UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

OR

o 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, states of incorporation, addresses of principal executive offices, and telephone numbers	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. 100 Central Avenue St. Petersburg, Florida 33701 Telephone (727) 820-5151 State of Incorporation: Florida	59-0247770

NONE

(Former name, former address and former fiscal year, if changed since last report)

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.

Yes x No o

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, Inc. (Progress Energy)	Large accelerated filer	x	Accelerated filer	o	Non-accelerated filer	o
Carolina Power & Light Company (PEC)	Large accelerated filer	o	Accelerated filer	o	Non-accelerated filer	x
Florida Power Corporation (PEF)	Large accelerated filer	o	Accelerated filer	o	Non-accelerated filer	x

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

Progress Energy	Yes	o	No	x
PEC	Yes	o	No	x
PEF	Yes	o	No	x

Indicate the number of shares outstanding of each registrants’ classes of common stock, as of the latest practicable date. At October 31, 2006, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	254,198,987
PEC	Common Stock (Without Par Value)	159,608,055 (all of which were held directly by Progress Energy, Inc.)
PEF	Common Stock (Without par value)	100 (all of which were held indirectly by Progress Energy, Inc.)

This combined Form 10-Q 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 H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

2

PROGRESS ENERGY, INC.

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

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

FORM 10-Q - For the Quarter Ended September 30, 2006

Glossary of Terms

Safe Harbor for Forward-Looking Statements

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Interim Financial Statements:

Progress Energy, Inc. (Progress Energy)

Unaudited Consolidated Statements of Income

Unaudited Consolidated Balance Sheets

Unaudited Consolidated Statements of Cash Flows

Carolina Power & Light Company

d/b/a Progress Energy Carolinas, Inc. (PEC)

Unaudited Consolidated Statements of Income

Unaudited Consolidated Balance Sheets

Unaudited Consolidated Statements of Cash Flows

Florida Power Corporation

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

Unaudited Statements of Income

Unaudited Balance Sheets

Unaudited Statements of Cash Flows

Combined Notes to Unaudited Interim 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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Item 6. Exhibits

Signatures

3

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
2005 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2005
401(k) Plan	Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC	Allowance for funds used during construction
AHI	Affordable housing investment
APB	Accounting Principles Board
APB No. 25	Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”
APB No. 28	Accounting Principles Board Opinion No. 28, “Interim Financial Reporting”
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
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	Progress Ventures’ 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 Fuel	Business segment primarily engaged in synthetic fuel production and sales operations, the operation of synthetic fuel 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 business areas
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
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

4

DOE	United States Department of Energy
Earthco	Four wholly owned coal-based solid synthetic fuel limited liability companies
ECRC	Environmental Cost Recovery Clause
EIA	Energy Information Agency
EIP	Progress Energy 2002 Equity Incentive Plan
EITF	Emerging Issues Task Force
EITF 03-1	Emerging Issues Task Force No. 03-1, “The Meaning of Other-Than-Temporary Impairments and Its Application to Certain Investments”
EITF 03-4	Emerging Issues Task Force No. 03-4, “Determining the Classification and Benefit Attribution Method for a ‘Cash Balance’ Pension Plan”
EMCs	Electric Membership Cooperatives
Energy Delivery	Distribution operations of the Utilities
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company
FIN 45	FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIN 46R	FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51”
FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
Fitch	Fitch Ratings
Florida Global Case	U.S. Global LLC v. Progress Energy, Inc. et al
Florida Progress or FPC	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	Progress Ventures’ natural gas drilling and production business
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
GITS	Georgia Integrated Transmission System
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
Jackson	Jackson Electric Membership Corporation
kV	Kilovolt
kVA	Kilovolt-ampere
kW	Kilowatt
kWh/s	Kilowatt-hour/s
Level 3	Level 3 Communications, Inc.
LIBOR	London Inter Bank Offering Rate
MACT	Maximum Achievable Control Technology
MDC	Maximum Dependable Capability
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant

5

MW	Megawatt
MWh	Megawatt-hour
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
NSR	New Source Review requirement by EPA
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
the Notes Guarantee	Florida Progress’ full and unconditional guarantee of the Subordinated Notes
NOx	Nitrogen 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
NRC	United States Nuclear Regulatory Commission
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
OCI	Other comprehensive income as defined by GAAP
O&M	Operation and maintenance expense
OPC	Florida’s Office of Public Counsel
OPEB	Postretirement benefits other than pensions
P11	PEF’s combustion turbine Intercession City Unit P11
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 fuel 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 Fuels Subsidiaries	Subsidiaries of Progress Fuels that purchased the Earthco synthetic fuel facilities
Progress Rail	Progress Rail Services Corporation
Progress Ventures	Business segment 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
PT LLC	Progress Telecom, LLC
PUHCA	Public Utility Holding Company Act of 1935, as amended
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.

6

PWR	Pressurized water reactor
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 Internal Revenue Service Code
Section 29/45K	General business tax credits earned after December 31, 2005 for synthetic fuel production activities in accordance with Section 29
Section 45K	General business tax credit
(See Note/s “#”)	For all sections, this is a cross-reference to the Combined Notes to the Unaudited Interim Financial Statements contained in PART I, Item 1
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. 131	Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information”
SFAS No. 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative and Hedging Activities”
SFAS No. 138	Statement of Financial Accounting Standards No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133”
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. 148	Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123”
SFAS No. 149	Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
SFAS No. 150	Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”

7

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
SPC	Southern Power Company, a subsidiary of Southern Company
SRS	Strategic Resource Solutions Corp.
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.

8

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-Q 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. In addition, examples of forward-looking statements discussed in this Form 10-Q include, but are not limited to, statements made in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” including, but not limited to, statements under the sub-headings RESULTS OF OPERATIONS about trends and uncertainties, LIQUIDITY AND CAPITAL RESOURCES about operating cash flows, future liquidity requirements and estimated capital expenditures and OTHER MATTERS about our synthetic fuel facilities and environmental matters.

Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and the Energy Policy Act of 2005; the financial resources and capital needed to comply with environmental laws and our ability to recover eligible costs under cost recovery clauses; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered or stranded costs; 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; 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 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 below investment grade; 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 use Internal Revenue Code Section 29/45K (Section 29/45K) tax credits related to our coal-based solid synthetic fuel businesses; the impact that future crude oil prices may have on the value of our Section 29/45K tax credits; our ability to manage the risks involved with the operation of nonregulated plants, including dependence on third parties and related counter-party risks; the results of our consideration of alternative business strategies for our Competitive Commercial Operations (CCO) business, our ability to execute such alternative business strategy, if any, and any potential resulting charges to earnings; 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 disclosed in the Progress Registrants’ periodic filings with the United States Securities and Exchange Commission (SEC). Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors section of the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2005 (2005 Form 10-K) and are updated from time to time in PART II, Item 1A of our Form 10-Qs. 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 us to predict all such factors, nor can we assess the effect of each such factor on the Progress Registrants.

9

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

PROGRESS ENERGY, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2006

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions except per share data)	2006			2005			2006			2005
Operating revenues
Electric	$	2,599		$	2,412		$	6,666		$	5,963
Diversified business		314			542			1,053			1,314
Total operating revenues		2,913			2,954			7,719			7,277
Operating expenses
Utility
Fuel used in electric generation		860			633			2,259			1,712
Purchased power		391			424			880			839
Operation and maintenance		383			408			1,216			1,357
Depreciation and amortization		243			232			705			647
Taxes other than on income		141			131			380			356
Other		-			(7	)		(2	)		(32	)
Diversified business
Cost of sales		370			585			1,144			1,418
Depreciation and amortization		12			21			51			59
Impairment of assets (Notes 6 and 7)		-			-			155			-
Gain on the sale of assets		-			-			(4	)		(4	)
Other		15			17			59			69
Total operating expenses		2,415			2,444			6,843			6,421
Operating income		498			510			876			856
Other income (expense)
Interest income		13			3			37			11
Other, net		(9	)		4			(1	)		-
Total other income		4			7			36			11
Interest charges
Net interest charges		156			159			498			481
Allowance for borrowed funds used during construction		-			(3	)		(4	)		(10	)
Total interest charges, net		156			156			494			471
Income from continuing operations before income tax and minority interest		346			361			418			396
Income tax expense (benefit)		106			(65	)		135			(101	)
Income from continuing operations before minority interest		240			426			283			497
Minority interest in subsidiaries’ loss (income), net of tax		3			7			(10	)		24
Income from continuing operations		243			433			273			521
Discontinued operations, net of tax		76			16			44			20
Cumulative effect of changes in accounting principles, net of tax		-			1			-			1
Net income	$	319		$	450		$	317		$	542
Average common shares outstanding - basic		251			248			250			246
Basic earnings per common share
Income from continuing operations	$	0.97		$	1.75		$	1.09		$	2.12
Discontinued operations, net of tax		0.30			0.07			0.18			0.08
Cumulative effect of changes in accounting principles, net of tax		-			-			-			-
Net income	$	1.27		$	1.82		$	1.27		$	2.20
Diluted earnings per common share
Income from continuing operations	$	0.97		$	1.74		$	1.09		$	2.12
Discontinued operations, net of tax		0.30			0.07			0.17			0.08
Cumulative effect of changes in accounting principles, net of tax		-			-			-			-
Net income	$	1.27		$	1.81		$	1.26		$	2.20
Dividends declared per common share	$	0.605		$	0.590		$	1.815		$	1.770

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

10

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	23,479		$	22,940
Accumulated depreciation		(9,969	)		(9,602	)
Utility plant in service, net		13,510			13,338
Held for future use		12			12
Construction work in progress		1,055			813
Nuclear fuel, net of amortization		231			279
Total utility plant, net		14,808			14,442
Current assets
Cash and cash equivalents		335			605
Short-term investments		333			191
Receivables, net		1,061			1,050
Inventory		953			848
Deferred fuel cost		304			602
Deferred income taxes		126			41
Assets of discontinued operations		707			1,272
Prepayments and other current assets		138			208
Total current assets		3,957			4,817
Deferred debits and other assets
Regulatory assets		939			854
Nuclear decommissioning trust funds		1,215			1,133
Diversified business property, net		759			826
Miscellaneous other property and investments		466			476
Goodwill		3,655			3,719
Intangibles, net		222			269
Other assets and deferred debits		359			478
Total deferred debits and other assets		7,615			7,755
Total assets	$	26,380		$	27,014
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 254 and 252 million shares issued and outstanding, respectively	$	5,672		$	5,571
Unearned ESOP shares (2 and 3 million shares, respectively)		(50	)		(63	)
Accumulated other comprehensive loss		(96	)		(104	)
Retained earnings		2,495			2,634
Total common stock equity		8,021			8,038
Preferred stock of subsidiaries - not subject to mandatory redemption		93			93
Minority interest		15			36
Long-term debt, affiliate		271			270
Long-term debt, net		9,542			10,176
Total capitalization		17,942			18,613
Current liabilities
Current portion of long-term debt		700			513
Accounts payable		613			663
Interest accrued		151			208
Dividends declared		154			152
Short-term obligations		-			175
Customer deposits		222			200
Liabilities of discontinued operations		171			198
Other current liabilities		980			830
Total current liabilities		2,991			2,939
Deferred credits and other liabilities
Noncurrent income tax liabilities		218			228
Accumulated deferred investment tax credits		154			163
Regulatory liabilities		2,432			2,527
Asset retirement obligations		1,289			1,242
Accrued pension and other benefits		907			870
Other liabilities and deferred credits		447			432
Total deferred credits and other liabilities		5,447			5,462
Commitments and contingencies (Note 14)
Total capitalization and liabilities	$	26,380		$	27,014

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

11

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine Months Ended September 30	2006			2005
Operating activities
Net income	$	317		$	542
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax		(44	)		(20	)
Cumulative effect of changes in accounting principles		-			(1	)
Impairment of assets (Notes 6 and 7)		155			-
Charges for voluntary enhanced retirement program		-			159
Depreciation and amortization		827			793
Deferred income taxes		(79	)		(156	)
Investment tax credit		(9	)		(10	)
Tax levelization		6			(27	)
Deferred fuel cost (credit)		197			(276	)
Other adjustments to net income		91			91
Cash (used) provided by changes in operating assets and liabilities
Receivables		(31	)		(275	)
Inventories		(112	)		(125	)
Prepayments and other current assets		(51	)		(42	)
Accounts payable		6			191
Other current liabilities		168			14
Regulatory assets and liabilities		6			(50	)
Other operating activities		47			3
Net cash provided by operating activities		1,494			811
Investing activities
Gross utility property additions		(1,012	)		(772	)
Diversified business property additions		(1	)		(20	)
Nuclear fuel additions		(71	)		(98	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		548			458
Purchases of available-for-sale securities and other investments		(1,687	)		(3,478	)
Proceeds from sales of available-for-sale securities and other investments		1,611			3,534
Other investing activities		(16	)		(32	)
Net cash used in investing activities		(628	)		(408	)
Financing activities
Issuance of common stock		73			193
Proceeds from issuance of long-term debt, net		397			792
Net decrease in short-term indebtedness		(175	)		(167	)
Retirement of long-term debt		(848	)		(562	)
Dividends paid on common stock		(454	)		(435	)
Cash distributions to minority interests of consolidated subsidiary		(74	)		-
Other financing activities		(42	)		(17	)
Net cash used in financing activities		(1,123	)		(196	)
Cash provided (used) by discontinued operations
Operating activities		130			94
Investing activities		(143	)		(155	)
Financing activities		-			-
Net (decrease) increase in cash and cash equivalents		(270	)		146
Cash and cash equivalents at beginning of period		605			55
Cash and cash equivalents at end of period	$	335		$	201

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

12

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2006

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Operating revenues
Electric	$	1,200		$	1,185		$	3,113		$	2,980
Diversified business		-			-			1			1
Total operating revenues		1,200			1,185			3,114			2,981
Operating expenses
Fuel used in electric generation		322			282			880			746
Purchased power		135			154			279			294
Operation and maintenance		218			235			722			719
Depreciation and amortization		128			130			383			389
Taxes other than on income		51			49			141			137
Other		-			(8	)		-			(8	)
Total operating expenses		854			842			2,405			2,277
Operating income		346			343			709			704
Other income (expense)
Interest income		7			2			18			5
Other, net		(10	)		(3	)		(12	)		(4	)
Total other (expense) income		(3	)		(1	)		6			1
Interest charges
Interest charges		44			59			158			161
Allowance for borrowed funds used during construction		-			(1	)		(1	)		(4	)
Total interest charges, net		44			58			157			157
Income before income tax		299			284			558			548
Income tax expense		110			100			207			181
Net income		189			184			351			367
Preferred stock dividend requirement		1			1			2			2
Earnings for common stock	$	188		$	183		$	349		$	365

See Notes to PEC Consolidated Interim Financial Statements.

13

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	14,281		$	13,994
Accumulated depreciation		(6,362	)		(6,120	)
Utility plant in service, net		7,919			7,874
Held for future use		3			3
Construction work in progress		488			399
Nuclear fuel, net of amortization		172			203
Total utility plant, net		8,582			8,479
Current assets
Cash and cash equivalents		130			125
Short-term investments		132			191
Receivables, net		489			518
Receivables from affiliated companies		14			24
Inventory		469			451
Deferred fuel cost		207			261
Prepayments and other current assets		16			20
Total current assets		1,457			1,590
Deferred debits and other assets
Regulatory assets		520			421
Nuclear decommissioning trust funds		692			640
Miscellaneous other property and investments		193			188
Other assets and deferred debits		172			184
Total deferred debits and other assets		1,577			1,433
Total assets	$	11,616		$	11,502
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$	2,005		$	1,981
Unearned ESOP common stock		(50	)		(63	)
Accumulated other comprehensive loss		(121	)		(120	)
Retained earnings		1,410			1,320
Total common stock equity		3,244			3,118
Preferred stock - not subject to mandatory redemption		59			59
Long-term debt, net		3,469			3,667
Total capitalization		6,772			6,844
Current liabilities
Current portion of long-term debt		200			-
Accounts payable		212			247
Payables to affiliated companies		68			73
Notes payable to affiliated companies		2			11
Interest accrued		51			73
Short-term obligations		-			73
Customer deposits		57			52
Taxes accrued		78			100
Other current liabilities		292			255
Total current liabilities		960			884
Deferred credits and other liabilities
Noncurrent income tax liabilities		828			814
Accumulated deferred investment tax credits		129			133
Regulatory liabilities		1,235			1,196
Asset retirement obligations		992			949
Accrued pension and other benefits		538			511
Other liabilities and deferred credits		162			171
Total deferred credits and other liabilities		3,884			3,774
Commitments and contingencies (Note 14)
Total capitalization and liabilities	$	11,616		$	11,502

See Notes to PEC Consolidated Interim Financial Statements.

14

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine Months Ended September 30	2006			2005
Operating activities
Net income	$	351		$	367
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program		-			42
Depreciation and amortization		446			450
Deferred income taxes and investment tax credits, net		23			(25	)
Deferred fuel credit		(47	)		(146	)
Other adjustments to net income		32			71
Cash provided (used) by changes in operating assets and liabilities
Receivables		24			(88	)
Receivables from affiliated companies		22			14
Inventories		(23	)		(70	)
Prepayments and other current assets		6			3
Accounts payable		21			30
Payables to affiliated companies		(8	)		(15	)
Other current liabilities		(5	)		96
Other operating activities		26			(30	)
Net cash provided by operating activities		868			699
Investing activities
Gross utility property additions		(493	)		(453	)
Nuclear fuel additions		(65	)		(52	)
Purchases of available-for-sale securities and other investments		(736	)		(1,504	)
Proceeds from sales of available-for-sale securities and other investments		772			1,560
Other investing activities		(3	)		3
Net cash used in investing activities		(525	)		(446	)
Financing activities
Proceeds from issuance of long-term debt, net		-			495
Net decrease in short-term indebtedness		(73	)		(34	)
Changes in advances from affiliates		(9	)		(36	)
Retirement of long-term debt		-			(300	)
Dividends paid to parent		(255	)		(343	)
Dividends paid on preferred stock		(2	)		(2	)
Other financing activities		1			1
Net cash used in financing activities		(338	)		(219	)
Net increase in cash and cash equivalents		5			34
Cash and cash equivalents at beginning of period		125			18
Cash and cash equivalents at end of period	$	130		$	52

See Notes to PEC Consolidated Interim Financial Statements.

15

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

INTERIM FINANCIAL STATEMENTS

September 30, 2006

UNAUDITED STATEMENTS of INCOME
	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2006		2005			2006			2005
Operating revenues	$	1,399	$	1,227		$	3,553		$	2,983
Operating expenses
Fuel used in electric generation		538		351			1,379			966
Purchased power		256		270			601			545
Operation and maintenance		171		181			515			658
Depreciation and amortization		108		95			301			236
Taxes other than on income		89		82			238			215
Other		-		1			(2	)		(24	)
Total operating expenses		1,162		980			3,032			2,596
Operating income		237		247			521			387
Other income
Interest income		4		-			12			-
Other, net		6		4			8			6
Total other income		10		4			20			6
Interest charges
Interest charges		39		28			119			96
Allowance for borrowed funds used during construction		-		(2	)		(3	)		(6	)
Total interest charges, net		39		26			116			90
Income before income tax		208		225			425			303
Income tax expense		83		74			160			98
Net income		125		151			265			205
Preferred stock dividend requirement		-		-			1			1
Earnings for common stock	$	125	$	151		$	264		$	204

See Notes to PEF Interim Financial Statements.

16

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED BALANCE SHEETS
(in millions)	September 30, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	9,014		$	8,756
Accumulated depreciation		(3,555	)		(3,434	)
Utility plant in service, net		5,459			5,322
Held for future use		9			9
Construction work in progress		567			414
Nuclear fuel, net of amortization		59			76
Total utility plant, net		6,094			5,821
Current assets
Cash and cash equivalents		16			218
Receivables, net		422			331
Receivables from affiliated companies		5			11
Deferred income taxes		72			12
Inventory		427			311
Deferred fuel cost		97			341
Prepayments and other current assets		72			100
Total current assets		1,111			1,324
Deferred debits and other assets
Regulatory assets		329			351
Debt issuance costs		20			22
Nuclear decommissioning trust funds		523			493
Miscellaneous other property and investments		45			47
Prepaid pension costs		216			200
Other assets and deferred debits		15			60
Total deferred debits and other assets		1,148			1,173
Total assets	$	8,353		$	8,318
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$	1,098		$	1,097
Accumulated other comprehensive loss		(2	)		-
Retained earnings		1,585			1,498
Total common stock equity		2,681			2,595
Preferred stock - not subject to mandatory redemption		34			34
Long-term debt, net		2,469			2,554
Total capitalization		5,184			5,183
Current liabilities
Current portion of long-term debt		88			48
Accounts payable		276			237
Payables to affiliated companies		88			101
Notes payable to affiliated companies		13			13
Short-term obligations		-			102
Customer deposits		165			148
Interest accrued		27			42
Other current liabilities		255			101
Total current liabilities		912			792
Deferred credits and other liabilities
Noncurrent income tax liabilities		450			433
Accumulated deferred investment tax credits		25			30
Regulatory liabilities		1,065			1,189
Asset retirement obligations		295			290
Accrued pension and other benefits		263			257
Other liabilities and deferred credits		159			144
Total deferred credits and other liabilities		2,257			2,343
Commitments and contingencies (Note 14)
Total capitalization and liabilities	$	8,353		$	8,318

See Notes to PEF Interim Financial Statements.

17

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED STATEMENTS of CASH FLOWS
(in millions)
Nine Months Ended September 30	2006			2005
Operating activities
Net income	$	265		$	205
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program		-			91
Depreciation and amortization		323			262
Deferred income taxes and investment tax credits, net		(46	)		4
Deferred fuel cost (credit)		244			(130	)
Other adjustments to net income		9			13
Cash (used) provided by changes in operating assets and liabilities
Receivables		(100	)		(140	)
Receivables from affiliated companies		6			10
Inventories		(117	)		(48	)
Prepayments and other current assets		(44	)		(8	)
Accounts payable		43			79
Payables to affiliated companies		(13	)		5
Other current liabilities		108			(18	)
Regulatory assets and liabilities		5			(52	)
Other operating activities		(29	)		30
Net cash provided by operating activities		654			303
Investing activities
Gross utility property additions		(528	)		(336	)
Nuclear fuel additions		(6	)		(46	)
Proceeds from sales of assets		3			42
Purchases of available-for-sale securities and other investments		(547	)		(241	)
Proceeds from sales of available-for-sale securities and other investments		547			241
Other investing activities		1			(5	)
Net cash used in investing activities		(530	)		(345	)
Financing activities
Proceeds from issuance of long-term debt, net		-			297
Net decrease in short-term indebtedness		(102	)		(1	)
Retirement of long-term debt		(47	)		(101	)
Changes in advances from affiliates		-			(147	)
Dividends paid to parent		(176	)		-
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		-			(2	)
Net cash (used) provided by financing activities		(326	)		45
Net (decrease) increase in cash and cash equivalents		(202	)		3
Cash and cash equivalents at beginning of period		218			12
Cash and cash equivalents at end of period	$	16		$	15

See Notes to PEF Interim Financial Statements.

18

PROGRESS ENERGY, INC.

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

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

COMBINEDNOTES TO UNAUDITED INTERIM FINANCIAL STATEMENTS

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

Each of the following combined notes to the interim financial statements of the Progress Registrants are applicable to Progress Energy, Inc. but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF.

Registrant	Applicable Notes
PEC	1, 2, 4 through 6, 8 through 10, and 12 through 14
PEF	1, 2, 4 through 6, 8 through 10, and 12 through 14

19

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 UNAUDITED INTERIM 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 Carolina Power & Light Company d/b/a/ Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a/ Progress Energy Florida, Inc. (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

The Parent is a holding company headquartered in Raleigh, N.C. and is subject to the regulatory provisions of the Federal Energy Regulatory Commission (FERC).

Our reportable segments are: PEC, PEF, Progress Ventures, and Coal and Synthetic Fuels. Our PEC and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity. Our Progress Ventures segment is primarily engaged in nonregulated electric generation operations and energy marketing activities in our Competitive Commercial Operations business (CCO). Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuel as defined under the Internal Revenue Code (the Code), the operation of synthetic fuel facilities for third parties, and coal terminal services. Through our other business units, we engage in other nonregulated business areas, which are included in our Corporate and Other segment (Corporate and Other).

PEC and PEF are public service corporations. PEC’s service territory covers portions of North Carolina and South Carolina and PEF’s covers portions of Florida. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory provisions of the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC); PEF is subject to the regulatory provisions of the Florida Public Service Commission (FPSC). Both of the Utilities are subject to regulation by the United States Nuclear Regulatory Commission (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) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2005 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2005 (2005 Form 10-K).

In accordance with the provisions of Accounting Principles Board (APB) Opinion No. 28, “Interim Financial Reporting” (APB No. 28), GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. The intra-period tax allocation, which will have no impact on total year net income, maintains an effective tax rate consistent with the estimated annual effective tax rate. The fluctuations in the effective tax rate for interim periods are primarily due to the recognition of synthetic fuel tax credits and seasonal fluctuations in energy sales and earnings from the Utilities. The impact of applying a levelized effective tax rate increased (decreased) income tax expense for the Progress Registrants for the three months and nine months ended September 30, 2006 and 2005, as follows:

20

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006		2005
Progress Energy	$	(12	)	$	(91	)	$	7	$	(27	)
PEC	$	1		$	3		$	-	$	6
PEF	$	2		$	(9	)	$	2	$	-

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in electric revenues and taxes other than on income in the Statements ofIncome for the three months and nine months ended September 30, 2006 and 2005 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2006		2005		2006		2005
Progress Energy	$	89	$	80	$	223	$	194
PEC	$	28	$	27	$	71	$	68
PEF	$	61	$	53	$	152	$	126

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all normal recurring adjustments necessary to fairly present the Progress Registrants’ financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or for future periods.

In preparing financial statements that conform with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Certain amounts for 2005 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 September 30, 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 September 30, 2006, the total assets of the two entities were $38 million, the majority of which are collateral for the entities’ obligations and are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

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 also has an interest in one power plant resulting from long-term power purchase contracts. PEC has requested the necessary information to determine if the 17 partnerships and the power

21

plant owner 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 No. 46R, paragraph 4(g), to the 17 partnerships and the power plant. PEC believes that if it is determined to be the primary beneficiary of these entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings or cash flows.

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 September 30, 2006, the aggregate maximum loss exposure that PEC could be required to record on its income statement as a result of these arrangements totals $22 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. See Note 2 of the 2005 Form 10-K for additional information.

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 September 30, 2006, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was $5 million. 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.

2.NEW ACCOUNTING STANDARDS

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 would be January 1, 2007. FIN 48 applies to all tax positions within the scope of Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes.” 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 currently assessing the impact of FIN 48 on our various income tax positions and results of operations.

SFAS No. 157, “Fair Value Measurements”

The FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157) in September 2006. 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.

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

22

accumulated other comprehensive income, 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 are effective for us as of December 31, 2006. We are currently in compliance with the year-end measurement date provisions, which are not required to be implemented until fiscal years ending after December 15, 2008. The implementation of SFAS No. 158 will have no impact on reported net income.

The effects of SFAS No. 158 for us, PEC and PEF at December 31, 2006 will be impacted by factors such as plan asset returns and the December 31, 2006 discount rate used to measure plan obligations. Based on current projections, the implementation of SFAS No. 158 could have the following incremental balance sheet effects as compared with continuation of the prior minimum pension adjustment requirement: Progress Energy - increase benefit liabilities by $181 million and decrease accumulated other comprehensive income by $71 million, net of tax; PEC - increase benefit liabilities by $72 million and decrease accumulated other comprehensive income by $58 million, net of tax; PEF - decrease benefit assets by $91 million and increase benefit liabilities by $98 million.

The estimated effects above for us and PEF reflect the regulatory asset or liability treatment of amounts that would otherwise be recorded in accumulated other comprehensive income, pursuant to an expected FPSC order consistent with the prior FPSC order related to minimum pension adjustments (See Note 16A to the 2005 Form 10-K). In addition, we and PEC are continuing to evaluate potential regulatory asset treatment for PEC amounts that would otherwise be charged to accumulated other comprehensive income.

Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”

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 September 2006. 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. We do not expect that the implementation of SAB 108 will have a material effect on our financial position or results of operations.

3.DIVESTITURES

A.Natural Gas Drilling and Production

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., 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. Proceeds from the sale are expected to be used primarily to reduce holding company debt and for other corporate purposes. The transaction closed on October 2, 2006, and is subject to customary post-closing provisions and post-closing adjustments. The sale will be included in the fourth quarter results. The accompanying consolidated financial

23

statements have been restated for all periods presented to reflect the operations of Gas as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated for the three months ended September 30, 2006 and 2005 was $4 million and $3 million, respectively. Interest expense allocated for the nine months ended September 30, 2006 and 2005 was $13 million and $9 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in July 2006. After-tax depreciation expense recorded by Gas during the three months ended September 30, 2005 totaled $7 million. After-tax depreciation expense recorded by Gas during the nine months ended September 30, 2006 and 2005 totaled $16 million and $19 million, respectively. Results of discontinued operations were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Revenues	$	100		$	43		$	192		$	115
Earnings before income taxes		88			24			138			57
Income tax expense		(31	)		(9	)		(54	)		(21	)
Net earnings from discontinued operations	$	57		$	15		$	84		$	36

B.DeSoto and Rowan Generation Facilities

On May 2, 2006, our board of directors approved a plan to divest of two subsidiaries of Progress Ventures, Inc., 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. We recorded an after-tax loss during the six months ended June 30, 2006 of $62 million on the sale of Rowan and DeSoto and an additional loss of $3 million during the three months ended September 30, 2006, related to post-closing adjustments.

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 three months ended September 30, 2005 was $3 million. Interest expense allocated for the nine months ended September 30, 2006 and 2005 was $6 million and $10 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in May 2006. After-tax depreciation expense recorded by DeSoto and Rowan during the three months ended September 30, 2005 totaled $2 million. After-tax depreciation expense recorded by DeSoto and Rowan during the nine months ended September 30, 2006 and 2005 totaled $3 million and $7 million, respectively. Results of discontinued operations were as follows:

24

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Revenues	$	50		$	37		$	64		$	62
Earnings before income taxes		22			12			15			12
Income tax expense		(7	)		(5	)		(6	)		(5	)
Net earnings from discontinued operations		15			7			9			7
Loss on disposal of discontinued operations, including income tax benefit of $2 and $40, respectively		(3	)		-			(65	)		-
Earnings (loss) from discontinued operations	$	12		$	7		$	(56	)	$	7

C.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 12 for a discussion of the subsequent sale of the Level 3 stock.

Based on the gross proceeds associated with the sale and after consideration of minority interest, we recorded an after-tax gain on disposal of $24 million during the three months ended March 31, 2006. During the three months ended June 30, 2006, we recorded an additional after-tax gain of $5 million in connection with certain tax matters. During the three months ended September 30, 2006, we recorded a $1 million adjustment related to additional tax expenses resulting in a total after-tax gain of $28 million for the nine months ended September 30, 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 the net assets of PT LLC, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated for the nine months ended September 30, 2005 was $1 million. Interest expense allocated for the three months ended September 30, 2005 was less than $1 million. We ceased recording depreciation upon classification of the assets as discontinued operations in January 2006. After-tax depreciation expense recorded by PT LLC during the nine months ended September 30, 2006 and 2005 was $1 million and $6 million, respectively. After-tax depreciation expense recorded for the three months ended September 30, 2005 was $2 million. Results of discontinued operations were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Revenues	$	-		$	18		$	18		$	49
Earnings before income taxes and minority interest		2			5			5			7
Income tax expense		-			(1	)		(4	)		(1	)
Minority interest		-			(2	)		(4	)		(3	)
Net earnings (loss) from discontinued operations		2			2			(3	)		3
(Loss) gain on disposal of discontinued operations, including income tax benefit (expense) of $1 and $(8), respectively, and minority interest of $1 and $35, respectively		(1	)		-			28			-
Earnings from discontinued operations	$	1		$	2		$	25		$	3

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 14A. The ultimate resolution of these matters could result in adjustments to the gain on sale in future periods.

25

D.Dixie Fuels and Other Fuels Businesses

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 businesses are expected to be sold within the next six months.

The accompanying consolidated financial statements have been restated for all periods presented to reflect Dixie Fuels and the other fuels businesses as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of Dixie Fuels and the other fuels businesses, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated was less than $1 million for the three months and nine months ended September 30, 2006 and 2005. We ceased recording depreciation expense upon classification to discontinued operations. After-tax depreciation expense during the three months and nine months ended September 30, 2006 was less than $1 million. After-tax depreciation expense during the three months and nine months ended September 30, 2005 was $1 million and $2 million, respectively. Results of discontinued operations were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Revenues	$	7		$	9		$	17		$	23
Earnings before income taxes		6			3			10			5
Income tax expense		(2	)		(1	)		(4	)		(2	)
Net earnings from discontinued operations		4			2			6			3
Gain on disposal of discontinued operations, including income tax expense of $1		-			-			2			-
Earnings from discontinued operations	$	4		$	2		$	8		$	3

E.Coal Mining Businesses

On November 14, 2005, our board of directors approved a plan to divest 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 nine months ended September 30, 2006, we recorded an after-tax loss of $13 million on the sale of these assets. The remaining coal mining operations are expected to be sold by the end of 2006.

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 was $1 million for the three months ended September 30, 2005. Interest expense allocated was $1 million and $2 million for the nine months ended September 30, 2006 and 2005, 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 three months and nine months ended September 30, 2005 was $4 million and $10 million, respectively. Results of discontinued operations were as follows:

26

	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2006		2005			2006			2005
Revenues	$	15	$	58		$	87		$	168
Earnings (loss) before income taxes		-		(14	)		(4	)		(15	)
Income tax benefit		2		5			3			6
Net earnings (loss) from discontinued operations		2		(9	)		(1	)		(9	)
Estimated loss on disposal of discontinued operations, including income tax benefit of $- and $17, respectively		-		-			(13	)		-
Earnings (loss) from discontinued operations	$	2	$	(9	)	$	(14	)	$	(9	)

F.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. Gross 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, we recorded an estimated after-tax loss on disposal of $25 million during the nine months ended September 30, 2005. During the nine months ended September 30, 2006, we recorded an additional after-tax loss on disposal of $3 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 14A.

The accompanying consolidated financial statements reflect the operations of Progress Rail as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of Progress Rail, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated for the nine months ended September 30, 2005 was $4 million. We ceased recording depreciation upon classification of the assets as discontinued operations in February 2005. After-tax depreciation expense during the nine months ended September 30, 2005 was $3 million. Results of discontinued operations were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2006		2005			2006			2005
Revenues	$	-	$	-		$	-		$	358
Earnings before income taxes		-		-			-			8
Income tax expense		-		-			-			(3	)
Net earnings from discontinued operations		-		-			-			5
Estimated loss on disposal of discontinued operations, including income tax benefit of $- and $2 for 2006, respectively, and $- and $15 for 2005, respectively		-		(1	)		(3	)		(25	)
Loss from discontinued operations	$	-	$	(1	)	$	(3	)	$	(20	)

G.Net Assets of Discontinued Operations

Included in net assets of discontinued operations are the assets and liabilities of Gas, the remaining coal mining operations and other fuels businesses at September 30, 2006 and the assets and liabilities of Gas, DeSoto and Rowan, PT LLC, Dixie Fuels, the five coal mining businesses and other fuels businesses at December 31, 2005. The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets were as follows:

27

(in millions)	September 30, 2006		December 31, 2005
Accounts receivable	$	40	$	61
Inventory		5		25
Other current assets		38		22
Total property, plant and equipment, net		603		1,152
Total other assets		21		12
Assets of discontinued operations	$	707	$	1,272
Accounts payable		10		25
Accrued expenses		46		61
Long-term liabilities		115		112
Liabilities of discontinued operations	$	171	$	198

4.REGULATORY MATTERS

A.PEC Retail Rate Matters

FUEL COST RECOVERY

On May 3, 2006, PEC filed with the SCPSC for an increase in the fuel rate charged to its South Carolina customers 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.

On June 2, 2006, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina customers. 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 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 factor effective October 1, 2006 included in the settlement agreement. Effective October 1, 2006, residential electric bills increased by $4.87 per 1,000 kWhs for fuel cost recovery.

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 13A). 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 will reverse $18 million of O&M expense and establish a regulatory asset as well as record $3 million of amortization expense.

B.PEF Retail Rate Matters

FUEL 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

28

filings to reflect lower projected fuel costs for PEF. PEF’s revised forecasts show a $40 million, or 0.7 percent, increase in rates over 2006. The proposed new charges would take effect January 1, 2007 and would increase residential bills in total by a net amount of $0.78 for the first 1,000 kWhs. The FPSC is scheduled to hold hearings on the proposal in early November. We cannot predict the outcome of this matter.

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus interest, of alleged excessive past fuel recovery charges and SO₂ allowance costs 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 1996-2005. 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. In the event that PEF’s motion to dismiss is not granted, we anticipate a hearing to be held during the second quarter of 2007. PEF believes that it has sound legal and factual arguments to successfully defend its position but cannot predict the outcome of this matter.

STORM COST RECOVERY

On April 25, 2006, PEF entered into a settlement agreement with certain interveners 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. The extension, which would begin August 2007, would replenish the existing storm reserve by an estimated additional $130 million. During the third quarter, PEF and the interveners modified the settlement agreement such 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. On August 29, 2006, the FPSC approved the settlement agreement as modified.

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 and associated transmission infrastructure. Hines Unit 4, which has a projected commercial operation date of December 2007, is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to ratepayers. 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, customers will receive the benefit of cost under-runs. Any costs that exceed the original 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 10 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.

On September 22, 2006, PEF filed a petition with the FPSC to recover the costs to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) through its fuel adjustment clause. The uprate will increase CR3’s gross output by approximately 180 MWs. The uprate will take place in two stages: approximately 40 MWs will be added through equipment modifications during the 2009 refueling outage and approximately 140 MWs will be added by modifying the design of the plant to use more highly enriched fuel during the 2011 refueling outage. 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. A hearing date has been tentatively set with the FPSC for January 18, 2007. 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. We cannot predict the outcome of this matter.

29

C.Other Matters

REGIONAL TRANSMISSION ORGANIZATION

PEF was one of three major investor-owned Florida utilities that formed a regional transmission organization (RTO), GridFlorida, in 2000. A cost-benefit study conducted during 2005 concluded that the GridFlorida RTO was not cost effective for jurisdictional customers and shifted benefits to nonjurisdictional customers. In light of these findings, the GridFlorida applicants filed a motion to withdraw the GridFlorida compliance filing and filed a petition to close the docketed proceeding on January 27, 2006. At a hearing held on April 18, 2006, the FPSC approved the request to close the docketed proceeding and the docket was closed effective May 9, 2006. The closing of the docketed proceeding did not impact PEF’s results of operations as PEF has fully recovered its GridFlorida startup costs from retail ratepayers. GridFlorida was dissolved on June 12, 2006. In light of the FPSC’s decision, the FERC also terminated its docket on June 19, 2006.

NUCLEAR LICENSE RENEWAL

On June 26, 2006, PEC’s Brunswick Nuclear Plant (Brunswick) received 20-year extensions from the NRC on the operating licenses for its two nuclear reactors. The operating license of Unit 1 extends until 2036 and Unit 2 until 2034.

5.EQUITY AND COMPREHENSIVE INCOME

A.Earnings Per Common Share

A reconciliation of our weighted-average number of common shares outstanding for basic and dilutive earnings per share purposes follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2006		2005		2006		2005
Weighted-average common shares - basic		251		248		250		246
Net effect of dilutive stock-based compensation plans		-		-		1		-
Weighted-average shares - fully dilutive		251		248		251		246

B.Comprehensive Income

Progress Energy

	Three Months Ended September 30,
(in millions)	2006			2005
Net income	$	319		$	450
Other comprehensive income (loss)
Reclassification adjustment included in net income
Change in cash flow hedges (net of tax expense of $20 and $11, respectively)		32			20
Changes in net unrealized losses on cash flow hedges (net of tax benefit of $33 and $28, respectively)		(41	)		(51	)
Minimum pension liability adjustment (net of tax benefit of $- and $45, respectively)		-			(70	)
Other (net of tax expense of $- and $1, respectively)		-			2
Other comprehensive loss		(9	)		(99	)
Comprehensive income	$	310		$	351

30

	Nine Months Ended September 30,
(in millions)	2006			2005
Net income	$	317		$	542
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $19 and $15, respectively)		31			25
Foreign currency translation adjustments included in discontinued operations		-			(6	)
Minimum pension liability adjustment included in discontinued operations (net of tax expense of $- and $1, respectively)		-			1
Changes in net unrealized losses on cash flow hedges (net of tax benefit of $17 and $3, respectively)		(23	)		(1	)
Minimum pension liability adjustment (net of tax benefit of $- and $45, respectively)		-			(70	)
Other (net of tax expense of $- and $2, respectively)		-			3
Other comprehensive income (loss)		8			(48	)
Comprehensive income	$	325		$	494

PEC

	Three Months Ended September 30,
(in millions)		2006		2005
Net income	$	189	$	184
Other comprehensive income (loss)
Changes in net unrealized gains on cash flow hedges (net of tax expense of $-)		1		-
Minimum pension liability adjustment (net of tax benefit of $- and $35, respectively)		-		(55	)
Other (net of tax expense of $- and $1, respectively)		-		2
Other comprehensive income (loss)		1		(53	)
Comprehensive income	$	190	$	131

	Nine Months Ended September 30,
(in millions)	2006			2005
Net income	$	351		$	367
Other comprehensive (loss) income
Changes in net unrealized (losses) gains on cash flow hedges (net of tax (benefit) expense of ($1) and $1, respectively)		(1	)		2
Minimum pension liability adjustment (net of tax benefit of $- and $35, respectively)		-			(55	)
Other (net of tax expense of $- and $1, respectively)		-			3
Other comprehensive loss		(1	)		(50	)
Comprehensive income	$	350		$	317

31

PEF

	Three Months Ended September 30,
(in millions)	2006			2005
Net income	$	125		$	151
Other comprehensive loss
Changes in net unrealized losses on cash flow hedges (net of tax benefit of $1 and $-, respectively)		(2	)		-
Other comprehensive loss		(2	)		-
Comprehensive income	$	123		$	151

	Nine Months Ended September 30,
(in millions)	2006			2005
Net income	$	265		$	205
Other comprehensive loss
Changes in net unrealized losses on cash flow hedges (net of tax benefit of $1 and $-, respectively)		(2	)		-
Other comprehensive loss		(2	)		-
Comprehensive income	$	263		$	205

C.Common Stock

At December 31, 2005, we had 500 million shares of common stock authorized under our charter, of which approximately 252 million were outstanding. For the three months ended September 30, 2006 and 2005, respectively, we issued approximately 0.3 million shares and 0.4 million shares of common stock resulting in approximately $13 million and $22 million in proceeds, net of purchases of restricted shares, primarily to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k) Plan) and the Investor Plus Stock Purchase Plan. For the nine months ended September 30, 2006 and 2005, respectively, we issued approximately 1.7 million shares and 4.4 million shares of common stock resulting in approximately $73 million and $193 million in proceeds, net of purchases of restricted shares. Included in these amounts were approximately 1.4 million shares and 4.3 million shares for net proceeds of approximately $58 million and $187 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. At December 31, 2005, we had approximately 58 million unissued shares of common stock reserved, primarily to satisfy the requirements of our stock plans. In 2002, the board of directors authorized meeting the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan with original issue shares.

D.Stock-Based Compensation

As discussed in Note 10 of the 2005 Form 10-K, we adopted SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), as of July 1, 2005, using the required modified prospective method. Under that method we began recording compensation expense as of July 1, 2005. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), and we made that election. The intrinsic value method resulted in our recording no compensation expense for stock options granted to employees. We curtailed our stock option program in 2004 and replaced that compensation program with other programs.

Progress Energy

The information below should be read in conjunction with the plan descriptions and other pertinent information disclosed in Note 10 of the 2005 Form 10-K. 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 during the nine months ended September 30, 2005:

32

(in millions except per share data)
Net income, as reported	$	542
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		2
Pro forma net income	$	540
Earnings per share
Basic - as reported	$	2.20
Basic - pro forma	$	2.19
Diluted - as reported	$	2.20
Diluted - pro forma	$	2.19

PEC

PEC participates in Progress Energy’s stock option and other stock-based compensation plans. The information below should be read in conjunction with the plan descriptions and other pertinent information disclosed in Note 10 of the 2005 Form 10-K. The following table illustrates the effect on PEC’s net income if the fair value method had been applied to all outstanding and nonvested awards during the nine months ended September 30, 2005:

(in millions)
Net income, as reported	$	367
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		2
Pro forma net income	$	365

PEF

PEF participates in Progress Energy’s stock option and other stock-based compensation plans. The information below should be read in conjunction with the plan descriptions and other pertinent information disclosed in Note 10 of the 2005 Form 10-K. The following table illustrates the effect on PEF’s net income if the fair value method had been applied to all outstanding and nonvested awards during the nine months ended September 30, 2005:

(in millions)
Net income, as reported	$	205
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1
Pro forma net income	$	204

6.GOODWILL AND OTHER INTANGIBLE ASSETS

As discussed in Note 8 of the 2005 Form 10-K, we perform annual goodwill impairment tests in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).

For our Progress Ventures segment, the goodwill impairment tests were performed at the reporting unit level of our Effingham, Monroe, Walton and Washington nonregulated generation plants (Georgia Region), which is one level below the Progress Ventures segment. As a result of our evaluation of certain business opportunities that may impact 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 is reported within impairment of assets on the Consolidated Statements of Income.

Under SFAS No. 142, all goodwill is assigned to our reporting units that are expected to benefit from the synergies of the business combination. The changes in the carrying amount of goodwill, by reportable segment, were as follows:

33

(in millions)	PEC(a)		PEF(a)		Progress Ventures			Totall
Balance at January 1, 2005	$	1,922	$	1,733	$	64		$	3,719
Balance at December 31, 2005		1,922		1,733		64			3,719
Impairment		-		-		(64	)		(64	)
Balance at September 30, 2006	$	1,922	$	1,733	$	-		$	3,655

^(a) Goodwill assigned to PEC and PEF is recorded in our Corporate and Other business segment.

The gross carrying amount and accumulated amortization of intangible assets at September 30, 2006 and December 31, 2005 were as follows:

	September 30, 2006					December 31, 2005
(in millions)	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Synthetic fuel intangibles	$	107	$	(107	)	$	134	$	(98	)
Power agreements acquired		188		(31	)		188		(19	)
Other		76		(11	)		76		(12	)
Total	$	371	$	(149	)	$	398	$	(129	)

We apply SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), for the accounting and reporting of impairment or disposal of long-lived assets. We have monitored our synthetic fuel intangibles for impairment and had previously determined that no impairment of these assets was required.On May 22, 2006, we idled our synthetic fuel facilities due to significant uncertainty surrounding future synthetic fuel production. With the idling of these facilities, we performed another impairment evaluation of the intangible assets, which were comprised primarily of capitalized acquisition costs (See Note 7 for impairment of related long-lived assets). The impairment test considered numerous factors including, among other things, continued high oil prices, the continued uncertainty of whether federal legislation will be enacted that would provide assurance that tax credits would exist for 2006 production and the then-current “idle” state of our synthetic fuel 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 fuel facilities resumed limited production of synthetic fuel in September and October 2006.

Certain intangible assets with net carrying values of $25 million at December 31, 2005, related to DeSoto and Rowan, were reclassified to net assets of discontinued operations during the second quarter of 2006.

7.IMPAIRMENT OF LONG-LIVED ASSETS

Concurrent with the synthetic fuels intangibles impairment evaluation discussed in Note 6, 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 fuel manufacturing facilities, as well as a portion of the asset carrying value associated with the river terminals at which the synthetic fuel manufacturing facilities are located. These assets had been reported within the Coal and Synthetic Fuels segment. As discussed in Note 6, our synthetic fuel facilities resumed limited production of synthetic fuel in September and October 2006.

For our Progress Ventures segment, long-lived asset impairment tests are performed at the Georgia Region asset group level. We have engaged a strategic advisor to help us pursue alternative business strategies related to our CCO business. As a result of the decision to pursue these strategies, as of September 30, 2006, we considered the likelihood of disposal of the CCO assets before the end of their useful life to be more likely than not. Under SFAS No. 144, the more likely than not to dispose determination triggered an impairment test of CCO’s intangible and

34

long-lived assets in the third quarter of 2006. The first step of the impairment test was based upon undiscounted cash flows using various hold and sale scenarios over the expected period of use of the assets, and the results of the test did not indicate impairment. At September 30, 2006, the long-lived assets were recorded at a net book value of approximately $926 million, including $727 million of property, plant and equipment assets and $199 million of intangible assets. As we continue to evaluate certain strategic business alternatives, we will monitor the carrying value of our long-lived assets associated with our Progress Ventures operations.

8. DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES

Material changes to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2005, are described below.

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 will be based on three-month London Inter Bank Offering Rate (LIBOR) plus 45 basis points and will be reset 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. Prior to 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 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, as of September 30, 2006, Progress Energy has 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 Progress Energy 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 still includes a defined maximum total debt to capital ratio of 68 percent and contains various cross-default and other acceleration provisions. However, 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 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 Standard & Poor’s Rating Services (S&P).

On May 3, 2006, PEC’s five-year $450 million credit facility 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.

On May 3, 2006, PEF’s five-year $450 million credit facility 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.

35

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.

9.BENEFIT PLANS

We have a noncontributory defined benefit retirement plan for substantially all full-time employees that provides 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. The components of the net periodic benefit cost for the respective Progress Registrants for the three months and nine months ended September 30 were:

Progress Energy

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2006			2005			2006			2005
Service cost	$	10		$	5		$	2		$	-
Interest cost		30			31			8			9
Expected return on plan assets		(39	)		(34	)		(2	)		(1	)
Amortization of actuarial loss		5			14			-			4
Other amortization, net		-			-			-			1
Net periodic cost		6			16			8			13
Additional benefit recognition (a)		(4	)		(3	)		-			-
Net periodic cost recognized	$	2		$	13		$	8		$	13

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Service cost	$	34		$	35		$	6		$	6
Interest cost		88			88			25			25
Expected return on plan assets		(111	)		(107	)		(4	)		(4	)
Amortization of actuarial loss		23			26			4			6
Other amortization, net		1			1			1			2
Net periodic cost		35			43			32			35
Additional (benefit) cost recognition (a)		(11	)		(11	)		2			1
Net periodic cost recognized	$	24		$	32		$	34		$	36

^(a)   Relates to the acquisition of Florida Progress. See Note 16B to the 2005 Form 10-K.

In addition, in the second quarter of 2005, we recorded costs for special termination benefits related to our voluntary enhanced retirement program of approximately $122 million for pension benefits and $19 million for other postretirement benefits. In the third quarter of 2005, we recorded an additional $1 million in special termination charges for pension benefits.

36

PEC

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2006			2005			2006			2005
Service cost	$	5		$	3		$	1		$	-
Interest cost		14			13			4			5
Expected return on plan assets		(16	)		(14	)		(1	)		(1	)
Amortization of actuarial (gain) loss		2			5			(1	)		3
Other amortization, net		-			-			-			-
Net periodic cost	$	5		$	7		$	3		$	7

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Service cost	$	16		$	17		$	3		$	3
Interest cost		39			40			12			13
Expected return on plan assets		(44	)		(46	)		(3	)		(3	)
Amortization of actuarial loss		8			7			2			3
Other amortization, net		1			1			1			1
Net periodic cost	$	20		$	19		$	15		$	17

In addition, in the second quarter of 2005, PEC recorded special termination benefits related to the voluntary enhanced retirement program of approximately $21 million for pension benefits and $8 million for other postretirement benefits.

PEF

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2006			2005			2006		2005
Service cost	$	4		$	1		$	1	$	-
Interest cost		12			13			3		3
Expected return on plan assets		(21	)		(17	)		-		-
Amortization of actuarial (gain) loss		(1	)		4			-		1
Other amortization, net		-			-			1		1
Net periodic (benefit) cost	$	(6	)	$	1		$	5	$	5

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Service cost	$	12		$	12		$	2		$	3
Interest cost		37			36			10			10
Expected return on plan assets		(58	)		(53	)		(1	)		(1	)
Amortization of actuarial loss		2			6			1			1
Other amortization, net		(1	)		(1	)		3			3
Net periodic (benefit) cost	$	(8	)	$	-		$	15		$	16

37

In addition, in the second quarter of 2005, PEF recorded costs for special termination benefits related to the voluntary enhanced retirement program of approximately $83 million for pension benefits and $7 million for other postretirement benefits. In the third quarter of 2005, PEF recorded an additional $1 million in special termination charges for pension benefits.

10.RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a Risk Management Committee comprised of senior executives from various functional areas. 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 for nonperformance by the counterparty. We minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. Additionally, in the normal course of business, some of our affiliates may enter into hedge transactions with one another, which are eliminated in the consolidated financial statements as appropriate. See Note 18 to the 2005 Form 10-K. The following discussion excludes commodity derivative instruments held by Gas, which was classified as discontinued operations.

A.Commodity Derivatives

GENERAL

Most of our commodity contracts are not derivatives pursuant to SFAS No. 133, “Accounting for Derivative and Hedging Activities” (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 12). At September 30, 2006 and December 31, 2005, the remaining liability was $15 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 according to established policies and guidelines that limit our exposure to market risk and require daily reporting to management of financial exposures.

For the three months and nine months ended September 30, 2006, we recorded pre-tax losses of $30 million and $39 million, respectively. For the three months and nine months ended September 30, 2005, we recorded pre-tax losses of $8 million. Gains and losses from such contracts were not material to the Utilities’ results of operations for the three months and nine months ended September 30, 2006 and 2005. At September 30, 2006, the fair values of these instruments for our nonregulated operations were a $12 million short-term derivative asset position included in other current assets, a $124 million long-term derivative asset position included in other assets and deferred debits, a $27 million short-term derivative liability position included in other current liabilities and a $7 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheet. We did not have material outstanding positions in such contracts at December 31, 2005, other than those at PEF, which are discussed below. See Cash Flow Hedge discussion below regarding dedesignation of derivative contracts covering approximately 95 bcf of natural gas. PEC did not have material outstanding positions in such contracts at September 30, 2006 or December 31, 2005. PEF did not have material outstanding positions in such contracts at September 30, 2006 or December 31, 2005, other than those receiving regulatory accounting treatment, as described below.

38

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, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel adjustment clause. At September 30, 2006, the fair values of these instruments were a $3 million short-term derivative asset position included in other current assets, a $5 million long-term derivative asset position included in other assets and deferred debits, a $45 million short-term derivative liability position included in other current liabilities and a $49 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheets. 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 Sheets.

CASH FLOW HEDGES

We 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 for our forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate.

For the nine months ending September 30, 2006, $7 million in after-tax deferred losses were reclassified to earnings in the second quarter due to discontinuance of the related cash flow hedges in anticipation of the sale of Gas (See Note 3A). During the three months ending September 30, 2006, no amount was reclassified to earnings due to discontinuance of cash flow hedges. Based on the alternative business strategies being pursued and our assessment of the likelihood of divestiture of CCO assets, management determined, as of July 12, 2006, 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. Beginning July 12, 2006, cash flow hedge accounting was discontinued. Unrealized after-tax gains on these contracts recorded in accumulated other comprehensive income/(loss) prior to July 12, 2006 have not been reclassified to earnings. However, if the disposition status of the assets increases to probable then we will evaluate whether the unrealized gains will be reclassified to earnings. The ineffective portion of commodity cash flow hedges for the three months and nine months ended September 30, 2006 and 2005, was not material to our or the Utilities’ results of operations.

The fair values of our commodity cash flow hedges at September 30, 2006 and December 31, 2005, were as follows:

	September 30, 2006							December 31, 2005
(in millions)	Progress Energy			PEC		PEF		Progress Energy			PEC			PEF
Fair value of assets	$	3		$	3	$	-	$	170		$	7		$	-
Fair value of liabilities		(2	)		-		-		(58	)		(4	)		-
Fair value, net	$	1		$	3	$	-	$	112		$	3		$	-

39

The following table presents selected information related to our commodity cash flow hedges at September 30, 2006:

	Maximum Term(a)						Accumulated Other Comprehensive Income/(Loss), net of tax(b)						Portion Expected to be Reclassified to Earnings during the Next 12 Months(c)
(term in years/ dollars in millions )	Progress Energy		PEC		PEF		Progress Energy		PEC		PEF		Progress Energy		PEC		PEF
Commodity cash flow hedges		Less than 1		Less than 1		-	$	77	$	2	$	-	$	1	$	2	$	-

^(a) The majority of hedges in fair value asset positions are currently classified as long-term.

^(b) Includes amounts related to dedesignated and terminated hedges.

^(c) Due to the volatility of the commodities markets, the value in accumulated other comprehensive income/(loss) is subject to change prior to its reclassification into earnings.

At December 31, 2005, we had $69 million of after-tax deferred income and PEC had $2 million in after-tax deferred income recorded in accumulated other comprehensive income/(loss) related to commodity cash flow hedges. PEF had no amount recorded in accumulated other comprehensive income/(loss) related to commodity cash flow hedges.

B.Interest Rate Derivatives - Cash Flow or Fair Value Hedges

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

The fair values of interest rate hedges at September 30, 2006 and December 31, 2005, were as follows:

	September 30, 2006									December 31, 2005
(in millions)	Progress Energy			PEC			PEF			Progress Energy			PEC		PEF
Interest rate cash flow hedges	$	(4	)	$	(2	)	$	(2	)	$	1		$	-	$	-
Interest rate fair value hedges	$	(3	)	$	-		$	-		$	(2	)	$	-	$	-

CASH FLOW HEDGES

Gains and losses from cash flow hedges are recorded in accumulated other comprehensive income/(loss) and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in accumulated other comprehensive income/(loss) related to terminated hedges are reclassified to earnings as the interest expense is recorded. The ineffective portion of interest rate cash flow hedges for the three months and nine months ended September 30, 2006 and 2005, was not material to our or the Utilities’ results of operations.

The following table presents selected information related to interest rate cash flow hedges at September30, 2006:

	Maximum Term						Accumulated Other Comprehensive Income/ (Loss), net of Tax (a)									Portion Expected to be Reclassified to Earnings during the Next 12 Months
(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	$	(15	)	$	(6	)	$	(2	)	$	(2	)	$	(1	)	$	-

^(a) Includes amounts related to terminated hedges.

40

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 fixed rate debt issuances in 2007. These swaps were designated as cash flow hedges as of July 1, 2006.

At December 31, 2005, we had $13 million of after-tax deferred loss and PEC had $5 million in after-tax deferred loss recorded in accumulated other comprehensive income/(loss) related to interest rate cash flow hedges. PEF had no amount recorded in accumulated other comprehensive income/(loss) 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 September30, 2006, and December 31,

2005, we had $150 million notional of interest rate fair value hedges and the Utilities had no open interest rate fair value hedges.

11.FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are: PEC, PEF, Progress Ventures, 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 on the east coast of the United States.

Our Progress Ventures segment is primarily engaged in nonregulated electric generation operations and energy marketing activities.

Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuel (as defined under the Code), the operation of synthetic fuel facilities for third parties, and coal terminal services. On May 22, 2006, we idled our synthetic fuel facilities due to significant uncertainty surrounding synthetic fuel production. In September and October 2006, we resumed limited synthetic fuel production. See Notes 6 and 7 for additional information.

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and Progress Energy Service Company, LLC (PESC) as well as other nonregulated business areas. These nonregulated business areas do not separately meet the disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131). The profit or loss of the identified segments plus the profit or loss of Corporate and Other represents our total income from continuing operations.

Prior to 2006, Gas, DeSoto and Rowan were included within the Progress Ventures segment and PT LLC was included within the Corporate and Other segment. In connection with their divestitures (See Notes 3A, 3B and 3C, respectively), the operations of (i) Gas (ii) DeSoto and Rowan and (iii) PT LLC were reclassified to discontinued operations in the third, second and first quarters of 2006, respectively, and therefore are not included in the results from continuing operations during the periods reported. During the fourth quarter of 2005, we reclassified our coal mining operations as discontinued operations (See Note 3E). Operational results and assets of discontinued operations are not included in the table presented below. For comparative purposes, the prior year results have been restated to conform to the current segment presentation. The cost management initiative 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. The following information is for the three months and nine months ended September 30:

41

											Income (loss)
	Revenues								Cost		from			Assets of
(in millions)	Unaffiliated		Intersegment			Total			Management Initiative		Continuing Operations			Continuing Operations
Three Months Ended September 30, 2006
PEC	$	1,200	$	-		$	1,200		$	-	$	188		$	11,616
PEF		1,399		-			1,399			-		125			8,353
Progress Ventures		137		-			137			-		(40	)		1,131
Coal and Synthetic Fuels		177		88			265			-		9			248
Corporate and Other		-		97			97			-		(39	)		17,558
Eliminations		-		(185	)		(185	)		-		-			(13,233	)
Totals	$	2,913	$	-		$	2,913		$	-	$	243		$	25,673
Three Months Ended September 30, 2005
PEC	$	1,185	$	-		$	1,185		$	-	$	183
PEF		1,227		-			1,227			1		151
Progress Ventures		210		-			210			-		(22	)
Coal and Synthetic Fuels		332		110			442			-		81
Corporate and Other		-		102			102			-		40
Eliminations		-		(212	)		(212	)		-		-
Totals	$	2,954	$	-		$	2,954		$	1	$	433

											Income (loss)
	Revenues								Cost		from			Assets of
(in millions)	Unaffiliated		Intersegment			Total			Management Initiative		Continuing Operations			Continuing Operations
Nine Months Ended September 30, 2006
PEC	$	3,113	$	-		$	3,113		$	-	$	349		$	11,616
PEF		3,553		-			3,553			-		264			8,353
Progress Ventures		422		-			422			-		(111	)		1,131
Coal and Synthetic Fuels		631		250			881			-		(75	)		248
Corporate and Other		-		289			289			-		(154	)		17,558
Eliminations		-		(539	)		(539	)		-		-			(13,233	)
Totals	$	7,719	$	-		$	7,719		$	-	$	273		$	25,673
Nine Months Ended September 30, 2005
PEC	$	2,980	$	-		$	2,980		$	60	$	365
PEF		2,983		-			2,983			108		204
Progress Ventures		404		-			404			2		(34	)
Coal and Synthetic Fuels		910		295			1,205			6		103
Corporate and Other		-		326			326			1		(117	)
Eliminations		-		(621	)		(621	)		-		-
Totals	$	7,277	$	-		$	7,277		$	177	$	521

12.OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income and other income and expense items as discussed below. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities. Allowance for funds used during construction (AFUDC) equity represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets. Contingent value obligations (CVOs) unrealized loss and gain is due to changes in the fair market value of the liability. See Note 15 to the 2005 Form 10-K for more information on CVOs. The FERC audit settlement includes amounts approved by the FERC on May 25, 2005, to settle the FERC Staff’s Audit of compliance with the FERC’s Standard of Conduct and Code of Conduct. The components of other, net as shown on the accompanying Statements of Income were as follows:

42

Progress Energy

	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2006			2005		2006			2005
Other income
Nonregulated energy and delivery services income	$	4		$	3	$	27		$	20
DIG Issue C20 amortization (See Note 10)		2			3		4			6
CVOs unrealized gain		-			4		-			4
Gain on sale of Level 3 stock (a)		-			-		32			-
Investment gains		1			1		3			2
AFUDC equity		6			5		13			14
Income from equity investments		-			4		-			8
Other		5			3		16			15
Total other income		18			23		95			69
Other expense
Nonregulated energy and delivery services expenses		7			7		22			17
Donations		3			3		15			14
CVOs unrealized loss		3			-		25			-
Loss from equity investments		3			5		6			14
FERC audit settlement		-			-		-			7
Indemnification liability (See Note 13)		8			-		13			-
Other		3			4		15			17
Total other expense		27			19		96			69
Other, net - Progress Energy	$	(9	)	$	4	$	(1	)	$	-

^(a)     Other income includes gains of $32 million for the nine months ended September 30, 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 3C). These gains are prior to the consideration of minority interest.

PEC

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Other income
Nonregulated energy and delivery services income	$	(2	)	$	(2	)	$	8		$	7
DIG Issue C20 amortization (See Note 10)		2			3			4			6
AFUDC equity		-			1			2			3
Income from equity investments		-			1			-			-
Other		2			2			6			6
Total other income		2			5			20			22
Other expense
Nonregulated energy and delivery services expenses		2			3			6			7
Donations		1			1			8			6
Loss from equity investments		-			-			1			-
FERC audit settlement		-			-			-			4
Indemnification liability (See Note 13)		8			-			13			-
Other		1			4			4			9
Total other expense		12			8			32			26
Other, net - PEC	$	(10	)	$	( 3	)	$	(12	)	$	(4	)

43

PEF

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2006		2005		2006		2005
Other income
Nonregulated energy and delivery services income	$	6	$	5	$	19	$	14
AFUDC equity		6		4		11		11
Investment gains		-		1		1		2
Other		-		-		1		-
Total other income		12		10		32		27
Other expense
Nonregulated energy and delivery services expenses		5		4		15		9
Donations		1		2		7		8
Loss from equity investments		-		-		1		-
FERC audit settlement		-		-		-		3
Other		-		-		1		1
Total other expense		6		6		24		21
Other, net - PEF	$	6	$	4	$	8	$	6

13.ENVIRONMENTAL MATTERS

We are subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. See Note 22 to the 2005 Form 10-K.

A.Hazardous and Solid Waste Management

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 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. A discussion of sites by legal entity follows below.

We record accruals for probable and estimable costs related to environmental sites on an undiscounted basis. We measure our liability for these sites based on available evidence including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

PEC and PEF filed claims with general liability insurance carriers to recover costs arising from actual or potential environmental liabilities for remediation of certain sites. No material claims are currently pending. We plan to file further claims with respect to sites for which claims were not previously presented.

44

The following table contains information about accruals for environmental remediation expenses described below. At September 30, 2006 and December 31, 2005, accruals for probable and estimable costs related to various environmental sites, which were included in other liabilities and deferred credits were:

Accruals for Environmental Remediation Expenses (in millions)	September 30, 2006		December 31, 2005
PEC
MGP and other sites(a)	$	23	$	7
PEF
Remediation of distribution and substation transformers		48		20
MGP and other sites		18		18
Total PEF environmental remediation accruals(b)		66		38
Progress Energy nonregulated operations		3		3
Total Progress Energy environmental remediation accruals	$	92	$	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 September 30, 2006 and December 31, 2005, the remaining accrual balance was approximately $3 million. Expenditures related to this liability were not material during the three months and nine months ended September 30, 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 14A).

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.

Including the Ward Transformer site and MGP sites discussed below, for the three months ended September 30, 2006, PEC made no additional accruals and spent approximately $1 million, and for the nine months ended September 30, 2006, PEC accrued approximately $21 million and spent approximately $5 million related to environmental remediation. For the three months and nine months ended September 30, 2005, PEC accrued approximately $3 million and spent approximately $1 million and $4 million, respectively, related to environmental remediation. PEC has received orders from the NCUC and SCPSC to defer and amortize certain environmental remediation expenses (See Note 4A).

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 reasonably estimate the amount of PEC’s share of the reimbursement for remediation of the Carolina Transformer site. PEC may file claims with respect to this 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

45

the site. In September 2005, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the site. In 2005, PEC accrued approximately $3 million for its portion of the EPA’s estimated remediation costs and the EPA's past costs. In March 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 September 30, 2006, to date expenditures for the site were approximately $3 million. Actual experience may differ from current estimates and it is probable that estimates will continue to change in the future. PEC plans to file claims with respect to this site. The outcome of this matter cannot be predicted.

In March 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.

On March 30, 2005, the North Carolina Division of Water Quality (NCDWQ) renewed a PEC permit for the continued use of coal combustion products generated at any of its coal-fired plants located in the state. PEC appealed the permit conditions, which could have significantly restricted the reuse of coal ash, resulting in higher ash management costs. Subsequently, based on comments from PEC, the permit was revised, and the appeal was withdrawn on July 11, 2006.

PEF

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). Under agreements with the Florida Department of Environmental Protection (FDEP), 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 review of distribution transformer sites, PEF currently expects to have completed its 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 three months and nine months ended September 30, 2006, PEF accrued approximately $1 million and $40 million, respectively, due to additional sites expected to require remediation and spent approximately $6 million and $12 million, respectively, related to the remediation of transformers. For the three months and nine months ended September 30, 2005, PEF accrued approximately $1 million and spent approximately $2 million and $7 million, respectively, related to the remediation of transformer sites. PEF records a regulatory asset for the probable recovery of these costs through the ECRC.

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 three months and nine months ended September 30, 2006 and 2005, accruals, expenditures and insurance proceeds received were not material to PEF’s results of operations, financial position, or cash flows.

B.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. Significant updates to these laws and regulations and related impacts to us since December 31, 2005, are discussed below. Additionally, Congress is considering legislation that would require additional reductions in air emissions of nitrogen oxide (NOx), sulfur dioxide (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, the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule (CAMR) and the Clean Air Visibility Rule (CAVR), which are discussed below, may address some of the issues outlined above. CAVR requires the installation of best available retrofit technology (BART). However, the outcome of this matter cannot be predicted.

46

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 pass-through 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 September 30, 2006
NOx SIP Call		2002-2006	$	355	$	346
Clean Smokestacks Act		2002-2013		1,000 - 1,400		466
CAIR/CAMR/CAVR(a)		2005-2018		970 - 1,930		13
Total air quality				2,325 - 3,685		825
Clean Water Act Section 316(b)		2005-2010		60 - 90		1
North Carolina Groundwater Standard(b)				-		-
Total water quality				60 - 90		1
Total air and water quality			$	2,385 - $3,775	$	826

PEC

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2006
NOx SIP Call		2002-2006	$	355	$	346
Clean Smokestacks Act		2002-2013		1,000 - 1,400		466
CAIR/CAMR/CAVR		2005-2018		170 - 330		1
Total air quality				1,525 - 2,085		813
Clean Water Act Section 316(b)		2005-2010		5 - 10		-
North Carolina Groundwater Standard(b)				-		-
Total water quality				5 - 10		-
Total air and water quality			$	1,530 - $2,095	$	813

PEF

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2006
CAIR/CAMR/CAVR(a)		2005-2018	$	800 - $1,600	$	12
Clean Water Act Section 316(b)		2005-2010		55 - 80		1
Total air and water quality			$	855 - $1,680	$	13

^(a)   Includes current estimates for the series of compliance alternatives filed by PEF with the FPSC as discussed below.

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

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

47

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 Court of Appeals for the District of Columbia Circuit set aside the EPA’s 2003 New Source Review 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.

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.

Parties unaffiliated with us have undertaken efforts to have Georgia excluded from the rule and its requirements. Georgia has not yet submitted a state implementation plan to comply with the NOx SIP Call. The outcome of this matter and the impact on our nonregulated operations in Georgia cannot be predicted.

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 plans to install 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 of approximately $1.1 billion to $1.4 billion by the end of 2013. 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.

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 rate freeze period. PEC recognized amortization of $21 million and $65 million, respectively, for the three months and nine months ended September 30, 2006, and has recognized $460 million in cumulative amortization through September 30, 2006. PEC recognized amortization of $26 million and $80 million, respectively, for the three months and nine months ended September 30, 2005. The remaining amortization requirement of $109 million will be recorded over the 15-month 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. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods.

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

48

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 their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act to approximately $38 million. PEC records a related liability for the joint owner's share of estimated costs in excess of the contract amount. At December 31, 2005, the amount of the liability was $16 million and increased to $29 million at September 30, 2006, based upon the respective current estimates for Clean Smokestacks Act compliance. Because PEC has taken a system-wide 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. PEC has 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. The outcome of this matter cannot be predicted.

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 out 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. O&M expenses will significantly increase due to the additional personnel, materials and general maintenance associated with the equipment. O&M expenses are recoverable through base rates, rather than as part of this program. 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 (MACT) 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. States are required to adopt mercury rules implementing the CAMR by November 17, 2006, which must be reviewed and approved by the EPA. At September 30, 2006, of the three states in which the Utilities operate, Florida and North Carolina had formally proposed mercury regulations.North Carolina's proposed rule would adopt the EPA’s cap-and-trade approach and would require the addition of mercury controls on certain of PEC's North Carolina units that do not have scrubbers by 2023. 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.Formal rulemaking in South Carolina is expected to occur in the fall of 2006. The outcome of this matter cannot be

49

predicted. 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.

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. 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 to take effect 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 the 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 on 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.

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 required by the 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. We expect this matter to be addressed during the FPSC hearings in November 2006, but cannot predict whether this proposed compliance plan, or another compliance plan, will be approved by the FPSC. These costs may continue to change depending upon the results of the engineering and strategy development work, increases in the underlying material, labor and equipment costs, and FPSC approval of the final compliance plan. 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.

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.

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

50

announced that it is finalizing the PM 2.5 NAAQS as proposed. In addition, 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 any additional nonattainment areas in PEC’s or PEF’s service territories.

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 requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. The rule requires us to assess the environmental effect of withdrawal of water at our facilities and may require us to install additional intake screens or other protective measures. The timing and extent of estimated costs may change depending upon the final compliance strategy.

3. North Carolina Groundwater Standard

On September 14, 2006, 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 by-products, and other coal combustion by-products. The specific requirements of the rule as finally adopted and associated costs, if any, cannot be predicted.

C.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 has stated it favors voluntary programs. There are proposals 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 customers. 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, a three-judge panel of 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. In a 2-1 decision, the court held that the EPA administrator properly exercised his discretion in denying the request for regulation. Officials from five states and the District of Columbia asked the full U.S. Court of Appeals for the D.C. Circuit to review the decision made by the three-judge panel. The U.S. Court of Appeals denied the request for rehearing and 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 has been scheduled for 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

51

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.

14.COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 23 to the 2005 Form 10-K are described below.

A.Guarantees

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45). Such agreements include guarantees, standby letters of credit and surety bonds. At September 30, 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 September 30, 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 fuel 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 13B). PEC’s maximum exposure cannot be determined. At September 30, 2006, the maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $208 million, including $32 million at PEF. At September 30, 2006 and December 31, 2005, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $66 million and $41 million, respectively. These amounts include $29 million and $16 million, respectively, for PEC at September 30, 2006 and December 31, 2005, and $8 million for PEF at September 30, 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 15 for additional information.

B.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 United States Department of Energy (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

52

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 plans to issue a new safety standard for the repository by 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 not be submitted until after September 2007. Congress approved $450 million for fiscal year 2006 for the Yucca Mountain project, approximately $201 million less than requested by the DOE. The DOE has stated that if legislative changes requested by the Bush administration are enacted, the repository will be able to accept spent nuclear fuel starting in 2017. The Utilities cannot predict the outcome of this matter.

With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at Robinson Nuclear Plant (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 all of their nuclear generating units.

2.Synthetic Fuel Matters

On May 15, 2005, the original owners of the Earthco synthetic fuel facilities filed suit in New York state court alleging breach of contract against the Progress Fuels subsidiaries that purchased the Earthco facilities (Progress Fuels Subsidiaries). The plaintiffs also named us as a defendant. The plaintiffs’ position in the lawsuit was that periodic payments otherwise due to them under the sales arrangement with the Progress Fuels Subsidiaries were, contrary to the sales agreement, being escrowed pending the outcome of the Internal Revenue Service (IRS) audit of the Earthco facilities. The Progress Fuels Subsidiaries believed that the parties’ agreements allowed for the payments to be escrowed in such event and also allowed for the use of such escrowed amounts to satisfy any potential disallowance of tax credits that could have arisen out of such an event. The escrowed amount in question was $103 million, which reflected periodic payments that would have been paid to the plaintiffs beginning April 30, 2003 through May 18, 2006. In light of the successful outcome of the IRS audit of the Earthco facilities, the parties agreed to resolve the case. The Progress Fuels Subsidiaries paid the plaintiffs the funds held in escrow in exchange for a release of claims and dismissal of the lawsuit, which occurred on May 18, 2006. The case is now resolved and dismissed.

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), Earthco, certain affiliates of Earthco (collectively the Earthco Sellers), 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 fuel facilities currently

53

owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuel facilities, (2) it is entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuel facilities, and (3) it is entitled to immediate payment of tonnage fees held in escrow (this claim is identical to the position taken by Earthco as described above).

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, Florida, 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.

We have escrowed $42 million that otherwise would have been paid to Global through September 30, 2006. These funds are being escrowed on the same basis as the funds that were escrowed for the original owners of the Earthco facilities, as discussed above. We are in discussion with Global regarding the terms under which the funds might be released, given the successful resolution of the IRS audit of the Earthco facilities.

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.

15.CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 24 to the 2005 Form 10-K, we have guaranteed certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.) since September 2005. 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 Corporation (Florida Progress). Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 12B to the 2005 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a special-purpose entity and was deconsolidated in 2003 in accordance with the provisions of FIN No. 46. 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.

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 these condensed consolidating statements, 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 non-guarantor

54

subsidiaries and elimination entries for all intercompany transactions. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities. The accompanying condensed consolidating financial statements have been restated for all periods presented to reflect the operations of Gas, the coal mines, PT LLC, DeSoto, Rowan, Dixie Fuels and other fuels businesses as discontinued operations as described in Note 3.

Condensed Consolidating Statement of Income Three Months Ended September 30, 2006
(in millions)	Parent			Subsidiary Guarantor		Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,399	$	1,200		$	2,599
Diversified business		−			175		139			314
Total operating revenues		−			1,574		1,339			2,913
Operating expenses
Utility
Fuel used in electric generation		−			538		322			860
Purchased power		−			256		135			391
Operation and maintenance		3			171		209			383
Depreciation and amortization		−			108		135			243
Taxes other than on income		−			89		52			141
Diversified business
Cost of sales		−			187		183			370
Depreciation and amortization		−			2		10			12
Other		−			7		8			15
Total operating expenses		3			1,358		1,054			2,415
Operating (loss) income		(3	)		216		285			498
Other income (expense), net		7			9		(12	)		4
Interest charges, net		70			47		39			156
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(66	)		178		234			346
Income tax (benefit) expense		(14	)		60		60			106
Equity in earnings of consolidated subsidiaries		371			−		(371	)		−
Minority interest in subsidiaries’ loss, net of tax		−			3		−			3
Income (loss) from continuing operations		319			121		(197	)		243
Discontinued operations, net of tax		−			59		17			76
Net income (loss)	$	319		$	180	$	(180	)	$	319

55

Condensed Consolidating Statement of Income Three Months Ended September 30, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,227		$	1,185		$	2,412
Diversified business		−			340			202			542
Total operating revenues		−			1,567			1,387			2,954
Operating expenses
Utility
Fuel used in electric generation		−			351			282			633
Purchased power		−			270			154			424
Operation and maintenance		2			181			225			408
Depreciation and amortization		−			95			137			232
Taxes other than on income		−			82			49			131
Other		−			1			(8	)		(7	)
Diversified business
Cost of sales		−			335			250			585
Depreciation and amortization		−			5			16			21
Other		−			13			4			17
Total operating expenses		2			1,333			1,109			2,444
Operating (loss) income		(2	)		234			278			510
Other income (expense), net		15			(1	)		(7	)		7
Interest charges, net		70			36			50			156
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(57	)		197			221			361
Income tax benefit		13			44			8			65
Equity in earnings of consolidated subsidiaries		494			−			(494	)		−
Minority interest in subsidiaries’ loss, net of tax		−			7			−			7
Income (loss) from continuing operations		450			248			(265	)		433
Discontinued operations, net of tax		−			9			7			16
Cumulative effect of changes in accounting principles, net of tax		−			−			1			1
Net income (loss)	$	450		$	257		$	(257	)	$	450

56

Condensed Consolidating Statement of Income Nine Months Ended September 30, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	3,553		$	3,113		$	6,666
Diversified business		−			628			425			1,053
Total operating revenues		−			4,181			3,538			7,719
Operating expenses
Utility
Fuel used in electric generation		−			1,379			880			2,259
Purchased power		−			601			279			880
Operation and maintenance		10			515			691			1,216
Depreciation and amortization		−			301			404			705
Taxes other than on income		−			238			142			380
Other		−			(2	)		−			(2	)
Diversified business
Cost of sales		−			645			499			1,144
Depreciation and amortization		−			11			40			51
Impairment of assets		−			44			111			155
Other		−			27			28			55
Total operating expenses		10			3,759			3,074			6,843
Operating (loss) income		(10	)		422			464			876
Other income (expense), net		9			47			(20	)		36
Interest charges, net		216			142			136			494
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(217	)		327			308			418
Income tax (benefit) expense		(73	)		107			101			135
Equity in earnings of consolidated subsidiaries		461			−			(461	)		−
Minority interest in subsidiaries’ income, net of tax		−			10			−			10
Income (loss) from continuing operations		317			210			(254	)		273
Discontinued operations, net of tax		−			86			(42	)		44
Net income (loss)	$	317		$	296		$	(296	)	$	317

57

Condensed Consolidating Statement of Income Nine Months Ended September 30, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	2,983		$	2,980		$	5,963
Diversified business		−			924			390			1,314
Total operating revenues		−			3,907			3,370			7,277
Operating expenses
Utility
Fuel used in electric generation		−			966			746			1,712
Purchased power		−			545			294			839
Operation and maintenance		11			658			688			1,357
Depreciation and amortization		−			236			411			647
Taxes other than on income		4			215			137			356
Other		−			(24	)		(8	)		(32	)
Diversified business
Cost of sales		−			947			471			1,418
Depreciation and amortization		−			16			43			59
Other		−			42			23			65
Total operating expenses		15			3,601			2,805			6,421
Operating (loss) income		(15	)		306			565			856
Other income (expense), net		49			(6	)		(32	)		11
Interest charges, net		225			121			125			471
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(191	)		179			408			396
Income tax (benefit) expense		(51	)		(68	)		18			(101	)
Equity in earnings of consolidated subsidiaries		682			−			(682	)		−
Minority interest in subsidiaries’ loss, net of tax		−			24			−			24
Income (loss) from continuing operations		542			271			(292	)		521
Discontinued operations, net of tax		−			(3	)		23			20
Cumulative effect of changes in accounting principles, net of tax		−			−			1			1
Net income (loss)	$	542		$	268		$	(268	)	$	542

58

Condensed Consolidating Balance Sheet September 30, 2006
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−	$	6,094	$	8,714		$	14,808
Current assets
Cash and cash equivalents		152		47		136			335
Short-term investments		201		−		132			333
Notes receivables from affiliated companies		219		5		(224	)		−
Deferred fuel cost		−		97		207			304
Assets of discontinued operations		−		724		(17	)		707
Other current assets		21		1,190		1,067			2,278
Total current assets		593		2,063		1,301			3,957
Deferred debits and other assets
Investment in consolidated subsidiaries		11,308		−		(11,308	)		−
Goodwill		−		2		3,653			3,655
Other assets and deferred debits		259		1,458		2,243			3,960
Total deferred debits and other assets		11,567		1,460		(5,412	)		7,615
Total assets	$	12,160	$	9,617	$	4,603		$	26,380
Capitalization
Common stock equity	$	8,021	$	3,146	$	(3,146	)	$	8,021
Preferred stock of subsidiaries - not subject to mandatory redemption		−		34		59			93
Minority interest		−		12		3			15
Long-term debt, affiliate		−		440		(169	)		271
Long-term debt, net		3,523		2,550		3,469			9,542
Total capitalization		11,544		6,182		216			17,942
Current liabilities
Current portion of long-term debt		351		149		200			700
Notes payable to affiliated companies		−		186		(186	)		−
Liabilities of discontinued operations		−		173		(2	)		171
Other current liabilities		218		997		905			2,120
Total current liabilities		569		1,505		917			2,991
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		−		218			218
Regulatory liabilities		−		1,065		1,367			2,432
Accrued pension and other benefits		13		313		581			907
Other liabilities and deferred credits		34		552		1,304			1,890
Total deferred credits and other liabilities		47		1,930		3,470			5,447
Total capitalization and liabilities	$	12,160	$	9,617	$	4,603		$	26,380

59

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 receivables from affiliated companies		467		−		(467	)		−
Deferred fuel cost		−		341		261			602
Assets of discontinued operations		−		757		515			1,272
Other current assets		22		992		1,133			2,147
Total current assets		728		2,329		1,760			4,817
Deferred debits and other assets
Investment in consolidated subsidiaries		11,594		−		(11,594	)		−
Goodwill		−		2		3,717			3,719
Other assets and deferred debits		259		1,561		2,216			4,036
Total deferred debits and other assets		11,853		1,563		(5,661	)		7,755
Total assets	$	12,581	$	9,713	$	4,720		$	27,014
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 obligations		−		102		73			175
Liabilities of discontinued operations		−		226		(28	)		198
Other current liabilities		245		762		1,046			2,053
Total current liabilities		649		1,514		776			2,939
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		−		228			228
Regulatory liabilities		−		1,189		1,338			2,527
Accrued pension and other benefits		12		307		551			870
Other liabilities and deferred credits		9		523		1,305			1,837
Total deferred credits and other liabilities		21		2,019		3,422			5,462
Total capitalization and liabilities	$	12,581	$	9,713	$	4,720		$	27,014

60

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	376		$	728		$	390		$	1,494
Investing activities
Gross utility property additions		−			(519	)		(493	)		(1,012	)
Diversified business property additions		−			(1	)		−			(1	)
Nuclear fuel additions		−			(6	)		(65	)		(71	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			134			414			548
Purchases of available-for-sale securities and other investments		(392	)		(547	)		(748	)		(1,687	)
Proceeds from sales of available-for-sale securities and other investments		191			646			774			1,611
Changes in advances to affiliates		248			(7	)		(241	)		−
Return of investment in consolidated subsidiary		287			−			(287	)		−
Other investing activities		(5	)		(3	)		(8	)		(16	)
Net cash provided (used) by investing activities		329			(303	)		(654	)		(628	)
Financing activities
Issuance of common stock		73			−			−			73
Proceeds from issuance of long-term debt, net		397			−			−			397
Net decrease in short-term indebtedness		−			(102	)		(73	)		(175	)
Retirement of long-term debt		(801	)		(47	)		−			(848	)
Dividends paid on common stock		(454	)		−			−			(454	)
Dividends paid to parent		−			(222	)		222			−
Cash distributions to minority interests of consolidated subsidiary		−			(74	)		−			(74	)
Changes in advances from affiliates		−			(132	)		132			−
Other financing activities		(7	)		9			(44	)		(42	)
Net cash (used ) provided by financing activities		(792	)		(568	)		237			(1,123	)
Cash provided (used) by discontinued operations
Operating activities		−			94			36			130
Investing activities		−			(143	)		−			(143	)
Financing activities		−			−			−			−
Net (decrease) increase in cash and cash equivalents		(87	)		(192	)		9			(270	)
Cash and cash equivalents at beginning of period		239			239			127			605
Cash and cash equivalents at end of period	$	152		$	47		$	136		$	335

61

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	168		$	251		$	392		$	811
Investing activities
Gross utility property additions		−			(336	)		(436	)		(772	)
Diversified business property additions		−			(2	)		(18	)		(20	)
Nuclear fuel additions		−			(46	)		(52	)		(98	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			449			9			458
Purchases of available-for-sale securities and other investments		(1,702	)		(241	)		(1,535	)		(3,478	)
Proceeds from sales of available-for-sale securities and other investments		1,702			241			1,591			3,534
Changes in advances to affiliates		127			1			(128	)		−
Proceeds from repayment of long-term affiliate debt		369			−			(369	)		−
Other investing activities		(11	)		(20	)		(1	)		(32	)
Net cash provided (used) by investing activities		485			46			(939	)		(408	)
Financing activities
Issuance of common stock		193			−			−			193
Proceeds from issuance of long-term debt, net		−			297			495			792
Net decrease in short-term indebtedness		(132	)		(1	)		(34	)		(167	)
Retirement of long-term debt		(160	)		(101	)		(301	)		(562	)
Retirement of long-term affiliate debt		−			(369	)		369			−
Dividends paid on common stock		(435	)		−			−			(435	)
Changes in advances from affiliates		−			(45	)		45			−
Other financing activities		(9	)		28			(36	)		(17	)
Net cash (used) provided by financing activities		(543	)		(191	)		538			(196	)
Cash provided (used) by discontinued operations
Operating activities		−			57			37			94
Investing activities		−			(154	)		(1	)		(155	)
Financing activities		−			−			−			−
Net increase in cash and cash equivalents		110			9			27			146
Cash and cash equivalents at beginning of period		5			23			27			55
Cash and cash equivalents at end of period	$	115		$	32		$	54		$	201

62

Item 2.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 “SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS” and Item 1A, “Risk Factors” of Part II herein and the “Risk Factors” section of our 2005 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

Amounts reported in the interim statements of income are not necessarily indicative of amounts expected for the respective annual or future periods due to the effects of seasonal temperature variations on energy consumption and the timing of maintenance on electric generating units, among other factors.

This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2005 Form 10-K.

RESULTS OF OPERATIONS

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;

·     Progress Ventures - primarily engaged in nonregulated electric generation operations and energy marketing activities in Georgia; 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 fuel facilities for third parties in West Virginia, and coal terminal services in Kentucky and West Virginia. On May 22, 2006, we idled production at our synthetic fuel plants due to significant uncertainty surrounding future synthetic fuel production. Following a significant decrease in oil prices, we resumed limited production at our synthetic fuel facilities in September and October 2006 (See Notes 6 and 7 for additional information).

The Corporate and Other segment includes businesses which do not meet the requirements for separate segment reporting disclosure. These businesses are engaged in other nonregulated business areas including holding company operations and Progress Energy Service Company, LLC (PESC) operations.

In 2005, we changed our reportable segments due to changes in the operations of certain businesses and the reclassification of our coal mining business as discontinued operations. In addition, due to our divestitures in 2006, we reclassified Progress Telecom, LLC’s (PT LLC) operations as discontinued operations in the first quarter of 2006, we reclassified DeSoto and Rowan generating facilities’ operations previously included in Progress Ventures, as discontinued operations in the second quarter of 2006 and we reclassified our natural gas drilling and production operations (Gas) and our Dixie Fuels Limited (Dixie Fuels) and other fuels businesses as discontinued operations in the third quarter of 2006. These reportable segment changes reflect the current reporting structure. For comparative purposes, prior year results have been restated to conform to the current presentation. In this section, earnings and the factors affecting earnings for the three months and nine months ended September 30, 2006 are compared to the same periods in 2005. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

63

OVERVIEW

For the quarter ended September 30, 2006, our net income was $319 million, or $1.27 per share, compared to net income of $450 million, or $1.82 per share, for the same period in 2005. The decrease in net income as compared to prior year was due primarily to:

·     The impact of tax levelization. Accounting principles generally accepted in the United States (GAAP) require companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate.

·     Lower tax credits due to lower synthetic fuel production and higher oil prices in 2006 and tax credit adjustments in 2005.

·     Unfavorable weather at the Utilities.

·     The impact of mark-to-market losses resulting from the discontinuance of cash flow hedge accounting for certain natural gas contracts.

Partially offsetting these items were:

·     Favorable results in Gas operations which are classified as discontinued operations.

·     Favorable operation and maintenance (O&M) expense at the Utilities.

·     Favorable retail growth and usage at the Utilities.

For the nine months ended September 30, 2006, our net income was $317 million, or $1.27 per share, compared to net income of $542 million, or $2.20 per share, for the same period in 2005. The decrease in net income as compared to prior year was due primarily to:

·     Lower tax credits primarily due to lower synthetic fuel production and higher oil prices.

·     The loss on sale of two of our nonregulated plants and the associated valuation allowance recorded against the deferred tax assets for state net operating loss carry forwards.

·     Impairment of our synthetic fuel assets and a portion of our coal terminal assets primarily due to continued high oil prices.

·     Impairment of goodwill related to our nonregulated plants in Georgia.

·     The impact of tax levelization.

·     Unrealized losses recorded on contingent value obligations.

·     Unfavorable weather at the Utilities.

·     Increased nuclear outage expenses at PEC.

·     The impact of mark-to-market losses resulting from the discontinuance of cash flow hedge accounting for certain natural gas contracts.

·     Prior year gain on the sale of our Winter Park distribution assets.

·     Increased estimated environmental remediation expenses at PEC.

Partially offsetting these items were:

·    Prior year postretirement and severance expenses related to the 2005 cost-management initiative.

·    Favorable results in Gas operations which are classified as discontinued operations.

·    Gain on sale of PT LLC.

·    Increased wholesale margin at PEC.

·    Gain on sale of Level 3 stock acquired as part of the divestiture of PT LLC.

·    Favorable retail growth and usage at the Utilities.

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

·    The impact of restructuring a long-term coal supply contract at Coal and Synthetic Fuels.

64

Our segments contributed the following profits or losses for the three months and nine months ended September 30, 2006 and 2005:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Business Segment
PEC	$	188		$	183		$	349		$	365
PEF		125			151			264			204
Progress Ventures		(40	)		(22	)		(111	)		(34	)
Coal and synthetic fuels		9			81			(75	)		103
Total segment profit		282			393			427			638
Corporate and Other		(39	)		40			(154	)		(117	)
Income from continuing operations		243			433			273			521
Discontinued operations, net of tax		76			16			44			20
Cumulative effect of changes in accounting principles		-			1			-			1
Net income	$	319		$	450		$	317		$	542

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $188 million and $183 million for the three months ended September 30, 2006 and 2005, respectively. The increase in profits for the three months ended September 30, 2006, when compared to the same period in 2005, was primarily due to favorable retail growth and usage, lower interest expense and lower O&M expenses partially offset by unfavorable weather.

PEC contributed segment profits of $349 million and $365 million for the nine months ended September 30, 2006 and 2005, respectively. The decrease in profits for the nine months ended September 30, 2006, when compared to the same period in 2005, was primarily due to unfavorable weather, higher O&M expenses related to outages at nuclear facilities, increased estimated environmental remediation expenses and the impact of suspending allocation of the Parent’s income tax benefit. 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, favorable wholesale margin and favorable retail customer growth and usage.

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

REVENUES

PEC’s electric revenues for the three months ended September 30, 2006 and 2005, and the percentage change by customer class were as follows:

(in millions)	Three Months Ended September 30,
Customer Class	2006			Change			% Change			2005
Residential	$	458		$	5			1.1		$	453
Commercial		297			16			5.7			281
Industrial		198			(1	)		(0.5	)		199
Governmental		28			2			7.7			26
Total retail revenues		981			22			2.3			959
Wholesale		205			(13	)		(6.0	)		218
Unbilled		(9	)		8			-			(17	)
Miscellaneous		23			(2	)		(8.0	)		25
Total electric revenues		1,200			15			1.3			1,185
Less: Fuel revenues		(392	)		(25	)		-			(367	)
Revenues excluding fuel	$	808		$	(10	)		(1.2	)	$	818

65

PEC’s energy sales for the three months ended September 30, 2006 and 2005, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2006			Change			% Change			2005
Residential		4,886			(172	)		(3.4	)		5,058
Commercial		3,975			(33	)		(0.8	)		4,008
Industrial		3,317			(164	)		(4.7	)		3,481
Governmental		427			6			1.4			421
Total retail energy sales		12,605			(363	)		(2.8	)		12,968
Wholesale		3,974			(382	)		(8.8	)		4,356
Unbilled		(248	)		268			-			(516	)
Total kWh sales		16,331			(477	)		(2.8	)		16,808

PEC’s electric revenues, excluding fuel revenues of $392 million and $367 million for the three months ended September 30, 2006 and 2005, respectively, decreased $10 million. The decrease in revenues is attributable primarily to unfavorable retail weather of $31 million, with cooling degree days 16 percent less than the prior year. This was partially offset by increased retail growth and usage and wholesale revenues less fuel. The increase in retail growth and usage of $13 million was driven by an approximate increase in the average number of customers of 28,000 as of September 30, 2006, compared to September 30, 2005. The increase in wholesale revenues less fuel of $6 million was driven primarily by decreased fuel costs related to Hurricanes Katrina and Rita impacting prior year.

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 $457 million for the three months ended September 30, 2006, which represents a $21 million increase compared to the same period in the prior year. Fuel used in electric generation increased $40 million to $322 million compared to the prior year. This increase is due to an increase in deferred fuel expense of $59 million driven by an increase in the fuel recovery rates for North Carolina and South Carolina. This was partially offset by a $20 million decrease in fuel. Fuel used in generation also decreased due to lower system requirements and a change in generation mix, as a greater percentage of generation during the three months ended September 30, 2006 was provided by nuclear relative to coal and gas, partially offset by higher fuel costs resulting from higher delivered coal costs. Current year purchased power costs were $19 million lower than the three months ended September 30, 2005, primarily due to lower system requirements and lower market prices in the third quarter of 2006.

Operation and Maintenance

O&M expenses were $218 million for the three months ended September 30, 2006, which represents a $17 million decrease compared to the same period in 2005. O&M expenses decreased $6 million due to lower outage costs at nuclear facilities, $4 million related to lower pension expenses due to revised actuarial estimates during 2006, $3 million of lower estimated environmental costs, $2 million of lower storm related costs and $2 million of postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative. These were partially offset by certain capital project write-offs of $6 million.

Other

Other had no material transactions for the three months ended September 30, 2006. The $8 million gain for the three months ended September 30, 2005 was primarily due to land sales.

66

Total Other (Expense) Income

Total other expense of $3 million increased $2 million compared to the three months ended September 30, 2005 primarily due to a $8 million increase in the indemnification liability recorded for estimated capital costs associated with the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) expected to be incurred in excess of the maximum billable costs to the joint owner (See Note 13B) partially offset by a $6 million increase in interest income related to temporary investments and under-recovered fuel costs.

Total Interest Charges, net

Total interest charges, net decreased $14 million for the three months ended September 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to a $22 million variance in the impact of tax matters, partially offset by the impact of a net increase in long-term debt and higher interest rates on variable rate pollution control bonds.

Income Tax Expense

Income tax expense increased $10 million for the three months ended September 30, 2006, as compared to the same period in the prior year, primarily due to the impact of higher earnings compared to prior year. Income tax expense also increased due to the allocation of $5 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 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. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEC’s income tax expense was increased by $1 million for the three months ended September 30, 2006 compared to an increase of $3 million for the three months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

REVENUES

PEC’s electric revenues for the nine months ended September 30, 2006 and 2005, and the percentage change by customer class were as follows:

(in millions)	Nine Months Ended September 30,
Customer Class	2006			Change			% Change		2005
Residential	$	1,133		$	34			3.1	$	1,099
Commercial		759			50			7.1		709
Industrial		534			22			4.3		512
Governmental		69			5			7.8		64
Total retail revenues		2,495			111			4.7		2,384
Wholesale		564			18			3.3		546
Unbilled		(21	)		(1	)		-		(20	)
Miscellaneous		75			5			7.1		70
Total electric revenues		3,113			133			4.5		2,980
Less: Fuel revenues		(1,004	)		(125	)		-		(879	)
Revenues excluding fuel	$	2,109		$	8			0.4	$	2,101

67

PEC’s energy sales for the nine months ended September 30, 2006 and 2005, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2006			Change			% Change			2005
Residential		12,741			(274	)		(2.1	)		13,015
Commercial		10,245			70			0.7			10,175
Industrial		9,389			(252	)		(2.6	)		9,641
Governmental		1,080			17			1.6			1,063
Total retail energy sales		33,455			(439	)		(1.3	)		33,894
Wholesale		11,260			(375	)		(3.2	)		11,635
Unbilled		(395	)		188			-			(583	)
Total kWh sales		44,320			(626	)		(1.4	)		44,946

PEC’s electric revenues, excluding fuel revenues of $1.004 billion and $879 million for the nine months ended September 30, 2006 and 2005, respectively, increased $8 million. The increase in revenues is attributable primarily to increased wholesale revenues less fuel and increased retail growth and usage, partially offset by unfavorable weather. The increase in wholesale revenues less fuel of $34 million was driven primarily by the impact of increased capacity under contract, higher excess generation sales due to favorable market conditions and gains on forward sales of excess generation. The increase in retail growth and usage of $19 million was driven by an approximate increase in the average number of customers of 29,000 as of September 30, 2006, compared to September 30, 2005. The impact of unfavorable weather was $43 million with cooling degree days 7 percent below the prior year and heating degree days 11 percent below the prior year.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.159 billion for the nine months ended September 30, 2006, which represents a $119 million increase compared to the same period in the prior year. Fuel used in electric generation increased $134 million to $880 million compared to the prior year. This increase is due to a $105 million increase in deferred fuel expense due to an increase in the fuel recovery rates for North Carolina and South Carolina. In addition, fuel used in generation increased $28 million due primarily to higher fuel costs which are being driven by higher delivered coal costs partially offset by lower system requirements and a change in generation mix, as generation shifted from higher priced gas to coal. Current year purchased power costs were $15 million lower than the nine months ended September 30, 2005, primarily due to lower system requirements partially offset by an increase in price.

Operation and Maintenance

O&M expenses were $722 million for the nine months ended September 30, 2006, which represents a $3 million increase compared to the same period in 2005. O&M expenses increased $40 million due to outages at nuclear facilities and $18 million due to increased estimated environmental remediation expenses (See Note 13A), and capital project write-offs of $15 million. These were partially offset by $61 million of postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative and $6 million due to lower outage costs at fossil facilities.

Depreciation and Amortization

Depreciation and amortization expense was $383 million for the nine months ended September 30, 2006, which represents a $6 million decrease compared to the same period in 2005. Depreciation expense decreased $15 million due to lower Clean Smokestacks Act amortization, partially offset by the impact of an increase in the depreciable base.

68

Other

Other had no material transactions for the nine months ended September 30, 2006. The $8 million gain for the nine months ended September 30, 2005 was primarily due to land sales.

Total Other (Expense) Income

Total other income of $6 million increased $5 million compared to the nine months ended September 30, 2005 primarily due to a $13 million increase in interest income related to temporary investments and under-recovered fuel costs and a $4 million expense related to a FERC Code of Conduct audit settlement recorded in the prior year partially offset by a $13 million increase in the indemnification liability recorded 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 (See Note 13B).

Total Interest Charges, net

Total interest charges, net of $157 million for the nine months ended September 30, 2006 were flat compared to the same period in the prior year. This is due primarily to a $22 million variance in the impact of tax matters, offset by the $16 million impact of a net increase in long-term debt and $5 million due to higher interest rates on variable rate pollution control bonds.

Income Tax Expense

Income tax expense increased $26 million for the nine months ended September 30, 2006, as compared to the same period in the prior year, primarily due to the allocation of $16 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 that is no longer allocated in 2006, $7 million benefit related to an income tax matter recorded in 2005 and the $3 million impact of a 2005 tax benefit related to state audit settlements. See Corporate and Other below for additional information on the change in the tax benefit allocation in 2006. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEC’s income tax expense was not materially increased for the nine months ended September 30, 2006 compared to an increase of $6 million for the nine months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $125 million and $151 million for the three months ended September 30, 2006 and 2005, respectively. The decrease in profits for the three months ended September 30, 2006, when compared to the same period in 2005, was primarily due to unfavorable weather, unfavorable tax adjustments and higher interest expense.

PEF contributed segment profits of $264 million and $204 million for the nine months ended September 30, 2006 and 2005, respectively. The increase in profits for the nine months ended September 30, 2006, when compared to the same period in 2005, was primarily due to lower O&M expenses, which included postretirement and severance expenses and the write-off of unrecoverable storm costs in 2005 and favorable retail margin partially offset by the gain on sale of utility distribution assets in the prior year and higher interest expense.

69

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

REVENUES

PEF’s revenues for the three months ended September 30, 2006 and 2005, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended September 30,
Customer Class	2006			Change			% Change			2005
Residential	$	754		$	94			14.2		$	660
Commercial		334			51			18.0			283
Industrial		90			13			16.9			77
Governmental		83			15			22.1			68
Retail revenue sharing		-			2			-			(2	)
Total retail revenues		1,261			175			16.1			1,086
Wholesale		98			2			2.1			96
Unbilled		(3	)		(11	)		-			8
Miscellaneous		43			6			16.2			37
Total electric revenues		1,399			172			14.0			1,227
Less: Fuel and other pass-through revenues		(925	)		(183	)		-			(742	)
Revenues excluding fuel and pass-through revenues	$	474		$	(11	)		(2.3	)	$	485

PEF’s electric energy sales for the three months ended September 30, 2006 and 2005, and the amount and percentage change by customer class are as follows:

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2006			Change			% Change			2005
Residential		6,369			(185	)		(2.8	)		6,554
Commercial		3,481			(70	)		(2.0	)		3,551
Industrial		1,067			(45	)		(4.0	)		1,112
Governmental		905			8			0.9			897
Total retail energy sales		11,822			(292	)		(2.4	)		12,114
Wholesale		1,372			(36	)		(2.6	)		1,408
Unbilled		(97	)		(292	)		-			195
Total kWh sales		13,097			(620	)		(4.5	)		13,717

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $925 million and $742 million for the three months ended September 30, 2006 and 2005, respectively, decreased $11 million. The decrease in revenues is primarily due to unfavorable weather of $20 million, with cooling degree days 10 percent below the prior year, partially offset by favorable miscellaneous service revenues of $6 million and increased retail growth and usage of $2 million driven by an approximate increase in the average number of customers of 40,000 as of  September 30, 2006, compared to September 30, 2005.

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 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 $794 million for the three months ended September 30, 2006, which represents a $173 million increase compared to the same period in the prior year. Fuel used in electric generation

70

increased $187 million to $538 million compared to the prior year. This increase is due to an increase in deferred fuel expense of $235 million due to an increase in the fuel recovery rates on January 1, 2006 partially offset by a $48 million decrease in fuel used in generation due primarily to lower oil and natural gas prices and a decrease in the volume of fuel purchases due to lower system requirements. Current year purchased power costs were $14 million lower than the three months ended September 30, 2005, primarily due to lower market prices in the third quarter of 2006 partially offset by an increase in capacity recovery rates under the capacity cost recovery clause. The FPSC allows 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.

Operation and Maintenance

O&M expenses were $171 million for the three months ended September 30, 2006, which represents a decrease of $10 million, when compared to the $181 million incurred during the three months ended September 30, 2005. O&M expenses decreased $8 million related to lower ECRC costs and $7 million related to lower pension expenses due to revised actuarial estimates. ECRC costs are pass-through expenses and have no material impact on earnings. These decreases were partially offset by increased nuclear outage accruals.

Depreciation and Amortization

Depreciation and amortization expense increased $13 million to $108 million for the three months ended September 30, 2006. The increase is primarily due to the amortization of $13 million in storm costs which began in August 2005. Storm cost amortization is a pass-through expense and has no material impact on earnings. In addition, depreciation increased $6 million due to increases in the depreciable base. These increases were partially offset by the $6 million impact of rate changes effective January 1, 2006 related to the 2005 depreciation study (See Note 7C of the 2005 Form 10-K).

Taxes other than on Income

Taxes other than on income increased $7 million to $89 million compared to the three months ended September 30, 2005. The increase is primarily due to higher gross receipts taxes and franchise taxes due to higher revenues. Gross receipts taxes and franchise taxes are pass-through expenses and have no material impact on earnings.

Total Other Income

Total other income increased $6 million to $10 million compared to the three months ended September 30, 2005 primarily due to a $4 million increase in interest income related to temporary investments and unrecovered storm costs.

Total Interest Charges, net

Total interest charges, net increased $13 million for the three months ended September 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to a $6 million interest benefit recognized in 2005 related to tax matters and the $4 million impact of long-term debt balances on interest expense.

Income Tax Expense

Income tax expense increased $9 million for the three months ended September 30, 2006, as compared to the same period in the prior year, primarily due to the impact of tax levelization, discussed below, partially offset by the impact of lower pre-tax income for the three months ended September 30, 2006 compared to the same period in 2005. In addition, income tax expense increased due to the allocation of $3 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 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. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was increased by $2 million for the three months ended September 30, 2006 compared to a decrease of $9 million for the three months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

71

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

REVENUES

PEF’s revenues for the nine months ended September 30, 2006 and 2005, and the amount and percentage change by customer class were as follows:

(in millions)	Nine Months Ended September 30,
Customer Class	2006			Change			% Change			2005
Residential	$	1,820		$	298			19.6		$	1,522
Commercial		869			158			22.2			711
Industrial		264			53			25.1			211
Governmental		223			45			25.3			178
Retail revenue sharing		1			4			-			(3	)
Total retail revenues		3,177			558			21.3			2,619
Wholesale		236			(1	)		(0.4	)		237
Unbilled		21			(1	)		-			22
Miscellaneous		119			14			13.3			105
Total electric revenues		3,553			570			19.1			2,983
Less: Fuel and other pass-through revenues		(2,315	)		(545	)		-			(1,770	)
Revenues excluding fuel and pass-through revenues	$	1,238		$	25			2.1		$	1,213

PEF’s electric energy sales for the nine months ended September 30, 2006 and 2005, and the amount and percentage change by customer class are as follows:

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2006		Change			% Change			2005
Residential		15,425		183			1.2			15,242
Commercial		9,040		30			0.3			9,010
Industrial		3,173		80			2.6			3,093
Governmental		2,432		64			2.7			2,368
Total retail energy sales		30,070		357			1.2			29,713
Wholesale		3,342		(721	)		(17.7	)		4,063
Unbilled		532		12			-			520
Total kWh sales		33,944		(352	)		(1.0	)		34,296

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $2.315 billion and $1.770 billion for the nine months ended September 30, 2006 and 2005, respectively, increased $25 million. The increase in revenues is primarily due to miscellaneous service revenues of $14 million and increased retail growth and usage of $13 million driven by an approximate increase in the average number of customers of 36,000 as of September 30, 2006, compared to September 30, 2005, even though approximately 14,000 Winter Park customers were transferred from the retail customer class to the wholesale customer class in June of 2005. This increase was partially offset by unfavorable weather of $2 million.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.98 billion for the nine months ended September 30, 2006, which represents a $469 million increase compared to the same period in the prior year. Fuel used in electric generation increased $413 million to $1.379 billion compared to the prior year. This increase is due to a $351 million increase in deferred fuel expense due to an increase in the fuel recovery rates on January 1, 2006. In addition, fuel used in generation increased $63 million due primarily to higher fuel costs which are being driven by increased delivered coal costs, higher oil prices and a change in generation mix, as generation shifted from coal to gas, partially offset by a decrease in the volume of fuel purchases due to lower system requirements. Current year purchased power

72

costs were $56 million higher than the nine months ended September 30, 2005, primarily due to $35 million related to increased purchases and higher market prices in the current year and $21 million due to an increase in capacity recovery rates under the capacity cost recovery clause. The FPSC allows 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.

Operation and Maintenance

O&M expenses were $515 million for the nine months ended September 30, 2006, which represents a decrease of $143 million, when compared to the $658 million incurred during the nine months ended September 30, 2005. O&M expenses decreased $108 million due to postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative, $18 million related to the prior year write-off of storm restoration costs, $18 million related to lower ECRC costs in the current year and $8 million related to lower pension expenses due to revised actuarial estimates. ECRC costs are pass-through expenses and have no material impact on earnings. These were partially offset by $7 million of additional spending on system reliability programs.

Depreciation and Amortization

Depreciation and amortization expense increased $65 million to $301 million for the nine months ended September 30, 2006. The increase is primarily due to an increase in storm cost amortization of $70 million. Storm cost amortization is a pass-through expense and has no material impact on earnings. In addition, depreciation increased $12 million due to increases in the depreciable base. These increases were partially offset by the $15 million impact of rate changes effective January 1, 2006 related to the 2005 depreciation study (See Note 7C of the 2005 Form 10-K).

Taxes other than on Income

Taxes other than on income increased $23 million to $238 million compared to the nine months ended September 30, 2005. The increase is primarily due to higher gross receipts taxes and franchise taxes due to higher revenues. Gross receipts taxes and franchise taxes are pass-through expenses and have no material impact on earnings.

Other

Other decreased $22 million from a gain of $24 million for the nine months ended September 30, 2005 to a gain of $2 million for the nine months ended September 30, 2006. The decrease is primarily due to the $24 million prior year gain on the sale of Winter Park distribution assets.

Total Other Income

Total other income increased $14 million to $20 million compared to the nine months ended September 30, 2005 primarily due to a $12 million increase in interest income related to temporary investments and unrecovered storm costs and a $3 million expense related to a FERC Code of Conduct audit settlement recorded in the prior year.

Total Interest Charges, net

Total interest charges, net increased $26 million for the nine months ended September 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to the $18 million impact of long-term debt balances on interest expense and a $6 million interest benefit recognized in 2005 related to tax matters.

Income Tax Expense

Income tax expense increased $62 million for the nine months ended September 30, 2006, as compared to the same period in the prior year, primarily due to higher earnings compared to prior year. In addition, income tax expense increased due to the allocation of $10 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 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. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was increased $2 million for the nine months ended September 30, 2006 compared to an immaterial decrease for the nine months

73

ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

DIVERSIFIED BUSINESSES

Our diversified businesses consist of the Progress Ventures segment and the Coal and Synthetic Fuels segment. These businesses are explained in more detail below.

PROGRESS VENTURES

The Progress Ventures segment is primarily engaged in nonregulated electric generation operations and energy marketing activities in our Competitive Commercial Operations business (CCO). The approximate 1,800 megawatts of gas-fired generation plants are located in Georgia and are utilized to help serve full requirements contracts with sixteen Georgia Electric Membership Cooperatives (the Georgia Contracts). There are six different contracts that expire in either 2010 or 2015. These contracts are served by resources owned by the customer, generation owned by Progress Ventures and market purchases. Progress Ventures has also entered into an agreement to provide capacity and associated energy to Georgia Power, a subsidiary of Southern Company, from 2009 through 2024. In addition, Progress Ventures has entered into an agreement to purchase combined-cycle capacity from Southern Power Company, a subsidiary of Southern Company, from 2009 through 2015. The Georgia Region business is an integrated generation and contract portfolio managed in CCO.

ALTERNATIVE BUSINESS STRATEGIES

As discussed in Note 3A, we entered into a definitive agreement to sell Gas, which was previously part of the Progress Ventures segment, and the transaction closed on October 2, 2006. Our Gas business acted as a natural long-term economic hedge for our nonregulated electric generation fuel needs. The Gas and CCO businesses were managed together in Progress Ventures, and the sale of Gas has resulted in an acceleration of the strategic review process at Progress Ventures. We have engaged a strategic advisor to help us pursue alternative business strategies related to our CCO business. As a result of the decision to pursue these strategies, as of September 30, 2006, we considered the likelihood of disposal of the CCO assets before the end of their useful life to be more likely than not. Under SFAS No. 144, the more likely than not to dispose determination triggered an impairment test of CCO’s intangible and long-lived assets in the third quarter of 2006. The first step of the impairment test was based upon undiscounted cash flows using various hold and sale scenarios over the expected period of use of the assets, and the results of the test did not indicate impairment. At September 30, 2006, the long-lived assets were recorded at a net book value of approximately $926 million, including $727 million of property, plant and equipment assets and $199 million of intangible assets. However, in a sale scenario, we would not expect to recover the recorded value of these assets.

As we continue to evaluate alternatives, we will monitor the carrying value of Progress Ventures’ long-lived assets. Future adverse changes in market conditions or changes in business conditions, including the manner in which the remaining long-lived assets are deployed under various alternatives that management is pursuing, could require future impairment evaluations of the $926 million of remaining long-lived and intangible assets, which could result in a material non-cash impairment charge against earnings.

The Georgia Contracts described above are sensitive to changes in power and natural gas market prices. As described in Note 10A, we have entered into certain power and natural gas hedge contracts to mitigate the impact of fluctuations in the price of power and natural gas. For the nine months ended September 30, 2006, the gross margin losses on the Georgia Contracts, including realized losses on the related hedges, were $10 million before taxes. The future earnings impacts of the Georgia Contracts are dependent on a number of factors including customer load growth, generation availability, weather and commodity prices (primarily natural gas and power). Based on changes in these factors, the earnings impacts from the Georgia Contracts could change materially in the future.

74

In evaluating a potential sale of the CCO business, we would expect three main components of value:

1.   Market value of the approximate 1,800 megawatts of Progress Ventures-owned generation in Georgia (including the associated tolling contracts with Georgia Power). The book value related to these assets at September 30, 2006 is $769 million including plant-related intangibles.

2.   Market value of power and natural gas hedges associated with the Georgia Contracts. Only the natural gas hedges are considered derivatives and are reflected on the Consolidated Balance Sheet. The book value of the net derivative asset at September 30, 2006 is $91 million.

3.   Market value of the future obligations to serve the Georgia Contracts. As these are executory contracts, no liabilities are recorded on the Consolidated Balance Sheet for these obligations in accordance with GAAP. There is $157 million of intangible assets related to these contracts on the Consolidated Balance Sheet at September 30, 2006.

The combination of the three items above results in a book value of approximately $1 billion related to CCO assets, hedges and Georgia Contracts at September 30, 2006. In a sale scenario, the potential market values for the generation assets and the hedges could be partially offset by the potential negative market value ascribed to the Georgia Contracts. If a sale of CCO were to occur, the charges to earnings related to these assets and contracts could exceed $500 million before taxes. Charges to earnings, should they occur, would likely occur in multiple future quarters depending upon the progress of our strategic review process.

If a sale of CCO were to be completed in 2007, we would expect to (1) eliminate the potential negative earnings related to the remaining CCO businesses, (2) receive an undetermined level of cash proceeds and (3) recognize a significant tax benefit related to the sale of the assets and/or contracts. These results are consistent with management’s intention to reduce holding company debt and business risk which was announced earlier this year.

IMPACT OF DISCONTINUED HEDGE ACCOUNTING

Based on the strategies being pursued and our assessment of the likelihood of divestiture of CCO assets, management determined, as of July 12, 2006, 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 hedges, and were dedesignated. Beginning July 12, 2006 cash flow hedge accounting was discontinued. Subsequent changes in market prices resulted in the recognition of mark-to-market losses of $28 million pre-tax ($18 million after-tax) for the three months ended September 30, 2006. Unrealized after-tax gains of $75 million recorded in accumulated other comprehensive loss on the Consolidated Balance Sheet prior to July 12, 2006 have not been reclassified to earnings. However, if the disposition status of CCO’s assets increases to probable then we will evaluate whether the unrealized gains will be reclassified to earnings. Future price volatility in the natural gas market will cause us to record mark-to-market changes through earnings and increase the volatility of future Progress Ventures’ operating results.

OPERATING RESULTS

The following summarizes the quarterly and year-to-date revenues, gross margin, goodwill impairment and segment losses for Progress Ventures:

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in millions)	2006			2005			2006			2005
Total revenues	$	137		$	210		$	422		$	404
Gross margin
In millions of $		(35	)		(6	)		(26	)		24
As a % of revenues		(26	)%		(3	)%		(6	)%		6	%
Goodwill impairment (after-tax)		-			-			(39	)		-
Segment losses	$	(40	)	$	(22	)	$	(111	)	$	(34	)

75

Although the Georgia Contracts operated at a loss, as a result of increased revenues and lower cost of sales, the margins for these contracts improved for the three months ended September 30, 2006 compared to the same period in 2005. The mark-to-market losses related to the dedesignated natural gas hedges were the main driver of the $18 million decrease in Progress Ventures’ segment earnings for the three months ended September 30, 2006 compared to the three months ended September 30, 2005. Progress Ventures’ revenues decreased $73 million to $137 million for the three months ended September 30, 2006 compared to the same period in 2005. The decrease in revenues is primarily due to a $41 million decrease in market sales due to lower 2006 market prices and $28 million of mark-to-market losses related to the dedesignated natural gas hedges described above. These decreases were partially offset by slightly higher revenues from the Georgia contracts due to serving a larger load. Progress Ventures’ cost of sales decreased $45 million for the three months ended September 30, 2006 primarily due to lower volumes of market purchases and lower power prices.

Progress Ventures’ revenues increased $18 million to $422 million for the nine months ended September 30, 2006 compared to the same period in 2005. Revenues increased $65 million primarily due to fixed price full-requirements contracts that began in April 2005 and serving an increased load on a pre-existing contract in Georgia. This increase was partially offset by $28 million of mark-to-market losses related to the dedesignated natural gas hedges and $16 million of realized losses on other hedges. Progress Ventures cost of sales increased $68 million for the nine months ended September 30, 2006 primarily due to higher market purchases and serving an increased load. Although the Georgia Contract revenues increased, the contracts operated at a loss for the nine months ended September 30, 2006 compared to the same period in 2005 due to the increase in the cost of sales. In addition to the realized losses and the mark-to-market losses, the $77 million decrease in Progress Venture’s segment earnings for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 resulted in part from the $64 million pre-tax impairment loss ($39 million after-tax) on goodwill recognized in the first quarter of 2006 (See Note 6).

COAL AND SYNTHETIC FUELS

The Coal and Synthetic Fuels’ segment includes synthetic fuels operations and coal terminal operations. The following summarizes Coal and Synthetic Fuels’ segment profits:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Synthetic fuel operations	$	20		$	71		$	(59	)	$	93
Coal terminals and marketing		(6	)		16			6			32
Corporate overhead and other operations		(5	)		(6	)		(22	)		(22	)
Segment profits (losses)	$	9		$	81		$	(75	)	$	103

76

SYNTHETIC FUEL OPERATIONS

The production and sale of synthetic fuels generate operating losses, but qualify for tax credits under Section 29/45K, which typically offset the effect of such losses. Our synthetic fuel operations resulted in the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Tons sold		0.2			3.0			1.9			7.3
After-tax losses, excluding tax credits	$	(2	)	$	(38	)	$	(52	)	$	(116	)
After-tax impairment charge		-			-			(45	)		-
Valuation allowance		-			-			(7	)		-
Tax credits generated		6			82			54			199
Tax credit inflation adjustment		-			-			10			-
Tax credit reserve (increase)/decrease due to potential phase-out		16			-			(19	)		-
Tax credits previously unrecorded		-			27			-			10
Net profit (loss)	$	20		$	71		$	(59	)	$	93

Prior to 2006, our synthetic fuel production levels and the amount of tax credits we could claim each year were a function of our projected 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’ earnings for the three months ended September 30, 2006, as compared to the same period in the prior year, decreased by $51 million. The decrease was impacted by the recording of fewer tax credits in 2006 due to lower production and the recording of $27 million of tax credits that had previously not been recognized in 2005. During the third quarter of 2005 while finalizing our 2004 regular federal income tax liability, we recorded $27 million of tax credits that had previously not been recognized. These credits were not previously recognized due to the decrease in tax liability resulting from expenses incurred for the 2004 hurricanes and loss on sale of Progress Rail. These were partially offset by lower 2006 production which resulted in lower pre-tax losses and reducing the tax credit reserve at September 30, 2006 by $16 million due to decreasing oil prices which decreased the estimated phase-out percentage of tax credits generated in 2006.

Synthetic fuels’ earnings for the nine months ended September 30, 2006, as compared to the same period in the prior year, were negatively impacted by the impairment of our synthetic fuel assets, the recording of fewer tax credits in 2006 due to lower production and recording a $19 million tax credit reserve at September 30, 2006 due to high oil prices which increased the anticipated phase-out of tax credits in 2006. In addition, results were unfavorably impacted by the recognition of a valuation allowance recorded against the deferred tax assets for state net operating loss carry forwards and recognition of $10 million of tax credits in the third quarter of 2005 related to the finalization of the 2004 tax return. These were partially offset by the recording of a $10 million inflation adjustment to 2005 tax credits and lower 2006 production which resulted in lower pre-tax losses. As a result of the impairment of our synthetic fuel assets, approximately $6 million of depreciation and amortization expense associated with the impaired assets will not be recorded during the remainder of 2006.

See OTHER MATTERS 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 fuel production in 2006 and 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 fuel 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 typically related to production volumes at our synthetic fuel plants. Coal operations resulted in a loss of $6 million for the three months ended September 30, 2006 compared to earnings of $16 million for the three months ended September 30, 2005.

77

Coal’s results were negatively impacted by lower revenues related to lower production at our synthetic fuels plants and higher cost of sales due to higher coal prices.

Coal operations contributed earnings of $6 million and $32 million for the nine months ended September 30, 2006 and 2005, respectively. Coal’s 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 plants and higher cost of sales due to higher coal prices. These were partially offset by an $11 million pre-tax reduction in expense related to a restructured coal supply contract. 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. For the nine months ended September 30, 2006, Coal recognized an $11 million pre-tax reduction in expense related to the restructured coal supply contract for 2005 coal commitments that were not delivered. 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, approximately $3 million of depreciation expense associated with the impaired assets will not be recorded during the remainder of 2006.

See OTHER MATTERS below for additional information on the results of our interim impairment review and its impact on our Coal terminals.

CORPORATE AND OTHER

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2006			2005			2006			2005
Other interest expense	$	(69	)	$	(65	)	$	(209	)	$	(203	)
Contingent value obligations		(3	)		4			(25	)		4
Tax levelization		15			85			(5	)		33
Tax reallocation		-			(10	)		-			(29	)
Other income tax benefit		18			23			67			82
Other		-			3			18			(4	)
Corporate and Other after-tax (expense)/income	$	(39	)	$	40		$	(154	)	$	(117	)

Other interest expense, which includes intercompany elimination entries, increased $4 million to $69 million for the three months ended September 30, 2006 compared to $65 million for the three months ended September 30, 2005. Other interest expense, which includes elimination entries, increased $6 million to $209 million for the nine months ended September 30, 2006 compared to $203 million for the nine months ended September 30, 2005. Interest expense increased primarily due to reversing $4 million of interest related to a tax matter in the prior year.

Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the 2000 acquisition of Florida Progress. Each CVO represents the right of the holder to receive contingent payments based on the performance of four synthetic fuel facilities owned by Progress Energy. The payments, if any, will be based on the net after-tax cash flows the facilities generate. At September 30, 2006 and 2005, the CVOs had fair market values of approximately $33 million and $9 million, respectively. We recorded unrealized losses of $3 million for the three months ended September 30, 2006 and unrealized gains of $4 million for the three months ended September 30, 2005, to record the changes in fair value of the CVOs, which had average unit prices of $0.33 and $0.09 at September 30, 2006 and 2005, respectively. We recorded an unrealized loss of $25 million for the nine months ended September 30, 2006 and an unrealized gain of $4 million for the nine months ended September 30, 2005.

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $15 million and $85 million for the three months ended September 30, 2006 and 2005, respectively, and increased by $5 million for the nine months ended

78

September 30, 2006 and decreased by $33 million for the nine months ended September 30, 2005, in order to maintain an effective rate consistent with the estimated annual rate. The tax credits associated with our synthetic fuel operations and seasonal fluctuations in our annual earnings primarily drive the fluctuations in the effective tax rate for interim periods. The tax levelization adjustment will vary each quarter, but it will have no effect on net income for the year.

For the three months and nine months ended September 30, 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) we will no longer allocate the Parent income tax benefits not related to acquisition interest expense to profitable subsidiaries beginning in 2006. Since 2002, Parent income tax benefits not related to acquisition interest expense were allocated to profitable subsidiaries, in accordance with a PUHCA order. For the three months ended September 30, 2005, income tax expense was increased by $10 million and for the nine months ended September 30, 2005, income tax expense was increased by $29 million due to the allocation of the Parent’s income tax benefit.

For the three months end September 30, 2006, other did not contribute any material earnings compared to $3 million for the same period in 2005. For the nine months ended September 30, 2006, other contributed $18 million to earnings compared to $4 million of expense in 2005. The $22 million change is primarily due to 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 Notes 3C and 12). In addition, other changed due to a $2 million increase in interest income on temporary investments and recording $4 million for South Carolina corporate license related to the South Carolina audit settlement in 2005.

DISCONTINUED OPERATIONS

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., 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. Proceeds from the sale are expected to be used primarily to reduce holding company debt and for other corporate purposes (See Note 3A).

The transaction closed on October 2, 2006 and is subject to customary post-closing provisions and post-closing adjustments. 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 of $57 million for the three months ended September 30, 2006 compared to net earnings of $15 million for the same period in 2005 and net earnings of $84 million for the nine months ended September 30, 2006 compared to net earnings of $36 million for the same period in 2005. During the fourth quarter of 2006, we expect to record a gain on the sale of Gas. We anticipate the gain will be approximately $100 million less than the $400 million previously estimated in July of 2006, due to the increase in value related to hedge contracts executed on behalf of the purchaser and other closing adjustments. Although these hedge contracts will reduce the gain on the sale, they have increased earnings for the three months and nine months ended September 30, 2006, and should therefore not result in a materially different net impact on retained earnings.

DESOTO AND ROWAN GENERATION FACILITIES

On May 2, 2006, our board of directors approved a plan to divest of our DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (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 3B).

79

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 during the nine months ended September 30, 2006 on the sale of DeSoto and Rowan of $65 million. Discontinued DeSoto and Rowan operations had combined earnings of $15 million for the three months ended September 30, 2006 compared to earnings of $7 million for the same period in 2005 and combined earnings of $9 million for the nine months ended September 30, 2006 compared to combined earnings of $7 million for the same period in 2005.

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 3C).

Based on the gross 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 nine months ended September 30, 2006. Discontinued PT LLC operations had earnings of $2 million for both the three months ended September 30, 2006 and 2005 and a net loss of $3 million for the nine months ended September 30, 2006 compared to earnings of $3 million for the same period in 2005.

DIXIE FUELS AND OTHER FUELS BUSINESSES

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 businesses are expected to be sold within the next six months (See Note 3D).

Discontinued Dixie Fuels and other fuels businesses had earnings of $4 million for the three months ended September 30, 2006 compared to $2 million for the same period in 2005 and earnings of $6 million for the nine months ended September 30, 2006 compared to $3 million for the same period in 2005.

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 an estimated $4 million working capital adjustment. As a result, during the nine months ended September 30, 2006 we recorded an estimated after-tax loss of $13 million for the sale of these assets. The remaining coal mining businesses are expected to be sold by the end of 2006 (See Note 3E).

Discontinued coal mining businesses had earnings of $2 million for the three months ended September 30, 2006 compared to a net loss of $9 million for the same period in 2005 and a net loss of $1 million for the nine months ended September 30, 2006 compared to $9 million for the same period in 2005.

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. Gross cash proceeds from the sale were approximately $429 million, consisting of $405 million base proceeds plus a working capital adjustment. During the nine months ended September 30, 2006 and 2005 we recorded an estimated after-tax loss for the sale of these assets of $3 million and $25 million, respectively. Proceeds from the sale were used to reduce debt (See Note 3F).

Rail discontinued operations had no earnings impact for the three months ended September 30, 2006 and 2005 and no earnings impact for the nine months ended September 30, 2006 compared to earnings of $5 million for the same period in 2005.

80

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Progress Energy, Inc. is a holding company and, as such, has no operations of its own. Our primary cash needs at the Parent level are our common stock dividend and interest and principal payments on our $3.9 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, and expenditures for our diversified businesses, primarily those of the Progress Ventures segment.

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. Such costs are recovered from customers 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 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.

Cash from operations, asset sales 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 2006. We expect to use excess cash proceeds to reduce debt. To the extent necessary, short-term and long-term debt may also be used as a source of liquidity.

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 in the “Risk Factors” section of our 2005 Form 10-K.

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

CASH FLOWS FROM OPERATIONS

Net cash provided by operating activities increased by $683 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to a $473 million increase in the recovery of fuel costs at the Utilities, a $261 million net decrease in working capital and other operating activity needs, and $66 million of storm restoration costs paid in the prior year at PEF, partially offset by lower net income. In 2005, the Utilities requested and received approval from their respective state commissions for 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 Note 4 for additional information. The decrease in working capital and other operating activity needs was primarily due to a $244 million decrease from the change in accounts receivable, approximately $103 million of proceeds received from the restructuring of a long-term coal supply contract, and $32 million due to fluctuations in emission allowance inventory at PEC. The change in accounts receivable included $112 million at PEC, principally driven by the timing of wholesale sales, and approximately $108 million at our nonregulated operations, primarily related to fixed price full-requirements contracts that began in April 2005 at Progress Ventures and lower synthetic fuel sales. These impacts were partially offset by a $185 million increase in working capital needs from the change in accounts payable, primarily driven by reduced purchases at our nonregulated operations.

81

INVESTING ACTIVITIES

Net cash used in investing activities increased by $220 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year. This was due primarily to $240 million in additional capital expenditures for utility property additions and a $132 million decrease in net proceeds from available-for-sale securities and other investments. Available-for-sale securities and other investments include marketable debt and equity securities and investments held in nuclear decommissioning and benefit investment trusts. These impacts were partially offset by a $27 million decrease in nuclear fuel additions and $90 million in additional proceeds from sales of discontinued operations and other assets for 2006 when compared to the corresponding period in the prior year.

Excluding proceeds from sales of discontinued operations and other assets, cash used in investing activities increased approximately $310 million in 2006 when compared with 2005. The increase in property additions was primarily due to environmental compliance and mobile meter reading project expenditures at PEC and to various distribution, transmission and steam production projects, as well as, a project to change the Bartow plant to more efficient natural gas-burning technology at PEF. The decrease in nuclear fuel additions was primarily related to nuclear facility outage expenditures at PEF in 2005.

During the nine months ended September 30, 2006, proceeds from sales of discontinued operations and other assets, net of cash divested primarily included approximately $405 million from the sale of DeSoto and Rowan (See Note 3B), approximately $70 million from the sale of PT LLC (See Note 3C), approximately $27 million from the sale of certain net assets of the coal mining business (See Note 3E), and approximately $16 million from the sale of Dixie Fuels (See Note 3D). During the same period in 2005, proceeds from sales of discontinued operations and other assets primarily included $393 million in proceeds from the sale of Progress Rail in March 2005, net of cash divested (See Note 3F).

FINANCING ACTIVITIES

Net cash used in financing activities increased by $927 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year. The increase in cash used in financing activities was due primarily to a decrease in the proceeds from issuances of long-term debt and common stock and payment of the March 1, 2006 maturity of $800 million 6.75% senior unsecured notes. These notes were paid with net proceeds from the sale of $400 million in senior notes, as discussed below, and a combination of cash and commercial paper proceeds.

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 will be based on three-month London Inter Bank Offering Rate (LIBOR) plus 45 basis points and will be reset 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 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, as of September 30, 2006, Progress Energy has the authority to issue and sell up to $1.679 billion aggregate principal amount of various securities.

82

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 Progress Energy 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 still includes a defined maximum total debt to capital ratio of 68 percent and contains various cross-default and other acceleration provisions. However, 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 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 Standard & Poor’s Rating Services (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 still 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 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.

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.

At December 31, 2005, we had 500 million shares of common stock authorized under our charter, of which approximately 252 million were outstanding. For the three months ended September 30, 2006 and 2005, respectively, we issued approximately 0.3 million shares and 0.4 million shares of common stock resulting in approximately $13 million and $22 million in proceeds, net of purchases of restricted shares, primarily to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k) Plan) and the Investor Plus Stock Purchase Plan. For the nine months ended September 30, 2006 and 2005, respectively, we issued approximately 1.7 million shares and 4.4 million shares of common stock resulting in approximately $73 million and $193 million in proceeds, net of purchases of restricted shares. Included in these amounts were approximately 1.4 million shares and 4.3 million shares for net proceeds of approximately $58 million and $187 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. For the fiscal year 2006, we expect to realize an aggregate amount of approximately $100 million from the sale of stock through these plans.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2006, there were no material changes in our “Capital Expenditures,” “Other Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 of the 2005 Form 10-K, other than as described below and above under “Financing Activities.”

The amount and timing of future sales of our debt and equity 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 needed to meet our immediate 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 September 30, 2006, the current portion of our long-term debt was $700 million, which we expect to fund with cash from operations, proceeds from sales of assets and/or commercial paper borrowings. See Note 3 for additional information on asset sales.

On October 27, 2006, Progress Energy announced that on November 27, 2006, it intends to redeem the entire outstanding $350 million principal amount of its 6.05% Senior Notes due April 15, 2007 and the entire outstanding

83

$400 million principal amount of its 5.85% Senior Notes due October 30, 2008. The redemptions will be funded with existing cash and no additional debt will be incurred in connection with the redemptions.

On June 13, 2006, Fitch Ratings (Fitch) placed the senior unsecured credit ratings of Progress Energy (BBB-), PEC (BBB+) and PEF (BBB+) on Rating Watch Positive. The short-term ratings of PEC and PEF were unaffected. The placement of PGN's ratings on Rating Watch Positive was based on Fitch's expectation that significant holding company reductions of debt and business risk will result from pending and planned asset sales, as well as the successful resolution of the IRS audit of the Earthco synthetic fuel facilities. 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 towards our holding company debt reduction plan and expectations of future financial performance at the BBB+ benchmark 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 fuel facilities. 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 fuel facilities, and lower business risk after divestitures of non-core 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. We do not expect these changes to have a material impact on our borrowing costs or overall liquidity.

Regulatory matters as discussed in Note 4 and filings for recovery of environmental costs as discussed in Note 13 may impact our future liquidity and financing activities.

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” (FIN No. 45). 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, surety bonds and guarantees in support of nuclear decommissioning. At September 30, 2006, we have issued $1.578 billion of guarantees for future financial or performance assurance. Included in this amount is $300 million of Parent-issued guarantees of certain payments of two wholly owned indirect subsidiaries (See Note 15). 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 BBB- or Baa3) by S&P or Moody’s, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. At September 30, 2006, 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 $585 million. 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 September 30, 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 fuel operations as discussed in Note 14A.

84

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 10 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

As of September 30, 2006, our contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2005 Form 10-K.

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 fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Qualifying synthetic fuel facilities entitle their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuel 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 fuel is generally not economical to produce and sell absent the credits. On May 22, 2006, we idled production of synthetic fuel at our synthetic fuel facilities. As discussed below in IMPACT OF CRUDE OIL PRICES, the decision to idle production was based on the high level of oil prices and the continued uncertainty of any proposed federal legislation regarding the value of the tax credits received as a result of synthetic fuel production. Based on significantly reduced oil prices combined with current favorable fuel price projections, we resumed limited production at our synthetic fuel facilities in September and October 2006. We currently expect to produce up to 1.5 million tons during the remainder of 2006. We will continue to monitor the economic environment surrounding synthetic fuel production and will adjust our production as warranted by changing market conditions.

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 currently 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 fuel production and subjects the credits to a 20-year carry forward period. This provision would allow us to produce synthetic fuel to a higher level than we have historically produced, should we choose to do so.

Total Section 29/45K credits generated through September 30, 2006 (including those generated by Florida Progress prior to our acquisition), were approximately $1.8 billion, of which $899 million has been used to offset regular federal income tax liability, $888 million is being carried forward as deferred tax credits and $19 million has been reserved due to the potential 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 2006 and 2007. This possibility is due to a provision of Section 29 that 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 price (the Threshold Price), the amount of Section 29/45K 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

85

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.

The Department of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (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. The Annual Average Price for calendar year 2005 was published on April 11, 2006. Based on the Annual Average Price of $50.26, there was no phase-out of our synthetic fuel tax credits in 2005.

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 monthly New York Mercantile Exchange (NYMEX) settlement price for light sweet crude oil. Through September 30, 2006, the average NYMEX settlement price for light sweet crude oil was $68.26 per barrel, and as of September 30, 2006, the average NYMEX futures price for light sweet crude oil for the remainder of calendar year 2006 was $63.53 per barrel. This results in a weighted-average annual price for light sweet crude oil of approximately $67.08 per barrel for calendar year 2006. Based upon the estimated 2006 Threshold Price and Phase-out Price, if oil prices for 2006 averaged this weighted price of approximately $67.08 per barrel for the entire year in 2006, we currently estimate that the synthetic fuel tax credit amount for 2006 would be reduced by approximately 35 percent. Therefore, we reserved 35 percent or approximately $19 million of the $54 million in tax credits generated during the first nine months of 2006. The NYMEX price of oil for the remainder of 2006 would have to be $43.66 to have no reduction in value of tax credits generated during 2006 and would have to be $99.90 to have a full reduction in value. The final calculations of any reductions in the value of the tax credits will not be determined until early 2007 when final 2006 oil prices are known. Additional fluctuations in oil prices may cause quarterly adjustments to our results of operations and the amount of tax credits we record or reserve, either positive or negative, depending on current and futures oil prices at the end of the quarter, which impact the estimated weighted average annual price of oil for 2006.

Legislation that would have provided synthetic fuel producers with additional certainty around future synthetic fuel production decisions was not included in the Tax Increase Prevention and Reconciliation Act passed in May 2006. However, similar provisions modifying the Section 29/45K synthetic fuel tax credit program may be included in future legislation. We cannot predict the outcome of this matter.

No decisions have been made about synthetic fuel production levels, if any, in 2007. Such decisions will be based on then-current and projected fuel prices. Assuming an inflation adjustment of 2.7 percent, we estimate that the 2007 Threshold Price and Phase-Out Price would be approximately $57 and $71, respectively.

IMPAIRMENT OF SYNTHETIC FUEL AND OTHER RELATED LONG-LIVED ASSETS

We monitor our long-lived assets for impairment as warranted.With the idling of our synthetic fuel facilities during the second quarter of 2006, we performed an impairment evaluation of our synthetic fuel and other related operating long-lived assets. The impairment test considered numerous factors, including, among other things, continued high oil prices, the continued uncertainty of whether federal legislation will be enacted that would provide assurance that tax credits would exist for 2006 production and the then-current “idle” state of our synthetic fuel 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 6 and 7). These charges represent the entirety of the asset carrying value of our synthetic fuel intangible assets and manufacturing facilities, as well as a portion of the asset carrying value associated with the river terminals at which the synthetic fuel manufacturing facilities are located.

PERMANENT SUBCOMMITTEE

In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation

86

concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel, and other aspects of Section 29 and is not specific to our synthetic fuel operations. Progress Energy provided information in connection with this investigation. We cannot predict the outcome of this matter and are not aware of any current investigation activity.

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 Synfuel Limited Partnership, LLLP (Colona), one of our synthetic fuel 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 fuel 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 fuel 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. With an extended idling of our production, the amount of proceeds realized from the sale could be significantly impacted. As of September 30, 2006, a pre-tax gain on monetization of $11 million has been deferred. Based on the current level of oil prices, we cannot predict how much, if any, of this gain will be recognized this year. 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 fuel facilities.

See Note 14B for additional discussion related to our synthetic fuel operations.

REGULATORY ENVIRONMENT

The Utilities’ operations in North Carolina, South Carolina and Florida are regulated by the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC), respectively. The electric businesses are also subject to regulation by the FERC, the NRC and other federal and state agencies common to the utility industry. As a result of regulation, many of our 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.

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.

Due to the damage electric utility facilities suffered during recent hurricanes, the FPSC and the Florida state legislature have reviewed proposals that sought to minimize future storm damage and resulting customer outages. While the proposed legislation did not pass, the FPSC has initiated rulemaking proceedings and workshops regarding changes in construction and maintenance standards. Regulations involving wooden pole inspection schedules have been adopted and the FPSC is currently considering vegetation maintenance and long-term initiatives. PEF has actively participated in the rulemaking process and will continue to address the FPSC’s concerns until remaining storm-hardening rulemaking issues are resolved. If all current and proposed rulemakings are adopted, PEF anticipates that these rules will not materially increase PEF’s costs. 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 government as well as provide enhancements for recreation, water quality and aquatic habits. The

87

remaining phase of the application process will take approximately two years and includes review by the FERC and solicitation of public comment. We cannot predict the outcome of this matter.

APPLICATIONS FOR NUCLEAR POWER PLANT LICENSES

We have announced that we are pursuing development of Combined License (COL) applications, which are not commitments to build nuclear plants but are a necessary step to keep open the option of building a potential plant or plants. On January 23, 2006, we announced that PEC had selected the Shearon Harris Nuclear Plant (Harris) site to evaluate for possible future nuclear expansion and we announced the selection of the Westinghouse Electric AP1000 reactor design as the technology upon which to base any potential application submission. We currently expect to file the application for the COL for PEC’s Harris site in 2007. We expect to file the application for the COL for an as-yet unspecified site in Florida in 2008. We plan to announce the selection of the Florida site during the fourth quarter of 2006. If we receive approval from the NRC, and if the decision to build is made, construction could begin as early as 2010, and a new plant could be in service around 2016.We estimate that it will take approximately 36 months for the NRC to review the COL applications and grant approval.

A new nuclear plant may be eligible for the federal production tax credits and risk insurance provided by the Energy Policy Act of 2005 (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 which filed license applications with the NRC by December 31, 2008 and which 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 constructed by us would qualify for these or other incentives. We cannot predict the outcome of this matter.

ENVIRONMENTAL MATTERS

We are subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. We currently estimate total remaining compliance costs for the Utilities, related to environmental laws and regulations addressing air and water quality, which will primarily be for capital expenditures, 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. These costs are eligible for regulatory recovery through either base rates or pass-through clauses. These environmental matters are discussed in further detail in Note 13, including identification of specific environmental issues, the status of the issues, accruals associated with issue resolutions and our associated exposures. We accrue costs to the extent they are probable and can be reasonably estimated. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

NEW ACCOUNTING STANDARDS

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

88

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; LIQUIDITY AND CAPITAL RESOURCES 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 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS and Item 1A, “Risk Factors” of Part II for a discussion of the factors that may impact any such forward-looking statements made herein.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities increased $169 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to a $99 million increase in the recovery of fuel costs, a $67 million net decrease in working capital needs and a $56 million net decrease in other operating activity needs, partially offset by lower net income. In 2005, PEC requested and received approval from the NCUC and SCPSC for rate increases for fuel cost recovery, including amounts for previous under-recoveries. The decrease in working capital needs was primarily due to decreases from the change in accounts receivable of $112 million, principally driven by the timing of wholesale sales, and $47 million related to fluctuations in inventory, primarily coal, partially offset by a $122 million net increase in tax payments for the period in 2006 compared to 2005. The decrease in other operating activity needs was largely due to $32 million of emission allowance inventory fluctuations.

Cash used in investing activities decreased $79 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year primarily due to a $53 million increase in property and nuclear fuel additions and a $20 million decrease in net proceeds from available-for-sale securities and other investments for the period in 2006. The increase in property additions was primarily related to environmental compliance and mobile meter reading project expenditures. The increase in nuclear fuel additions was related to nuclear facility refueling outages. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

See Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, LIQUIDITY AND CAPITAL RESOURCES, for a discussion of PEC’s financing activities.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

At September 30, 2006, PEC’s off-balance sheet arrangements and contractual obligations have not changed materially from what was reported in PEC’s 2005 Form 10-K.

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 10 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

At September 30, 2006, PEC’s contractual cash obligations and other commercial commitments have not changed materially from what was reported in PEC’s 2005 annual report on Form 10-K.

89

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, LIQUIDITY AND CAPITAL RESOURCES 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 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS and Item 1A, “Risk Factors” of Part II for a discussion of the factors that may impact any such forward-looking statements made herein.

LIQUIDITY AND CAPITAL RESOURCES

PEF’s net cash provided by operating activities increased by $351 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year. The increase was due primarily to a $374 million increase in the recovery of fuel costs, $90 million due to the timing of income tax payments, $66 million of storm restoration costs paid in the prior year. In 2005, PEF requested and received approval from the FPSC for 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 Note 4 for additional information. These impacts were partially offset by a $69 million decrease from fluctuations in inventory, primarily related to coal.

Cash used in investing activities increased $185 million for the nine months ended September 30, 2006, when compared to the corresponding period in the prior year. The increase in cash used in investing activities was primarily due to $192 million of property additions, primarily related to various distribution, transmission and steam production projects, as well as, a project to change the Bartow plant to more efficient natural gas-burning technology and lower proceeds from sales of assets in 2006 as compared to 2005 due to the sale of assets to Winter Park in 2005. These impacts were partially offset by a $40 million decrease in nuclear fuel additions related to nuclear facility refueling outages in 2005.

See Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, LIQUIDITY AND CAPITAL RESOURCES, for a discussion of PEF’s financing activities.

90

Item 3.Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various risks related to changes in market conditions. We have a Risk Management Committee comprised of senior executives from various functional areas. 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 for nonperformance by the counterparty. We minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. Additionally, in the normal course of business, some of our affiliates may enter into hedge transactions with one another, which are eliminated in the consolidated financial statements as appropriate (See Note 10).

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.

PROGRESS ENERGY

Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2005.

INTEREST RATE RISK

Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at September 30, 2006, has changed from December 31, 2005. The total notional amount of fixed rate long-term debt at September 30, 2006, was $9.192 billion, with an average interest rate of 6.29% and fair market value of $9.559 billion. The total notional amount of variable rate long-term debt at September 30, 2006, was $1.411 billion, with an average interest rate of 4.38% and fair market value of $1.411 billion.

In addition to our variable rate long-term debt, we typically have commercial paper and/or loans outstanding under our RCA facilities, which are also exposed to floating interest rates. At September 30, 2006, approximately 14.7 percent of consolidated debt, including interest rate swaps, was floating rate compared to 12.8 percent at the end of 2005.

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 only enter into interest rate derivative agreements 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, 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 summarize the terms, fair market values and exposures of our interest rate derivative instruments.

91

CASH FLOW HEDGES

At September 30, 2006, the Utilities had a combined $100 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions. Under terms of these swap agreements, we will pay a fixed rate and received a floating rate based on 3-month LIBOR. The Parent had no open interest rate cash flow hedges at September 30, 2006, while the Utilities had no open interest rate cash flow hedges at December 31, 2005.

Cash Flow Hedges (dollars in millions)	Notional Amount	Pay	Receive(a)	Fair Value	Exposure(b)
Progress Energy, Inc.
Risk hedged at September 30, 2006:	None
Risk hedged at December 31, 2005:
Anticipated 10-year debt issue(c)	$100	4.87%	3-month LIBOR	$1	$(2)
PEC
Risk hedged at September 30, 2006:
Anticipated 10-year debt issue	$50	5.61%	3-month LIBOR	$(2)	$(1)
Risk hedged at December 31, 2005:	None
PEF
Risk hedged at September 30, 2006:
Anticipated 10-year debt issue	$50	5.61%	3-month LIBOR	$(2)	$(1)
Risk hedged at December 31, 2005:	None

 (a)  3-month LIBOR rate was 5.37% at September 30, 2006 and 4.54% at December 31, 2005.

 (b) ^{Sensitivity indicates change in value due to 25 basis points unfavorable shift in interest rates.}

 ^(c) Progress Energy, Inc. anticipated 10-year debt issue hedges terminated on March 1, 2006 with required mandatory cash settlement.

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 fixed rate debt issuances in 2007. These swaps were designated as cash flow hedges as of July 1, 2006.

FAIR VALUE HEDGES

At September 30, 2006 and December 31, 2005, we had $150 million notional of fixed rate debt swapped to floating rate debt. Under terms of these swap agreements, we will receive a fixed rate and pay a floating rate based on 3-month LIBOR. At September 30, 2006 and December 31, 2005, the Utilities had no open interest rate fair value hedges.

92

Fair Value Hedges (dollars in millions)	Notional Amount	Receive	Pay(b)	Fair Value	Sensitivity(c)
Progress Energy, Inc.
Risk hedged at September 30, 2006:
5.85% Notes due 10/30/2008	$100	4.10%	3-month LIBOR	$(2)	$-
7.10% Notes due 3/1/2011	50	4.65%	3-month LIBOR	(1)	-
Total	$150	4.28%(a)		$(3)	$-
Risk hedged at December 31, 2005:
5.85% Notes due 10/30/2008	$100	4.10%	3-month LIBOR	$(2)	$(1)
7.10% Notes due 3/1/2011	50	4.65%	3-month LIBOR	-	-
Total	$150	4.28%(a)		$(2)	$(1)

^(a) Weighted average interest rate.

^(b) 3-month LIBOR rate was 5.37% at September 30, 2006 and 4.54% at December 31, 2005.

^(c) Sensitivity indicates change in value due to 25 basis point unfavorable shift in interest rates.

MARKETABLE SECURITIES PRICE RISK

At September 30, 2006 and December 31, 2005, the fair value of our nuclear decommissioning trust funds was $1.215 billion and $1.133 billion, respectively, including $692 million and $640 million, respectively, for PEC and $523 million and $493 million, respectively, for PEF. 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.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At September 30, 2006 and December 31, 2005, the fair value of CVOs was $33 million and $7 million, respectively. At September 30, 2006, a hypothetical 10 percent change in the market price would not have a material effect on our financial position, results of operations or cash flows.

COMMODITY PRICE RISK

See Note 10 for additional information with regard to our commodity contracts and use of derivative financial instruments. The following discussion excludes commodity derivative instruments held by Gas, which was classified as discontinued operations.

GENERAL

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, many of our long-term power sales contracts shift substantially all fuel responsibility to the purchaser. We also have oil price risk exposure related to synthetic fuel tax credits as discussed in the OTHER MATTERS section of Item 2.

Most of our commodity contracts are not derivatives pursuant to SFAS No. 133, “Accounting for Derivative and Hedging Activities” (SFAS No. 133), or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.

93

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments. Derivative commodity instruments held by the Gas business sold on October 2, 2006, (see Note 3A) were excluded from the analysis. The following discussion addresses the stand-alone commodity risk created by our 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 September 30, 2006 levels would decrease our after-tax earnings by approximately $53 million.

The above analysis of our derivative commodity instruments used for hedging purposes does not include the potential favorable impact of the same hypothetical price movement on our 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 our earnings 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.

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 according to established policies and guidelines that limit our exposure to market risk and require daily reporting to management of financial exposures.

For the three months and nine months ended September 30, 2006, we recorded pre-tax losses of $30 million and $39 million, respectively. For the three months and nine months ended September 30, 2005, we recorded pre-tax losses of $8 million. Gains and losses from such contracts were not material to the Utilities’ results of operations for the three months and nine months ended September 30, 2006 and 2005. At September 30, 2006, the fair values of these instruments for our nonregulated operations were a $12 million short-term derivative asset position included in other current assets, a $124 million long-term derivative asset position included in other assets and deferred debits, a $27 million short-term derivative liability position included in other current liabilities and a $7 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheet. We did not have material outstanding positions in such contracts at December 31, 2005, other than those at PEF, which are discussed below. See Cash Flow Hedge discussion below regarding dedesignation of derivative contracts covering approximately 95 bcf of natural gas. PEC did not have material outstanding positions in such contracts at September 30, 2006 or December 31, 2005. PEF did not have material outstanding positions in such contracts at September 30, 2006 or December 31, 2005, other than those receiving regulatory accounting treatment, as described 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, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel adjustment clause. At September 30, 2006, the fair values of these instruments were a $3 million short-term derivative asset position included in other current assets, a $5 million long-term derivative asset position included in other assets and deferred debits, a $45 million short-term derivative liability position included in other current liabilities and a $49 million long-term derivative liability position included in other liabilities and deferred credits on the Balance Sheets. 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 Sheets.

94

CASH FLOW HEDGES

We 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 for our forecasted purchases and sales.

Based on the alternative strategies being pursued and our assessment of the likelihood of divestiture of CCO assets, management determined, as of July 12, 2006, 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. Beginning July 12, 2006, cash flow hedge accounting was discontinued. Unrealized after-tax gains on these contracts recorded in accumulated other comprehensive income/(loss) prior to July 12, 2006 have not been reclassified to earnings. However, if the disposition status of the assets increases to probable then we will evaluate whether the unrealized gains will be reclassified to earnings.

The fair values of our commodity cash flow hedges at September 30, 2006 and December 31, 2005, were as follows:

	September 30, 2006					December 31, 2005
(in millions)	Progress Energy			PEC		Progress Energy			PEC
Fair value of assets	$	3		$	3	$	170		$	7
Fair value of liabilities		(2	)		-		(58	)		(4	)
Fair value, net	$	1		$	3	$	112		$	3

PEC

The information required by this item is incorporated herein by reference to the “Quantitative and Qualitative Disclosures about Market Risk” discussed above insofar as it relates to 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. Other than as discussed above, PEC’s exposure to these risks has not materially changed since December 31, 2005.

PEF

Other than as discussed above, the information called for by Item 3 is omitted pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).

95

Item 4:Controls and Procedures

Progress Energy, Inc.

Pursuant to the Securities Exchange Act of 1934, we carried out an evaluation, with the participation of management, including our Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act, are recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2006, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 September 30, 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, and 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 September 30, 2006, that has materially affected, or is reasonably likely to materially affect, PEF’s internal control over financial reporting.

96

PART II. OTHER INFORMATION

Item 1.Legal Proceedings

Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 14B).

Item 1A.Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors of the 2005 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this report and in our 2005 Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. Other than as discussed below, there have been no material changes to our risk factors from those disclosed in the 2005 Form 10-K.

Our results of operations may be materially and adversely affected by the high price of oil and its impact on our synthetic fuels business. This risk is not applicable to PEC and PEF.

Section 29 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. See IMPACT OF CRUDE OIL PRICES in OTHER MATTERS of Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information on the impact of crude oil prices on our synthetic fuel operations and the value of our Section 29/45K tax credits.

Recent increases in the price of oil have limited the amount of Section 29/45K tax credits we recognized through September 30, 2006 and could eliminate them altogether. On May 22, 2006, we idled production of synthetic fuel at our synthetic fuel facilities. The decision to idle production was based on the high level of oil prices and the continued uncertainty of any proposed federal legislation regarding the value of the tax credits received as a result of synthetic fuel production. We resumed limited production in September and October as a result of significantly reduced oil prices combined with current favorable fuel price projections. We currently expect to produce up to 1.5 million tons during the remainder of 2006. No decisions have been made about synthetic fuel production levels, if any, for 2007. We will continue to monitor the economic environment surrounding synthetic fuel production and will adjust our production as warranted by changing market conditions.

The idling of our synthetic fuel facilities triggered an impairment test of our synthetic fuel and other related long-lived assets during the quarter ended June 30, 2006. Based on the results of the impairment test, during the second quarter of 2006, we recorded an after-tax impairment charge of $91 million ($55 million after-tax) that represents the entirety of the asset carrying value of our synthetic fuel intangible assets and manufacturing facilities, as well as a portion of the asset carrying value associated with the river terminals at which the synthetic fuel manufacturing facilities are located (See Notes 6 and 7).

If the Section 29/45 tax credits earned to date during 2006 were completely phased out due to high oil prices, then the current year losses from our synthetic fuel operations would equal its operating losses ($59 million through September 30, 2006) plus the reversal of income related to Section 29/45 tax credits recorded during the year ($35 million through September 30, 2006).

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 severe weather. While the Utilities have historically been granted regulatory approval to recover 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.

97

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. On August 29, 2006, the FPSC approved a modified settlement agreement that extends PEF’s current two-year storm surcharge for retail customers, equaling approximately $3.61 on the average residential monthly customer bill of 1,000 kWhs, for an additional 12-month period. The extension is expected to replenish the existing storm reserve by an estimated additional $130 million. In the event future storms cause the reserve to be depleted, the modified settlement agreement provides that PEF would be able 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 the 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 on-going 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 2005 or through September 30, 2006.

If we cannot recover costs associated with future significant weather events in a timely manner, or in an amount sufficient to cover our actual costs, or if our storm reserve is inadequate, our financial conditions and results of operations could be materially and adversely impacted.

Item 2.Unregistered Sale of Equity Securities and Use of Proceeds

(a) PERFORMANCE SHARE SUB-PLAN AWARD PAYOUT

(a)    Securities Delivered. On September 21, 2006, 54 shares of our common stock were delivered to the estate of an employee pursuant to the terms of the Progress Energy 2002 Equity Incentive Plan (EIP), which was approved by the Progress Energy’s shareholders on May 8, 2002. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

(c)    Consideration. The performance share awards were initially granted during the employee’s term of employment to provide an incentive to the former employee to exert his utmost efforts on Progress Energy’s behalf and thus enhance our performance while aligning the employee's interest with those of our shareholders.

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

98

(c)ISSUER PURCHASES OF EQUITY SECURITIES FOR THIRD QUARTER OF 2006

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)
July 1 - July 31	127,161	$43.9172	N/A	N/A
August 1- August 31	-	-	N/A	N/A
September 1 - September 30	173,500	$43.5255	N/A	N/A
Total	300,661	$43.6912	N/A	N/A

(1) As of September 30, 2006, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) Open-market transactions were executed by the plan administrator to purchase 300,661 shares of our common stock at an average price of $43.6912 to meet share delivery obligations under the Progress Energy 401(k) Savings and Stock Ownership Plan.

Item 6.Exhibits

(a) Exhibits

ExhibitNumber	Description	Progress Energy	PEC	PEF
31(a)	302 Certifications of Chief Executive Officer	X
31(b)	302 Certifications of Chief Financial Officer	X
31(c)	302 Certifications of Chief Executive Officer		X
31(d)	302 Certifications of Chief Financial Officer		X
31(e)	302 Certifications of Chief Executive Officer			X
31(f)	302 Certifications of Chief Financial Officer			X
32(a)	906 Certifications of Chief Executive Officer	X
32(b)	906 Certifications of Chief Financial Officer	X
32(c)	906 Certifications of Chief Executive Officer		X
32(d)	906 Certifications of Chief Financial Officer		X
32(e)	906 Certifications of Chief Executive Officer			X
32(f)	906 Certifications of Chief Financial Officer			X

99

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY
	FLORIDA POWER CORPORATION
Date: November 3, 2006	(Registrants)
	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 and Controller
	Progress Energy, Inc.
	Chief Accounting Officer
	Carolina Power & Light Company
	Florida Power Corporation

100