of the Performance Period and the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the “Prorated Peer Group TSR”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group TSR.

(iii)The Prorated Peer Group TSR for the Performance Period shall be subtracted from the Prorated Company TSR for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

(b)The other one-half of the Award shall be adjusted as follows:

(i)The Company EBITDA Growth shall be determined for each Year or partial Year, and a weighted average Company EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the “Prorated Company EBITDA Growth”).

(ii)The average Peer Group EBITDA Growth shall be determined for each Year or partial Year, and a weighted average Peer Group EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the “Prorated Peer Group EBITDA Growth”). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group EBITDA Growth.

(iii)The Prorated Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Prorated Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant’s Account.

                (c)The total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above.

(d)In the event of the death of the Participant, payment shall be made within a reasonable time after the Participant dies to the Participant’s Designated Beneficiary. In the event of the termination of employment of the Participant as a result of a Divestiture payment shall be made within a reasonable time after the date of termination. If the Award vests pursuant to Section 3.2, the Award shall be paid within a reasonable time after the date of vesting. However, with respect to Deferred Awards, if the Participant is a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees), payment shall not be made before the date that is six months after the date of Separation from Service (or, if earlier, the date of death of the Participant) and the amount of any payment made in cash (i.e., with respect to Awards granted prior to January 1, 2005) shall be based upon the value of the Performance Shares as determined by reference to the closing price of the Stock on the trading day occurring on or next following the date that is six months after the date of Separation from Service of the Participant (or, if earlier the date of death of the Participant). If the Award vests pursuant to Section 3.2(b), the Award shall be paid within a reasonable time after the date of vesting, notwithstanding any election under Section 2.6. The Company will issue one share of Stock in payment for each Performance Share (rounded to the nearest whole Performance Share) credited to the Account of the Participant.

3.4Termination of Employment. In the event that a Participant’s employment with the Company terminates for any reason other than as provided in this Section 3, any Award made to the Participant which has not vested as provided in Section 2 or Section 3 shall be forfeited. Provided such termination is Separation from Service, any vested Awards shall be paid within a reasonable time after Separation (for reasons other than Retirement), notwithstanding any election to defer the payment of any Award under Section 2.6. However, with respect to Deferred Awards, if the Participant is a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees), payment shall not be made before the date that is six months after the date of Separation from Service for any reason including Retirement (or, if earlier, the date of death of the Participant) and the amount of any payment made in cash (i.e., with respect to Awards granted prior to January 1, 2005) shall be based upon the value of the Performance Shares as determined by reference to the closing price of the Stock on the trading day occurring on or next following the date that is six months after the date of Separation from Service of the Participant (or, if earlier the date of death of the Participant).

Section 4. Non-Assignability of Awards

The Awards and any right to receive payment under the Plan and this Sub-Plan may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a Participant becomes bankrupt, then in the sole discretion of the Committee, any Award made to the Participant which has not vested as provided in Sections 2 and 3 shall be forfeited.

Section 5. Amendment and Termination

This Sub-Plan shall be subject to amendment, suspension, or termination as provided in the Plan. No action to amend, suspend or terminate this Sub-Plan shall permit the acceleration of the time or schedule of the payment of any Award granted under this Sub- Plan (except as provided in regulations under Section 409A).

Section 6. Section 409A

This Sub-Plan shall be administered in compliance with Section 409A.

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

    PROGRESS ENERGY, INC.

        By: /s/ Robert B. McGehee

            < font id="TAB2" style="LETTER-SPACING: 9pt">                  Robert B. McGehee

            < font id="TAB2" style="LETTER-SPACING: 9pt">      Chief Executive Officer

ATTACHMENT 1

PERFORMANCE SCHEDULE

PERFORMANCE SHARE CALCULATION¹

The following table shall be used to adjust one half of the Participant’s Award in

accordance with Section 2.5(a) or Section 3.4(a) of the Plan:

If the Company TSR2 minus the Peer Group TSR2 is:	Then the 50% of the vested Performance Share Award shall be multiplied by:
5% or better	2.00
4.0 - 4.99	1.75
3.0 - 3.99	1.50
2.0 - 2.99	1.25
1.0 - 1.99	1.00
(0.99) - 0.99	.50
(1.0) - (1.99)	.25
(2.0) or less	0.00

The following table shall be used to adjust one half of the Participant’s Award in

accordance with Section 2.5(b) or Section 3.3(b) of the Plan:

If the Company EBITDA Growth2 minus the Peer Group EBITDA Growth2 is:	Then the 50% of the vested Performance Share Award shall be multiplied by:
5% or better	2.00
4.0 - 4.99	1.75
3.0 - 3.99	1.50
2.0 - 2.99	1.25
1.0 - 1.99	1.00
0.00 - 0.99	.50
Less than 0	0

¹The number of Performance Shares as calculated above shall be paid in accordance with the provisions of

Section 2.5 and 2.6 of this Sub-Plan.

² For purposes of Section 3, the Prorated Company TSR and EBITDA Growth and Prorated Peer Group TSR

and EBITDA Growth shall be used, and the number of Performance Shares as calculated above shall be paid in accordance with the provisions of the Sub-Plan.

ATTACHMENT 2

PERFORMANCE SHARE SUB-PLAN

200_ DEFERRAL ELECTION FORM

As a Participant in the Performance Share Sub-Plan of the 2002 Equity Incentive Plan ("Sub-Plan"), I hereby elect to defer payment of my Award otherwise payable to me by the Company and attributable to services to be performed by me during the Performance Period beginning on January __, 200__. This election shall apply to [CHECK ONE]:

[ ]100% of the Award[ ] 50% of the Award

[ ]75% of the Award                              [ ] 25% of the Award

Upon vesting, I understand that my Award shall continue to be recorded in my Account as Performance Shares as described in the Sub-Plan and adjusted to reflect the payment and reinvesting of the Company’s common stock dividends over the deferral period, until paid in full.

I hereby elect to defer receipt (or commencement of receipt) of my Award until the date specified below, or as soon as practical thereafter [CHECK ONE]:*

[ ]a specific date certain at least 5 years from expiration of the Performance Period: 4 / 1 / 

   (month/day/year)

 

                [ ]  the April 1 following the date of Retirement, or if later, the date which is six months after the date of my Separation from Service for any reason (including Retirement),

                     if I am a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of

                     officers treated as key employees).

[ ]the April 1 following the first anniversary of my date of Retirement

* Notwithstanding any election above, if I elect a date certain distribution and I Retire before that date certain, I understand that the Company will commence distribution of my Account as soon as practicable on or after the later of: (i) the April 1 following the first anniversary of the date of Retirement, or (ii) the April 1 of the year following the end of the Performance Period, even though said date is earlier than 5 years from the expiration of the Performance Period.

I hereby elect to be paid as described in the Sub-Plan in the form of [CHECK ONE]:

[ ]a single payment  [ ] annual payments commencing on the date set forth above and payable

 on the anniversary date thereof over:

[ ] a two year period [ ] a three year period

        [ ] a four year period [ ] a five year period

I understand that I will receive “earnings” on those deferred amounts when they are paid to me.

I understand that the election made as indicated herein is irrevocable and that all deferral elections are subject to the provisions of the Sub-Plan, including provisions that may affect timing of distributions.

I understand that this deferral election is subject to the requirements of Section 409A of Code, and regulations and other guidance issued thereunder. The Company makes no representation or guarantee that any tax treatment, including, but not limited to, federal, state and local income, or estate and gift tax treatment, will be applicable with respect to the amounts deferred. The Company shall have no responsibility for the tax consequences that I may incur as a result of Section 409A, regulations or guidance issued thereunder, or any other provision of the Internal Revenue Code. I understand it is my responsibility to consult a legal or tax advisor regarding the tax effects of this deferral election. I further acknowledge and agree that the Company may (but shall not be required to) modify this election as necessary to comply with Section 409A and any guidance or regulations issued thereunder. I further agree to cooperate in any manner necessary to ensure that this election is in compliance with Section 409A and any guidance or regulations issued thereunder.

I understand and acknowledge that my interests herein and my rights to receive distribution of the deferred amounts may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or I become bankrupt, my interest may be terminated by the Committee, in its sole discretion, may cause the same to be held or applied for the benefit of one or more of my dependents or make any other disposition of such interests that it deems appropriate. I further understand that nothing in the Sub-Plan shall be interpreted or construed to require the Company in any manner to fund any obligation to me, or to my beneficiary(ies) in the event of my death.

(Signature)(Date)

(Print Name)(Company Location)

Received:

Agent of Chief Executive Officer

   (Signature)(Date)

EX-10.C8

Exhibit 10c(8)

AMENDED MANAGEMENT INCENTIVE COMPENSATION PLAN

OF

PROGRESS ENERGY, INC.

AS AMENDED JANUARY 1, 2007

TABLE OF CONTENTS

		Page
ARTICLE I	PURPOSE	1
ARTICLE II	DEFINITIONS	1
ARTICLE III	ADMINISTRATION	7
ARTICLE IV	PARTICIPATION	8
ARTICLE V	AWARDS	8
ARTICLE VI	DISTRIBUTION AND DEFERRAL OF AWARDS	11
ARTICLE VII	TERMINATION OF EMPLOYMENT	17
ARTICLE VIII	MISCELLANEOUS	18
EXHIBIT A	MICP RELATIVE PERFORMANCE WEIGHTINGS
EXHIBIT B	MANAGEMENT INCENTIVE EXAMPLE
EXHIBIT C	PARTICIPATING EMPLOYERS
FORM OF DESIGNATION OF BENEFICIARY

ARTICLE I

PURPOSE

The purpose of the Management Incentive Compensation Plan (the “Plan”) of Progress Energy, Inc. is to promote the financial interests of the Company, including its growth, by (i) attracting and retaining executive officers and other management-level employees who can have a significant positive impact on the success of the Company; (ii) motivating such personnel to help the Company achieve annual incentive, performance and safety goals; (iii) motivating such personnel to improve their own as well as their business unit/work group’s performance through the effective implementation of human resource strategic initiatives; and (iv) providing annual cash incentive compensation opportunities that are competitive with those of other major corporations.

The Sponsor amends and restates the Plan effective January 1, 2007. The terms of the amended and restated Plan shall govern the payment of any benefits commencing after January 1, 2007.

ARTICLE II

DEFINITIONS

The following definitions are applicable to the Plan:

1.“Achievement Factor”: The sum of the Weighted Achievement Percentages determined for each of the Performance Measures for the Year.

2.“Award”: The benefit payable to a Participant hereunder based upon achievement of the Performance Measures and as may be adjusted in accordance with Section 6 of Article V below.

3.“Affiliated Entity”: Any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Sections 414(b), (c), (m), or (o) of the Internal Revenue Code of 1986, as amended (the “Code”), but only to the extent required.

4.“Board”: The Board of Directors of the Sponsor.

5.“Cause”: Any of the following:

(a)   embezzlement or theft from the Company, or other acts of dishonesty, disloyalty or otherwise injurious to the Company;

(b)   disclosing without authorization proprietary or confidential information of the Company;

(c)   committing any act of negligence or malfeasance causing injury to the Company;

(d)   conviction of a crime amounting to a felony under the laws of the United States or any of the several states;

(e)   any violation of the Company’s Code of Ethics; or

(f)   unacceptable job performance which has been substantiated in accordance with the normal practices and procedures of the Company.

6.“Change in Control”: The earliest of the following dates:

(a)   the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or

(b)   the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or

(c)   the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or

(d)   the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or

(e)   the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor’s assets; or

(f)   the date of any event which the Board determines should constitute a Change in Control.

A Change in Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Compensation Committee that one of the events set forth in this Section 6 has occurred. Any determination that an event described in this Section 6 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Compensation Committee, the Sponsor, each Affiliated Entity, the Participant and their Beneficiaries for all purposes of the Plan.

7.“Company”: The Sponsor and each Affiliated Entity.

8.“Compensation Committee”: The Organization and Compensation Committee of the Board of Directors of the Sponsor.

9.“Continuing Director”: The members of the Board as of the Effective Date; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.

10.“Date of Retirement”: The first day of the calendar month immediately following the Participant’s Retirement.

11.“Designated Beneficiary”: The beneficiary designated by the Participant, pursuant to procedures established by the Human Resources Department of the Company, to receive amounts due to the Participant or to exercise any rights of the Participant to the extent permitted hereunder in the event of the Participant’s death. If the Participant does not make an effective designation, then the Designated Beneficiary will be deemed to be the Participant's estate.

12.“EBITDA”: The earnings of the Participating Employer before interest, taxes, depreciation, and amortization as determined from time to time by the Compensation Committee.

13.“ECIP Goals”: The goals set forth to receive a payment under the Employee Cash Incentive Plan of each department or business unit of the Company.

14.“Effective Date”: The Effective Date of this Plan, as amended, is January 1, 2007.

15.“EPS”: The on-going earnings per share of the Sponsor’s Common Stock for a Year as determined by the Compensation Committee from time to time.

16.“Legal Entity EBITDA”: The EBITDA of the Participating Employer which employs the Participant.

17.“Participant”: An employee of a Participating Employer who is selected pursuant to Article IV hereof to be eligible to receive an Award under the Plan.

18.“Participating Employer”: Each Affiliated Entity that, with the consent of the Compensation Committee, adopts the Plan and is included in Exhibit C, as in effect from time to time.

19.“Performance Measures”: The EPS, Legal Entity EBITDA and ECIP Goals.

20.“Performance Unit”: A unit or credit, linked to the value of the Sponsor’s Common Stock under the terms set forth in Article VI hereof.

21.“Plan”: The Management Incentive Compensation Plan of Progress Energy, Inc. as contained herein, and as it may be amended from time to time.

22.“Retirement”: A Participant’s termination of employment from the Companyon or after attaining (i) age 65 with 5 years of service, (ii) age 55 with 15 years of service, or (iii) 35 years of service.

23.“Salary”: The compensation paid by the Company to a Participant in a relevant Year, consisting of regular or base compensation, such compensation being understood not to include bonuses, if any, or incentive compensation, if any. Provided, that such compensation shall not be reduced by any cash deferrals of said compensation made under any other plans or programs maintained by such Company.

24.“Senior Management Committee”: The Senior Management Committee of the Company.

25.“Section 409A”: Section 409A of the Code, or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time and by related guidance.

26.“Separation from Service”: The death, Retirement or other termination of employment with the Company as defined for purposes of Section 409A.

27.“Sponsor”: Progress Energy, Inc., a North Carolina corporation, or any successor to it in the ownership of substantially all of its assets.

28.“Target Award Opportunity”: The target for an Award under this Plan as set forth in Section 1 of Article V hereof.

29.“Unforeseeable Emergency”: A severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse, or a dependent (as defined in Section 152(a) of the Code) of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.

30.“Weighted Achievement Percentage”: The percentage determined by multiplying the relative percentage weight assigned to each of the Performance Measures applicable to the Participant for the Year by the payout percentage corresponding to the level of achievement of the Performance Measure as determined for each department or business unit for the Year.

31.“Year”: A calendar year.

ARTICLE III

ADMINISTRATION

The Plan shall be administered by the Chief Executive Officer of the Sponsor. Except as otherwise provided herein, the Chief Executive Officer of the Sponsor shall have sole and complete authority to (i) select the Participants; (ii) establish and adjust (either before or during the Year) the performance criteria necessary for a Participant to attain an Award for the Year; (iii) adjust and approve Awards; (iv) establish from time to time regulations for the administration of the Plan; and (v) interpret the Plan and make all determinations deemed necessary or advisable for the administration of the Plan, all subject to its express provisions. Notwithstanding the foregoing, the Compensation Committee shall (a) approve the applicable threshold, target and outstanding levels of performance for a Performance Measure for the Year; (b) approve the performance criteria and Awards for all Participants who are members of the Senior Management Committee; (c) determine the total payout under the Plan up to a maximum of four percent (4%) of the Sponsor’s after-tax income for a relevant Year; and (d) certify to the Board that a Change in Control has occurred as provided in Section 6 of Article II.

A majority of the Compensation Committee shall constitute a quorum, and the acts of a majority of the members present at any meeting at which a quorum is present, or acts approved in writing by a majority of the members of the Committee without a meeting, shall be the acts of such Committee.

ARTICLE IV

PARTICIPATION

The Chief Executive Officer of the Sponsor shall select from time to time the Participants in the Plan for each Year from those employees of each Company who, in his opinion, have the capacity for contributing in a substantial measure to the successful performance of the Company that Year. No employee shall at any time have a right to be selected as a Participant in the Plan for any Year nor, having been selected as a Participant for one Year, have the right to be selected as a Participant in any other Year.

ARTICLE V

AWARDS

1.Target Award Opportunities. The following table sets forth Target Award Opportunities, expressed as a percentage of Salary, for various levels of participation in the Plan:

Participation	Target Award Opportunities
Chief Executive Officer of Sponsor*	85%
Chief Operating Officer of Sponsor*	70%
Presidents*/Executive Vice Presidents*	55%
Senior Vice Presidents*	45%
Department Heads	35%
Other Participants: Key Managers Other Managers	25% 20%

*Senior Management Committee level positions.

The Target Award Opportunity for the Chief Executive Officer of the Sponsor shall be 85%; however, the Compensation Committee of the Board shall be authorized to change that amount from year to year, or to award an amount of compensation based on other considerations, in its complete discretion.

2.Award Components. Awards under the Plan to which Participants are eligible shall depend upon the achievement of the Performance Measures for the Year. Prior to the beginning of each Year, or as soon as practical thereafter, the Chief Executive Officer of the Sponsor will establish and the Compensation Committee will approve the Performance Measures for the Year, their relative percentage weight, and the performance criteria necessary for attainment of various performance levels. Attached hereto as Exhibit A are the relative percentage weights for each of the Performance Measures for each level of participation as of the Effective Date, which may be changed from time to time by the Compensation Committee.

3.Performance Levels. The Compensation Committee may establish three levels of performance related to a Performance Measure: outstanding, target, and threshold. In such case, the payout percentages to be applied to each Participant’s Target Award Opportunity are as follows:

Performance LevelPayout Percentage

      Outstanding200%

           Target          100%

        Threshold                 50%

Payout percentages shall be adjusted for performance between the designated performance levels; provided, however, that performance which falls below the “Threshold” performance level results in a payout percentage of zero.

4.Determination of Award Amount. The Chief Executive Officer of the Sponsor shall determine the amount of the Award, if any, earned by each Participant for the Year; provided, that the Compensation Committee shall approve the amount of the Award for a Participant who is a member of the Senior Management Committee. The amount of an Award earned by the Participant shall be determined by multiplying the Salary times the Target Award Opportunity times the Achievement Factor applicable to the Participant for the Year. The amount of the Award of a Participant is subject to further adjustment as provided in Section 6 of this Article V.

5.New Participants. Any Award that is earned during the initial Year of participation shall be pro rated based on the length of time served in the qualifying job.

6.Adjustment of Award Amount. The Chief Executive Officer of the Sponsor, in his sole discretion, may adjust the Award for the Year payable to Participants who are not members of the Senior Management Committee based upon management’s determination of the performance goals and core skill achievement of the Participant, the succession planning leadership rating of the Participant and any other applicable performance criteria. Similar adjustments of Awards to Participants who are members of the Senior Management Committee shall be subject to approval by the Compensation Committee.

7.Example. Attached as Exhibit B and incorporated by reference is an example of the process by which an Award is granted hereunder. Exhibit B is intended solely as an example and in no way modifies the provisions of this Article V.

ARTICLE VI

DISTRIBUTION AND DEFERRAL OF AWARDS

1.Distribution of Awards. Unless a Participant elects to defer an Award pursuant to the remaining provisions of this Article VI, Awards under the Plan earned during any Year shall be paid in cash by March 15 of the succeeding Year.

2.Deferral Election. A Participant may elect to defer the Plan Award he or she will earn for any Year by completing and submitting a deferral election in a form acceptable to the Vice President, Human Resources, by the last day of the preceding Year (or such other time as permitted by Section 409A). Such election shall apply to the Participant’s Award, if any, otherwise to be paid after the Year during which it is earned. A Participant’s deferral election may apply to 100%, 75%, 50%, or 25% of the Plan Award; provided, however, that in no event shall the amount deferred be less than $1,000.

The election to defer shall be irrevocable as to the Award earned during the particular Year except as provided in Section 9 of this Article VI or as may be permitted by rules promulgated under Section 409A and the plan administrator.

3.Period of Deferral. At the time of a Participant’s deferral election, a Participant must also select a distribution date and form of distribution. Subject to Section 6, the distribution date may be: (a) any date that is at least five (5) years subsequent to the date the Plan Award would otherwise be payable, but not later than the second anniversary of the Participant’s Date of Retirement; or (b) any date that is within two years following the Participant’s Date of Retirement. Subject to Section 6, the form of distribution may be either (i) a lump sum or (ii) equal installments over a period extending from two years to ten years, as elected by the Participant. A Participant may not subsequently change the distribution date and form of distribution designated in the initial deferral election.

4.Performance Units. All Awards which are deferred under the Plan shall be recorded in the form of Performance Units. Each Performance Unit is generally equivalent to a share of the Sponsor’s Common Stock. In converting the cash award to Performance Units, the number of Performance Units granted shall be determined by dividing the amount of the Award by 85% of the average value of the opening and closing price of a share of the Sponsor’s Common Stock on the last trading day of the month preceding the date of the Award. The Performance Units attributable to the 15% discount from the average value of the Sponsor’s Common Stock shall be referred to as the “Incentive Performance Units.” The Incentive Performance Units and any adjustments or earnings attributable to those Performance Units shall be forfeited by the Participant if he or she terminates employment either voluntarily or involuntarily other than for death or Retirement prior to five years from March 15 of the Year in which payment would have been made if the Award had not been deferred; provided, however, that if before such date the employment of the Participant is terminated by the Company without Cause following a Change in Control, the Incentive Performance Units shall not be forfeited but shall be payable to the Participant in accordance with Section 8 of this Article VI.

5.Plan Accounts. A Plan Deferral Account will be established on behalf of each Participant, and the number of Performance Units awarded to a Participant shall be recorded in each Participant’s Plan Deferral Account as of the first of the month coincident with or next following the month in which a deferral becomes effective. The number of Performance Units recorded in a Participant’s Plan Deferral Account shall be adjusted to reflect any splits or other adjustments in the Sponsor’s Common Stock, the payment of any cash dividends paid on the Sponsor’s Common Stock and the payment of Awards under this Plan to the Participant. To the extent that any cash dividends have been paid on the Sponsor’s Common Stock, the number of Performance Units shall be adjusted to reflect the number of Performance Units that would have been acquired if the same dividend had been paid on the number of Performance Units recorded in the Participant’s Plan Deferral Account on the dividend record date. For purposes of determining the number of Performance Units acquired with such dividend, the average of the opening and closing price of the Sponsor’s Common Stock on the payment date of the Sponsor’s Common Stock dividend shall be used.

Each Participant shall receive an annual statement of the balance of his Plan Deferral Account, which shall include the Incentive Performance Units and associated earnings and adjustments that are subject to being forfeited as provided above.

6.Payment of Deferred Plan Awards. Subject to Section 4 related to forfeiture of Incentive Performance Units, deferred Plan Awards shall be paid in cash by each Company on the deferred distribution date specified by the Participant in accordance with Section 3, or as soon as practicable thereafter. To convert the Performance Units in a Participant’s Plan Deferral Account to a cash payment amount, Performance Units shall be multiplied by the average of the opening and closing price of the Sponsor’s Common Stock on the last trading day preceding the applicable distribution date specified by the Participant for the deferred Plan Award. Except as otherwise provided, deferred amounts will be paid either in a single lump-sum payment or in up to ten (10) annual payments as elected by the Participant at the time of the deferral election.

In the event that a Participant elects to receive the deferred Plan Award in equal annual payments, the amount of the Award to be received in each year shall be determined as follows:

(a)To determine the amount of the initial annual payment, the number of Performance Units in the Participant’s Plan Deferral Account will be divided by the total number of annual payments to be received, and the result will be multiplied by the average of the opening and closing price of the Sponsor’s Common Stock on the last trading day preceding the due date of the initial payment.

(b)To determine the amount of each successive annual payment, the Plan Deferral Account balance will be divided by the number of annual payments remaining, and the result will be multiplied by the average of the opening and closing price of the Sponsor’s Common Stock on the last trading day preceding the due date of the annual payment.

7.Termination of Employment/Effect on Deferral Election. If the employment of a Participant terminates prior to the last day of a Year for which a Plan Award is determined, then any deferral election made with respect to such Plan Award for such Year shall not become effective and any Plan Award to which the Participant is otherwise entitled shall be paid as soon as practicable after the end of the Year during which it was earned, in accordance with Section 1 of this Article VI.

8.Separation from Service/Payment of Deferral. Notwithstanding the foregoing, if a Participant Separates from Service by reason other than death or Retirement, full payment of all amounts due to the Participant shall be made on the first day of the month following the date of Separation, or as soon as practicable thereafter. However, if the Participant is a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees), payment shall not be made before the date that is six months after the date of Separation from Service for any reason including Retirement (or, if earlier, the date of death of the Participant). Incentive Performance Units shall be subject to forfeiture to the extent provided in Section 4.

9.Payments Due to Unforeseeable Emergency. In the event of an Unforeseeable Emergency, a Participant may apply to receive a distribution earlier than initially elected. The Chief Executive Officer of Sponsor or his designee may, in his sole discretion, either approve or deny the request. The determination made by the Chief Executive Officer of Sponsor will be final and binding on all parties. If the request is granted, the amount distributed will not exceed the amount necessary to satisfy the emergency need plus amounts necessary to pay taxes reasonably anticipated to result from the distribution, after taking into account the extent to which such hardship is or may be relieved through cancellation of a deferral election under this Section 9, reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets (to the extent such liquidation of assets would not itself cause severe financial hardship). Any deferral election made with respect to a Plan Award that would otherwise become payable by the next succeeding March 15 shall be cancelled and such Plan Award shall be paid in cash by the next succeeding March 15 pursuant to Section 1. Incentive Performance Units shall not be subject to early distribution under this Section 9 until five years from March 15 of the Year in which payment would have been made if the Award had not been deferred.

10.Death of a Participant. If the death of a Participant occurs before a full distribution of the Participant’s Plan Deferral Account is made, the remaining portion of the Participant’s Plan Deferral Account shall be paid in a lump sum to the Designated Beneficiary of the Participant based on the value of such account immediately following the date of death. Said payment shall be made as soon as practicable following notification that death has occurred.

11.Non-Assignability of Interests. The interests herein and the right to receive distributions under this Article VI may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or a Participant becomes bankrupt, the interests of the Participant under this Article VI may be terminated by the Chief Executive Officer of Sponsor, which, in his sole discretion, may cause the same to be held or applied for the benefit of one or more of the dependents of such Participant or make any other disposition of such interests that he deems appropriate.

12.Unfunded Deferrals. Nothing in this Plan, including this Article VI, shall be interpreted or construed to require the Sponsor or any Company in any manner to fund any obligation to the Participants, terminated Participants or beneficiaries hereunder. Nothing contained in this Plan nor any action taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between the Sponsor or any Company and the Participants, terminated Participants, beneficiaries, or any other persons. Any funds which may be accumulated in order to meet any obligation under this Plan shall for all purposes continue to be a part of the general assets of the Sponsor or Company. The Sponsor or Company may establish a trust to hold funds intended to provide benefits hereunder to the extent the assets of such trust become subject to the claims of the general creditors of the Sponsor or Company in the event of bankruptcy or insolvency of the Sponsor or Company. To the extent that any Participant, terminated Participant, or beneficiary acquires a right to receive payments from the Sponsor or Company under this Plan, such rights shall be no greater than the rights of any unsecured general creditor of the Sponsor or Company.

13.Change in Control. In the case of a Change in Control, the Company shall, subject to the restrictions in this Section 13 and Section 12 of Article VI, irrevocably set aside funds in one or more such grantor trusts in an amount that is sufficient to pay each Participant employed by such Company (or Designated Beneficiary) the net present value as of the date on which the Change in Control occurs, of the benefits to which Participants (or their Designated Beneficiaries) would be entitled pursuant to the terms of the Plan if the value of their Plan Deferral Account would be paid in a lump sum upon the Change in Control.

14.Limitation on Trust. Notwithstanding the provisions of the foregoing Sections 12 and 13, the Company shall establish no such trust if the assets thereof shall be includable in the income of Participants thereby pursuant to Section 409A(b).

ARTICLE VII

TERMINATION OF EMPLOYMENT

Except as otherwise provided in this Article VII, a Participant must be actively employed by the Company on the next January 1 immediately following the Year for which a Plan Award is earned in order to be eligible for payment of an Award for that Year. In the event the active employment of a Participant shall terminate or be terminated for any reason, including death, before the next January 1 immediately following the Year for which a Plan Award is earned, such Participant shall receive his or her Award for the year, if any, in an amount that the Chief Executive Officer of the Sponsor deems appropriate. Notwithstanding the foregoing provisions of this Article VII, in the event the employment of the Participant is terminated by the Company without Cause within one (1) year following a Change in Control, the Award of the Participant for the Year in which the termination occurs shall equal the amount of the Award which would have been earned for the Year if the Participant had remained in the employment of the Company through December 31, pro rated to reflect the portion of the Year completed by the Participant as an employee; provided, however, that such Award shall not be less than the Target Award Opportunity of the Participant for the Year, pro rated to reflect the portion of the Year completed by the Participant as an employee.

ARTICLE VIII

MISCELLANEOUS

1.Assignments and Transfers. The rights and interests of a Participant under the Plan may not be assigned, encumbered or transferred except, in the event of the death of a Participant, by will or the laws of descent and distribution.

2.Employee Rights Under the Plan. No Company employee or other person shall have any claim or right to be granted an Award under the Plan or any other incentive bonus or similar plan of the Sponsor or any Company. Neither the Plan, participation in the Plan nor any action taken hereunder shall be construed as giving any employee any right to be retained in the employ of the Sponsor or any Company.

3.Withholding. The Sponsor or Company (as applicable) shall have the right to deduct from all amounts paid in cash any taxes required by law to be withheld with respect to such cash payments.

4.Amendment or Termination. The Compensation Committee may in its sole discretion amend, suspend or terminate the Plan or any portion thereof at any time; provided, that in the event of a Change in Control, no such action shall take effect prior to the January 1 next following the Year in which occurs the Change in Control. No action to amend, suspend or terminate the Plan shall affect the right of a Participant to the payment of a Plan Award earned prior to the effective date of such action, or permit the acceleration of the time or schedule of any payment of amounts deferred under the Plan (except as provided in regulations under Section 409A).

5.Governing Law. This Plan shall be construed and governed in accordance with the laws of the state of North Carolina to the extent not preempted by federal law and in a manner consistent with the requirements of Section 409A.

6.Entire Agreement. This document (including the Exhibits attached hereto) sets forth the entire Plan.

(Signature page follows)

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

     PROGRESS ENERGY, INC.

 By: /s/ Robert B. McGehee

        Robert B. McGehee

        Chief Executive Officer

EXHIBIT A

MICP RELATIVE PERFORMANCE WEIGHTINGS

POSITION	COMPANY EPS	LEGAL  ENTITY EBITDA	ECIP GOALS
SMC - CEO	100%	-	-
SMC - COO	45%	55%	-
SMC - Presidents	45%	55%	-
SMC - Service Company CEO	100%	-	-
SMC - Non Service Company	35%	65%	-
SMC - Service Company	100%	-	-
Non Service Company Department Heads and Managers	25%	50%	25%
Service Company Department Heads and Managers	45%	30%	25%

Note: This structure may be modified from time to time as provided in Section 2 of Article V of the Plan. In addition, the Compensation Committee may consider ECIP Goals in determining any reduction of Awards of Participants who are members of the Senior Management Committee.

EXHIBIT B

MANAGEMENT INCENTIVE EXAMPLE
(Assumes preliminary PDP and Succession Planning rates are complete)
Step 1: Calculate achievement factor for members of a department
	Achievement Level	Achievement Percentage	Weighting (see Pro Rate %)	Achievement Factor
PGN EPS	Target	100%	25.0%	25.0%
Legal entity EBITDA	Outstanding	200%	50.0%	100.0%
ECIP goals	At least 7	100%	25.0%	25.0%
	Total achievement factor			150.0% Would be calculated for each BU
Step 2:Apply achievement factor to target levels
	Target %	Achievement Factor	Initial Payout %
Department Head	35.0%	150.0%	52.5%
Section Manager	25.0%	150.0%	37.5%
Unit Manager	20.0%	150.0%	30.0%
Step 3:Determine dollars eligible by department:
	Salary	Target %	Initial Payout %	Calculated Award
John Doe, Department Head	200,000	35.0%	52.5%	105,000
Jane Doe, Section Manager	100,000	25.0%	37.5%	37,500
John Smith, Section Manager	120,000	25.0%	37.5%	45,000
Jane Smith, Unit Manager	80,000	20.0%	30.0%	24,000
John Jones, Unit Manager	75,000	20.0%	30.0%	22,500
Jane Jones, Unit Manager	90,000	20.0%	30.0%	27,000
				261,000
Step 4:Provide each group executive a list of their departments and calculated award totals. Allow them to redistribute dollars based on organization performance within group.
Step 5:Allocate dollars by group and department:
	Salary	Target %	Initial Payout %	Calculated Award	Discretionary Adjustment	Actual Award	Award %
John Doe	200,000	35%	52.5%	105,000	(12,600)	92,400	46.2%
Jane Doe	100,000	25%	37.5%	37,500	5,000	42,500	42.5%
John Smith	120,000	25%	37.5%	45,000	(3,000)	42,000	35%
Jane Smith	80,000	20%	30.0%	24,000	-	24,000	30%
John Jones	75,000	20%	30.0%	22,500	5,000	27,500	36.7%
Jane Jones	90,000	20%	30.0%	27,000	(10,400)	16,600	18.4%
				261,000		245,000
		Per group executive, department total to spend is $245,000
		(Step 4)
General notes:
The departmental sheets would still be rolled into group level sheets and reviewed by level as in prior years (all dh’s together, 25% participants, 20% participants) Discretion based on PDP (core skills and performance goals) and succession planning ratings Discretionary percentage should reflect a range of +/- TBD% of payout % for group Steps 1 & 2 (MICP) fund determination) based on legal entities. Steps 3-5 (MICP allocation) utilize reporting organization/group.

EXHIBIT C

PARTICIPATING EMPLOYERS

Progress Energy Carolinas, Inc.

Progress Energy Service Company, LLC

Progress Energy Florida, Inc.

Progress Energy Ventures, Inc.

Progress Fuels Corporation (corporate employees)

DESIGNATION OF BENEFICIARY

MANAGEMENT INCENTIVE COMPENSATION PLAN

OF

PROGRESS ENERGY, INC.

As provided in the Management Incentive Compensation Planof Progress Energy, Inc., I hereby designate the following person as my beneficiary in the event of my death before a full distribution of my Deferral Account is made.

PRIMARY BENEFICIARY:

_______________________________

_______________________________

_______________________________

CONTINGENT BENEFICIARY:

_______________________________

_______________________________

_______________________________

Any and all prior designations of one or more beneficiaries by me under the Management Incentive Compensation Plan of Progress Energy, Inc. are hereby revoked and superseded by this designation. I understand that the primary and contingent beneficiaries named above may be changed or revoked by me at any time by filing a new designation with the Sponsor’s Human Resources Department.

DATE:__________________

SIGNATURE OF PARTICIPANT:_________________________________

The Participant named above executed this document in our presence on the date set forth above.

WITNESS::__________________   WITNESS:                                                   

EX-10.C9

Exhibit 10c(9)

PROGRESS ENERGY, INC.

AMENDED AND RESTATED

MANAGEMENT DEFERRED COMPENSATION PLAN

Adopted as of January 1, 2000

(As Revised and Restated effective January 1, 2007)

TABLE OF CONTENTS

			Page
PREAMBLE			1
ARTICLE I		DEFINITIONS	2
	1.1	Account Balance	2
	1.2	Additional Deferral Election	2
	1.3	Affiliated Company	2
	1.4	Board	2
	1.5	Board Committee	2
	1.6	Change in Control	2
	1.7	Change of Form Election	4
	1.8	Change-of-Investment Election	4
	1.9	Code	4
	1.10	Committee	5
	1.11	Company	5
	1.12	Company Incentive Plans	5
	1.13	Continuing Directors	5
	1.14	Deemed Investment Return	5
	1.15	Deferral Election	5
	1.16	Deferrals	6
	1.17	Effective Date	6
	1.18	Eligible Employee	6
	1.19	Employee Stock Incentive Plan	6
	1.20	Enrollment Form	6
	1.21	ERISA	6
	1.22	Incentive Matching Allocations	6
	1.23	Investment Election	7
	1.24	Matching Allocation	7
	1.25	Net Salary	7
	1.26	Participant	7
	1.27	Participant Accounts	7
	1.28	Participant Company Account	7
	1.29	Participant Deferral Account	8
	1.30	Participant Matchable Deferral	8
	1.31	Payment Commencement	8
	1.32	Phantom Investment Fund	8
	1.33	Phantom Funds Account	9
	1.34	Phantom Investment Subaccount	9
	1.35	Phantom Stock Unit	9
	1.36	Plan	9
	1.37	Plan Year	9
	1.38	Plan Year Accounts	9
	1.39	Progress Energy 401(k) Savings & Stock Ownership Plan	10
	1.40	Retirement Date	10
	1.41	Salary	10
	1.42	Section 409A	10
	1.43	Separation from Service	10
	1.44	SMC Participant	11
	1.45	Sponsor	11
	1.46	SSERP	11
	1.47	Valuation Date	11
	1.48	Value	11
	1.49	Years of Service	11
ARTICLE II		PARTICIPATION	12
	2.1	Eligibility	12
	2.2	Commencement of Participation	12
	2.3	Annual Participation Agreement	12
	2.4	Election of Phantom	12
ARTICLE III		DEFERRAL ELECTIONS	13
	3.1	Participant Deferred Salary Elections	13
	3.2	Matching Allocations	14
	3.3	Incentive Matching Allocations	15
ARTICLE IV		ACCOUNTS	16
	4.1	Maintenance of Accounts	16
	4.2	Separate Plan Year Accounts	16
	4.3	Phantom Investment Subaccounts	16
	4.4	Administration of Deferral Accounts	16
	4.5	Administration of Company Accounts	17
	4.6	Change of Phantom Investment Subaccounts and Phantom Stock Units	19
	4.7	Transferred Accounts	19
ARTICLE V		VESTING	21
	5.1	Vesting	21
ARTICLE VI		DISTRIBUTIONS	22
	6.1	Distribution Elections	22
	6.2	Change-of-Form Elections and Additional Deferral Elections	22
	6.3	Payment	23
	6.4	Unforeseeable Emergency	24
	6.5	Separation from Service	25
	6.6	Taxes	26
	6.7	Acceleration of Payment	26

ARTICLE VII		DEATH BENEFITS	27
	7.1	Designation of Beneficiaries	27
	7.2	Death Benefit	27
ARTICLE VIII		CLAIMS	28
	8.1	Claims Procedure	28
	8.2	Claims Review Procedure	28
ARTICLE IX		ADMINISTRATION	29
	9.1	Committee	29
	9.2	Authority	29
ARTICLE X		AMENDMENT AND TERMINATION OF THE PLAN	31
	10.1	Amendment of the Plan	31
	10.2	Termination of the Plan	31
	10.3	No Impairment of Benefits	31
ARTICLE XI		FUNDING AND CLAIM STATUS	32
	11.1	General Provisions	32
ARTICLE XII		EFFECT ON EMPLOYMENT OR ENGAGEMENT	35
	12.1	General	35
ARTICLE XIII		GOVERNING LAW	36
	13.1	General	36
EXHIBIT A			37

PREAMBLE

The Progress Energy, Inc. Management Deferred Compensation Plan (the “Plan”) was originally adopted by Carolina Power & Light Company effective as of January 1, 2000, and was transferred to Progress Energy, Inc. (the “Sponsor”) effective August 1, 2000. The Plan is unfunded and will benefit only a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”).

The Plan is intended to constitute a non-qualified deferred compensation plan that complies with Section 409A of the Code, related regulations and other guidance (“Section 409A”). Notwithstanding any provision of the Plan to the contrary, the Plan shall be construed in accordance with Section 409A.

The Plan as amended and restated effective January 1, 2007 shall govern deferrals under the Plan beginning January 1, 2007.

  ARTICLE I

DEFINITIONS

1.1   Account Balance

The value in terms of a dollar amount of a Participant’s Deferral Account or Company Account, as the case may be, as of the last Valuation Date.

1.2   Additional Deferral Election

The election by a Participant under Section 6.2 to defer distribution from a Plan Year Account.

1.3   Affiliated Company

Any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Sections 414(b), (c), (m), or (o) of the Code.

1.4   Board

The Board of Directors of the Sponsor.

1.5   Board Committee

The Organization and Compensation Committee of the Board.

1.6   Change in Control

The earliest of the following dates:

(a)   the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or  

(b)   the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or  

(c)   the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or  

(d)   the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or  

(e)   the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets; or  

(f)   the date of any event which the Board determines should constitute a Change in Control.  

A Change in Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Board Committee that one of the events set forth in this Section 1.6 has occurred. Any determination that an event described in this Section 1.6 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Board Committee, the Company, the Participants and their beneficiaries for all purposes of the Plan.

1.7   Change of Form Election

The election by a Participant under Section 6.2 to change the form of distribution of a Plan Year Account.

1.8   Change-of-Investment Election

The election by a Participant under Section 4.6 to change a Phantom Subaccount for the Participant Deferral Account or Company Account.

1.9   Code

The Internal Revenue Code of 1986, as amended, or any successor statute.

1.10   Committee

The Administrative Committee described in Section 9.1 for administering the Plan.

1.11   Company

Progress Energy, Inc. or any successor to it in the ownership of substantially all of its assets and each Affiliated Company that, with the consent of the Board Committee, adopts the Plan and is included in Exhibit A, as in effect from time to time.

1.12   Company Incentive Plans

The Sponsor’s Management Incentive Compensation Plan, or any Company sales incentive plans, marketing incentive plans, and any other cash incentive plans as determined by the Committee.

1.13   Continuing Directors

The members of the Board at the Effective Date; provided, however, that any person becoming a director subsequent to such whose election or nomination for election was supported by 75% or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.

1.14   Deemed Investment Return

The amounts that are credited (or charged) from time to time to each Participant’s Deferral Account and Company Account to reflect deemed investment gains and losses of Phantom Investment Subaccounts.

1.15   Deferral Election

An election to defer Salary pursuant to Section 3.1.

1.16   Deferrals

The deferrals of Salary of a Participant pursuant to Section 3.1.

1.17   Effective Date

January 1, 2007.

1.18   Eligible Employee

An employee of the Company (a) who is eligible to participate in the Sponsor’s Management Incentive Compensation Plan, or (b) who is eligible to participate in any other eligible Company Incentive Plan and is determined by the Committee to be eligible to be a Participant; and who is not excluded from participation pursuant to Section 2.1(b).

1.19   Employee Stock Incentive Plan

The Employee Stock Incentive Plan as adopted by the Board and any successor to such plan which provides additional matching allocations under the Progress Energy 401(k) Savings & Stock Ownership Plan.

1.20   Enrollment Form

The enrollment form prepared by the Company which a Participant must execute to have Deferrals with respect to a Plan Year.

1.21   ERISA

The Employee Retirement Income Security Act of 1974, as amended.

1.22   Incentive Matching Allocations

The additional match allocation which is to be allocated to a Participant's Company Account in accordance with Section 3.3.

1.23   Investment Election

The election by a Participant under Sections 2.4 and 4.6 of the Phantom Investment Subaccounts in which the Participant’s Deferral Accounts and Company Accounts will be allocated.

1.24   Matching Allocation

A match allocation to a Participant's Company Account of a Participant’s Matchable Deferrals in accordance with Section 3.2.

1.25   Net Salary

The Salary of a Participant projected to be payable (assuming no deferral elections under the Plan or the Progress Energy 401(k) Savings & Stock Ownership Plan) with respect to a Plan Year reduced by the projected Deferrals of a Participant for the Plan Year under the Plan.

1.26   Participant

An Eligible Employee participating in the Plan pursuant to Article II.

1.27   Participant Accounts

The aggregate of a Participant’s Deferral Account and Participant’s Company Accounts.

1.28   Participant Company Account

The notational bookkeeping account maintained under Sections 4.1 and 4.5 to record Matching Allocations and Incentive Matching Allocations on behalf of a Participant and the Deemed Investment Return thereon pursuant to the provisions of the Plan.

1.29   Participant Deferral Account

The notational bookkeeping account maintained under Section 4.1 of the Plan to record Deferrals of a Participant and the Deemed Investment Return thereon pursuant to the provisions of the Plan.

1.30   Participant Matchable Deferral

6% of the amount of Deferrals of a Participant for a Plan Year but no greater than 6% of (A-B) where A is the compensation limit under Section 401(a)(17) of the Code for the Plan Year and B is the Net Salary of a Participant for the Plan Year (with any negative differences equating to $0 for purposes of this calculation); provided, however, that the Participant Matchable Deferrals for an SMC Participant for a Plan Year shall be an amount equal to 6% of (C - D) where C is the projected Salary of a Participant for the Plan Year and D is the compensation limit under Section 401(a)(17) of the Code for the Plan Year. Participant Matchable Deferrals for a Plan Year shall be determined for each payroll period during the Plan Year based on projected Matchable Deferrals for the entire Plan Year.

1.31   Payment Commencement

The date payments are to commence with respect to a Plan Year Account in accordance with Section 6.1.

1.32   Phantom Investment Fund

A deemed investment option for purposes of the Plan, each of which shall be the same as those investment options generally available to all participants in the Progress Energy 401(k) Savings & Stock Ownership Plan, or as otherwise selected by the Committee.

1.33   Phantom Funds Account

Notational bookkeeping accounts maintained under the Plan at the direction of the Committee representing allocations of Participants of Phantom Investment Subaccounts in a Phantom Investment Fund.

1.34   Phantom Investment Subaccount

A notational bookkeeping account maintained under the Plan at the direction of the Committee representing a deemed investment in one or more Phantom Investment Funds as directed by the Participant under Sections 2.4 and 4.6.

1.35   Phantom Stock Unit

A hypothetical share of common stock of the Sponsor or its parent company, as applicable.

1.36   Plan

The Progress Energy, Inc. Management Deferred Compensation Plan as set forth herein and as amended from time to time.

1.37   Plan Year

The twelve (12) consecutive month periods beginning January 1 and ending the following December 31 commencing with the Effective Date.

1.38   Plan Year Accounts

The separate Participant Deferral Account and Participant Company Account maintained under the Plan pursuant to Section 4.2 with respect to a Participant for each Plan Year a Participant has Deferrals.

1.39   Progress Energy 401(k) Savings & Stock Ownership Plan

The Progress Energy 401(k) Savings & Stock Ownership Plan of the Company adopted by the Board, as amended from time to time, and any successor to such plan.

1.40   Retirement Date

  The date a Participant retires from the Company on or after attaining (i) age 65 with 5 years of service, (ii) age 55 with 15 years of service, (iii) 35 years of service, or (iv) eligibility for retirement under the SSERP if covered under such plan.

1.41   Salary

The amount of an Eligible Employee's regular annual base salary, payable from time to time by the Company prior to a Deferral Election under the Plan and prior to any deferral election under the Progress Energy 401(k) Savings & Stock Ownership Plan.

1.42   Section 409A

Section 409A of the Code or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time.

1.43   Separation from Service

A participant separates from service if the Participant dies, retires or otherwise has a “termination of employment” with the Company, as defined for purposes of Section 409A.

1.44   SMC Participant

A senior executive officer of the Company who is a member of the “Senior Management Committee” of the Sponsor.

1.45   Sponsor

Progress Energy, Inc. and its successors in interest.

1.46   SSERP

The Supplemental Senior Executive Retirement Plan of the Company.

1.47   Valuation Date

The last day of each calendar month and such other dates as selected by the Committee, in its sole discretion.

1.48   Value

The value of an account maintained under the Plan based on the fair market value of notational investments of Phantom Investment Subaccounts and Phantom Stock Units, as the case may be, as of the last Valuation Date. For purposes of calculating Value as of the end of a Plan Year, accrued but unallocated Incentive Matching Allocations shall be taken into consideration with respect to Participant Company Accounts.

1.49   Years of Service

Years of service of a Participant as calculated under the Progress Energy 401(k) Savings & Stock Ownership Plan.

ARTICLE II

PARTICIPATION

2.1   Eligibility

(a)Participation in the Plan shall be limited to Eligible Employees.

(b)The Committee, in its sole discretion, may at any time limit the participation of an Eligible Employee in the Plan so as to assure that the Plan will not be subject to the provisions of parts 2, 3 and 4 of Title I of ERISA.

2.2   Commencement of Participation

An Eligible Employee who is not a Participant may elect to become a Participant as of the first day of a Plan Year by completing and submitting an Enrollment Form to the Sponsor’s designated agent by November 30prior to the first day of the Plan Year as of which participation is to commence.

2.3   Annual Participation Agreement

Each Participant shall complete a new Enrollment Form with respect to a Plan Year by November 30 prior to the commencement of the Plan Year. If the Participant does not complete such form and submit it to the Sponsor’s designated agent by November 30, the Participant will have no Deferrals for the following Plan Year.

2.4   Election of Phantom Investment Subaccounts

Each Participant shall elect on his Enrollment Form the allocation of his Plan Year Participant Deferral Account among the Phantom Investment Subaccounts.

ARTICLE III

DEFERRAL ELECTIONS

3.1   Participant Deferred Salary Elections

(a)A Participant completing an Enrollment Form in accordance with Sections 2.2 or 2.3 may make an election, pursuant to this Section 3.1, to defer his or her Salary (a “Deferral Election”) in accordance with the Plan. A Deferral Election shall apply only to the Participant’s Salary for the Plan Year specified in the Enrollment Form.

(b)The amount of Salary that may be deferred by a Participant shall be based on their target incentive level under the Sponsor’s Management Incentive Compensation Plan (“MICP”); or, for Participants in Company Incentive Plans other than the MICP, their target incentive level assuming that they participated in the MICP. Deferral Elections shall be made on the Enrollment Form for the applicable Plan Year pursuant to the following limitations:

(i)A Participant who is (or would be) eligible for a bonus at the 20% of salary target incentive level (the “Target”) for the Plan Year under the MICP may defer up to 15% of Salary.

(ii)A Participant who is (or would be) eligible for a bonus at the 25% of salary Target for the Plan Year under the MICP may defer up to 25% of Salary.

(iii)A Participant who is (or would be) eligible for a bonus at the 35% or more of salary Target under the MICP may defer up to 50% of Salary.

All Deferrals shall be in increments of 5% of Salary. The minimum projected Deferrals for a Plan Year for a Participant who commences Deferrals after the beginning of a Plan Year in accordance with Section 2.2 shall be $1,000.

(c)A Deferral Election once made with respect to a Plan Year, cannot be changed or revoked. In the case of a new Participant, the Deferral Election will apply only to amounts that are both paid after the election is made and earned for services performed after the election is made. The amount of Salary that is deferred pursuant to a Deferral Election will reduce the Participant Salary proportionately throughout the applicable Plan Year or, in the case of a new Participant, throughout the portion of the Plan Year to which the Deferral Election is applicable.

(d)A dollar amount equal to the Salary deferred pursuant to this Section 3.1 (“Deferrals”) at each applicable payroll date shall be credited to the Participant’s Deferral Account within ten business days following the applicable payroll date.

3.2   Matching Allocations

A Participant who has made a Deferral Election with respect to a Plan Year and has Participant Matchable Deferrals for such Plan Year shall receive a credit to his Participant Company Account of a Matching Allocation for such Plan Year. The Matching Allocation with respect to a Plan Year shall equal 50% of the Participant Matchable Deferrals. Matching Allocations shall be credited to the Participant Company Account within ten business days following the applicable payroll date, based on a pro-rata portion of projected Matchable Deferrals for the Plan Year applicable to each payroll period during the Plan Year.

3.3   Incentive Matching Allocations

Participants with Matchable Deferrals for a Plan Year shall receive a credit to their Participant Company Account for the Plan Year of an Incentive Matching Allocation if an “Incentive Matching Allocation” is provided under the Progress Energy 401(k) Savings & Stock Ownership Plan for the Plan Year. The Incentive Matching Allocation shall equal that percentage of the Participant Matchable Deferrals for the Plan Year equal to the “Incentive Matching Allocation” (stated as a percentage) provided (or that would have been provided if the Participant participated) under the Progress Energy 401(k) Savings & Stock Ownership Plan for such Plan Year. Incentive Matching Allocations with respect to a Plan Year, if any, shall be credited to a Participant’s Company Account in accordance with Section 4.5 pursuant to rules and procedures adopted by the Committee approximately coincident with the credit under the Progress Energy 401(k) Savings & Stock Ownership Plan of “Incentive Matching Allocations” following the end of a Plan Year; provided, however, no such allocation shall be made if a Participant is not employed at the end of the applicable Plan Year, unless the Participant retired, died, or became disabled during the Plan Year.

ARTICLE IV

ACCOUNTS

4.1   Maintenance of Accounts

The Committee shall maintain a Participant Deferral Account and a Participant Company Account for each Participant. There shall be credited to a Participant's Deferral Account all Deferrals by a Participant under the Plan and there shall be credited to a Participant's Company Account all Matching Allocations and Incentive Matching Allocations with respect to a Participant under the Plan in accordance with Sections 3.2 and 3.3.

4.2   Separate Plan Year Accounts

The Committee shall maintain a separate Participant Deferral Account and Participant Company Account for each Plan Year a Participant has Deferrals (separately a “Plan Year Deferral Account” and a “Plan Year Company Account” and together the “Plan Year Account”).

4.3   Phantom Investment Subaccounts

The Committee shall maintain separate Phantom Investment Subaccounts representing deemed investments in Phantom Investment Funds as directed by the Participant. Phantom Investment Subaccounts shall be valued as of each Valuation Date based on the notional investments of each such account, pursuant to rules and procedures adopted by the Committee.

4.4   Administration of Deferral Accounts

(a)A Participant's Deferral Accounts shall be comprised in total, of units in Phantom Investment Subaccounts.

(b)Participants shall allocate their Deferrals among Phantom Investment Subaccounts pursuant to elections under Section 2.4.

(c)The Value of that portion of a Participant’s Deferral Account allocated to a Phantom Investment Subaccount shall be changed on each Valuation Date to reflect the new Value of the Phantom Investment Subaccount.

(d)The interest of a Participant’s Deferral Account in a Phantom Investment Subaccount shall be stated in a unit value or dollar amount, as determined by the Committee.

4.5   Administration of Company Accounts

(a)A Participant’s Company Account shall be comprised of Phantom Investment Fund units which shall be recorded in Phantom Investment Subaccounts. All Matching Allocations and Incentive Matching Allocations shall be recorded in Phantom Investment Subaccounts and shall be deemed invested in Phantom Stock Units, units of other Phantom Investment Funds, or a combination of Phantom Stock Units and other Phantom Investment Funds as determined by the Committee in its sole discretion. To the extent the Matching Allocations and Incentive Matching Allocations are initially deemed to be invested in Phantom Stock Units, the number of Phantom Stock Units will be determined on the date of each allocation under the Plan based on the closing price of a share of common stock of the Sponsor on the New York Stock Exchange on the date of each allocation. To the extent the Matching Allocations and Incentive Matching Allocations are initially deemed to be invested in one or more Phantom Investment Funds (other than Phantom Stock Units), the number of units in these Phantom Investment Funds will be determined on the date of each allocation under the Plan, using the closing price of the units of the underlying investment fund on which the Phantom Investment fund is based, on the date of each allocation.

(b)The number of Phantom Stock Units allocated to a Participant’s Company Account shall be adjusted periodically to reflect the deemed reinvestment of dividends on Sponsor common stock in additional Phantom Stock Units.

(c)In the event there is any change in the common stock of the Sponsor, through merger, consolidation, reorganization, recapitalization (other than pursuant to bankruptcy proceedings), stock dividend, stock split, reverse stock split, split-up, split-off, spin-off, combination of shares, exchange of shares, dividend in kind or other like change in capital structure (an “Adjustment Event”), the number of Phantom Stock Units subject to the Plan shall be adjusted by the Committee in its sole judgment so as to give appropriate effect to such Adjustment Event. Any fractional units resulting from such adjustment may be eliminated. Each successive Adjustment Event shall result in the consideration by the Committee of whether any adjustment to the number of Phantom Stock Units subject to the Plan is necessary in the Committee’s judgment. Issuance of common stock or securities convertible into common stock for value will not be deemed to be an Adjustment Event unless otherwise expressly determined by the Committee.

4.6   Change of Phantom Investment Subaccounts and Phantom Stock Units

(a)A Participant may elect to reallocate the value of his Phantom Investment Subaccounts comprising his Deferral Accounts among other Phantom Investment Subaccounts and change the allocation of future Deferrals among Phantom Investment Subaccounts once per calendar month, pursuant to uniform rules and procedures adopted by the Committee.

(b)A Participant may elect to reallocate Phantom Investment Subaccounts comprising his Company Account, once per calendar month, pursuant to uniform rules adopted by the Committee.

4.7   Transferred Accounts

(a)Effective as of the Effective Date, the Value of a SMC Participant’s Company Account shall include the value of such Participant’s deferral account as of such date (being a “Transferred Account”) under the Carolina Power & Light Executive Deferred Compensation Plan, but only to the extent the Participant acknowledges in writing he has no further interest in the Executive Deferred Compensation Plan.

(b)Effective on the Effective Date, the Value of any Participant’s Company Account shall include the value of such Participant’s additional benefits (currently recorded as phantom Company stock units) granted under Article VIII.2. (also being a “Transferred Account”) under the Company’s Deferred Compensation Plan for Key Management Employees, but only to the extent the Participant acknowledges in writing that he has no further interest in these benefits in the Company’s Deferred Compensation Plan for Key Management Employees.

(c)The total value of the Transferred Accounts as described in this Section 4.7 shall be deemed a vested Company Account for all purposes of the Plan.

ARTICLE V

VESTING

5.1   Vesting

A Participant’s Deferral Accounts shall be 100% vested at all times. A Participant’s Company Accounts shall vest in accordance with the following schedule:

Years of Service	Percent of Vesting
Less than 1	0
1 or more	100%

ARTICLE VI

DISTRIBUTIONS

6.1   Distribution Elections

A Participant when making a Deferral Election pursuant to an Enrollment Form with respect to a Plan Year shall elect on such Enrollment Form (a) to defer the payment of his Plan Year Accounts with respect to such Plan Year, in accordance with the Plan until (i) the April 1 following the date that is five years from the last day of such Plan Year, (ii) the April 1 following the Participant’s Retirement or (iii) the April 1 following the first anniversary of the Participant’s Retirement (each a “Payment Commencement Date”) and (b) to provide for the payment of such Plan Year Account in the form of (i) a lump sum or (ii) approximately equal installments over a period extending from two years to ten years (by paying a fraction of the account balance each year during such period), as elected by the Participant. Except as otherwise provided in this Article VI, such elections may not be changed or revoked. Notwithstanding the foregoing, if the Participant is a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees), payment of deferred amounts shall not be made pursuant to an election under Section 6.1(a)(ii) above before the date that is six months after the date of Separation from Service for any reason including Retirement (or, if earlier, the date of death of the Participant).

6.2   Change-of-Form Elections and Additional Deferral Elections

(a)Any Participant who has made elections under Section 6.1 with respect to amounts deferred before January 1, 2005, may change such elections pursuant to this Section 6.2(a) as in effect prior to January 1, 2005, unless such provisions are materially modified after October 3, 2004. For this purpose, an amount is considered deferred before January 1, 2005, if the amount is earned and vested before such date. Such Participant may elect at least one year prior to the Payment Commencement Date with respect to such Plan Year Accounts a new Payment Commencement Date that either is five years from the then current Payment Commencement Date or otherwise is permitted under Section 6.1(a)(ii) or (iii). Only one such Additional Deferral Election will be permitted with respect to Plan Year Accounts relating to a particular Plan Year. In addition, the Participant may elect to change the form of distribution to any of the forms permitted under Section 6.1(b) by completing a Change-of-Form Elections with respect to Plan Year Accounts at least one year prior to the applicable Payment Commencement Date for such accounts.

(b)Any elections made under Section 6.1 with respect to amounts deferred after December 31, 2004, shall be irrevocable except as permitted by rules promulgated under Section 409A and consented to by the Committee.

6.3   Payment

Upon occurrence of an event specified in the Participant’s distribution election under Section 6.1 (a “Distribution Event”) with respect to Plan Year Accounts, as modified by any applicable subsequent Additional Deferral Election under Section 6.2, the Account Balance of a Participant’s Plan Year Accounts shall be paid by the Company to the Participant in the form elected under Section 6.1. Such payments shall commence as soon as practicable and in no event more than 30 days following the occurrence of the Distribution Event.

6.4   Unforeseeable Emergency

In case of an unforeseeable emergency, a Participant may request the Committee, on a form to be provided by the Committee or its delegate, that payment of the vested portion of Participant Accounts be made earlier than the date provided under the Plan.

An “unforeseeable emergency” shall mean a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Section 152(a) of the Code) of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.

The Committee shall consider any requests for payment under this Section 6.4 on a uniform and nondiscriminatory basis and in accordance with the standards of interpretation described in Section 409A. If the request is granted, the amounts distributed will not exceed the amounts necessary to satisfy the emergency need plus amounts necessary to pay taxes reasonably anticipated as result of the distribution, after taking into account the extent to which such hardship is or may be relieved by reason of the cessation of Deferrals for the Plan Year in which the distribution is made and through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets (to the extent such liquidation would not itself cause severe financial hardship).

In the event of a hardship determination by the Committee, the Company shall pay out in a lump sum to the Participant such portion of the Participant Accounts as determined by the Committee and Deferrals by the Participant for the Plan Year in which the hardship distribution is made shall cease.

6.5   Separation from Service

In the event of the Separation from Service of a Participant with the Company and any parent, subsidiary or affiliate for any reason, prior to the Retirement or death of the Participant, the vested portion of the Participant Accounts of such Participant shall be paid in a lump sum to such Participant based on the Value of such accounts as of the Valuation Date coincident with or immediately preceding the date of distribution. Such payment shall be made as soon as administratively practicable following the Participant’s termination date as determined under the Company’s normal administrative practices. The nonvested portion of a terminated Participant’s Company Account shall be forfeited by the Participant. In the event of the Separation from Service of a SMC Participant for whom no Deferral Election was made for a Plan Year, any Matching Allocation, Incentive Matching Allocation and Deemed Investment Return allocated to such Participant shall be distributed to the Participant following termination of employment in accordance with this Section 6.5. In the event of the Retirement of a Participant prior to the Payment Commencement Date elected by the Participant under Section 6.1(a)(i) with respect to a Plan Year Account, distribution of such account shall commence no later than April 1 following the first anniversary of the Participant’s Retirement. Notwithstanding the foregoing, if the Participant is a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees), payment of deferred amounts shall not be made before the date that is six months after the date of Separation from Service for any reason including Retirement (or, if earlier, the date of death of the Participant).

6.6Taxes

The Company shall report Deferrals in the year they occur as required by Section 6041 and Section 6051 of the Code. The Company shall deduct from all payments under the Plan federal, state and local income and employment taxes, as required by applicable law. Deferrals will be taken into account for purposes of any tax or withholding obligation under the Federal Insurance Contributions Act and Federal Unemployment Tax Act in the year of the Deferrals, as required by Sections 3121(v) and 3306(r) of the Code and the regulations thereunder. Amounts required to be withheld in the year of the Deferrals pursuant to Sections 3121(v) and 3306(r) shall be withheld out of current wages or other compensation paid by the Company to the Participant.

6.7   Acceleration of Payment

The acceleration of the time or schedule of any payment due under the Plan is prohibited except as provided in regulations and administrative guidance provided under Section 409A of the Code. It is not an acceleration of the time or schedule of payment if the Company waives or accelerates the vesting requirements applicable to a benefit under the Plan.

ARTICLE VII

DEATH BENEFITS

7.1   Designation of Beneficiaries

The Participant’s beneficiary under this Plan entitled to receive benefits under the Plan in the event of the Participant’s death shall be designated by the Participant on a form provided by the Committee. In the absence of such designation or in the event the designated beneficiary has predeceased the Participant, the beneficiary shall be deemed the estate of the Participant.

7.2   Death Benefit

In the event of the death of a Participant prior to the payout of his Participant Accounts, the Value of the remaining portion of the Participant Accounts shall be paid by the Company in a lump sum to the Participant’s beneficiary (as defined under Section 7.1) based on the Value of such accounts on the Valuation Date immediately following the date of death. Payment shall be made as soon as administratively practicable following such Valuation Date pursuant to rules and procedures adopted by the Committee.

ARTICLE VIII

CLAIMS

8.1   Claims Procedure

If any Participant or his or her beneficiary has a claim for benefits which is not being paid, such claimant may file with the Committee a written claim setting forth the amount and nature of the claim, supporting facts, and the claimant’s address. The Committee shall notify each claimant of its decision in writing by registered or certified mail within sixty (60) days after its receipt of a claim or, under special circumstances, within ninety (90) days after its receipt of a claim. If a claim is denied, the written notice of denial shall set forth the reasons for such denial, refer to pertinent Plan provisions on which the denial is based, describe any additional material or information necessary for the claimant to realize the claim, and explain the claims review procedure under the Plan.

8.2   Claims Review Procedure

A claimant whose claim has been denied, or such claimant’s duly authorized representative, may file, within sixty (60) days after notice of such denial is received by the claimant, a written request for review of such claim by the Committee. If a request is so filed, the Committee shall review the claim and notify the claimant in writing of its decision within sixty (60) days after receipt of such request. In special circumstances, the Committee may extend for up to sixty (60) additional days the deadline for its decision. The notice of the final decision of the Committee shall include the reasons for its decision and specific references to the Plan provisions on which the decision is based. The decision of the Committee shall be final and binding on all parties.

ARTICLE IX

ADMINISTRATION

9.1   Committee

The Administrative Committee consisting of not less than three (3) or more than seven (7) persons appointed by the Board Committee or its delegate to administer the Plan.

9.2   Authority

(a)The Committee shall have the exclusive right to interpret the Plan to the maximum extent permitted by law, to prescribe, amend and rescind rules and regulations relating to it, and to make all other determinations necessary or advisable for the administration of the Plan, including the determination under Section 9.2(b) herein. The decisions, actions and records of the Committee shall be conclusive and binding upon the Company and all persons having or claiming to have any right or interest in or under the Plan.

(b)The Committee may delegate to one or more agents, or to the Company such administrative duties as it may deem advisable. The Committee may employ such legal or other counsel and consultants as it may deem desirable for the administration of the Plan and may rely upon any opinion or determination received from counsel or consultant.

(c)No member of the Committee shall be directly or indirectly responsible or otherwise liable for any action taken or any failure to take action as a member of the Committee, except for such action, default, exercise or failure to exercise resulting from such member’s gross negligence or willful misconduct. No member of the Committee shall be liable in any way for the acts or defaults of any other member of the Committee, or any of its advisors, agents or representatives.

(d)The Company shall indemnify and hold harmless each member of the Committee against any and all expenses and liabilities arising out of his or her own activities relating to the Committee, except for expenses and liabilities arising out of a member’s gross negligence or willful misconduct.

(e)The Company shall furnish to the Committee all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. The Committee shall be entitled to rely on any information provided by the Company without any investigation thereof.

(f)No member of the Committee may act, vote or otherwise influence a decision of such Committee relating to his or her benefits, if any, under the Plan.

ARTICLE X

AMENDMENT AND TERMINATION OF THE PLAN

10.1   Amendment of the Plan

The Plan may be wholly or partially amended or otherwise modified at any time by the Board or the Board Committee consistent with the requirements of Section 409A of the Code.

10.2   Termination of the Plan

The Plan may be terminated at any time by written action of the Board or the Board Committee or by the Committee as provided under the Plan; provided, that termination of the Plan shall not affect the distribution of the Participant Accounts (except as otherwise permitted under Section 409A of the Code). Notwithstanding the foregoing, the Plan may be terminated and Participant Accounts distributed to Participants within twelve months of a “change in control event” as defined for purposes of Section 409A of the Code.

10.3   No Impairment of Benefits

Notwithstanding the provisions of Sections 10.1 and 10.2, no amendment to or termination of the Plan shall impair any rights to benefits which theretofore accrued hereunder; provided, however, the payout of all Plan benefits on termination of the Plan, if permitted pursuant to Section 10.2, or a change of any Phantom Investment Funds or creation of a substitute for Phantom Investment Funds as a result of a Plan amendment or action of the Committee shall not constitute an impairment of any rights or benefits.

ARTICLE XI

FUNDING AND CLAIM STATUS

11.1   General Provisions

(a)The Company shall make no provision for the funding of any Participant Accounts payable hereunder that (i) would cause the Plan to be a funded plan for purposes of Section 404(a)(5) of the Code or for purposes of Title I of ERISA, or (ii) would cause the Plan to be other than an “unfunded and unsecured promise to pay money or other property in the future” under Treasury Regulations § 1.83-3(e); and, except in the case of a Change in Control of the Sponsor, the Company shall have no obligation to make any arrangements for the accumulation of funds to pay any amounts under this Plan. Subject to the restrictions of this Section 11.1(a), the Company, in its sole discretion, may establish one or more grantor trusts described in Treasury Regulations § 1.677(a)-1(d) to accumulate funds to pay amounts under this Plan, provided that the assets of such trust(s) shall be required to be used to satisfy the claims of the Company’s general creditors in the event of the Company’s bankruptcy or insolvency.

(b)In the case of a Change in Control that is not a “change in the financial health” of the Company, as defined for purposes of Section 409A, the Company shall, subject to the restrictions in this paragraph and in Section 11.1(a), irrevocably set aside funds in one or more such grantor trusts in an amount that is sufficient to pay each Participant employed by such Company (or beneficiary) the net present value as of the date on which the Change in Control occurs, of the benefits to which Participants (or their beneficiaries) would be entitled pursuant to the terms of the Plan if the Value of their Participant Account would be paid in a lump sum upon the Change of Control.

(c)In the event that the Company shall decide to establish an advance accrual reserve on its books against the future expense of payments from any Participant, such reserve shall not under any circumstances be deemed to be an asset of this Plan but, at all times, shall remain a part of the general assets of the Company, subject to claims of the Company’s creditors.

(d)Participants, their legal representatives and their beneficiaries shall have no right to anticipate, alienate, sell, assign, transfer, pledge or encumber their interests in the Plan, nor shall such interests be subject to attachment, garnishment, levy or execution by or on behalf of creditors of the Participants or of their beneficiaries.

(e)Participants shall have no right, title, or interest whatsoever in or to any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create a trust of any kind, or a fiduciary relationship between the Company and any Participant, beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. All payments to be made hereunder with respect to a Participant shall be paid from the general funds of the Company employing such Participant.

            (f)      The foregoing provisions of this Article XI notwithstanding, the Company shall establish no grantor trust if its assets are includable in the income of Participants thereby pursuant to Section 409A(b).

ARTICLE XII

EFFECT ON EMPLOYMENT OR ENGAGEMENT

12.1   General

Nothing contained in the Plan shall affect, or be construed as affecting, the terms of employment or engagement of any Participant except to the extent specifically provided herein. Nothing contained in the Plan shall impose, or be construed as imposing, an obligation on the Company to continue the employment or engagement of any Participant.

ARTICLE XIII

GOVERNING LAW

13.1   General

The Plan and all actions taken in connection with the Plan shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.

IT WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

     PROGRESS ENERGY, INC.

         By: /s/ Robert B. McGehee

            < font id="TAB2" style="LETTER-SPACING: 9pt">        Robert B. McGeehee

          Chief Executive Officer

EXHIBIT A

Progress Energy Carolinas, Inc.

Progress Energy Service Company, LLC

Progress Energy Ventures, Inc.

Progress Energy Florida, Inc.

Progress Fuels Corporation (corporate employees only)

EX-10.C10

Exhibit 10c(10)

PROGRESS ENERGY, INC.

MANAGEMENT CHANGE-IN-CONTROL PLAN

(Amended and Restated Effective January 1, 2007)

1.0          PURPOSE OF PLAN

1.1          Purpose. The purpose of the Progress Energy, Inc. Management Change-in-Control Plan (the “Plan”) is to attract and retain certain highly qualified individuals as management employees of Progress Energy, Inc. and its subsidiaries, and to provide a benefit to such management employees if their employment is terminated in connection with a Change in Control (as defined below). This Plan is intended to qualify as a “top-hat” plan under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), in that it is intended to be an “employee pension benefit plan” (as such term is defined under Section 3(2) of ERISA) which is unfunded and provides benefits only to a select group of management or highly compensated employees of the Company or any Subsidiary. The Plan amends and restates the Plan as restated effective January 1, 2005 and July 10, 2002. The Carolina Power & Light Company Management Change-in-Control Plan was originally adopted effective January 1, 1998.

2.0DEFINITIONS

The following terms shall have the following meanings unless the context indicates otherwise:

2.1          “Beneficiary” shall mean a beneficiary designated in writing by a Participant to receive any payments to be made under the Plan tosuch Participant, and if no beneficiary is designated by the Participant, then the Participant’s estate shall be deemed to be the Participant’s designated beneficiary.

2.2“Board” shall mean the Board of Directors of the Company.

2.3           “Cash Payment” shall mean a payment in cash by the Company or any Subsidiary to a Participant in accordance with Section 6.1 below.

2.4           “Cause” shall mean:

(a)embezzlement or theft from the Company or any Subsidiary, or other acts of dishonesty, disloyalty or otherwise injurious to the Company or any Subsidiary;

(b)disclosing without authorization proprietary or confidential information of the Company or any Subsidiary;

(c)committing any act of negligence or malfeasance causing injury to the Company or any Subsidiary;

(d)conviction of a crime amounting to a felony under the laws of the United States or any of the several states;

(e)any violation of the Company’s Code of Ethics; or

(f)unacceptable job performance which has been substantiated in accordance with the normal practices and procedures of the Company or any Subsidiary.

2.5           Change-in-Control” shall mean:

2.5.1 General: A Change-in-Control shall be deemed to have occurred on the earliest of the following dates:

(a)the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Company, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Company representing twenty-five percent (25%) or more of the combined voting power of the Company’s then outstanding securities (excluding the acquisition of securities of the Company by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Company); or

(b) the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Company’s then outstanding voting securities; or

(c) the date of consummation of a merger, share exchange or consolidation of the Company with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Company or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or

(d) the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Company (other than such an offer by the Company for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or

(e)           the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or    

                disposition by the Company of all or substantially all of the Company’s assets; or

(f) the date of any event which the Board determines should constitute a Change-in-Control.

A Change-in-Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Committee that one of the events set forth in this Section 2.5.1 has occurred. Any determination that an event described in this Section 2.5.1 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Committee, the Company, the Participants and their Beneficiaries for all purposes of the Plan.

2.5.2Definition Applicable to Change-in-Control Benefits Subject to Section 409A: Notwithstanding the preceding provisions of Section 2.5.1, in the event that any Change-in-Control Benefits under the Plan are deemed to be deferred compensation subject to the provisions of Section 409A, then distributions related to such benefits may be permitted, in the Committee’s discretion, upon the occurrence of one or more of the following events (as they are defined and interpreted under Section 409A): (A) a change in the ownership of the Company, (B) a change in effective control of the Company, or (C) a change in the ownership of a substantial portion of the assets of the Company.

2.6         “Change-in-Control Benefits” shall mean the benefits described under Section 6 below provided to Terminated Participants. Except as otherwise provided herein, a Terminated Participant who is terminated in anticipation of a Change-in-Control as described in Section 5.1 shall be entitled to receive the Change-in-Control Benefits as of the Termination Date notwithstanding the fact that the anticipated Change-in-Control does not occur.

2.7          “Change-in-Control Date” shall mean the date that a Change-in-Control first occurs.

2.8           “Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

2.9          “Committee” shall mean (i) the Board or (ii) a committee or subcommittee of the Board appointed by the Board from among its members. The Committee shall be the Board’s Committee on Organization and Compensation until a different Committee is appointed. On a Change-in-Control Date, and during the 36-month period following such Change-in-Control Date, the Committee shall be comprised of such persons as appointed by the Board prior to the Change-in-Control Date, with any additions or changes to the Committee following such Change-in-Control Date to be made and or approved by all Committee members then in office.

2.10       “Company” shall mean Progress Energy, Inc., a North Carolina corporation, including any successor entity or any successor to the assets of the Company that has assumed the Plan.

2.11        “Continuing Directors” shall mean the members of the Board as of the Effective Date; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.

2.12         “Effective Date” of the Plan, as amended and restated herein,shall mean January 1, 2007.

2.13         “Good Reason” shall mean the occurrence of any of the following:

(a)a reduction in the Participant’s base salary without the Participant’s prior written consent (other than any reduction applicable to management employees generally);

(b)a material adverse change in the Participant’s position, duties or responsibilities with respect to his or her employment with the Company and/or any Subsidiary without the Participant’s prior written consent;

(c) a material reduction in the Participant’s total incentive compensation opportunity under the Company’s Management Incentive Compensation Plan, the 1997 Equity Incentive Plan, the 2002 Equity Incentive Plan, the Performance Share Sub-Plans, or any other incentive compensation plan (based on the total incentive compensation opportunity previously granted to such Participant during the 12-month period preceding a Change-in-Control Date) without the Participant’s prior written consent;

(d)an actual change in the Participant’s principal work location by more than 50 miles and more than 50 miles from the Participant’s principal place of abode as of the date of such change in job location without the Participant’s prior written consent;

(e)the failure of the Company to obtain the assumption of its obligation under the Plan by any successor to all or substantially all of the assets of the Company within 30 days after a merger, consolidation, sale or similar transaction constituting a Change-in-Control; or

(f) a material breach by the Company of any term or provision of the Plan without the Participant’s prior written consent.

2.14“Gross-Up Payment” shall mean a payment described in Section 11 below.

2.15“Management Employee” shall mean a regular full-time employee of the Company or any Subsidiary with managerial duties and responsibilities.

2.16“Participant” shall mean any Management Employee who has been designated to participate in the Plan under Section 3below.

2.17         “Plan”shall mean the Progress Energy, Inc. Management Change-in-Control Plan.

2.18        “Retirement” shall mean the termination of employment of a Participant after having attained the age of 65 with five or more years of service, or the age of 55 with 15 or more years of service, or after having completed 35 or more years of service regardless of age.

2.19       “Section 409A” shall mean Section 409A of the Code, or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time and by related guidance.

2.20        “Separation from Service” shall mean the death, Retirement or other termination of employment with the Company as defined for purposes of Section 409A.

2.21        “Specified Employee” shall mean a “key employee,” as defined in Section 416(i) of the Code without regard to paragraph 5 thereof or the 50-employee limit on the number of officers treated as key employees.

2.22         “Subsidiary” shall mean a corporation of which the Company directly or indirectly owns more than fifty percent (50%) of the voting stock (meaning the capital stock of any class or classes having general voting power under ordinary circumstances, in the absence of contingencies, to elect the directors of a corporation) or any other business entity in which the Company directly or indirectly has an ownership interest of more than 50 percent.

2.23       “Terminated Participant” shall mean a Participant whose employment is terminated as described in Section 5 below; provided, however, that a Participant who is reemployed by the Company or any Subsidiary without an intervening break in service shall not be a Terminated Participant for purposes of this Plan.

2.24        “Termination Date”shall mean the date a Terminated Participant’s employment with the Company and/or a Subsidiary is terminated as described in Section 5 below.

2.25        “Trigger Trust” shall mean a trust as described in Section 8 below.

3.0 ELIGIBILITY AND PARTICIPATION

3.1 Eligibility. An individual shall be eligible to participate in the Plan who is a Management Employee in one of the following positions:

(a)Tier I -Chief Executive Officer, Chief Operating Officer, President and Executive Vice Presidents who are members of the Senior Management Committee of the Company.

(b)Tier II -Senior Vice Presidents who are members of the Senior Management Committee of the Company.

(c)Tier III -Vice Presidents, Department Heads and other selected Management Employees of the Company or any Subsidiary.

3.2 Participation. The Committee shall designate each eligible Management Employee who is a Participant in the Plan. The Committee may, in its sole discretion, terminate the participation of a Participant at any time prior to the date that substantive negotiationsoccur in connection with a potential Change-in-Control.

4.0 ADMINISTRATION

4.1 Responsibility. The Committee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms.

4.2 Authority of the Committee. The Committee shall have the maximum discretionary authority permitted by law that may be necessary to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following:

(a) to determine eligibility for participation in the Plan;

(b) to designate Participants;

(c) to determine and establish the formula to be used in calculating a Participant’s Change-in-Control Benefits;

(d) to correct any defect, supply any omission, or reconcile any inconsistency in the Plan in such manner and to such extent as it shall deem appropriate in its sole discretion to carry the same into effect;

(e) to issue administrative guidelines as an aid to administer the Plan and make changes in such guidelines as it from time to time deems proper;

(f) to make rules for carrying out and administering the Plan and make changes in such rules as it from time to time deems proper;

(g) to the extent permitted under the Plan, grant waivers of Plan terms, conditions, restrictions, and limitations;

(h) to make reasonable determinations as to a Participant’s eligibility for benefits under the Plan, including determinations as to Cause and Good Reason; and

(i) to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan.

4.3 Action by the Committee. The Committee may act only by a majority of its members. Any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee.

4.4 Delegation of Authority. The Committee may delegate to one or more of its members, or to one or more agents, such administrative duties as it may deem advisable; provided, however, that any such delegation shall be in writing. In addition, the Committee, or any person to whom it has delegated duties as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid bythe Company, or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee.

4.5 Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive to the maximum extent permitted by law on all Participants and their heirs, successors, and legal representatives.

4.6 Information. The Company shall furnish to the Committee in writing all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. Such information may include, but shall not be limited to, the full names of all Participants, their earnings and their dates of birth, employment, retirement or death. Such information shall be conclusive for all purposes of the Plan, and the Committee shall be entitled to rely thereon without any investigation thereof.

4.7 Self-Interest. No member of the Committee may act, vote or otherwise influence a decision of the Committee specifically relating to his or her benefits, if any, under the Plan.

5.0 TERMINATION OF EMPLOYMENT

5.1 Termination of Employment. If the Company or a Subsidiary employing a Participant terminates such Participant’s employment without Cause, or if a Participant terminates his or her employment with the Company or a Subsidiary for Good Reason, and in either case such termination of employment is a Separation from Service that is not due to the death or Retirement of the Participant, and such termination of employment occurs during the 24-month period following the Change-in-Control Date, or occurs prior to the Change-in-Control Date but after substantive negotiationsleading to the Change-in-Control and can be demonstrated to have occurred at the request or initiation of parties to the Change-in-Control (such date of termination of employment shall be referred to herein as the “Termination Date”), the Terminated Participant shall be entitled to receive the Change-in-Control Benefits in accordance with Section 6 below.

6.0 CHANGE-IN-CONTROL BENEFITS

6.1 Cash Payment. Within ten days following the Termination Date, the Company shall pay to the Terminated Participant, in a lump sum, an amount in cash as determined under a formula established by the Committee (such formula to be established by the Committee, in its sole discretion, on the date the Committee designates such individual as a Participant in accordance with Section 3.2 above); provided, however, that such Cash Payment shall not exceed in the aggregate an amount equal to the sum of:

   (a)  The Applicable Percentage of the Terminated Participant’s annual base salary in effect on the Termination Date; plus

   (b)  The Applicable Percentage of the greater of (i) the average of the Terminated Participant's annual incentive bonus paid to the Terminated Participant under the Company's Management Incentive Compensation Plan or otherwise with respect to the three completed calendar years immeidately preceding the year in which the Termination Date occurs; provided however, that if the Terminated Participant was not eligible to receive an annual incentive bous with respect to each of the three calendar years immediately preceding the year in which the Termination Date occurs, the average shall be determined for that period of calendar years, if any, for which the Terminated Participant was eleigle to receive an annual incentive bonus or (ii) the Terminated Participant's target annual incentive bonus for the year in which the Termination Date occurs.

For this purpose, the “Applicable Percentage” shall be determined as follows:

Participant    Applicable Percentage

Tier I                   300%

Tier II                                                                         200%

Tier III                                                                        150%

6.2Annual Cash Incentive Compensation Plans. The Terminated Participant shall be entitled to receive an amount equal to his or her compensation under the annual cash incentive compensation plan covering the Terminated Participant based on 100 percent (100%) of his or her target bonus under such plan, which shall be paid during the 10-day period following the Termination Date.

           6.3          Long Term Compensation Plan. The Terminated Participant shall be entitled to receive any awards which have been earned prior to the Termination Date under the Company’s Amended and Restated Long Term Compensation Plan, which shall be paid during the 10-day period following the Termination Date.

6.4 Restricted Stock Agreements. The Terminated Participant shall become vested as of the Termination Date in any restricted share awards which have been granted to     him or her under the Company’s 1997 Equity Incentive Plan, the 2002 Equity Incentive Plan or any successor plans, and such shares shall be delivered to him or her without restriction during the 10-day period following the Termination Date.

6.5Performance Share Sub-Plans. The Terminated Participant shall become vested as of the Termination Date in any awards which have been granted to such Participant under the Company’s Performance Share Sub-Plans. The Terminated Participant shall be entitled to payment of any awards which have been granted to him or her under such plans prior to the Termination Date within ten days following the date that the data needed to calculate the value of the awards is available to the Company.

 6.6Stock Option Agreements. Except to the extent that greater rights are provided to the Terminated Participant under the terms of a Stock Option Agreement between the Terminated Participant and the Company, the Terminated Participant shall have the following rights under any Stock Option Agreement following the Termination Date:

 (a)      Option Assumed by Successor. If the Stock Option Agreement has been assumed by the successor to the Company on or before the Change-in-Control Date, any options not previously forfeited shall vest in accordance with the terms of the Stock Option Agreement and any vested options may be exercised by the Terminated Participant during the remaining term of such options notwithstanding the termination of employment by the Terminated Participant.

 (b)Option Not Assumed by Successor. If the Stock Option Agreement has not been assumed by the successor on or before the Change-in-Control Date, any outstanding options shall be fully vested as of the Change-in-Control Date and, in lieu of exercise, the value of such options shall be paid to the Terminated Participant in an amount equal to the excess, if any, of the aggregate fair market value as of the Change-in-Control Date of the shares subject to such options over the aggregate exercise price for such shares. Such payment shall be made during the 10-day period following the later of (i) the Termination Date, or (ii) the Change-in-Control Date. Notwithstanding the foregoing, if the Terminated Participant was terminated in anticipation of a Change-in-Control as described in Section 5.1 and the anticipated Change-in-Control does not occur, this Section 6.6(b) shall not apply and the terms of the Stock Option Agreement shall control.

For purposes of this Section 6.6, the successor shall be deemed to have “assumed” a Stock Option Agreement if the excess of the aggregate fair market value of the shares subject to the options over the aggregate exercise price immediately after the assumption is no less than the excess of the aggregate fair market value of the shares subject to the options over the aggregate exercise price immediately prior to the assumption.

6.7Other Company Incentive Compensation Plans. The Terminated Participant shall become vested as of the Termination Date in any awards which have been granted to such Participant under any Company incentive compensation plan, program or agreements (other than those plans or agreements specified in Sections 6.2, 6.3, 6.4, 6.5 and 6.6 above) prior to the Termination Date. A Terminated Participant shall be entitled to (i) payment of any cash awards and (ii) delivery of any unrestricted shares (if such award is in the form of restricted stock), which have been granted to him or her under such plan(s) prior to the Termination Date during the 10-day period following the Termination Date.

6.8 Payment of Change-in-Control Benefits to Beneficiaries. In the event of the Participant’s death, all Change-in-Control Benefits that would have been paid to the Participant under this Section 6 but for his or her death shall be paid to the Participant’s Beneficiary.

7.0 PARTICIPATION IN NONQUALIFIED PENSION AND WELFARE BENEFIT PLANS

7.1 Nonqualified Deferred Compensation Plans; Restoration Retirement Plan. The Terminated Participant shall be entitled to payment of his or her benefit in any nonqualified deferred compensation or restoration pension plan of the Company (including, but not limited to, the Management Deferred Compensation Plan, the Deferred Compensation Plan for Key Management Employees and the Restoration Retirement Plan) in accordance with the terms of such plan.

7.2Supplemental Senior Executive Retirement Plan. A Terminated Participant who is a member of the Senior Management Committee and would otherwise be eligible to participate in the Company’s Supplemental Senior Executive Retirement Plan but for the applicable service requirements shall (i) be deemed to have a minimum of three years of service on the Senior Management Committee and as a Senior Vice President or more senior officer and (ii) receive a grant of additional service so that such Terminated Participant has a minimum of ten years of service with the Company for benefit purposes. Such a terminated Participant shall be entitled to payment of his or her benefit under the Supplemental Senior Executive Retirement Plan in accordance with the terms of such plan upon reaching the earliest age for receipt of benefits (including any additional credited service described in the previous sentence).

7.3Split-Dollar Life Insurance Policies. Following the Termination Date, the Terminated Participant shall be entitled to payment by the Company of all premiums due under any split-dollar life insurance arrangement of the Company (including, but not limited to, the Split Dollar Life Insurance Plan, the Executive Estate Conservation Plan and the Executive Permanent Life Insurance Plan) for any life insurance policy under which the Terminated Participant is the insured that come due during the Applicable Period following the Termination Date.

7.4 Employee Welfare Benefits. The Company or the applicable Subsidiary shall pay the total cost for the Terminated Participant to continue coverage after the Termination Date in the medical, dental, vision, and life insurance plans of the Company or the applicable Subsidiary in which he or she was participating on the Termination Date until the earlier of:

(a) the end of the Applicable Period following the Termination Date;

(b) the date, or dates, he or she receives comparable coverage and benefits under the plans, programs and/or arrangements of a subsequent employer (such coverage and benefits to be determined on a coverage-by-coverage or benefit-by-benefit basis); or

     (c)the Retirement of the Terminated Participant.

Notwithstanding the foregoing, however, the termination of the Participant shall constitute a qualifying event with respect to the right of the Terminated Participant and any covered dependents to continue group medical, dental and vision coverage in accordance with COBRA, and the continuation period for purposes of COBRA shall run concurrently with the Applicable Period.

7.5 Applicable Period. For purposes of Section 7.3 and 7.4, the Applicable Period shall be determined as follows:

ParticipantApplicable Period

Tier I        36 Months

Tier II        24 Months

Tier III       18 Months

8.0 TRIGGER TRUST

8.1 Establishment of Trigger Trust. The Board may, in its sole discretion, establish or cause to be established a Trigger Trust as described in Section 8.2 below, the purpose of which is to provide a fund for the payment of some or all of the Change-in-Control Benefits and other benefits under Sections 6 and 7 above to Terminated Participants following a Change-in-Control Date, and such other benefits as may be determined by the Board from time to time.

8.2 Trigger Trust Requirements. The Trigger Trust shall be a trust:

(a) of which the Company is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Code;

(b) under which all Participants as of the Change-in-Control Date are beneficiaries;

(c) the assets of which shall be subject to the claims of the Company’s general creditors in accordance with Internal Revenue Service Revenue Procedure 92-64; and

(d) none of the assets of which shall be includable in the income of Participants solely as a result of Section 409A of the Code.

9.0 CLAIMS

9.1 Claims Procedure. If any Participant or Beneficiary, or their legal representative, has a claim for benefits which is not being paid, such claimant may file a written claim with the Committee setting forth the amount and nature of the claim, supporting facts, and the claimant’s address. Written notice of the disposition of a claim by the Committee shall be furnished to the claimant within 90 days after the claim is filed. In the event of special circumstances, the Committee may extend the period for determination for up to an additional 90 days, in which case it shall so advise the claimant. If the claim is denied, the reasons for the denial shall be specifically set forth in writing, the pertinent provisions of the Plan will be cited, including an explanation of the Plan’s claim review procedure, and, if the claim is perfectible, an explanation as to how the claimant can perfect the claim shall be provided.

9.2 Claims Review Procedure. If a claimant whose claim has been denied wishes further consideration of his or her claim, he or she may request the Committee to review his or her claim in a written statement of the claimant’s position filed with the Committee no later than 60 days after receipt of the written notification provided for in Section 9.1 above. The Committee shall fully and fairly review the matter and shall promptly advise the claimant, in writing, of its decision within the next 60 days. Due to special circumstances, the Committee may extend the period for determination for up to an additional 60 days.

9.3 Reimbursement of Expenses. If there is any dispute between the Company and a Participant with respect to a claim under the Plan, the Company shall reimburse such Participant all reasonable fees, costs and expenses incurred by such Participant with respect to such disputed claim; provided, however, that (i) such Participant is the prevailing party with respect to such disputed claim or (ii) the disputed claim is settled.

10.0TAXES

10.1 Withholding Taxes. The Company shall be entitled to withhold from any and all payments made to aParticipant under the Plan all federal, state, local and/or other taxes or imposts which the Company determines are required to be so withheld from such payments or by reason of any other payments made to or on behalf of the Participant or for his or her benefit hereunder.

10.2 No Guarantee of Tax Consequences. No person connected with the Plan in any capacity, including, but not limited to, the Company and any Subsidiary and their directors, officers, agents and employees makes any representation, commitment, or guarantee that any tax treatment, including, but not limited to, federal, state. and local income, estate and gift tax treatment, will be applicable with respect to amounts deferred under the Plan, or paid to or for the benefit of a Participant under the Plan, or that such tax treatment will apply to or be available to a Participant on account of participation in the Plan.

11.0 ADDITIONAL PAYMENTS

11.1 Gross-Up Payment. In the event that any payment or benefit received or to be received by any Participant pursuant to the terms of the Plan other than the Gross-Up Payment described in this Section 11.1 (the “Plan Payments”) or of any other plan, arrangement or agreement of the Company or any Subsidiary (“Other Payments” and, together with the Plan Payments, the “Payments”) would be subject to the excise tax (the “Excise Tax”) imposed by Section 4999 of the Code as determined as provided below, the Company shall pay to such Participant, at the time specified in Section 11.3 below, an additional amount (the “Gross-Up Payment”) such that the net amount of such Gross-Up Payment retained by such Participant, after deduction of the Excise Tax on the Gross-Up Payment and any federal, state and local income tax on the Gross-Up Payment, and any interest, penalties or additions to tax payable by such Participant with respect to the Gross-Up Payment, shall beequal to the total present value (using the applicable federal rate (as defined in Section 1274(d) of the Code in such calculation) of the amount of the Exise Tax on the Payments at the time such Payments are to be made. Notwithstanding the foregoing provisions of this Section 11.1, if it shall be determined that a Participant in Tier II or Tier IIIis entitled to a Gross-Up Payment, but that the Payments would not be subject to the Excise Tax if the Payments were reduced by an amount that does not exceed ten percent (10%) of the portion of the Payments that would be treated as “parachute payments” under Section 280G of the Code, then the Plan Payments shall be reduced (but not below zero) to the maximum amount that could be paid to the Participant without giving rise to the Excise Tax (the “Safe Harbor Cap”), and no Gross-Up Payment shall be made to the Participant. The reduction of the Plan Payments hereunder, if applicable, shall be made by reducing first the Cash Payment under Section 6.1, unless an alternative method of reduction is elected by the Participant and agreed to by the Committee. For purposes of reducing the Payments to the Safe Harbor Cap, only Plan Payments (and no other Payments) shall be reduced. If the reduction of the Plan Payments would not result in a reduction of the Payments to the Safe Harbor Cap, no amounts payable under this Plan shall be reduced pursuant to this provision.

11.2 Determination. For purposes of determining whether any of the Payments will be subject to the Excise Tax and the amounts of such Excise Tax:

 (a)the total amount of the Payments shall be treated as “parachute payments” within the meaning of Section 280G(b)(2) of the Code, and all “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax, except to the extent that, in the opinion of independent counsel selected by the Company and reasonably acceptable to such Participant (“Independent Counsel”), a Payment (in whole or in part) does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code, or such “excess parachute payments” (in whole or in part) are not subject to the Excise Tax;

      (b) the amount of the Payments that shall be treated as subject to the Excise Tax shall be equal to the lesser of (i) the total amount of the Payments or (ii) the amount of “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code (after applying Section 11.2(a) above); and

      (c) the value of any noncash benefits or any deferred payment or benefit shall be determined by Independent Counsel in accordance with the principles of Sections 280G(d)(3) and (4) of the Code.

For purposes of determining the amount of the Gross-Up Payment, such Participant shall be deemed to pay federal income taxes at the highest marginal rates of federal income taxation applicableto the individualsinthe calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rates of taxation applicable to individuals as arein effect in the state and locality of such Participant’s residence in the calendar year in which the Gross-Up Payment is to be made, net of the maximum reduction in federal income taxes that can be obtained from deduction of such state and local taxes, taking into account any limitations applicable to individuals subject to federal income tax at the highest marginal rates.

11.3Date of Paymentof Gross-Up Payments. The Gross-Up Payments provided for in Section 11.1 above shall be paid upon theearlier of (i) the payment to such Participant of any Payment or (ii) the imposition upon such Participant or payment by such Participant of any Excise Tax.

 11.4        Adjustment. If it isestablished pursuant to a final determination of a court or an Internal Revenue Serviceproceeding or theopinion of Independent Counsel that the Excise Tax is less than the amount taken into account under Section 11.1 above, such Participant shall repay to the Company within 30 days of such Participant’s receipt of notice of such final determination or opinion the portion of theGross-Up Payment attributable to such reduction (plus the portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by such Participant if such repayment results in a reduction in Excise Tax or a federal, state and local income tax deduction) plus any interest received by such Participant on the amount of such repayment.

If it is established pursuant to a final determination of acourt or an Internal RevenueService proceeding or the opinion of independent Counsel that the Excise Tax exceeds the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess within 30 days of the Company’s receiptof notice of such final determination or opinion.

11.5        Further Interpretation of Section 280G or 4999 of the Code. In the event of any change in, or further interpretation of, Section 280G or 4999 of the Code and the regulations promulgated thereunder, such Participant shall beentitled, by written notice to the Company, to request an opinion of Independent Counsel regarding the application of such change to any of the foregoing, and the Company shall use its best efforts to cause such opinion to be rendered as promptly as practicable. All fees and expenses of Independent Counsel incurred in connection with this agreement shall be borne by the Company.

12.0         TERM OF PLAN; AMENDMENT AND TERMINATION

12.1        Term of Plan, Amendment, Termination. The Plan shall be effective as of the Effective Date and shall remain in effect until the Board terminates the Plan. The Plan may be terminated, suspended or amended by the Board at any time with or without prior notice prior to a Change-in-Control; provided, however, that the Plan shall not beterminated, suspended or amended on a Change-in-Control Date or during the 3-year period following such Change-in-Control Date, and if the Plan is terminated, suspended or amended thereafter, such action shall not adversely affect thebenefits of any Terminated Participant.

13.0        COMPLIANCE WITH SECTION 409A

13.1        General. Notwithstanding any other provision in the Plan to the contrary, if and to the extent that Section 409A is deemed to apply to the Plan or any Change-in-Control Benefit provided under the Plan, it is the general intention of the Company that the Plan and all such benefits shall comply with Section 409A, related regulations or other guidance, and the Plan and any such Change-in-Control Benefit shall, to the extent practicable, be construed in accordance therewith. Without in any way limiting the effect of the foregoing, in the event that Section 409A, related regulations or other guidance require that any special terms, provisions or conditions be included in the Plan or any Change-in-Control Benefit, then such terms, provisions and conditions shall, to the extent practicable, be deemed to be made a part of the Plan or Change-in-Control Benefit, as applicable. Further, in the event that the Plan or any Change-in-Control Benefit shall be deemed not to comply with Section 409A or any related regulations or other guidance, then neither the Company, the Committee nor its or their designees or agents shall be liable to any Participant or other person for actions, decisions or determinations made in good faith.

13.2        Specific Terms Applicable to Change-in-Control Benefits Subject to Section 409A. Without limiting the effect of Section 13.1 above, and notwithstanding any other provision in the Plan to the contrary, the following provisions shall, to the extent required under Section 409A, related regulations or other guidance, apply with respect to Change-in-Control Benefits deemed to involve the deferral of compensation under Section 409A:

(a) Distributions: Distributions may be made with respect to Change-in-Control Benefits subject to Section 409A not earlier than upon the occurrence of one or more of the following events: (A) Separation from Service; (B) disability; (C) death; (D) a specified time or pursuant to a fixed schedule; (E) a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company, as defined in Section 2.5.2; or (F) the occurrence of an unforeseeable emergency. Each of the preceding distribution events shall be defined and interpreted in accordance with Section 409A and related regulations or other guidance.

(b) Specified Employees: With respect to Participants who are Specified Employees, a distribution of deferred compensation due to Separation from Service may not be made before the date that is six months after the Termination Date (or, if earlier, the date of death of the Participant), except as may be otherwise permitted pursuant to Section 409A. To the extent that a Participant is subject to this section and a distribution is to be paid in installments, through an annuity, or in some other manner where payment will be periodic, the Participant shall be paid, during the seventh month following the Termination Date, the aggregate amount of payments he or she would have received but for the application of this section; all remaining payments shall be made in their ordinary course.

    (c)No Acceleration: Unless permissible under Section 409A, related regulations or other guidance, the acceleration of the time or schedule for the payment of any Change-in-Control Benefit under the Plan is prohibited.

14.0         MISCELLANEOUS

14.1        Offset. The Change-in-Control Benefits shall be reduced by any payment or benefit made or provided by the Company or any Subsidiary to the Participant pursuant to (i) any severance plan, program, policy or arrangement of the Company or any subsidiary of the Company not otherwise referred to in the Plan, (ii) any employment agreement between the Company or any Subsidiary and the Participant, and (iii) any federal, state or local statute, rule, regulation or ordinance.

14.2        No Right, Title, or Interest in Company Assets. Participants shall have no right, title, or interest whatsoever in or to any assets of the Company or any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, Beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. Subject to Section 8 above, all payments to be made hereunder shall be paid from the general funds of the Company and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts except as expressly set forth in the Plan.

14.3        No Right to Continued Employment. The Participant’s rights, if any, to continue to serve the Company or any Subsidiary as an employee shall not be enlarged or otherwise affected by his or her designation as a Participant under the Plan, and the Company or the applicable Subsidiary reserves the right to terminate the employment of any employee at anytime. The adoptionof the Plan shall not be deemed to give any employee, or any other individual any right to be selectedas a Participant or to continued employment with the Company or any Subsidiary.

14.4        Other Rights. The Plan shall not affect or impair the rights or obligations of the Company, any Subsidiary or a Participant under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan.

14.5        Governing Law. The Plan shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.

14.6        Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent.

14.7        Incapacity. If the Committee determines that a Participant or a Beneficiary is unable to care for his or her affairs because of illness or accident or because he or she is a minor, any benefit due the Participant or Beneficiary may be paid to the Participant’s spouseor to any other person deemed by the Committee to have incurred expense for such Participant (including a duly appointed guardian, committee or other legal representative), and any such payment shall be a complete discharge of the Company’s obligation hereunder.

14.8        Transferability of Rights. The Company shall have the unrestricted right to transfer its obligations under the Plan with respect to one or more Participants to any person, including, but not limited to, any purchaser of all or any part of the Company’s business. No Participant or Beneficiary shall have any right to commute, encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Participant or Beneficiary may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be non-assignable and nontransferable, except to the extent required by law. Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Participant or the spouse of a Participant shall,in the sole discretion of the Committee (after consideration of such facts as it deems pertinent), be grounds for terminating any rights of the Participant or Beneficiary to any portion of the Plan benefits not previously paid.

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

     PROGR ESS ENERGY, INC.

       0;     By: /s/ Robert B. McGehee

            0;     Robert B. McGehee

     Chief Executive Officer

EX-10.C11

Exhibit 10c(11)

PROGRESS ENERGY, INC.

NON-EMPLOYEE DIRECTOR

DEFERRED COMPENSATION PLAN

Restated Effective January 1, 2007

1.RECITALS

1.1Whereas, Progress Energy, Inc. (the “Company”) adopted this Non-Employee Director Deferred Compensation Plan (the “Plan”) as of December 16, 1981 (the “Effective Date”).

1.2Whereas, the Company has maintained and operated the Plan since the Effective Date pursuant to individual deferral agreements with the Company’s Directors.

1.3Whereas, the Company adopted this written restatement of the Plan effective as of January 1, 2007 in order to clarify the rights and obligations under the Plan of the Company and its Directors.

2.PURPOSE

2.1Purpose. The purpose of the Plan is to permit the Company’s non-employee Directors to defer all or a portion of their annual retainers and meeting fees in the form of Stock Units (as defined below), thereby aligning the interests of the Directors with the interests of the Company’s shareholders.

2.2Limitations. Distributions required or contemplated by this Plan or actions required to be taken under this Plan shall not be construed as creating a trust of any kind or a fiduciary relationship between the Company and any Director, any Director’s designated beneficiary, or any other person.

2.3Code Section 409A. This Plan is intended to comply with the requirements of Section 409A of the Internal Revenue Code and the regulations and other guidance issued thereunder, as in effect from time to time (“Section 409A”). To the extent a provision of the Plan is contrary to or fails to address the requirements of Section 409A, the Plan shall be construed and administered as necessary to comply with such requirements until this Plan is appropriately amended.

3.DEFINITIONS

The following terms shall have the following meanings unless the context in which they are used clearly indicates that some other meaning is intended:

3.1“Account” means the bookkeeping account maintained for each Director which shall be credited with all Voluntary Deferrals elected by a Director, all Automatic Deferrals and Matching Contributions made on behalf of a Director, and all dividend credits with respect to Stock Units in the Account, and other adjustments thereto.

3.2“Automatic Deferral” means the portion of a Director’s annual retainer that is automatically deferred under this Plan pursuant to Section 6.1.

3.3“Beneficiary” means the beneficiary or beneficiaries designated by a Director pursuant to Section 11.7 to receive the benefits, if any, payable on behalf of the Director under the Plan after the death of such Director, or, when there has been no such designation or an invalid designation, the individual or entity, or the individuals or entities, who will receive such amount.

3.4“Board” means the Board of Directors of the Company.

3.5“Change in Control” means “Change in Control,” as defined in Section 2.5.1 of the Progress Energy, Inc. Management Change in Control Plan (Amended and Restated Effective January 1, 2007).

3.6“Code” means the Internal Revenue Code of 1986, as amended.

3.7“Committee” means the Board’s Committee on Corporate Governance.

3.8“Common Stock” means the common stock of the Company.

3.9“Company” means Progress Energy, Inc., a North Carolina corporation, including any successor entity.

3.10“Compensation” means a Director’s annual retainer fees, meeting fees and committee fees otherwise payable to such Director during his or her current term as a Director.

3.11“Continuing Directors” mean the members of the Board as of January 1, 2007; provided, however, that any person becoming a Director subsequent to such date whose election or nomination for election was supported by 75 percent or more of the Directors who then comprised the Continuing Directors shall be considered to be a Continuing Director.

3.12“Deferral Election” means an annual irrevocable election, made in accordance with Section 6 in such form (electronic or otherwise) as approved and provided by the Committee, to defer the receipt of a designated amount of Compensation.

3.13“Deferrals” mean Automatic Deferrals and Voluntary Deferrals.

3.14“Director” means any person (other than a person who is an employee of the Company) who has been elected to serve as a member of the Board and any former member of the Board for whom an Account is maintained under this Plan.

3.15“Effective Date” means January 1, 2007.

3.16“Fair Market Value” means the average of the highest and lowest selling prices of Common Stock on the date a Director’s Account is credited (or on the last preceding trading date if Common Stock is not traded on such date) if Common Stock is readily tradable on a national securities exchange or other market system. If the Common Stock is not readily tradable on a national securities exchange or other market system, an amount determined in good faith by the Board as the fair market value of Common Stock on the date of determination.

3.17“Matching Contributions” mean discretionary amounts the Company may from time to time contribute to Directors’ Accounts based on the Company’s achievement of corporate incentive goals.

3.18“Plan” means this Progress Energy, Inc. Non-Employee Director Deferred Compensation Plan, as amended from time to time.

3.19“Plan Year” means the calendar year ending on each December 31.

3.20“Stock Units” mean investment units, each of which is deemed to be equivalent to one share of Common Stock.

3.21“Voluntary Deferrals” mean the Compensation that a Director elects to defer under this Plan pursuant to Section 6.2.

4.ADMINISTRATION

4.1Responsibility. The Committee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms.

4.2Authority of the Committee. The Committee shall have all the discretionary authority that may be necessary or helpful to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following:

(a)to correct any defect, supply any omission, and reconcile any inconsistency in the Plan in such manner and to such extent as it shall deem appropriate in its sole discretion to carry the same into effect;

(b)to issue administrative guidelines as an aid to administer the Plan and make changes in such guidelines as it from time to time deems proper;

(c)to make rules for carrying out and administering the Plan and make changes in such rules as it from time to time deems proper;

(d)to the extent permitted under the Plan, grant waivers of Plan terms, conditions, restrictions and limitations; and

(e)to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan.

4.3Action by the Committee. The Committee may act only by a majority of its members. Subject to applicable law, any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee.

4.4Delegation of Authority. Subject to applicable law, the Committee may delegate to one or more of its members, or to one or more agents, such duties, responsibility and authority with respect to this Plan as it may deem advisable. In addition, the Committee, or any person to whom it has delegated duties, responsibility and authority as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid by the Company or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee.

4.5Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive on all Directors and their heirs, successors, and legal representatives.

5.ELIGIBILITY AND PARTICIPATION

5.1Eligibility and Participation. All Directors are automatically eligible and shall participate in the Plan.

6.DEFERRALS

6.1Automatic Deferrals. A portion of each Director’s annual retainer, in an amount established from time to time by the Board, shall automatically be deferred under this Plan, which amount for purposes of the Plan shall be referred to as an “Automatic Deferral.” Unless and until changed by the Board, the annual amount of the Automatic Deferral shall be $15,000.

6.2Voluntary Deferrals. In addition to Automatic Deferrals, a Director may elect to defer all or any portion, expressed as a whole percentage, of his or her remaining Compensation by filing the appropriate Deferral Election with the Committee's designee. Deferrals under this Section 6.2 shall be known as “Voluntary Deferrals.”

6.3 First Term Deferral Elections. An individual who is elected to serve as a Director or who is nominated for election as a Director (other than an individual who was a Director immediately before such election or nomination) shall have the right at any time before the end of the thirty (30) day period immediately following the effective date of his or her election as a Director to elect to defer the payment of all or any portion of his or her future Compensation by filing the appropriate Deferral Election with the Committee's designee.

6.4Annual Deferral Elections. Before the beginning of each calendar year, a Director shall have the right to elect to defer the payment of his or her Compensation which is attributable to services rendered as a Director during such calendar year by filing the appropriate Deferral Election with the Committee's designee. Any Deferral Election which is made and which is not revoked before the beginning of such calendar year shall become irrevocable on the first day of such calendar year and shall remain irrevocable through the end of such calendar year.

6.5Automatic Renewal of Deferral Elections. If a Director makes a Deferral Election under either Section 6.3 or Section 6.4 for any calendar year and does not revoke such Deferral Election before the beginning of any subsequent calendar year, such Deferral Election shall remain in effect for each such subsequent calendar year and shall be irrevocable through the end of each subsequent calendar year.

6.6Account Credits. The Compensation which a Director defers under this Section shall be credited to his or to her Account effective as of the business day on which such Compensation would otherwise have been paid to the Director.

7. MATCHING CONTRIBUTIONS

7.1The Company may from time to time in its sole discretion make Matching Contributions to Directors’ Accounts which shall be converted to Stock Units as specified in Section 8.

8.STOCK UNITS

8.1Conversion of Deferrals and Matching Contributions to Stock Units. All Deferrals and Matching Contributions shall be converted to Stock Units on the day such Deferrals and Matching Contributions are credited to a Director’s Account. The number of Stock Units to be credited shall be determined by dividing the dollar value of the Deferrals and Matching Contributions credited to a Director’s Account by the Fair Market Value of one share of Common Stock as of the date on which the Deferrals and Matching Contributions are converted to Stock Units.

8.2Conversion of Dividend Equivalents to Stock Units. Directors’ Accounts will be credited with additional fully vested Stock Units as of the payment date of any dividends declared on the Common Stock. The number of additional Stock Units credited to an Account shall be determined by dividing (i) the product of the per-share cash dividend amount (or the value of any non-cash dividend) times the number of Stock Units credited to the Account as of the record date for such dividend, by (ii) the Fair Market Value of one share of Common Stock as of the dividend payment date.

8.3No Other Investment Alternatives. Nothing contained in this Plan shall be construed to give any Director any power or control to make investment decisions with respect to Deferrals or Matching Contributions other than the conversion to Stock Units as provided in this Section 8. Nothing contained in the Plan shall be construed to require the Company or the Committee to fund any Director's Account.

9.DISTRIBUTIONS

9.1Vesting. A Director shall be fully vested at all times in the Stock Units credited to his or her Account.

9.2Timing and Form of Distributions

(a)Election Regarding Distributions. Directors must make or have in effect an election for each Plan Year regarding the timing of distributions to be made under the Plan as set forth in Section 9.2(b) below (a “Distribution Election”). The Distribution Election shall have been or shall be made pursuant to a “Method of Payment Agreement” or otherwise pursuant to a Director’s Deferral Election.

A Director may only have one Distribution Election in effect with respect to Deferrals and Matching Contributions made prior to January 1, 2005 (the “409A Grandfathered Amounts”). A Director may change his or her Distribution Election with respect to 409A Grandfathered Amounts by completing and signing a new Method of Payment Agreement provided by the Company; provided, however, that any such new Method of Payment Agreement shall not be effective for a period of six (6) months from the day it is delivered to the Company.

With respect to Deferrals and Matching Contributions made after January 1, 2005, a Director must make or have in effect a Deferral Election with respect to an upcoming Plan Year no later than December 31 of the preceding Plan Year, which Deferral Election shall be irrevocable for such Plan Year. A Director may change his or her Distribution Election in effect for a subsequent Plan Year by delivering a new Method of Payment Agreement to the Company on or before December 31 of the preceding Plan Year. A Deferral Election will remain in effect for future Plan Years unless and until changed by the Director’s timely delivery of a new Method of Payment Agreement with respect to an upcoming Plan Year. A Director may not amend or change a Distribution Election with respect to any prior Plan Year. Notwithstanding the foregoing, a Director may make a one-time change to his or her Distribution Election with respect to all Plan Years, including the 2007 Plan Year, on or before December 31, 2007, subject to the transition relief rules under Code Section 409A and the regulations thereunder.

(b)Timing of Distributions. A director’s Distribution Election shall specify whether the Director shall receive distributions (i) in a single lump sum payment in cash as soon as practicable following the first business day of the calendar year following the year in which the Director’s service as a member of the Board terminates for any reason or (ii) in a series of annual installments (not to exceed 10) commencing as soon as practicable following the first business day of the calendar year following the year in which the Director’s service as a member of the Board terminates for any reason. If the Director has elected to receive installment payments, the amount of each installment shall be determined by dividing the number of Stock Units credited to the Director’s Account on the first business day preceding the date of payment by the number of installments remaining to be paid, and then converting the number of Stock Units determined thereby into a cash payment as provided in Section 9.2(c) below.

(c)Form of Distributions. All distributions under this Plan shall be in cash. Prior to any distribution, Stock Units shall be converted into the right to receive a cash payment equal to the number of Stock Units being distributed multiplied by the Fair Market Value of a share of Common Stock on the date of distribution.

(d)Death. Notwithstanding anything in this Plan to the contrary (and regardless of any distribution election in the Director’s Deferral Agreement, Method of Payment Agreement or Deferral Election), the value of the Director's entire Account shall be distributed in a single lump sum to the Director’s Beneficiary as soon as administratively feasible after the Director’s death.

9.3Unforeseeable Emergency Payments. In the event a Director incurs a financial hardship as a result of an “unforeseeable emergency” (as such term is defined below), the Director may apply to the Committee for the distribution of all or a portion of the Director’s Account. The application shall provide such information and be in such form as the Committee shall require. The Committee, in the exercise of its sole and absolute discretion, may approve or deny the request in whole or in part. The term “unforeseeable emergency” shall mean a severe financial hardship to the Director resulting from an illness or accident of the Director, the Director’s spouse, or a dependent (as defined in Section 152(a) of the Code) of the Director, loss of the Director’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Director. In no event may the amounts distributed with respect to an unforeseeable emergency exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement, cancellation of Deferrals for the remainder of the Plan Year, or compensation by insurance or otherwise or by liquidation of the Director’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship). If a Director receives a distribution of all or a portion of the Director’s Account pursuant to this Section 9.3, any Deferral Election in effect for the Director shall be cancelled, and the Director shall make no additional Voluntary Deferrals for the remainder of the current Plan Year. The Director may make Voluntary Deferrals with respect to future Plan Years by delivering a new Deferral Election in accordance with Section 6.4. Notwithstanding any provision in the Plan to the contrary, any payment made pursuant to this Section 9.3 shall comply with Section 409A(a)(2)(A)(vi) of the Code and the regulations (or similar guidance) promulgated thereunder (or under any successor provisions).

10.TERM OF PLAN; AMENDMENT AND TERMINATION

10.1Term. The Plan shall be effective as of the Effective Date. The Plan shall remain in effect until the Board terminates the Plan.

10.2Termination or Amendment of Plan. The Board may amend, suspend or terminate the Plan at any time with or without prior notice; provided, however,that no action authorized by this Section 10.2 shall reduce the balance or adversely affect the Account of a Director.

11.MISCELLANEOUS

11.1Adjustments. If there shall be any change in Common Stock through merger, consolidation, reorganization, recapitalization, stock dividend, stock split, reverse stock split, split up, spin-off, combination of shares, exchange of shares, dividend in kind or other like change in capital structure or distribution (other than normal cash dividends) to holders of Common Stock, the number of Stock Units and the Director’s Account shall be adjusted to equitably reflect such change or distribution.

11.2Governing Law. The Plan and all actions taken in connection herewith shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.

11.3No Right Title or Interest in Company Assets. Directors shall have no right, title, or interest whatsoever in or to any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Director, beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. All payments to be made hereunder shall be paid from the general funds of the Company and, except as provided in Section 11.10 below, no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts.

11.4No Right to Continued Service. The Director’s rights, if any, to continue to serve the Company as a member of the Board shall not be enlarged or otherwise affected by his or her participation in the Plan.

11.5Other Rights. The Plan shall not affect or impair the rights or obligations of the Company or a Director under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan.

11.6Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent. If, however, the Committee determines in its sole discretion that any term or condition of the Plan which is invalid or unenforceable is material to the interests of the Company, the Committee may declare the Plan null and void in its entirety.

11.7Beneficiary Designation. Every Director may file with the Company a designation in such form (electronic or otherwise) as approved and provided by the Company of one or more persons as the Beneficiary who shall be entitled to receive the benefits, if any, payable under the Plan after the Director’s death. A Director may from time to time revoke or change such Beneficiary designation without the consent of any prior Beneficiary by filing a new designation with the Company. The last such designation received by the Company shall be controlling; provided, however, that no designation, or change or revocation thereof, shall be effective unless received by the Company prior to the Director’s death, and in no event shall it be effective as of any date prior to such receipt. All decisions of the Committee concerning the effectiveness of any Beneficiary designation and the identity of any Beneficiary shall be final. If a Beneficiary shall die after the death of the Director and prior to receiving the payment(s) that would have been made to such Beneficiary had such Beneficiary’s death not occurred, then for the purposes of the Plan the payment(s) that would have been received by such Beneficiary shall be made to the Beneficiary’s estate.

11.8Transferability of Rights. No Director or spouse of a Director shall have any right to encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Director or such spouse may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be nonassignable and nontransferable, except to the extent required by law. Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Director or the spouse of a Director shall be null and void and without effect.

11.9Entire Document. The Plan, as set forth herein, supersedes any and all prior practices, understandings, agreements, descriptions or other non-written arrangements with respect to the subject matter hereof.

11.10 Change in Control. In the case of a Change in Control, the Company, subject to the restrictions in this Section 11.10 and in Section 11.3, shall irrevocably set aside funds in one or more grantor trusts in an amount that is sufficient to pay each Director the value of the Director’s Account as of the date on which the Change in Control occurs; provided, however, that the Company shall establish no such trust if the assets thereof are includable in the income of Directors thereby pursuant to Section 409A(b). The obligations and responsibilities of the Company under this Plan shall be assumed by any successor or acquiring corporation, and all of the rights, privileges and benefits of the Directors hereunder shall continue following the Change in Control.

IN WITNESS WHEREOF, this instrument has been executed this 13th day of December, 2006.

PROGRESS ENERGY, INC.

                        By:  /s/ Robert B. McGehee

Robert B. McGehee

Chief Executive Officer

EX-10.C12

Exhibit 10c(12)

Amended and Restated

Progress Energy, Inc.

Restoration Retirement Plan

Carolina Power & Light Company established the Carolina Power & Light Company Restoration Retirement Plan (the “Plan”), effective as of January 1, 1998 (“Effective Date”), which was subsequently amended and restated as of January 1, 1999, January 1, 2000, July 10, 2002 and January 1, 2005. The Sponsor hereby amends and restates the Plan effective as of January 1, 2007. The terms of the amended and restated Plan shall govern the payment of any benefits commencing after January 1, 2007.

ARTICLE I

PURPOSE

The purpose of the Plan is to provide a means by which certain employees may be provided benefits which otherwise would be provided under the Retirement Plan, in the absence of certain restrictions imposed by applicable law on benefits which may be provided under the Retirement Plan. The Plan is intended to constitute a nonqualified deferred compensation plan that complies with the provisions of Section 409A of the Code. Accordingly, the Plan and all Plan benefits shall be administered in accordance with Section 409A, related regulations and other guidance (“Section 409A”), notwithstanding any provisions of the Plan to the contrary. The Plan also is intended to constitute an unfunded retirement plan for a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended.

ARTICLE II

DEFINITIONS

Capitalized terms which are not defined herein shall have the meaning ascribed to them in the Retirement Plan.

2.1“Actuarial Value” shall mean an equivalent lump sum value as of the Benefit Commencement Date using the average 30-year Treasury Rate for the month of August immediately preceding the calendar year the determination is made and the GAR 94 mortality table (50% male, 50% female).

2.2“Affiliated Company” shall mean any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Sections 414(b), (c), (m), or (o) of the Code, but only to the extent so required.

2.3“Benefit Commencement Date” shall mean the first day of the month following the Termination of the Participant. Notwithstanding the foregoing, payments with respect to a Participant who is a Key Employee shall not begin earlier than the date that is six months after the date of Termination of the Participant (or, if earlier, the date of death).

2.4“Board” shall mean the Board of Directors of the Sponsor.

2.5“Change in Control” shall occur on the earliest of the following dates:

(a)the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or

(b)the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or

(c)the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or

(d)the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or

(e)the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor’s assets; or

(f)the date of any event which the Board determines should constitute a Change in Control.

A Change in Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Committee on Organization and Compensation of the Board that such event has occurred. Any determination that such an event has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Board, the Sponsor, the Company, the Participants and their beneficiaries for all purposes of the Plan.

2.6“Code” shall mean the Internal Revenue Code of 1986, as amended.

2.7“Committee” shall mean a committee selected by the Plan Administrator to hear claim disputes under Article IV of the Plan.

2.8“Company” shall mean Progress Energy, Inc. or any successor to it in the ownership of substantially all of its assets and each Affiliated Company that, with the consent of the Board, adopts the Plan and is included in Appendix A, as in effect from time to time. Appendix A shall set forth any limitations imposed on employees of Affiliated Companies that adopt the Plan including any limitations on benefit accruals, notwithstanding any provision in the Plan to the contrary.

2.9“Compensation and Benefit Limitations” shall mean (a) the limitation on compensation under the Retirement Plan in accordance with Section 401(a)(17) of the Code and (b) any limits on benefits paid under the Retirement Plan that are necessary for compliance with Section 415 of the Code.

2.10“Continuing Directors” shall mean the members of the Board as of January 1, 2007; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by 75 percent or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.

2.11“Deferrals” shall mean a Participant's deferrals of compensation under the MDCP to the extent not utilized in calculating a Participant's Accrued Benefit under the Retirement Plan.

2.12“Eligible Employee” shall mean any member of the Retirement Plan who is not a Participant in the Sponsor's Supplemental Senior Executive Retirement Plan and who has not retired or terminated his or her employment with the Company prior to the Effective Date.

2.13“Key Employee” shall mean a Participant who is a “key employee” as defined in Section 416(i) of the Code, but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees.

2.14“MDCP” shall mean the Progress Energy, Inc. Amended and Restated Management Deferred Compensation Plan.

2.15“Participant” shall mean an Eligible Employee who participates in the Plan pursuant to Article III. An Eligible Employee shall remain a Participant under the Plan until the earlier of (a) all amounts payable on his or her behalf under the Plan have been paid, (b) the Eligible Employee no longer has a Restoration Accrued Benefit, (c) the Eligible Employee has a Termination without a Vested Restoration Accrued Benefit, or (d) the Eligible Employee becomes a Participant in the Sponsor’s Supplemental Senior Executive Retirement Plan.

2.16“Restoration Accrued Benefit” shall mean, as of any determination date, the excess of (a) a Participant’s Accrued Benefit calculated under the Retirement Plan (1) assuming a Participant’s Compensation under the Retirement Plan includes Deferrals of a Participant and (ii) without regard to the Compensation and Benefit Limitations, over (b) a Participant’s Accrued Benefit calculated under the Retirement Plan. For purposes of this Section 2.16, a Participant's Accrued Benefit for purposes of clauses (a) and (b) above shall be calculated in the form of a Single Life Annuity for a Participant who does not have a Spouse and in the form of a 50% Qualified Joint and Survivor Annuity for a Participant who has a Spouse, with such calculation performed without regard to any other form of benefit elected by a Participant under the Retirement Plan.

2.17“Retirement Plan” shall mean the Progress Energy Pension Plan, as it may be amended from time to time, or any successor plan.

2.18“Sponsor” shall mean Progress Energy, Inc.

2.19“Spouse” shall mean the spouse of a Participant as would be determined at the applicable time under the definition of Spouse in the Retirement Plan (or any successor provisions).

2.20“Termination” shall mean “separation from service,” as defined for purposes of Section 409A.

2.21“Vested Restoration Accrued Benefit” shall mean a Participant’s Restoration Accrued Benefit when the Participant becomes fully vested under the provisions of the Retirement Plan (or any successor provisions) or as provided in Article VI of the Plan.

Unless the context clearly indicates to the contrary in interpreting the Plan, any references to the masculine alone shall include the feminine and the singular shall include the plural.

ARTICLE III

PARTICIPATION AND BENEFITS

3.1Participation. An Eligible Employee will participate in the Plan when he or she has a Restoration Accrued Benefit.

3.2Amount of Benefit Payable. Subject to the forfeiture provisions of Section 3.4 and lump sum payment provisions of Section 3.5 of the Plan, a Participant who becomes eligible for the payment of a benefit under the Retirement Plan, shall be entitled to monthly benefit payments commencing as of his Benefit Commencement Date or as soon thereafter as practicable based on the Participant’s Restoration Accrued Benefit calculated immediately prior to the Benefit Commencement Date and actuarially adjusted as if an annuity were being paid under the Retirement Plan as of the Benefit Commencement Date. The monthly payment shall be in the form of a Single Life Annuity if the Participant has no Spouse and in the form of a 50% Joint and Survivor Annuity if the Participant has a Spouse, with the Spouse determined at the Benefit Commencement Date entitled to any survivor benefit upon the death of the Participant.

3.3Pre-Retirement Death Benefit. Subject to the provisions of Section 3.5, if a surviving Spouse of a deceased Participant would have been eligible for a pre-retirement death benefit under the Retirement Plan (i.e., the Spouse being married to the Participant for a one-year period prior to the date of death), then upon such Participant’s death, such Spouse shall be entitled to a monthly benefit payment under the Plan equal to the amount, if any, by which (a) exceeds (b) each month, where (a) is the Spouse’s monthly death benefit that would be payable in accordance with the provisions of the Retirement Plan determined as if (i) the Participant’s Compensation under the Retirement Plan included Deferrals and (ii) the Compensation and Benefit Limitations did not apply, and (b) is the monthly death benefit payable under the Retirement Plan, and assuming for purposes of clauses (a) and (b) that the Spouse elected a monthly annuity as a death benefit under the Retirement Plan commencing on the same date as the pre-retirement death benefit is payable to the Spouse under this Plan. The pre-retirement death benefit under this Plan shall commence as of the first day of the month following the Participant’s death or as soon thereafter as practicable, and shall continue on the first day of the each month thereafter for the life of the Spouse.

3.4Other Termination of Employment; Forfeitures. Neither Eligible Employees, Participants nor their Spouses or Beneficiaries are entitled to any benefits under the Plan except as otherwise provided in this Article III and under Article VI of the Plan. Any Participant who terminates employment with the Sponsor and any of its Affiliated Companies without being 100% vested under the Retirement Plan shall not be eligible to receive any benefits under the Plan and shall forfeit his or her Restoration Accrued Benefit. Any Participant ceasing to be an Eligible Employee because he or she becomes a Participant in the Supplemental Senior Executive Retirement Plan shall forfeit his or her Restoration Accrued Benefit.

Notwithstanding any other provision of the Plan, no benefit shall be payable under the Plan with respect to an Eligible Employee whose employment with the Sponsor or any of its Affiliated Companies is terminated for Cause. As used herein, the term “Cause” shall be limited to (a) action by the Eligible Employee involving willful malfeasance having a material adverse effect on the Sponsor or any of its Affiliated Companies (b) substantial and continuing willful refusal by the Eligible Employee to perform the duties ordinarily performed by an employee in the same position and having similar duties as the Eligible Employee, (c) the Eligible Employee being convicted of a felony, or (d) willful failure to comply with the Sponsor or the applicable Affiliated Company's Code of Conduct or other Policy or Procedure.

3.5Lump Sum Payments. The Committee shall provide for the payment under the Plan of a cash lump sum amount in lieu of the annuity otherwise payable under Sections 3.2 or 3.3, if the annuity amount to be paid is less than $500 per month. For a Participant (or spouse) whose benefit under the Retirement Plan is based upon the Participant’s Cash Balance Account, the lump sum shall be equal to what the Restoration Accrued Benefit would be if “Cash Balance Account” were substituted for “Accrued Benefit” in Section 2.15 and Restoration Accrued Benefit referred to a dollar amount. For a Participant (or spouse) whose benefit under the Retirement Plan is based on the Final Average Pay Formula Pension, the lump sum shall be equal to the Actuarial Value of the annuity payments that would otherwise be made to the Participant (or spouse) under Sections 3.2 or 3.3, as the case may be. Notwithstanding the foregoing, no lump sum payment shall be made under the Plan unless (i) the payment accompanies the termination of the entirety of the Participant’s interest in the Plan; (ii) the payment is made on or before the later of (A) December 31 of the calendar year in which the Termination of the Participant occurs, or (B) the date that is 2 ½ months after the Termination of the Participant; and (iii) the payment is not greater than $75,000.

3.6Payments to Key Employees. In the event the Benefit Commencement Date under this Plan of a Participant who is a Key Employee shall be delayed for six months following the Termination of the Participant as provided in Section 2.3, the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the Termination in an amount equal to six times the monthly payment due to the Participant under this Plan, in addition to the monthly payment then due to the Participant. If the Participant dies following Termination but prior to the commencement of payments under this Plan, the Participant’s surviving Spouse, if any, shall be entitled to receive the same death benefit payable in the event the Participant had commenced receiving benefit payments as of the first day of the month prior to his death.

ARTICLE IV

PLAN ADMINISTRATION

4.1Administration. The Plan shall be administered by the Sponsor's Vice President, Human Resources (the “Plan Administrator”). The Plan Administrator and the Committee shall have full authority to administer and interpret the Plan, determine eligibility for benefits, make benefit payments and maintain records hereunder, all in their sole and absolute discretion, subject to the allocation of responsibilities set forth below.

4.2Delegated Responsibilities. The Plan Administrator shall have the authority to delegate any of his or her responsibilities to such persons as he or she deems proper.

4.3Claims.

(a)Claims Procedure. If any Participant, Spouse or Beneficiary has a claim for benefits which is not being paid, such claimant may file with the Plan Administrator a written claim setting forth the amount and nature of the claim, supporting facts, and the claimant’s address. The Plan Administrator shall notify each claimant of its decision in writing by registered or certified mail within sixty (60) days after its receipt of a claim or, under special circumstances, within ninety (90) days after its receipt of a claim. If a claim is denied, the written notice of denial shall set forth the reasons for such denial, refer to pertinent Plan provisions on which the denial is based, describe any additional material or information necessary for the claimant to realize the claim, and explain the claim review procedure under the Plan.

(b)Claims Review Procedure. A claimant whose claim has been denied or such claimant’s duly authorized representative may file, within sixty (60) days after notice of such denial is received by the claimant, a written request for review of such claim by the Committee. If a request is so filed, the Committee shall review the claim and notify the claimant in writing of its decision within sixty (60) days after receipt of such request. In special circumstances, the Committee may extend for up to sixty (60) additional days the deadline for its decision. The notice of the final decision of the Committee shall include the reasons for its decision and specific references to the Plan provisions on which the decision is based. The decision of the Committee shall be final and binding on all parties.

ARTICLE V

MISCELLANEOUS

5.1Amendment and Termination. The Board may amend, modify or terminate the Plan at any time, provided, however, that no such amendment or termination shall reduce any Participant’s Vested Restoration Accrued Benefit under the Plan as of the date of such amendment or termination, unless at the time of such amendment or termination, affected Participants and spouses become entitled to an amount equal to the equivalent actuarial value, to be determined in the sole discretion of the Committee, of such Vested Restoration Accrued Benefit under another plan, program or practice adopted by a Company. In the event the Plan is terminated, the Sponsor shall pay the Vested Restoration Accrued Benefits in accordance with the terms of the Plan as in effect prior to such termination except as otherwise provided in Section 6.4.

5.2Source of Payments. Each Company will pay with respect to its own Eligible Employees all benefits arising under the Plan and all costs, charges and expenses relating thereto out of its general assets.

5.3Non-Assignability of Benefits. Except as otherwise required by law, neither any benefit payable hereunder nor the right to receive any future benefit under the Plan may be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits under the Plan becomes bankrupt, the interest under the Plan of the person affected may be terminated by the Plan Administrator which, in his or her sole discretion, may cause the same to be held or applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate.

5.4Plan Unfunded. Nothing in the Plan shall be interpreted or construed to require a Company in any manner to fund any obligation to the Participants, terminated Participants, or beneficiaries hereunder. Nothing contained in the Plan nor any action taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between a Company and the Participants, terminated Participants, beneficiaries, or any other persons. Any funds which may be accumulated by a Company in order to meet any obligations under the Plan shall for all purposes continue to be a part of the general assets of a Company. A Company may establish a trust to hold funds intended to provide benefits hereunder to the extent the assets of such trust become subject to the claims of the general creditors of such Company in the event of bankruptcy or insolvency of such Company; provided, however, that a Company shall establish no such trust if the assets thereof are includable in the income of any Participant thereby pursuant to Section 409A(b). To the extent that any Participant, terminated Participant, or beneficiary acquires a right to receive payments from a Company under the Plan, such rights shall be no greater than the rights of any unsecured general creditor of such Company.

5.5Applicable Law. All questions pertaining to the construction, validity and effect of the Plan shall be determined in accordance with the laws of the State of North Carolina to the extent not preempted by Federal law and shall be construed in a manner consistent with the requirements of Section 409A.

5.6Limitation of Rights. The Plan is a voluntary undertaking on the part of the Sponsor and each Company. Neither the establishment of the Plan nor the payment of any benefits hereunder, nor any action of the Sponsor, a Company or the Plan Administrator shall be held or construed to be a contract of employment between the Sponsor, a Company and any Eligible Employee or to confer upon any person any legal right to be continued in the employ of the Sponsor or a Company. The Sponsor and each Company expressly reserve the right to discharge, discipline or otherwise terminate the employment of any Eligible Employee at any time. Participation in the Plan gives no right or claim to any benefits beyond those which are expressly provided herein and all rights and claims hereunder are limited as set forth in the Plan.

5.7Severability. In the event any provision of the Plan shall be held illegal or invalid, or the inclusion of any Participant would serve to invalidate the Plan as an unfunded plan for a select group of management or highly compensated employees under ERISA, then the illegal or invalid provision shall be deemed to be null- and void, and the Plan shall be construed as if it did not contain that provision and in the case of the inclusion of any such Participant, a separate plan, with the same provisions as the Plan, shall be deemed to have been established for the Participant or Participants ultimately determined not to constitute a select group of management or highly compensated employees.

5.8Headings. The headings to the Articles and Sections of the Plan are inserted for reference only, and are not to be taken as limiting or extending the provisions hereof.

5.9Incapacity. If the Plan Administrator shall determine that a Participant, or any other person entitled to a benefit under the Plan (the "Recipient") is unable to care for his or her affairs because of illness, accident, or mental or physical incapacity, or because the Recipient is a minor, the Plan Administrator may direct that any benefit payment due the Recipient be paid to his or her duly appointed legal representative, or, if no such representative is appointed, to the Recipient's spouse, child, parent, or other blood relative, or to a person with whom the Recipient resides or who has incurred expense on behalf of the Recipient. Any such payment so made shall be a complete discharge of the liabilities of the Plan with respect to the Recipient.

5.10Binding Effect and Release. Obligations incurred by the Sponsor or a Company pursuant to this Plan shall be binding upon the Sponsor or a Company, its successors and assigns, and inure to the benefit of the Participant or his Eligible Spouse. All persons accepting benefits under the Plan shall be deemed to have consented to the terms of the Plan. Any payment or distribution to any person entitled to benefits under the Plan shall be in full satisfaction of all claims against the Plan, the Committee, and the Sponsor and any Company arising by virtue of the Plan.

5.11Acceleration of Payments. The acceleration of the time or schedule of any payment due under the Plan is prohibited except as provided in regulations and administrative guidance provided under Section 409A of the Code. It is not an acceleration of the time or schedule of payment if the Company waives or accelerates the vesting requirements applicable to a benefit under the Plan.

ARTICLE VI

CHANGE IN CONTROL

Upon the occurrence of a Change in Control, the following provisions shall become effective immediately:

6.1Vesting. There shall be full Vesting of each Participant’s Restoration Accrued Benefit, regardless of any termination of employment prior to eligibility for an Early Retirement Pension under the Retirement Plan, if he or she is otherwise vested under the Retirement Plan.

6.2No Reduction Benefit. No amendment or termination of the Plan may reduce any Participant's Restoration Accrued Benefit as of the date of such amendment or termination.

6.3Contributions to Trust. The Sponsor shall irrevocably set aside funds in one or more grantor trusts, subject to the provisions of Section 5.4, in an amount that is sufficient to pay each Participant (or Spouse) the benefits accrued under the Plan as of the date of the Change in Control. Any such trust shall be subject to the claims of the general creditors of the Sponsor in the event of the bankruptcy or insolvency of the Sponsor. The Sponsor shall establish no such trust if the assets thereof are includable in the income of Participants thereby pursuant to Section 409A(b).

6.4Termination of Plan. The Plan may be terminated and benefits distributed to Participants within twelve months of a “change in control event” as defined for purposes of Section 409A of the Code.

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

        PROGRESS ENERGY, INC.

         By: /s/ Robert B. McGehee

            Robert B. McGehee

  0;           Chief Executive Officer

APPENDIX A

Progress Energy Florida, Inc. (non-bargaining employees) solely with respect to accrued benefits on or after January 1, 2002 so that no Restoration Accrued Benefit is calculated under the Plan with respect to employment prior to January 1, 2002.

Progress Fuels Corporation (corporate employees) solely with respect to accrued benefits on or after January 1, 2002 so that no Restoration Accrued Benefit is calculated under the Plan with respect to employment prior to January 1, 2002.

Progress Energy Carolinas, Inc.

Progress Energy Service Company, LLC

Progress Energy Ventures, Inc.

EX-10.C13

Exhibit 10c(13)

AMENDED AND RESTATED

SUPPLEMENTAL SENIOR EXECUTIVE RETIREMENT PLAN

OF

PROGRESS ENERGY, INC.

Effective January 1, 1984

(As last amended effective January 1, 2007)

TABLE OF CONTENTS

			Page
ARTICLE I
STATEMENT OF PURPOSE			1
ARTICLE II
DEFINITIONS			2
	2.01	Terms	2
	2.02	Affiliated Company	2
	2.03	Assumed Deferred Vested Pension Benefit	2
	2.04	Assumed Early Retirement Pension Benefit	2
	2.05	Assumed Normal Retirement Pension Benefit	3
	2.06	Board	3
	2.07	Change in Control	3
	2.08	Committee	5
	2.09	Company	5
	2.10	Continuing Director	5
	2.11	Designated Beneficiary	6
	2.12	Early Retirement Date	6
	2.13	Eligible Spouse	6
	2.14	Final Average Salary	6
	2.15	Normal Retirement Date	7
	2.16	Participant	7
	2.17	Pension	7
	2.18	Plan	7
	2.19	Retirement Plan	7
	2.20	Salary	7
	2.21	Separation from Service	8
	2.22	Service	8
	2.23	Social Security Benefit	8
	2.24	Spouse’s Pension	10
	2.25	Target Early Retirement Benefit	10
	2.26	Target Normal Retirement Benefit	10
	2.27	Target Pre-Retirement Death Benefit	10
	2.28	Target Severance Benefit	10
ARTICLE III
ELIGIBILITY AND PARTICIPATION			10
	3.01	Eligibility	10
	3.02	Date of Participation	11
	3.03	Duration of Participation	11
ARTICLE IV
RETIREMENT BENEFITS			11
	4.01	Normal Retirement Benefit	11
	4.02	Early Retirement Benefit	13
	4.03	Surviving Spouse Benefit	15
	4.04	Re-employment of Retirement Participant	15
ARTICLE V
PRE-RETIREMENT DEATH BENEFITS			15
	5.01	Eligibility	15
	5.02	Amount	16
	5.03	Alternative Benefit	16
	5.04	Commencement and Duration	16
ARTICLE VI
SEVERANCE BENEFITS			16
	6.01	Eligibility	16
	6.02	Amount	17
	6.03	Commencement and Duration	17
	6.04	Surviving Spouse Benefit	18
ARTICLE VII
ADMINISTRATION			19
	7.01	Committee	19
	7.02	Voting	19
	7.03	Records	19
	7.04	Liability	20
	7.05	Expenses	20
ARTICLE VIII
AMENDMENT AND TERMINATION			20
ARTICLE IX
MISCELLANEOUS			21
	9.01	Non-Alienation of Benefits	21
	9.02	No Trust, Created	21
	9.03	No Employment Agreement	22
	9.04	Binding Effect	22
	9.05	Suicide	22
ARTICLE X
CONSTRUCTION			24
	10.01	Governing Law	24
	10.02	Gender	24
	10.03	Headings, etc.	24
	10.04	Action	24
APPENDIX A AFFILIATED COMPANIES

ARTICLE I

STATEMENT OF PURPOSE

This Plan is designed and implemented for the purpose of enhancing the earnings and growth of Progress Energy, Inc. (the “Sponsor”) by providing to the limited group of senior management employees largely responsible for such earnings and long-term growth deferred compensation in the form of supplemental retirement income benefits, thereby increasing the incentive of such key senior management employees to make the Sponsor and its Affiliated Companies more profitable. The benefits are normally payable to Participants upon retirement or death. The terms of the benefits operate in conjunction with the Participant’s benefits payable under the Progress Energy Pension Plan and are designed to supplement such pension plan benefits and provide the Participant with additional financial security upon retirement or death.

The Plan is intended to constitute a nonqualified deferred compensation plan that complies with the provisions of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). Accordingly, the Plan shall be construed in accordance with Section 409A of the Code, regulations promulgated thereunder and related guidance (“Section 409A”), not- withstanding any provision of the Plan to the contrary. The Plan is further intended to be an unfunded retirement plan for a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended.

The Sponsor hereby restates and amends the Plan effective January 1, 2007. The terms of the amended and restated Plan shall govern the payment of any benefits commencing after January 1, 2007.

ARTICLE II

DEFINITIONS

2.01   Terms. Unless otherwise clearly required by the context, the terms used herein shall have the following meaning. Capitalized terms that are not defined below shall have the meaning ascribed to them in the Retirement Plan.

2.02   Affiliated Company. Shall mean any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Section 414(b), (c), (m), or (o) of the Code, but only to the extent required.

2.03   Assumed Deferred Vested Pension Benefit. Shall mean the monthly benefit of the deferred vested Pension to commence on his Normal Retirement Date payable in the form of an annuity to which a separated Participant would be entitled under the Retirement Plan, calculated with the following assumptions based on such Participant’s marital status at the time benefits hereunder commence:

(a)   In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan.

(b)   In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan.

(c)   Without regard to any other benefit payment option under the Retirement Plan.

2.04   Assumed Early Retirement Pension Benefit. Shall mean the monthly benefit of the normal retirement Pension payable in the form of an annuity to which a Participant would be entitled under the Retirement Plan at his Normal Retirement Date, based upon his projected years of Service at his Normal Retirement Date and calculated with the following assumptions based upon his marital status at the time benefits hereunder commence:

(a)   In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan.

(b)   In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan.

(c)   Without regard to any other benefit payment option under the Retirement Plan.

2.05   Assumed Normal Retirement Pension Benefit. Shall mean the monthly benefit of the normal retirement Pension payable in the form of an annuity to which a Participant would be entitled under the Retirement Plan if he retired at his Normal Retirement Date, calculated with the following assumptions based on his marital status at the time benefits hereunder commence:

(a)   In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan.

(b)   In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan.

(c)   Without regard to any other benefit payment option under the Retirement Plan.

2.06   Board. Shall mean the Board of Directors of Sponsor.

2.07   Change in Control. Shall occur on the earliest of the following dates:

(a)   the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or

(b)   the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or

(c)   the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or

(d)   the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or

(e)   the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor’s assets; or

(f)   the date of any event which the Board determines should constitute a Change in Control.

A Change in Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Committee that such event has occurred. Any determination that such an event has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Committee, the Sponsor, the Company, the Participants and their beneficiaries for all purposes of the Plan.

2.08   Committee. Shall mean the Committee on Organization and Compensation of the Board.

2.09   Company. Shall mean Progress Energy, Inc. or any successor to it in the ownership of substantially all of its assets, and each Affiliated Company that, with the consent of the Board adopts the Plan and is included in Appendix A, as in effect from time to time. Appendix A shall set forth any limitations imposed on employees of Affiliated Companies that adopt the Plan, including limitations on “Service,” notwithstanding any provision of the Plan to the contrary.

2.10   Continuing Director. Shall mean the members of the Board as of January 1, 2007; provided, however, that any person becoming a Director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of theDirectors who then comprised Continuing Directors shall be considered to be a Continuing Director.

2.11   Designated Beneficiary. Shall mean one or more beneficiaries as designated by a Participant in writing delivered to the Committee. In the event no such written designation is made by a Participant or if such beneficiary shall not be living or in existence at the time for commencement of payment to any Designated Beneficiary under the Plan, the Participant shall be deemed to have designated his estate as such beneficiary.

2.12   Early Retirement Date. Shall mean the date on which a Participant who qualifies for the early retirement benefit of Section 4.02 hereof retires from the employ of the Company and its affiliated entities.

2.13   Eligible Spouse. Shall mean the spouse of a Participant who, under the laws of the State where the marriage was contracted, is deemed married to that Participant on the date on which the payments from this Plan are to begin to the Participant, except that for purposes of Articles V and VI hereof, Eligible Spouse shall mean a person who is married to a Participant for a period of at least one year prior to his death.

2.14   Final Average Salary. Shall mean a Participant’s average monthly Salary (as defined in Section 2.20 hereof) during the 36 completed calendar months of highest compensation within the 120-month period immediately preceding the earliest to occur of the Participant’s death, Separation from Service, Early Retirement Date, or Normal Retirement Date, whichever is applicable. Provided, however, if a Participant becomes entitled to a benefit hereunder while under a period of long-term disability under the Sponsor’s Group Insurance Plan, Final Average Salary shall be determined for the 12 calendar months immediately preceding the commencement of such period of long-term disability. Provided, further, in determining average monthly Salary (i) annual incentives and other similar payments shall be deemed received in twelve (12) equal payments beginning with the eleventh preceding month and ending with the month in which actual payment is made, and (ii) amounts of compensation deferred under any deferred compensation plan or arrangement shall be deemed received in the months such payments would have been received assuming no deferral had occurred. For years of Service granted under the terms of a written employment agreement as provided under Section 2.22, Salary during each such month is deemed to be zero dollars ($0.00) for purposes of calculating Final Average Salary.

2.15   Normal Retirement Date. Shall mean the first day of the calendar month coinciding with or next following the Participant’s 65th birthday.

2.16   Participant. Shall mean an employee of the Company who is eligible and is participating in this Plan in accordance with Article III hereof.

2.17   Pension. Shall mean a level monthly annuity which is payable under the Retirement Plan as of the Benefit Commencement Date if the Participant elected an annuity form of benefit.

2.18   Plan. Shall mean the “Supplemental Senior Executive Retirement Plan of Progress Energy, Inc.” as contained herein and as it may be amended from time to time hereafter.

2.19   Retirement Plan. Shall mean the “Progress Energy Pension Plan” (as amended effective January 1, 2002) as it may be amended from time to time thereafter.

2.20   Salary. Shall mean the sum of:

(1)   The annual base compensation paid by the Company to a Participant, and

(2)   annual cash awards made under incentive compensation programs excluding, however, any payment made under the Sponsor’s Long-Term Compensation Program or the Sponsor’s 1997 and 2002 Equity Incentive Plans, and

(3)   amounts of annual compensation deferred under any deferred compensation plan or arrangement (including, without limitation, the “Executive Deferred Compensation Plan,” the “Deferred Compensation Plan for Key Management Employees of Progress Energy, Inc.,” the “Progress Energy, Inc. Management Deferred Compensation Plan” and the “Progress Energy 401(k) Savings and Stock Ownership Plan”) and which, but for the deferral, would have been reflected in Internal Revenue Service Form W-2.

2.21   Separation from Service. Shall mean the date the Participant leaves the employ of the Company and all affiliated entities other than on account of his death, a period of long-term disability under the Company’s long-term disability plan, or retirement at either his Early Retirement Date or upon or after his Normal Retirement Date. Separation from Service under this Section 2.21 must also be “separation from service,” as defined for purposes of Section 409A.

2.22   Service. Shall have the same meaning as “Eligibility Service,” determined as provided in Sections 2.02 and 3.01 of the Retirement Plan, plus any additional years of service that may be granted to the Participant in connection with this Plan under the terms of a written employment agreement (or any amendment thereto) entered into between the Company and the Participant.

2.23   Social Security Benefit. Means the monthly amount of benefit which a Participant is or would be entitled to receive at age 65 as a primary insurance amount under the federal Social Security Act, as amended, whether or not he applies for such benefit, and even though he may lose part or all of such benefit through delay in applying for it, by making application prior to age 65 for a reduced benefit, by entering into covered employment, or for any other reason. The amount of such Social Security Benefit to which the Participant is or would be entitled shall be estimated by the Committee for the purposes of this Plan as of the January 1 of the year in which his Separation from Service or retirement occurs on the following basis:

(a)   For a Participant entitled to a normal retirement benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Normal Retirement Date (regardless of any retroactive changes made by legislation enacted after said January 1);

(b)   For a Participant entitled to an early retirement benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Early Retirement Date (regardless of any retroactive change made by legislation enacted after said January 1), assuming that his employment, and Salary in effect at his Early Retirement Date, continued to age 65; or

(c)   For a Participant entitled to a severance benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Separation from Service (regardless of any retroactive change made by legislation enacted after said January 1), assuming that his employment, and Salary in effect at his Separation from Service, continued to age 65.

For purposes of the calculations required under paragraphs (a) and (b) above, if a Participant is disabled under a period of long-term disability under the Company’s Group Insurance Plan, said Social Security Benefit shall be calculated as if his Salary in effect at the commencement of such period of long-term disability continued to age 65.

2.24   Spouse’s Pension. Shall mean the actual monthly benefit payable to an Eligible Spouse under the Retirement Plan, assuming the Eligible Spouse elected a 50% Joint and Survivor Annuity form of benefit.

2.25   Target Early Retirement Benefit. Shall mean an amount equal to a Participant’s Final Average Salary determined at his Early Retirement Date multiplied by four percent (4%) for each projected year of Service at his Normal Retirement Date up to a maximum of sixty-two percent (62%).

2.26   Target Normal Retirement Benefit. Shall mean an amount equal to a Participant’s Final Average Salary determined at his Normal Retirement Date multiplied by four percent (4%) for each projected year of Service at his Normal Retirement Date up to a maximum of sixty-two percent (62%).

2.27   Target Pre-Retirement Death Benefit. Shall mean an amount equal to a deceased Participant’s Final Average Salary determined at his death multiplied by four percent (4%) for each year of Service at his death up to a maximum of sixty-two percent (62%).

2.28   Target Severance Benefit. Shall mean an amount equal to a Participant’s Final Average Salary determined at his Separation from Service multiplied by four percent (4%) for each year of Service at his Separation from Service up to a maximum of sixty-two percent (62%).

ARTICLE III

ELIGIBILITY AND PARTICIPATION

3.01   Eligibility. Any executive employee of a Company who has served on the Senior Management Committee of the Sponsor and who has been a Senior Vice President or above for a minimum period of three (3) years and who has at least ten (10) years of Service shall be eligible to participate in this Plan.

3.02   Date of Participation. Each executive who is eligible to become a Participant under Section 3.01 shall become a Participant on the first day of the month following the month in which he is first eligible to participate.

3.03   Duration of Participation. Each executive who becomes a Participant shall continue to be a Participant until the termination of his employment with the Company or, if later, the date he is no longer entitled to benefits under this Plan.

ARTICLE IV

RETIREMENT BENEFITS

4.01   Normal Retirement Benefit.

(a)Eligibility. A Participant whose employment with the Company or any Affiliated Company terminates on or after his Normal Retirement Date and whose termination is “separation from service,” as defined for purposes of Section 409A, shall be eligible for the normal retirement benefit described in this Section 4.01.

(b)Amount and Form. The monthly payment hereunder shall be in the form of a Single Life Annuity if the Participant has no Eligible Spouse and in the form of a 50% Qualified Joint and Survivor Annuity if the Participant has an Eligible Spouse. The eligible Participant’s normal retirement benefit shall be a monthly amount equal to his Target Normal Retirement Benefit reduced by the sum of (1) his Assumed Normal Retirement Pension Benefit and (2) his Social Security Benefit.

(c)Commencement and Duration. Monthly normal retirement benefit payments shall commence as of the first day of the calendar month next following the retirement of the Participant or as soon thereafter as practicable, and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant’s death occurs, unless the benefit is being paid in the form of a Qualified Joint and Survivor Annuity, in which case the survivor benefit shall be paid to the Eligible Spouse, if living, for his or her life. If at the time of commencement of payment such eligible Participant does not have an Eligible Spouse the monthly benefit payments shall be guaranteed for one hundred twenty (120) monthly payments with any such guaranteed payments remaining at such Participant’s death payable to his Designated Beneficiary.

(d)Key Employees. Notwithstanding the foregoing, payments with respect to a Participant who is a key employee (as defined in Section 416(i) of the Code but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees) shall not begin earlier than the date that is six months after the date of termination of the Participant (or, if earlier, the date of death). In the event payments to the Participant under this Plan shall be delayed for six months following the termination of the Participant as provided in this paragraph (d), the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the termination of employment in an amount equal to six times the monthly payment due to the Participant under this Plan, plus the monthly payment then due to the Participant. If the Participant dies following termination of employment but prior to the commencement of payments under this paragraph (d), the Participant’s surviving Eligible Spouse, if any, or Designated Beneficiary shall be entitled to receive the same death benefit payable in the event the Participant had commenced receiving benefit payments as of the first day of the month prior to his death.

4.02   Early Retirement Benefit.

(a)   Eligibility. A Participant whose employment with the Company or any Affiliated Company terminates upon or after his attainment of age fifty-five (55) with at least fifteen (15) years of Service (except for purposes of calculating benefits payable under Article V and Article VI hereinbelow, as applicable) but prior to his Normal Retirement Date, shall be eligible for the early retirement benefit described in this Section 4.02, provided that such termination of employment is “separation from service,” as defined for purposes of Section 409A.

(b)   Amount and Form. The monthly payment hereunder shall be in the form of a Single Life Annuity if the Participant has no Eligible Spouse and in the form of a 50% Qualified Joint and Survivor Annuity if the Participant has an Eligible Spouse. The eligible Participant’s early retirement benefit shall be a monthly amount equal to his Target Early Retirement Benefit reduced by the sum of (1) his Assumed Early Retirement Pension Benefit and (2) his Social Security Benefit; provided, however, such benefit will be reduced, where applicable, by the following:

(i)   The amount of 2.5% for each year that such benefit is received prior to his Normal Retirement Date, and

(ii)   If such eligible Participant’s projected years of Service at his Normal Retirement Date are less than fifteen (15), his Target Early Retirement Benefit and his Assumed Early Retirement Pension Benefit shall be calculated based upon his actual years of Service at his Early Retirement Date rather than upon his projected years of Service at his Normal Retirement Date.

(c)   Commencement and Duration. Monthly early retirement benefit payments shall commence as of the first day of the calendar month next following the retirement of the Participant or as soon thereafter as practicable, and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant’s death occurs, unless the benefit is being paid in the form of a Qualified Joint and Survivor Annuity, in which case the survivor benefit shall be paid to the Eligible Spouse, if living, for his or her life. If at the time of commencement of payment such eligible Participant does not have an Eligible Spouse, the monthly benefit payments shall be guaranteed for one hundred twenty (120) monthly payments with any such guaranteed payments remaining at such Participant’s death payable to his Designated Beneficiary.

(d)   Key Employees. Notwithstanding the foregoing, payments with respect to a Participant who is a key employee (as defined in Section 416(i) of the Code but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees) shall not begin earlier than the date that is six months after the date of termination of the Participant (or, if earlier, the date of death). In the event payments to the Participant under this Plan shall be delayed for six months following the termination of the Participant as provided in this paragraph (d), the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the termination of employment in an amount equal to six times the monthly payment due to the Participant under this Plan, plus the monthly payment then due to the Participant. If the Participant dies following termination of employment but prior to the commencement of payments under this paragraph (d), the Participant’s surviving Eligible Spouse, if any, or Designated Beneficiary shall be entitled to receive the same death benefit payable in the event the Participant had commenced receiving benefit payments as of the first day of the month prior to his death.

4.03   Surviving Spouse Benefit. The surviving Eligible Spouse of a Participant who is entitled to receive a Qualified Joint and Survivor Benefit as a normal retirement benefit or as an early retirement benefit shall be eligible for the surviving spouse benefit upon the death of the Participant for the duration of the Eligible Spouse’s life.

4.04   Re-employment of Retired Participant. A retired Participant receiving or eligible to receive the retirement benefits described in Sections 4.01 and 4.02 hereof who is reemployed by the Company shall be ineligible to again participate in this Plan.

ARTICLE V

PRE-RETIREMENT DEATH BENEFITS

5.01   Eligibility. A Participant’s surviving Eligible Spouse shall be eligible for the pre- retirement death benefit as described in this Article V if such Participant dies while in the employ of the Company with 10 or more years of Service.

5.02   Amount. Such surviving Eligible Spouse shall be entitled to a monthly pre-retirement death benefit payable in the form of an annuity in an amount equal to the difference, if any, between (a) forty percent (40%) of the Target Pre-Retirement Death Benefit and (b) the Spouse’s Pension.

5.03   Alternative Benefit. If greater than the monthly benefit of Section 5.02 hereof, the surviving Eligible Spouse of a Participant who dies while in the employ of the Company after attaining age fifty-five (55) with fifteen (15) years of Service shall be entitled to a monthly pre-retirement death benefit equal to fifty percent (50%) of the early retirement benefit the Participant would have been entitled to receive under Section 4.02 hereof (calculated using both reductions, where applicable, in subsections 4.02(b)(i) and 4.02(b)(ii)) as if he had retired immediately prior to his death with the recommendation of the Chief Executive Officer and approval of the Committee.

5.04   Commencement and Duration. The surviving Eligible Spouse’s monthly pre-retirement death benefit payments shall commence in the month following the Participant’s death and shall be paid in monthly installments thereafter ending with a payment for the month in which such surviving Eligible Spouse’s death occurs.

ARTICLE VI

SEVERANCE BENEFITS

6.01   Eligibility. Upon his Separation from Service from the Company or any Affiliated Company, a Participant who has completed ten (10) or more years of Service but is not eligible for a retirement benefit under Article IV shall be eligible for one of the severance benefits described in this Article VI.

6.02   Amount.

(a)   If at Separation from Service such eligible Participant is not entitled to a deferred vested Pension pursuant to Section 5.03 of the Retirement Plan or an early retirement Pension pursuant to Section 5.02 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by his Social Security Benefit.

(b)   If at Separation from Service such eligible Participant is entitled to a deferred vested Pension pursuant to Section 5.03 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by the sum of (1) his Assumed Deferred Vested Pension Benefit and (2) his Social Security Benefit.

(c)   If at his Separation from Service such eligible Participant is entitled to an early retirement Pension pursuant to Section 5.02 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by the sum of (1) his Assumed Early Retirement Pension Benefit and (2) his Social Security Benefit; provided, however, such Assumed Early Retirement Pension Benefit shall be calculated based upon his actual years of Service at his Separation from Service rather than upon his projected years of Service at his Normal Retirement Date.

6.03   Commencement and Duration.

(a)   General. Monthly severance benefit payments shall commence as of the eligible Participant’s Normal Retirement Date and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant’s death occurs.

(b)   Key Employees. Notwithstanding the foregoing, payments with respect to a Participant who is a key employee (as defined in Section 416(i) of the Code but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees) shall not begin earlier than the date that is six months after the date of termination of the Participant (or, if earlier, the date of death). In the event payments to the Participant under this Plan shall be delayed for six months following the termination of the Participant as provided in this paragraph (b), the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the termination of employment in an amount equal to six times the monthly payment due to the Participant under this Plan, in addition to the monthly payment then due to the Participant. If the Participant dies following termination of employment but prior to the commencement of payments under this paragraph (b), the Participant’s surviving Eligible Spouse, if any, shall be eligible for the surviving spouse benefit provided in Section 6.04.

6.04   Surviving Spouse Benefit.

(a)   Eligibility. The surviving Eligible Spouse of a Participant who is receiving or who dies after attaining age fifty-five (55) entitled to receive a severance benefit hereunder shall be eligible for the surviving spouse benefit described in this Section 6.04.

(b)   Benefit Amount. Such surviving Eligible Spouse shall be entitled to a monthly surviving spouse benefit in an amount equal to fifty percent (50%) of the severance benefit which the deceased Participant was receiving or entitled to receive at his Normal Retirement Date under either Section 6.02(a) or 6.02(b) hereof on the day before his death.

(c)   Commencement and Duration. The monthly surviving spouse benefit payment shall commence in the month following the Participant’s death and shall be paid in monthly installments thereafter ending with a payment for the month in which such surviving Eligible Spouse’s death occurs.

ARTICLE VII

ADMINISTRATION

7.01   Committee. This Plan shall be administered by the Committee. The Committee shall have all powers necessary to enable it to carry out its duties in the administration of the Plan. Not in limitation, but in application of the foregoing, the Committee shall have the duty and power to determine all questions that may arise hereunder as to the status and rights of Participants in the Plan.

7.02   Voting. The Committee shall act by a majority of the number then constituting the Committee, and such action may be taken either by vote at a meeting or in writing, without a meeting.

7.03   Records. The Committee shall keep a complete record of all its proceedings and all data relating to the administration of the Plan. The Committee shall select one of its members as a Chairman. The Committee shall appoint a Secretary to keep minutes of its meetings and the Secretary may or may not be a member of the Committee. The Committee shall make such rules and regulations for the conduct of its business as it shall deem advisable.

7.04   Liability. To the extent permitted by law, no member of the Committee shall be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Plan unless attributable to his own gross negligence or willful misconduct. The Sponsor shall indemnify the members of the Committee against any and all claims, losses, damages, expenses, including counsel fees, incurred by them, and any liability, including any amounts paid in settlement with their approval, arising from their action or failure to act, except when the same is judicially determined to be attributable to their gross negligence or willful misconduct.

7.05   Expenses. The cost of payments from this Plan and the expenses of administering the Plan shall borne by each Company with respect to its own employees.

ARTICLE VIII

AMENDMENT AND TERMINATION

The Sponsor reserves the right, at any time or from time to time, by action of its Board, to modify or amend in whole or in part any or all provisions of the Plan. In addition, the Sponsor reserves the right by action of its Board to terminate the Plan in whole or in part; provided, however, that no such modification, amendment or termination shall in any way affect a Participant’s accrued benefit or the right to payment thereof under the provisions of the Plan as in effect immediately prior to such amendment or termination. Notwithstanding the foregoing, the Plan may be terminated and benefits distributed to Participants within twelve months of a “change in control event” as defined for purposes of Section 409A.

ARTICLE IX

MISCELLANEOUS

9.01   Non-Alienation of Benefits. No right or benefit under the Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right or benefit under the Plan shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities or torts of the person entitled to such benefits. If the Participant or Eligible Spouse shall become bankrupt, or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right hereunder, then such right or benefit shall, in the discretion of the Committee, cease and terminate, and in such event, the Committee may hold or apply the same or any part thereof for the benefit of the Participant or his spouse, children, or other dependents, or any of them, in such manner and in such amounts and proportions as the Committee may deem proper.

9.02   No Trust Created. The obligations of the Sponsor and each Company to make payments hereunder shall constitute a liability of the Sponsor and each Company, as the case may be, to a Participant. Such payments shall be made from the general funds of the Sponsor or a Company, and the Sponsor or a Company shall not be required to establish or maintain any special or separate fund, or purchase or acquire life insurance on a Participant’s life, or otherwise to segregate assets to assure that such payment shall be made, and neither a Participant nor Eligible Spouse shall have any interest in any particular asset of the Sponsor or a Company by reason of its obligations hereunder. Nothing contained in the Plan shall create or be construed as creating a trust of any kind or any other fiduciary relationship between the Sponsor, a Company and a Participant or any other person.

9.03   No Employment Agreement. Neither the execution of this Plan nor any action taken by the Sponsor or a Company pursuant to this Plan shall be held or construed to confer on a Participant any legal right to be continued as an employee of the Sponsor or a Company in an executive position or in any other capacity whatsoever. This Plan shall not be deemed to constitute a contract of employment between the Sponsor or a Company and a Participant, nor shall any provision herein restrict the right of any Participant to terminate his employment with the Sponsor or a Company.

9.04   Binding Effect. Obligations incurred by the Sponsor or a Company pursuant to this Plan shall be binding upon and inure to the benefit of the Sponsor or a Company, its successors and assigns, and the Participant or his Eligible Spouse.

9.05   Suicide. No benefit shall be payable under the Plan to a Participant or Eligible Spouse where such Participant dies as a result of suicide within two (2) years of his commencement of participation herein.

9.06   Claims for Benefits. Each Participant or Eligible Spouse must claim any benefit to which he is entitled under this Plan by a written notification to the Committee. If a claim is denied, it must be denied within a reasonable period of time, and be contained in a written notice stating the following:

A.The specific reason for the denial.

B.Specific reference to the Plan provision on which the denial is based.

C.  Description of additional information necessary for the claimant to present his claim, if any, and an explanation of why such material is necessary.

                                D.An explanation of the Plan’s claims review procedure.

The claimant will have 60 days to request a review of the denial by the Committee, which will provide a full and fair review. The request for review must be in writing delivered to the Committee. The claimant may review pertinent documents, and he may submit issues and comments in writing.

The decision by the Committee with respect to the review must be given within 60 days after receipt of the request, unless special circumstances require an extension (such as for a hearing). In no event shall the decision be delayed beyond 120 days after receipt of the request for review. The decision shall be written in a manner calculated to be understood by the claimant, and it shall include specific reasons and refer to specific Plan provisions as to its effect.

9.07   Entire Plan. This document and any amendments contain all the terms and provisions of the Plan and shall constitute the entire Plan, any other alleged terms or provisions being of no effect.

9.08   Change in Control. In the event of a Change in Control, the Sponsor shall irrevocably set aside funds in one or more grantor trusts in an amount that is sufficient to pay each Participant (or Designated Beneficiary) the amount of benefits accrued under the Plan as of the date of the Change in Control. Any such trust shall be subject to the claims of the general creditors of the Company in the event of the bankruptcy or insolvency of the Company.

9.09   Acceleration of Payment. The acceleration of the time or schedule of any payment due under the Plan is prohibited except as provided in regulations and administrative guidance provided under Section 409A. It is not an acceleration of the time or schedule of payment if the Company waives or accelerates the vesting requirements applicable to a benefit under the Plan.

ARTICLE X

CONSTRUCTION

10.01   Governing Law. This Plan shall be construed and governed in accordance with the laws of the State of North Carolina to the extent not preempted by Federal Law.

10.02   Gender. The masculine gender, where appearing in the Plan, shall be deemed to include the feminine gender, and the singular may include the plural, unless the context clearly indicates to the contrary.

10.03   Headings, etc. The cover page of this Plan, the Table of Contents and all headings used in this Plan are for convenience of reference only and are not part of the substance of this Plan.

10.04   Action. Any action under this Plan required or permitted by the Sponsor shall be by action of its Board or its duly authorized designee.

IN WITNESS WHEREOF, this instrument has been executed this 15th day of December, 2006.

          PROGRESS ENERGY, INC.

          By: /s/ Robert B. McGehee

                      Robert B. McGehee

                      Chief Executive Officer

APPENDIX A

AFFILIATED COMPANIES

Progress Energy Florida, Inc. (non-bargaining employees) (“PEF”); provided that for all purposes of the Plan, Service for an employee of PEF on December 31, 2001 (as defined in Section 2.21) shall include employment only with PEF (or another adopting Company) on or after January 1, 2002; and further provided that the accrued benefit calculated under Sections 2.03, 2.04 and 2.05 shall not include the “Accrued Benefit” under Supplement B, Paragraph B-2(a) of the Retirement Plan, attributable to the FPC Plan.

Progress Fuels Corporation (corporate employees) (“PFC”); provided that for all purposes of the Plan, Service for an employee of PFC on December 31, 2001 (as defined in Section 2.21) shall include employment only with PFC (or another adopting Company) on or after January 1, 2002; and further provided that the accrued benefit calculated under Sections 2.03, 2.04 and 2.05 shall not include the “Accrued Benefit” under Supplement B, Paragraph B-2(a) of the Retirement Plan, attributable to the FPC Plan.

Progress Energy Carolinas, Inc.

Progress Energy Service Company, LLC

Progress Energy Ventures, Inc.

EX-10.C14

Exhibit 10c(14)

PROGRESS ENERGY, INC.

NON-EMPLOYEE DIRECTOR STOCK UNIT PLAN

Amended and Restated Effective January 1, 2007

1.0 RECITALS

1.1 Whereas, Carolina Power & Light Company ("CP&L") adopted the Carolina Power & Light Company Retirement Plan for Outside Directors (the "Directors Retirement Plan") in 1986, which provided for a fixed-dollar retirement benefit for non-employee directors of CP&L following their termination of service as a member of the Board of Directors of CP&L.

1.2  Whereas, effective January 1, 1998, CP&L froze the Directors Retirement Plan so that no further benefits would accrue under such plan, and adopted the Carolina Power & Light Company Non-Employee Director Stock Unit Plan (the ^"Plan"), the purpose of which was to provide deferred compensation to the non-employee directors of CP&L based on the value of CP&L common stock.

1.3 Whereas, sponsorship of the Plan was transferred to CP&L Energy, Inc. effective August 1, 2000, and the name of the Plan was subsequently changed to Progress Energy, Inc. Non-Employee Director Stock Unit Plan.

1.4 Whereas, the Company amended and restated the Plan effective January 1, 2005 to increase the Annual Stock Unit Grant and to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the "Code"), regarding the payment of benefits from the Plan.

1.5 Whereas, the Company amended and restated the Plan effective January 1, 2006, for the purposes of (i) changing the date of the allocation of the annual stock unit grant to participants' accounts from the date of the Company’s annual meeting of shareholders to the first business day in January of each year; and (ii) to eliminate the requirement that to be eligible to receive an annual stock unit grant a participant must have served on the Board for one year.

1.6 Whereas, the Company desires to amend and restate the Plan effective January 1, 2007 for the purpose of making certain clarifying and conforming changes to the Plan.

1.7 Now, therefore, effective January 1, 2007, the Company adopts this amended and restated Progress Energy, Inc. Non-Employee Director Stock Unit Plan.

2.0  PURPOSE

2.1  Purpose. The purpose of the Plan is to attract and retain highly qualified individuals as non-employee directors of the Company, and to provide deferred compensation to the Company's non-employee directors based on the value of the Company's stock.

3.0  DEFINITIONS

 The following terms shall have the following meanings unless the context indicates otherwise:

3.1 "Annual Stock Unit Grant" shall mean a grant to Stock Units as described in Section 5.2 below

3.2 "Board^"shall mean the Board of Directors of the Company.

3.3 "Change in Control" shall mean the earliest of the following dates:

(1) the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Company, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Company representing twenty-five percent (25%) or more of the combined voting power of the Company's then outstanding securities (excluding the acquisition of securities of the Company by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Company); or

(2) the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Company's then outstanding voting securities; or

     (3) the date of consummation of a merger, share exchange or consolidation of the Company with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Company or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or

(4) the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Company (other than such an offer by the Company for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at leasttwo-thirds (2/3) of the members of the Board of Directors; or

(5) the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets; or

(6) the date of any event which the Board of Directors determinesshould constitute a Change in Control.

A Change in Control shall not be deemed to have occurred until a majority of the members of the Board of Directors receive written certification from the Committee that one of the events set forth in this Section 3.3 has occurred. Any determination that an event described in this Section 3.3 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Board of Directors, the Company, the Participants and their beneficiaries for all purposes of the Plan.

3.4 "Committee" shall mean the Board's Committee on Corporate Governance.

3.5 "Common Stock"shall mean the common stock of the Company.

3.6 "Company"shall mean Progress Energy, Inc., a North Carolina corporation, including any successor entity.

3.7 "Continuing Directors" shall mean the members of the Board as of January 1, 2007; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by 75 percent or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.

3.8 "Distribution Date"shall mean the later of (i) the date a Participant is no longer a member of the Board and otherwise “separates from service” with the Company, as defined for purposes of Section 409A of the Code, or (ii) the date such Participant attains age 65.

3.9 "Effective Date"shall mean January 1, 1998. The Plan has been subsequently amended and restated effective July 10, 2002, January 1, 2005, January 1, 2006 and January 1, 2007.

3.10  "Common Stock Value"shall mean:

(1) the average of the highest and lowest selling prices of Common Stock on the relevant date (or on the last preceding trading date if Common Stock was not traded on the relevant date) if Common Stock is readily tradable on a national securities exchange or other market system; or

(2) an amount determined in good faith by the Board as the fair market value of  Common Stock on the date of determination if Common Stock is not readily tradable on a national securities exchange or other market system.

3.11 "Initial Stock Unit Grant" shall mean a grant of Stock Units us described in Section 5.1 below.

3.12"Participant"shall mean a member of the Board who is not an employee of the Company or any of its Subsidiaries.

3.13 "Stock Unit"shall mean a unit maintained by the Company for bookkeeping purposes, equal in value to one (1) share of Common Stock.

3.14 "Stock Unit Account”shall mean a bookkeeping account established and maintained (or caused to be established and maintained) by the Company for the Participant which shall record the number of Stock Units granted to the Participant under Section 5 below. This account shall be established (or caused to be established) by the Company for bookkeeping purposes only, and no separate funds shall be segregated by the Company for the benefit of the Participant.

3.15"Plan"shall mean the Progress Energy, Inc. Non-Employee Director Stock Unit Plan.

3.16 "Subsidiary"shall mean a corporation of which the Company directly or indirectly owns more than 50 percent of the Voting Stock (meaning the capital stock of any class or classes having general voting power under ordinary circumstances, in the absence of contingencies, to elect the directors of a corporation) or any other business entity in which the Company directly or indirectly has an ownership interest of more than 50 percent.

4.0 ADMINISTRATION

4.1 Responsibility. TheCommittee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms.

4.2 Authority of the Committee. The Committee shall have all the discretionary authority that may be necessary or helpful to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following:

(a) to determine eligibility for participation in the Plan;

(b) to correct any defect, supply any omission, or reconcile any inconsistency in the Plan in such manner and to such extent as it shall deem appropriate in its sole

discretion to carry the same into effect;

(c) to issue administrative guidelines as an aid to administer the Plan and make changes in such guidelines as it from time to time deems proper;

(d) to make rules for carrying out and administering the Plan and make changes in such rules as it from time to time deems proper;

(e) to the extent permitted under the Plan, grant waivers of Plan terms, conditions restrictions, and limitations;

(f) to make reasonable determinations as to a Participant's eligibility for benefits under the Plan, including determinations as to vesting; and

(g) to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan.

4.3 Action by the Committee. The Committee may act only by a majority of its members. Any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee.

4.4 Delegation of Authority. The Committee may delegate to one or more of its members, or to one or more agents, such administrative duties as it may deem advisable; provided, however, that any such delegation shall be in writing. In addition, the Committee, or any person to whom it has delegated duties as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid by the Company, or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee.

4.5 Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive on all Participants and their heirs, successors, and legal representatives.

4.6 Information. The Company shall furnish to the Committee in writing all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. Such information may include, but shall not be limited to, the full names of all Participants, their earnings and their dates of birth, employment, retirement or death. Such information shall be conclusive for all purposes of the Plan, and the Committee shall be entitled to rely thereon without any investigation thereof.

4.7 Self-Interest. No member of the Committee may act, vote or otherwise influence a decision of the Committee specifically relating to his or her benefits, if any, under the Plan.

5.0 STOCK UNIT GRANTS

5.1 Rollover. CP&L granted an Initial Stock Unit Grant to the Participants listed on Schedule A (who were participants in the CP&L Retirement Plan for Outside Directors) who were elected by December 31, 1997, pursuant to an election made in writing to the CP&L Vice President-Human Resources to rollover their accrued benefit under such plan (the "Accrued Benefit") into the Plan. The number of shares underlying each Initial Stock Unit Grant was equal to the present value of the Participant's Accrued Benefit as of December 31, 1997, divided by the Common Stock Value of CP&L common stock on the last trading day of 1997. Any fractional Stock Unit greater than 50 percent was rounded up to one Stock Unit, and any fractional Stock Unit equal to or less than 50 percent was disregarded. Such number of Stock Units underlying the Initial Stock Unit Grant was entered and recorded in the Participant's Stock Unit Account, and later adjusted to reflect the change in the capital structure of CP&L as a result of which CP&L became a Subsidiary of the Company.

5.2 Annual Grant. Effective January 1, 2006, the Company shall grant to each Participant an Annual Stock Unit Grant equal to 1,200 Stock Units. The Annual Stock Unit Grant shall be made the first business day of January. The Company shall enter and record (or shall cause to be entered and recorded) in the Participant's Stock Unit Account such number of Stock Units underlying the Annual Stock Unit Grant.

5.3 Dividend Stock Units. On the date that any holder of Common Stock receives a dividend with respect to Common Stock, the Company shall grant to each Participant, and shall enter and record (or shall cause to be entered and recorded) in each such Participant's Stock Unit Account a number of Stock Units equal to the result of (x) the dollar amount of such dividend paid with respect to one share of Common Stock multiplied by (y) the number of Stock Units in the Stock Unit Account as of the date such dividend is paid divided by (z) the Common Stock Value as of the date such dividend is paid. Any fractional Stock Unit greater than 50 percent shall be rounded up to one Stock Unit, and any fractional Stock Unit equal to or less than 50 percent shall be disregarded.

6.0 BENEFIT

6.1 Vesting. A Director shall be fully vested at all times in the Stock Units credited to his or her Account.

6.2 Timing of Benefit. In accordance with Section 6.4 below, the Company shall pay or begin paying a Benefit to a vested Participant during the 60-day period following the Distribution Date. If the Participant has selected annual payments in accordance with Section 6.4(b) below, all payments other than the first payment shall be made on the applicable anniversary of the Distribution Date.

6.3 Valuation. The value of a Participant's Stock Unit Account for purposes of the Benefit shall be equal to the product of (x) the number of Stock Units in the Participant's Stock Unit Account as of the Distribution Date or the applicable anniversary of the Distribution Date multiplied by (y) the Common Stock Value on the Distribution Date or the applicable anniversary of the Distribution Date, in accordance with Section 6.4 below.

6.4 Form of Benefit. The Company shall pay a Benefit to a vested Participant in one of the following four (4) forms, as elected by the Participant:

(a) a lump sum payment, with such payment equal to the value of the Participant's Stock Unit Account as of the Distribution Date: or

(b)annual payments over 5, 10 or 15 years, with each annual payment equal to (x) the value of the Participant's Stock Unit Account as of the Distribution Date or the applicable anniversary of the Distribution Date divided by (y) the number of payments yet to be made.

Participants who are elected on or after January 1, 2005, shall elect the form of payment within 30 days after the date they are elected, except that if a Participant is elected within 30 days of the next Annual Stock Unit Grant date, the Participant shall elect the form of payment no later than such Annual Stock Unit Grant date.

6.5 Change of Form of Benefit. The Participant may change the form of payment of all Stock Units credited to the Stock Unit Account of the Participant and vested prior to January 1, 2005, so long as the change is made at least six (6) months prior to the Distribution Date. With respect to Stock Units credited to the Stock Unit Account of the Participant or vesting on or after January 1, 2005, the Participant must make or have in effect an election as to the form of payment of Stock Units to be credited to the Stock Unit Account of the Participant during the upcoming year no later than December 31 of the preceding year, which election shall be irrevocable for such upcoming year. The Participant may change his or her election for a subsequent year by delivering a new election as to the form of payment to the Company on or before December 31 of the preceding year. An election as to form of payment will remain in effect for future years unless and until changed by the Participant’s timely delivery of a new election as to the form of payment with respect to an upcoming Plan Year. The Participant may not amend or change such an election with respect to any prior year. Notwithstanding the foregoing, on or before December 31, 2007 the Participant may make a one-time change to the Participant’s election as to the form of payment of Stock Units credited to his or her Stock Unit Account as to all years prior to and including 2007, as permitted by the transition relief rules under Code Section 409A and the regulations thereunder.

6.6 Death of Participant Prior to the Distribution Date. If the Participant's death occurs prior to the Distribution Date, the Company shall pay or begin paying a Benefit to a vested Participant's beneficiary (as designated by the Participant under Section 6.8 below) on the first day of the sixth month following the date of the Participant's death, and if the Participant has selected a form of Benefit under Section 6.4(b) above, the Company shall pay the remaining annual payments on the anniversary of the first payment date as determined under this Section 6.6.

6.7 Death of Participant Following the Distribution Date. If the Participant's death occurs following the Distribution Date, the Company shall continue to pay the Benefit to the Participant's beneficiary (as designated by the Participant under Section 6.8 below) following the date of the Participant's death in the form of Benefit selected by the Participant in accordance with Section 6.4 above.

6.8 Designation of Beneficiary. Within 30 days after becoming a Participant, a Participant shall designate a beneficiary to receive the Benefit in the event of the Participant's death. If the Participant does not designate a beneficiary, the beneficiary shall be deemed to be the Participant's spouse on the date of the Participant's death, and if the Participant does not have a spouse on the date of his or her death, then the Participant's estate shall be deemed to be the beneficiary under this Section 6.

7.0TAXES

7.1 Withholding Taxes. The Company shall be entitled to withhold from any and all payments made to a Participant under the Plan all federal, state, local and/or other taxes or imposts which the Company determines are required to be so withheld from such payments or by reason of any other payments made to or on behalf of the Participant or for his or her benefit hereunder.

7.2 No Guarantee of Tax Consequences. No person connected with the Plan in any capacity, including, but not limited to, the Company and any Subsidiary and their directors, officers, agents and employees makes any representation, Commitment, or guarantee that any tax treatment, including, but not limited to, federal, state and local income, estate and gift tax treatment, will be applicable with respect to amounts deferred under the Plan, or paid to or for the benefit of a Participant under the Plan, or that such tax treatment will apply to or be available to a Participant on account of participation in the Plan.

8.0TERM OF PLAN; AMENDMENT AND TERMINATION

8.1 Term. The Plan shall be effective as of the Effective Date. The Plan shall remain in effect until the Board terminates the Plan.

8.2 Termination or Amendment of Plan. The Board may suspend or terminate the Plan at any time with or without prior notice and the Board may amend the Plan at any time with or without prior notice; provided however, that no action authorized by this Section 8.2 shall reduce the balance or adversely affect the vesting of the Stock Unit Account of a Participant, or cause the acceleration of the time or schedule of any payment under the Plan except as provided by regulations under Section 409A of the Code.

9.0MISCELLANEOUS

9.1 Adjustments. If there shall be any change in Common Stock through merger, consolidation, reorganization, recapitalization, stock dividend, stock split, reverse stock split, split up, spin-off, combination of shares, exchange of shares, dividend in kind or other like change in capital structure or distribution (other than normal cash dividends) to holders of Common Stock, the number of Stock Units and the Participant's Stock Unit Account shall be adjusted to equitably reflect such change or distribution.  

9.2 Governing Law. The Plan and all actions taken in connection herewith shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.

9.3No Right Title or Interest in Company Assets. Participants shall have no right, title, or interest whatsoever in or to any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. All payments to be made hereunder shall be paid from the general funds of the Company and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts except as expressly set forth in the Plan.

9.4 No Right to Continued Service. The Participant's rights, if any, to continue to serve the Company as a member of the Board shall not be enlarged or otherwise affected by his or her participation in the Plan.

9.5 Other Rights. The Plan shall not affect or impair the rights or obligations of the Company or a Participant under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan.

9.6 Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent. If, however, the Committee determines in its sole discretion that any term or condition of the Plan which is invalid or unenforceable is material to the interests of the Company, the Committee may declare the Plan null and void in its entirety.

9.7 Incapacity. If the Committee determines that a Participant or a designated beneficiary is unable to care for his or her affairs because of illness or accident or because he or she is a minor, any benefit due the Participant or designated beneficiary may be paid to the Participant's spouse or to any other person deemed by the Committee to have incurred expense for such Participant (including a duly appointed guardian, committee or other legal representative), and any such payment shall be a complete discharge of the Company's obligation hereunder.

9.8 Transferability of Rights. No Participant or spouse of a Participant shall have any right to encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Participant or such spouse may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be nonassignable and nontransferable, except to the extent required by law. Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Participant or the spouse of a Participant shall be null and void and without effect.

9.9 Entire Document. The Plan, as set forth herein, supersedes any and all prior practices, understandings, agreements, descriptions or other non-written arrangements respecting severance, and written employment or severance contracts signed by the Company.

9.10 Change in Control. In the case of a Change in Control, the Company, subject to the restrictions in this Section 9.10 and in Section 9.3, shall irrevocably set aside funds in one or more grantor trusts in an amount that is sufficient to pay each Participant the value of the Participant's Stock Unit Account as of the date on which the Change in Control occurs. The foregoing notwithstanding, the Company shall establish no such grantor trust if its assets shall become includable in the income of Participants thereby solely as a result of Section 409A of the Code. The obligations and responsibilities of the Company under this Plan shall be assumed by any successor or acquiring corporation, and all of the rights, privileges and benefits of the Participants hereunder shall continue following the Change in Control.

9.11Section 409A. Notwithstanding any provision in this Plan to the contrary, this Plan and all rights and benefits of Participants hereunder shall comply with Section 409A of the Code, related regulations and other guidance, and be construed in accordance therewith.

IN WITNESS WHEREOF, this instrument has been executed this 13^th day of December, 2006.

       & #160;  PROGRESS ENERGY, INC.

           By: /s/ Robert B. McGehee

            ;       Robert B. McGehee

            ;       Chief Executive Officer

SCHEDULE A

Participants Who Received Initial Stock Unit Grants

1.   Edwin B. Borden

2.   Richard L. Daugherty

3.   Robert L. Jones

4.   Felton J. Capel

5.   Charles W. Coker

6.   Estell C. Lee

7.   Leslie M. Baker, Jr.

8.   William O. McCoy

9.   J. Tylee Wilson

EX-10.C22

Exhibit 10c(22)

SELECTED EXECUTIVES

SUPPLEMENTAL DEFERRED COMPENSATION PROGRAM AGREEMENT

THIS AGREEMENT is made this the _____ day of August, 1996, between CAROLINA POWER & LIGHT COMPANY, a North Carolina corporation (hereinafter the “Company”), and CLAYTON S. HINNANT a key management employee of the Company (hereinafter called the “Participant”).

WHEREAS, the Board of Directors of the Company has approved an additional deferred compensation program for the purpose of attracting and retaining outstanding key management personnel as employees of the Company; and

WHEREAS, the Participant shall be eligible to receive additional deferred compensation if all conditions described in this Agreement are met.

NOW THEREFORE, in consideration of the mutual agreements herein contained, the Company and the Participant agree as follows:

1. Amount of Award. If the Participant terminates employment with the Company before attaining age sixty, the Participant will not be entitled to receive any deferred compensation under this Agreement. If the Participant remains employed with the Company until or beyond age sixty, the Participant will be entitled to receive a deferred compensation award that shall become payable in accordance with the table set forth in Exhibit A to this Agreement, based on the age of the Participant while the Participant remains employed with the Company. The amount of any deferred compensation award as determined in accordance with this Section 1 is hereafter referred to as the “Deferral Award”. Notwithstanding the above, if the Participant terminates employment voluntarily or involuntarily before age sixty, upon management’s recommendation the Personnel, Executive Development & Compensation Committee of the Board of Directors (hereinafter the “Committee”), in their sole discretion, may grant the Participant a deferred compensation award in some smaller amount as they deem appropriate considering the Participant’s performance of duties for the Company and other factors regarding the best interest of the Company.

2. Payment. Any Deferral Award that the Participant is entitled to receive will be paid after the Participant leaves the employment of the Company for any reason. If the Deferral Award is paid before the Participant has met the requirements for normal or early retirement under the Company’s Supplemental Retirement Plan (hereinafter “Retirement”), the Deferral Award shall be paid in a single lump sum within thirty days after the Participant leaves the employment of the Company. If the Deferral Award is paid after the Participant’s Retirement, the Deferral Award shall be paid in sixty equal monthly installments as specified in Exhibit A, or if a timely election is made, the Participant shall be paid in a single lump sum. The Participant must exercise the option to receive payment of the Deferral Award after retirement in a single lump sum by completing and signing the form attached to this Agreement as Exhibit B, and submitting it to the Company’s senior vice president responsible for Human Resources before the Participant’s fifty-eighth birthday. Once elected, the option to receive payment of the Deferral Award after retirement in a single lump sum can be revoked by written notice to the Company’s senior vice president responsible for Human Resources at any time before the Participant’s fifty-eighth birthday. The option to receive payment of the Deferral Award in a single lump sum payment after retirement cannot be elected or revoked after the Participant’s fifty-eighth birthday.

3.Taxes. All FICA taxes shall be paid by the Company in accordance with applicable laws, rules and regulations. If any Deferral Award is paid to the Participant, the Company shall withhold any other federal and state income and payroll taxes as required by law.

4.Death of Participant.In the event that the Participant dies after the Participant’s sixtieth birthday, but before the Deferral Award is fully paid, any unpaid amounts in the Participant’s account will be paid in a lump sum to any beneficiary or beneficiaries that are designated by the Participant (the “Designated Beneficiary”). The form attached to this Agreement as Exhibit C shall be completed, signed, and sent to Company’s senior vice president responsible for Human Resources within thirty days from the date of this Agreement. The Participant may change the Designated Beneficiary at any time by submitting a new beneficiary designation form. If at any time the Participant has not designated a beneficiary, or if the beneficiary predeceases the Participant, payment of any vest Deferral Award will be made to the Participant’s estate.

5.Deferral Award Accounting.A ledger account shall be established by the Company to track the balance of the Participant’s Deferral Award. The account will be charged with any payments made to the Participant or the Participant’s Designated Beneficiary. The actual Deferral Award payable to the Participant, if any, will be determined as of the date that the Deferral Award becomes payable. Any Deferral Award that becomes payable shall be paid from the general assets of the Company. No special fund or trust has been established for paying the Deferral Award. Neither the Participant nor the Designated Beneficiary shall have any interest in any specific assets of the Company, but shall only be entitled to receive the benefits described in this Agreement.

6. Non-Alienation of Benefits. The Participant’s right to receive the benefits described in this Agreement shall not be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right or benefits hereunder shall be void.

7. Reservation of Rights. Nothing in this Agreement shall in any way limit the right of the Company to terminate the Participant’s employment at any time, with or without cause, or at will.

8. Non-Competition. During the period of five years following the termination of the employment of the Participant if the Participant is entitled to a Deferral Award, the Participant will not, without the Committee’s prior written consent, directly or indirectly engage as an employee, consultant, or in any other capacity in any business activities: (a) which compete with the Company or any of it’s subsidiaries business; (b) which relate to the production or delivery of electricity in the Company’s service area or any immediate surrounding area; or (c)  for any wholesale customer or any general service retail customer for whom the Company has produced or delivered electricity or to whom it may present a proposal or otherwise negotiate to provide such services. Participant shall submit any request for such consent to the Company’s senior vice president responsible for Human Resources.

9. Applicable Law. This Agreement shall be interpreted and construed in accordance with the laws of the State of North Carolina, without regard to any conflicts of laws provisions that might require the application of the laws of any other state or jurisdiction.

10.     Entire Agreement. This Agreement contains the entire agreement and understanding by and between the Company and the Participant with respect to the subject matter hereof, and no representations, promises, agreements, or understandings with regard to the payment of Deferral Award, whether written or oral, not contained herein shall be of any force or effect.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.

CAROLINA POWER & LIGHT COMPANY           PARTICIPANT

By: _______________________________  ________________________________

Title:______________________________

EXHIBIT B

SELECTED EXECUTIVES SUPPLEMENTAL DEFERRED COMPENSATION

PROGRAM AGREEMENT

EXERCISE OF OPTION

FOR

LUMP SUM PAYMENT

As provided in my Selected Executives Supplemental Deferred Compensation Program Agreement with Carolina Power & Light Company dated August ____, 1996, in the event that a Deferral Award is paid to me after my retirement from Carolina Power & Light Company, I hereby exercise my option to receive payment of the Deferral Award in a single lump sum.

DATE: ___________________

SIGNATURE OF PARTICIPANT:____________________________________

EXHIBIT A

SELECTED EXECUTIVES SUPPLEMENTAL DEFERRED COMPENSATION

PROGRAM AGREEMENT

DEFERRAL AWARD TABLE

Target Benefit:$750,000

If the Participant continues his employment with the Company until or beyond age sixty, the Participant’s Deferral Award pursuant to the Agreement shall be as follows:

Ages	Deferral Award	Annual Amounts (payable for 5 years)
51-59	$0
60	421,000	97,000
61	473,000	109,000
62	531,000	122,000
63	595,000	137,000
64	668,000	154,000
65	750,000	173,000

The amount of the Deferral Award shall be equal to the amount specified above on the Participant’s birthday for the ages specified above. The Deferral Award amount shall not be prorated between birthdays. The amount of the Deferral Award shall not increase after the Participant’s sixty-fifth birthday.

EXHIBIT C

DESIGNATION OF BENEFICIARY

SELECTED EXECUTIVES SUPPLEMENTAL DEFERRED COMPENSATION

PROGRAM AGREEMENT

WITH

CAROLINA POWER & LIGHT COMPANY

As provided in my Selected Executives Supplemental Deferred Compensation Program Agreement with Carolina Power & Light Company dated August ____, 1996, I hereby designate the following person(s) as my “Designated Beneficiary”, with respect to any Deferral Award that becomes payable.

PRIMARY BENEFICIARY:

_________________________________

_________________________________

_________________________________

CONTINGENT BENEFICIARY:

_________________________________

_________________________________

_________________________________

Any and all prior designations of one or more beneficiaries under my Selected Executives Supplemental Deferred Compensation Program Agreement with Carolina Power & Light Company are hereby revoked and superseded by this designation, I understand that the Designated Beneficiary named above may be changed or revoked by me at any time by filing a new designation in writing with the Company’s senior vice president responsible for Human Resources.

DATE: ________________________

SIGNATURE OF PARTICIPANT: __________________________________

The Participant named above executed this document in my presence.

WITNESS: ______________________________ WITNESS: ______________________________

EX-10.C23

Exhibit 10c(23)

EXECUTIVE PERMANENT LIFE INSURANCE AGREEMENT

THIS AGREEMENT is made this ____________ between CAROLINA POWER & LIGHT COMPANY ("Company") and ____________________________________ ("Employee").

WITNESSETH:

WHEREAS, the Company has instituted an Executive Permanent Life Insurance Program in order to assist selected key employees in providing death benefits for their beneficiaries; and

WHEREAS, the Company desires to provide such benefits in the Executive Permanent Life Insurance Program to the extent provided herein;

NOW, THEREFORE, it is mutually agreed that:

1.    Insurance Policy. In furtherance of the purpose of the Executive Permanent Life Insurance Program, the Company and Employee have jointly applied for and purchased life insurance from Northwestern Mutual Life Insurance Company ("Insured") insuring the life of __________________, an employee of the Company. The policy number is __________________and the original face amount is ________________ ("Policy").

2.     Policy Ownership. The Company and the Employee agree that the Policy shall be divided into two separate and distinct policy interests as provided in Paragraph 4. During the term of this Agreement, the parties shall have the following ownership rights with respect to such policy interests.

a)Company.

i)     The contingent limited right to obtain one or more loans or advances on the Policy which shall be limited to the extent of the Company's Policy Interest, as defined in Paragraph 4 below, and to pledge or assign the Policy for such loans or advances. Any such loan, advance, pledge or assignment by the Company shall be subject to the written consent of the Employee. If such loans are for the purpose of paying premiums or otherwise to purchase or carry the Policy, the Company agrees to adhere to the requirement of Section 264 of the Internal Revenue code of 1986, as amended from time to time, so that the interest paid on such loans, or some portion thereof, may be deductible for federal income tax purposes;

ii)     Ownership of Policy cash value equal to the sum of all "Company premiums" as defined in Paragraph 3(a) hereof; and

iii)   The limited right to receive death proceeds of the Policy to the extent of the Company’s Policy Interest in the event of the Employee’s death during the term of this Agreement.

b)    Employee. Except as provided in Paragraph 2(a) above and otherwise in this Agreement, the Employee shall have all remaining ownership rights in the Policy, including but not limited to, the following:

i)     The contingent limited right to obtain one or more loans or advances on the Policy which shall be limited to the extent of the Employee's Policy Interest, as defined in Paragraph 4 below, and to pledge or assign the Policy for such loans or advances. Any such loan, advance, pledge or assignment by the Employee shall be subject to the written consent of the Company;

ii)     The right to designate beneficiaries of the Employee's Policy Interest including selection of settlement options;

iii)     The right to assign any part or all of the Employee's ownership rights in the Policy to any person, entity or trust by execution of appropriate documents;

iv)     The right to surrender the Policy subject to the Company’s Policy Interest; and

v)     Ownership of all Policy cash value not owned by the Company.

3.Payment of Premiums.

a)

   i)      Subject to Paragraph 3(b) below, payment of the Policy’s annual premium shall be split between the Company and the Employee. The Employee shall pay that portion of

             the annual premium equal to the “economic benefit” as defined in Revenue Rulings 64-325 and 66-110. The value of the economic benefit shall be calculated by using

             the lower of the P.S. 58 rates or the Insurer’s term rates. The Company shall pay the remainder of the premium (hereafter referred to as “Company premium(s)”).

ii)    Notwithstanding the foregoing, during the term of this Agreement, the Company shall pay its portion of the annual premium for ten (10) years commencing with the premium for the initial policy year beginning July 1, 1998, and including the premium due on the July 1, 2007 policy anniversary; provided, however, that the Company may agree to pay such additional premiums as it and the Employee may agree. In the event the Company is not obligated to pay a portion of the premium on the policy for any policy year during the term of this Agreement, the Employee shall pay such premium either in cash or by the application of policy dividends and/or values.

iii)    By mutual consent of the parties hereto and for administrative convenience, the Company may pay the entire premium as it becomes due, whereupon the Employee shall reimburse the Company for the Employee's share of the premium in such manner as the Company and the Employee may mutually agree.

b)If either a standard disability waiver of premium benefit or accidental death benefit is added as a rider to the Policy, the Employee agrees to pay the annual cost of such riders.

4.Policy Interests.

a)    Subject to Paragraph 4(b) below, during the term of this Agreement and prior to or upon the death of the Employee, the Company, by reason of payment of

       premiumspursuant to Paragraph 3 above, shall have an interest in the Policy equal to the sum of Company premiums paid reduced by any Policy indebtedness

       which is incurred by the Company and unpaid interest on such Policy indebtedness ("Company's Policy Interest"). The Employee, by reason of payment

       of premiums pursuant to Paragraph 3 above, shall have all the remaining interest in the Policy in excess of the Company's Policy Interest ("Employee's Policy Interest").

b) In the event of the death of the Employee during the term of this Agreement, the proceeds of the Policy shall be payable as follows:

i)     The Company shall be entitled to receive an amount of the Policy death proceeds equal to the proceeds of the Policy reduced by the death benefit payable to the Employee’s beneficiary pursuant to Paragraph 4(b)(ii) below, less any Policy indebtedness which is incurred by the Company and unpaid interest on such Policy indebtedness.

ii)    The Employee's beneficiary shall be entitled to receive an amount of the Policy death proceeds as follows plus death proceeds, if any, from an accidental death benefit rider:

Year	Amount
1	705,000
2	747,300
3	792,138
4	839,666
5	890,046
6	943,449
7	1,000,056
8	1,060,059
9	1,123,663
10	1,191,083
11	1,262,548
12	1,338,300

5.    Dividends. During the term of the Agreement, the Company and Employee agree that any dividends attributable to the Policy shall be used to purchase paid-up additional life insurance on the Employee's life unless mutually agreed otherwise. Notwithstanding the foregoing, in the event a premium on the Policy becomes due during the term of this Agreement and the Company is not obligated to pay any portion of such premium, the Employee may elect to have Policy dividends first offset such premium due with any remaining dividends used to purchase paid-up additional life insurance.

6.     Beneficiary Designation. The Company and Employee agree that the beneficiary designation for the payment of death proceeds in the Policy Application shall be completed so that the Company will be entitled to receive proceeds equal to the Company's Policy Interest and the Employee's beneficiary will be entitled to receive proceeds equal to the Employee's Policy Interest. The Employee may change his designated beneficiary at any time upon notification to the Insurer and completion of the proper beneficiary designation forms.

7.     Termination. This Agreement shall terminate upon the happening of any of the following:

a)    The July I, 2008 policy anniversary (which is the policy anniversary next following the Employee's attainment of age 65);

b) Failure of the Employee to either pay his share of a premium or to reimburse the Company for the Employee share of a premium pursuant to Paragraph 3;

c) Surrender of the Policy by the Employee;

d) Termination for cause of the Employee's employment with the Company. For purposes hereof, termination for cause shall mean the termination of the Employee's employment with the Company for any one or more of the following reasons: (a) embezzlement or theft from the Company, or other acts of dishonest or disloyalty injurious to the Company; (b) use by the Employee of alcohol, drugs, narcotics, or other controlled substances to such an extent that the Employee's ability to perform his duties as an employee of the Company is materially impaired; (c) disclosing without authorization proprietary or confidential information of the Company; (d) committing any act ofgross negligence or gross malfeasance; or (e) conviction of a crime amounting to a felony under the laws of the United States of America or any of the several states. The determination of whether or not there has been a termination forcause shall be made by the Board of Directors of theCompany provided that, if the Employee or the terminated Employee is a member of the Board of Directors, he shall not participate in the determination.

e) Termination of the Employee's employment with the Company prior to attainment of age 62 for any reason other than due to the Employee's disability or following a change in control; provided, however, that in its sole and absolute discretion the Chief Executive Officer of the Company may elect to continue this Agreement. For purposes hereof:

i)     Disability shall have the same meaning as “total disability” in the Company's Long-Term Disability Insurance Plan; provided, however, that if at the time of determination of disability the Company does not sponsor the Long-Term Disability Insurance Plan, disability shall mean the complete inability to perform the normal duties of occupation during the first 18 months after commencement of disability; thereafter, disability means the inability to engage in any gainful occupation forwhich the Employee is reasonably fitted by education, training or experience.

ii)    Change in control shall mean a change in control of the Company of a nature that would be required to be reported in response to Item 1(a) of the Current Report on form 8-K, as in effect on the date hereof, pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 (the "Exchange Act"); provided, that without limitation, such a change in control shall be deemed to have occurred at such time as a "person" (as used in Section 14(d) of the Exchange Act) is or becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of 25% or more of the combined voting power of the Company's outstanding securities ordinarily having the right to vote in elections of directors; or (b) individuals who constitute the Board of Directors of the Company on the date hereof (the "Incumbent Board") cease for any reason to constitute at least a majority thereof,provided that any person becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least three quarters of the directors comprising the Incumbent Board shall be, for purposes of this subsection (b), considered as though such person were a member of the Incumbent Board. Notwithstanding the foregoing definition, no change in control shall be deemed to have occurred unless and until the Employee or the Employee has actual knowledge from one of the following sources: a report filed with the Securities and Exchange Commission, a public statement issued by the Company, or a periodical of general circulation, including but not limited to The New York Times or The Wall Street Journal.

8.     Rights Upon Termination.

a)    Upon the termination of this Agreement pursuant to Paragraph 7 above if the Employee's interest in Policy cash value (prior to reduction for Policy indebtedness) is zero, the Employee shall surrender his interest in the Policy to the Company and the Company shall become the sole owner of the Policy. In such event the Employee shall immediately execute any documents necessary to assign and release all of his interest in the Policy to the Company.

b)    Upon the termination of this Agreement pursuant to Paragraph 7 above if the Employee's interest in Policy cash value (prior to reduction for Policy indebtedness) is greater than zero, the Policy shall be divided into a separate policy owned solely by the Company and a separate policy owned solely by the Employee. The values of each separate policy shall be determined by dividing the total value of the Policy prior to such division in proportion to each party's ownership interest in Policy cash value determined prior to reduction for Policy indebtedness. In the event there are outstanding policy loans, the separate policy received shall be subject to either the Company's or Employee's outstanding policy loan, as the case may be. The Company and the Employee shall immediately execute any documents necessary to cause the Policy to be divided into such separate policies.

9.     Special Provisions. The following provisions are part of this Agreement and the Executive Permanent Life Insurance Program and are intended to meet the requirements of the Employee Retirement Income Security Act of 1974:

a)The named fiduciary: The Company.

b)The funding policy under this Agreement is that the Company and the Employee remit all premiums on the Policy when due.

c)Direct payment by the Insurer is the basis of payment of benefits under this Agreement, with those benefits in turn being based on the payment of premiums by the

     Company and the Employee.

d)For claims procedure purposes, the "Claims Manager" shall be the Secretary of the Company.

i)     If for any reason a claim for benefits under this Agreement is denied by the Company, the Secretary shall deliver to the claimant a written explanation setting forth the specific reasons for the denial, pertinent references to the section of the Agreement onwhich the denial is based, such other data as may be pertinent and information on the procedures to be followed by the claimant in obtaining a review of his claim, all written in a manner calculated to be understood by the claimant. For this purpose:

(1)The claimant's claim shall be deemed filed when presented orally or in writing to the Secretary.

(2)The Secretary's explanation shall be in writing delivered to the claimant within ninety (90) days of the date the claim is filed.

ii)    The claimant shall have sixty (60) days following his receipt of the denial of the claim to file with the Secretary a written request for review of the denial. For such review, the claimant or his representative may submit pertinent documents and written issues and comments.

  iii)      The Secretary shall decide the issue on review and furnish the claimant with a copy within sixty (60) days of receipt of the claimant's request for review of his claim. The decision on review shall be in writing and shall include specific reasons for the decision written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent provisions of the Agreement on which the decision is based. If a copy of the decision is not so furnished to the claimant within such sixty (60) days, the claim shall be deemed denied on review.

10.      Amendment and Assignment of Agreement. This Agreement may be altered, amended, or modified by written Agreement signed by the Company and the Employee. In

           addition, either party may assign its rights, interests and obligations under this Agreement; provided, however, that any assignment shall be made subject to the terms

           of this Agreement.

11.      Liability of Insurer. The Insurer shall be bound only by the provisions of and endorsements on the Policy, and any payments made or action taken by it is accordance therewith

           shall fully discharge it from all claims, suits and demands of all persons whatsoever. The Insurer shall be entitled to rely exclusively on a statement by the Company as to the

           determination of the Company's Policy Interest and the Employee's Policy Interest. The Insurer shall in no way be bound by or be deemed to have notice of the provisions

           of this Agreement.

12.     Miscellaneous. Where appropriate in this Agreement, words used in the singular shall include the plural, and words used in masculine shall include the feminine. The Agreement

          shall bind the Company and its successors and its assigns, and the Employee and its successors and its assigns. The laws of the State of North Carolina shall govern this

          Agreement.

IN WITNESS WHEREOF, the parties have executed this Agreement under seal as of the day and year first above written.

CAROLINA POWER & LIGHT COMPANY

BY:_____________________________________

Title _____________________________________

(CORPORATE SEAL)

ATTEST:

____________________________________

EMPLOYEE:

________________________________

EAL)

EX-12.A

Exhibit No. 12(a)

PROGRESS ENERGY, INC.

Computation of Ratio of Earnings to Fixed Charges

For the Years Ended December 31

(dollars in millions)	2006			2005			2004			2003			2002
Earnings, as defined:
Income from continuing operations before minority interest	$	523		$	692		$	654		$	771		$	546
Fixed charges, as below		651			606			591			590			632
Preferred dividend requirements		(7	)		(7	)		(7	)		(7	)		(7	)
Minority interest		(9	)		29			19			-			-
Income taxes, as below		199			(42	)		62			(138	)		(152	)
Total earnings, as defined	$	1,357		$	1,278		$	1,319		$	1,216		$	1,019
Fixed Charges, as defined:
Interest on long-term debt	$	619		$	566		$	529		$	543		$	541
Other interest		13			21			43			27			71
Imputed interest factor in rentals - charged
principally to operating expenses		12			12			12			13			13
Preferred dividend requirements of subsidiaries		7			7			7			7			7
Total fixed charges, as defined	$	651		$	606		$	591		$	590		$	632
Income Taxes:
Income tax expense (benefit)	$	204		$	(37	)	$	67		$	(130	)	$	(144	)
Included in AFUDC - deferred taxes in
book depreciation		(5	)		(5	)		(5	)		(8	)		(8	)
Total income taxes	$	199		$	(42	)	$	62		$	(138	)	$	(152	)
Ratio of Earnings to Fixed Charges		2.08			2.11			2.23			2.06			1.61

EX-12.B

Exhibit No. 12 (b)

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

Computation of Ratio of Earnings to Fixed Charges and

Ratio of Earnings to Fixed Charges and Preferred Dividends Combined

For the Years Ended December 31

(dollars in millions)	2006			2005			2004			2003			2002
Earnings, as defined:
Income before cumulative effect of changes in accounting principles	$	457		$	493		$	461		$	504		$	431
Fixed charges, as below		225			205			201			206			224
Income taxes, as below		260			234			234			233			199
Total earnings, as defined	$	942		$	932		$	896		$	943		$	854
Fixed Charges, as defined:
Interest on long-term debt	$	218		$	191		$	183		$	188		$	205
Other interest		(1	)		6			11			11			12
Imputed interest factor in rentals - charged
principally to operating expenses		8			8			7			7			7
Total fixed charges, as defined		225			205			201			206			224
Preferred dividends, as defined		5			4			5			4			4
Total fixed charges and preferred dividends combined	$	230		$	209		$	206		$	210		$	228
Income Taxes:
Income tax expense	$	265		$	239		$	239		$	241		$	207
Included in AFUDC - deferred taxes in
book depreciation		(5	)		(5	)		(5	)		(8	)		(8	)
Total income taxes	$	260		$	234		$	234		$	233		$	199
Ratio of Earnings to Fixed Charges		4.19			4.55			4.45			4.59			3.81
Ratio of Earnings to Fixed Charges and Preferred Dividends Combined		4.10			4.46			4.36			4.50			3.74

EX-12.C

Exhibit No. 12 (c)

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

Computation of Ratio of Earnings to Fixed Charges and

Ratio of Earnings to Fixed Charges and Preferred Dividends Combined

For the Years Ended December 31

(dollars in millions)	2006		2005		2004		2003			2002
Earnings, as defined:
Net income	$	328	$	260	$	335	$	297		$	325
Fixed charges, as below		159		138		122		103			114
Income taxes		193		121		174		147			163
Total earnings, as defined	$	680	$	519	$	631	$	547		$	602
Fixed Charges, as defined:
Interest on long-term debt	$	145	$	116	$	107	$	103		$	99
Other interest		10		18		10		(6	)		10
Imputed interest factor in rentals - charged
principally to operating expenses		4		4		5		6			5
Total fixed charges, as defined		159		138		122		103			114
Preferred dividends, as defined		2		2		2		2			3
Total fixed charges and preferred dividends combined	$	161	$	140	$	124	$	105		$	117
Ratio of Earnings to Fixed Charges		4.28		3.76		5.17		5.31			5.27
Ratio of Earnings to Fixed Charges and Preferred Dividends Combined		4.22		3.71		5.08		5.21			5.13

EX-21

Exhibit No. 21

PROGRESS ENERGY, INC.

List of Subsidiaries

The following is a list of certain direct and indirect subsidiaries of Progress Energy, Inc., and their respective states of incorporation as of December 31, 2006. All other subsidiaries, if considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary.

Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.	North Carolina
CaroFinancial, Inc.	North Carolina
Florida Progress Corporation	Florida
Florida Power Corporation d/b/a/ Progress Energy Florida, Inc.	Florida
Progress Capital Holdings, Inc.	Florida
Progress Telecommunications Corporation	Florida
Progress Fuels Corporation	Florida
EFC Synfuel LLC	Delaware
Ceredo Synfuel LLC	Delaware
Solid Energy LLC	Delaware
Kanawha River Terminals, Inc.	Florida
Black Hawk Synfuel LLC	Delaware
PV Holdings, Inc.	North Carolina
Progress Ventures, Inc. d/b/a Progress Energy Ventures, Inc.	North Carolina
Progress Genco Ventures, LLC	North Carolina
PV Synfuels, LLC	North Carolina
Solid Fuel, LLC	Delaware
Sandy River Synfuel, LLC	Delaware
Progress Energy Service Company, LLC	North Carolina

EX-23.A

Exhibit No. 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 33−33520 on Form S−8, Post−Effective Amendment 1 to Registration Statement No. 33−38349 on Form S−3, Registration Statement No. 333−81278 on Form S−3, Registration Statement No. 333−81278−01 on Form S−3, Registration Statement No. 333−81278−02 on Form S−3, Registration Statement No. 333−81278−03 on Form S−3, Post−Effective Amendment 1 to Registration Statement No. 333−69738 on Form S−3, Registration Statement No. 333−70332 on Form S−8, Registration Statement No. 333−87274 on Form S−3, Post−Effective Amendment 1 to Registration Statement No. 333−47910 on Form S−3, Registration Statement No. 333−52328 on Form S−8, Post−Effective Amendment 1 to Registration Statement No. 333−89685 on Form S−8, Registration Statement No. 333−48164 on Form S−8, Registration Statement No. 333-114237 on Form S-3, Registration Statement No. 333-104951 on Form S-8 and Registration Statement No. 333-104952 on Form S-8 of our reports dated February 28, 2007 relating to the consolidated financial statements and consolidated financial statement schedule of Progress Energy, Inc. (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2006 and 2005) and management’s report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10−K of Progress Energy, Inc. for the year ended December 31, 2006.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

EX-23.B

Exhibit No. 23(b)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333−126966 on Form S−3 of our reports dated February 28, 2007, relating to the consolidated financial statements and consolidated financial statement schedule of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)(which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2006 and 2005), appearing in this Annual Report on Form 10−K of PEC for the year ended December 31, 2006.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2007

EX-31.A

Exhibit 31(a)

CERTIFICATION

I, Robert B. McGehee, certify that:

1.   I have reviewed this annual report on Form 10-K of Progress Energy, Inc.;

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)   designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)   designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)   evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

d)   disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of this annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:

a)   all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2007	By: /s/ Robert B. McGehee
	Robert B. McGehee
	Chairman and Chief Executive Officer

EX-31.B

Exhibit 31(b)

CERTIFICATION

I, Peter M. Scott III, certify that:

1.   I have reviewed this annual report on Form 10-K of Progress Energy, Inc.;

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

d) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of this annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2007	By: /s/ Peter M. Scott III
	Peter M. Scott III
	Executive Vice President and Chief Financial Officer

EX-31.C

Exhibit 31(c)

CERTIFICATION

I, Fred N. Day IV, certify that:

1.   I have reviewed this annual report on Form 10-K of Carolina Power & Light Company;

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of this annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2007	/s/ Fred N. Day IV
	Fred N. Day IV
	President and Chief Executive Officer

EX-31.D

Exhibit 31(d)

CERTIFICATION

I, Peter M. Scott III, certify that:

1.   I have reviewed this annual report on Form 10-K of Carolina Power & Light Company;

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of this annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2007	/s/ Peter M. Scott III
	Peter M. Scott III
	Executive Vice President and Chief Financial Officer

EX-31.E

Exhibit 31(e)

CERTIFICATION

I, Jeffrey J. Lyash, certify that:

1.   I have reviewed this annual report on Form 10-K of Florida Power Corporation;

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of this annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2007	/s/ Jeffrey J. Lyash
	Jeffrey J. Lyash
	President and Chief Executive Officer

EX-31.F

Exhibit 31(f)

CERTIFICATION

I, Peter M. Scott III, certify that:

1.   I have reviewed this annual report on Form 10-K of Florida Power Corporation;

2.   Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.   Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of this annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 26, 2007	/s/ Peter M. Scott III
	Peter M. Scott III
	Executive Vice President and Chief Financial Officer

EX-32.A

Exhibit 32(a)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Progress Energy, Inc. (the “Company”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert B. McGehee, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Robert B. McGehee

Robert B. McGehee

Chairman and Chief Executive Officer

February 26, 2007

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.B

Exhibit 32(b)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Progress Energy, Inc. (the “Company”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter M. Scott III, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Peter M. Scott III

Peter M. Scott III

Executive Vice President and

Chief Financial Officer

February 26, 2007

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.C

Exhibit 32(c)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Carolina Power & Light Company (the “Company”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Fred N. Day IV, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Fred N. Day IV

Fred N. Day IV

President and Chief Executive Officer

February 26, 2007

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.D

Exhibit 32(d)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Carolina Power & Light Company (the “Company”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter M. Scott III, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Peter M. Scott III

Peter M. Scott III

Executive Vice President and

Chief Financial Officer

February 26, 2007

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.E

Exhibit 32(e)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Florida Power Corporation (the “Company”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey J. Lyash, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Jeffrey J. Lyash

Jeffrey J. Lyash

President and Chief Executive Officer

February 26, 2007

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.F

Exhibit 32(f)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Florida Power Corporation (the “Company”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter M. Scott III, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Peter M. Scott III

Peter M. Scott III

Executive Vice President and

Chief Financial Officer

February 26, 2007

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.