Duke Energy Progress 10-Q 2006 Q2 Quarterly report

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 June 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 July 31, 2006, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	253,348,322
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., PROGRESS ENERGY CAROLINAS, INC.

AND PROGRESS ENERGY FLORIDA, INC.

FORM 10-Q - For the Quarter Ended June 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 4. Submission of Matters to a Vote of Security Holders

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
BART	Best Available Retrofit Technology
Bcf	Billion cubic feet
Broad River	Broad River LLC’s Broad River Facility
Brunswick	Brunswick Nuclear Plant
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
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	Crystal River Unit No. 3 Nuclear Plant
CVO	Contingent value obligation
DeSoto	DeSoto County Generating Co., LLC
DIG Issue C20	FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”
Dixie Fuels	Dixie Fuels Limited
DOE	United States Department of Energy
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

4

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 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	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
MW	Megawatt
MWh	Megawatt-hour
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCNG	North Carolina Natural Gas Corporation
NSR	New Source Review requirement by EPA
NCUC	North Carolina Utilities Commission

5

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
OPEB	Postretirement benefits other than pensions
P11	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
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 Energy	Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants	The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
Progress Fuels	Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail	Progress Rail Services Corporation
Progress Ventures	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
PTC	Progress Telecommunications Corporation
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.
PWR	Pressurized water reactor
QF	Qualifying facility
RCA	Revolving credit agreement
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	Robinson Nuclear Plant
ROE	Return on equity
Rowan	Rowan County Power, LLC
RSA	Restricted stock awards program
RTO	Regional transmission organization
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

6

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”
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., an indirectly owned subsidiary of Progress Fuels Corporation

7

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 ability to manage the risks associated with our energy marketing operations, including potential impairment charges caused by adverse changes in market or business conditions; the ability to divest of our gas and other selected assets on a timely basis; 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, as appropriate, in PART II, Item 1A of this Form 10-Q. 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.

8

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

PROGRESS ENERGY, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

June 30, 2006

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions except per share data)	2006			2005			2006			2005
Operating revenues
Electric	$	2,082		$	1,768		$	4,067		$	3,551
Diversified business		417			497			858			856
Total operating revenues		2,499			2,265			4,925			4,407
Operating expenses
Utility
Fuel used in electric generation		709			529			1,399			1,079
Purchased power		260			217			489			415
Operation and maintenance		417			543			833			949
Depreciation and amortization		234			207			462			415
Taxes other than on income		120			108			239			225
Other		−			(25	)		(2	)		(25	)
Diversified business
Cost of sales		398			492			800			853
Depreciation and amortization		33			32			65			59
Impairment of assets (Notes 6 and 7)		91			−			155			−
Gain on the sale of assets		−			−			(7	)		(4	)
Other		28			26			50			55
Total operating expenses		2,290			2,129			4,483			4,021
Operating income		209			136			442			386
Other income (expense)
Interest income		7			4			24			8
Other, net		11			(6	)		9			(5	)
Total other income (expense)		18			(2	)		33			3
Interest charges
Net interest charges		173			163			351			325
Allowance for borrowed funds used during construction		(2	)		(4	)		(4	)		(7	)
Total interest charges, net		171			159			347			318
Income (loss) from continuing operations before income tax and minority interest		56			(25	)		128			71
Income tax expense (benefit)		35			(23	)		48			(25	)
Income (loss) from continuing operations before minority interest		21			(2	)		80			96
Minority interest in subsidiaries’ (income) loss, net of tax		(7	)		8			(14	)		16
Income from continuing operations		14			6			66			112
Discontinued operations, net of tax		(61	)		(7	)		(68	)		(20	)
Net (loss) income	$	(47	)	$	(1	)	$	(2	)	$	92
Average common shares outstanding - basic		250			246			250			245
Basic earnings per common share
Income from continuing operations	$	0.06		$	0.02		$	0.26		$	0.46
Discontinued operations, net of tax		(0.25	)		(0.03	)		(0.27	)		(0.09	)
Net (loss) income	$	(0.19	)	$	(0.01	)	$	(0.01	)	$	0.37
Diluted earnings per common share
Income from continuing operations	$	0.06		$	0.02		$	0.26		$	0.46
Discontinued operations, net of tax		(0.25	)		(0.03	)		(0.27	)		(0.09	)
Net (loss) income	$	(0.19	)	$	(0.01	)	$	(0.01	)	$	0.37
Dividends declared per common share	$	0.605		$	0.590		$	1.210		$	1.180

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

9

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	June 30, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	23,240		$	22,940
Accumulated depreciation		(9,854	)		(9,602	)
Utility plant in service, net		13,386			13,338
Held for future use		12			12
Construction work in progress		1,060			813
Nuclear fuel, net of amortization		249			279
Total utility plant, net		14,707			14,442
Current assets
Cash and cash equivalents		264			606
Short-term investments		95			191
Receivables, net		998			1,099
Inventory		948			848
Deferred fuel cost		449			602
Deferred income taxes		44			50
Assets of discontinued operations		384			722
Prepayments and other current assets		154			209
Total current assets		3,336			4,327
Deferred debits and other assets
Regulatory assets		825			854
Nuclear decommissioning trust funds		1,181			1,133
Diversified business property, net		1,309			1,318
Miscellaneous other property and investments		478			476
Goodwill		3,655			3,719
Intangibles, net		234			277
Other assets and deferred debits		429			478
Total deferred debits and other assets		8,111			8,255
Total assets	$	26,154		$	27,024
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 253 and 252 million shares issued and outstanding, respectively	$	5,653		$	5,571
Unearned ESOP shares (2 and 3 million shares, respectively)		(50	)		(63	)
Accumulated other comprehensive loss		(87	)		(104	)
Retained earnings		2,328			2,634
Total common stock equity		7,844			8,038
Preferred stock of subsidiaries - not subject to mandatory redemption		93			93
Minority interest		16			43
Long-term debt, affiliate		270			270
Long-term debt, net		9,822			10,176
Total capitalization		18,045			18,620
Current liabilities
Current portion of long-term debt		460			513
Accounts payable		654			676
Interest accrued		199			208
Dividends declared		153			152
Short-term obligations		−			175
Customer deposits		214			200
Liabilities of discontinued operations		32			91
Other current liabilities		808			871
Total current liabilities		2,520			2,886
Deferred credits and other liabilities
Noncurrent income tax liabilities		246			277
Accumulated deferred investment tax credits		157			163
Regulatory liabilities		2,500			2,527
Asset retirement obligations		1,279			1,249
Accrued pension and other benefits		904			870
Other liabilities and deferred credits		503			432
Total deferred credits and other liabilities		5,589			5,518
Commitments and contingencies (Note 14)
Total capitalization and liabilities	$	26,154		$	27,024

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

10

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Six Months Ended June 30	2006			2005
Operating activities
Net (loss) income	$	(2	)	$	92
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Discontinued operations, net of tax		68			20
Impairment of assets (Notes 6 and 7)		155			−
Charges for voluntary enhanced retirement program		−			158
Depreciation and amortization		575			534
Deferred income taxes		(28	)		(137	)
Investment tax credit		(6	)		(6	)
Tax levelization		19			63
Deferred fuel cost		170			−
Other adjustments to net income		113			65
Cash provided (used) by changes in operating assets and liabilities
Receivables		85			(67	)
Inventories		(107	)		(125	)
Prepayments and other current assets		(5	)		15
Accounts payable		(6	)		75
Other current liabilities		(8	)		(59	)
Regulatory assets and liabilities		4			(52	)
Other operating activities		18			(47	)
Net cash provided by operating activities		1,045			529
Investing activities
Gross utility property additions		(669	)		(539	)
Diversified business property additions		(92	)		(120	)
Nuclear fuel additions		(62	)		(67	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		221			444
Purchases of available-for-sale securities and other investments		(956	)		(3,205	)
Proceeds from sales of available-for-sale securities and other investments		1,126			3,229
Other investing activities		(14	)		(23	)
Net cash used in investing activities		(446	)		(281	)
Financing activities
Issuance of common stock		60			171
Proceeds from issuance of long-term debt, net		397			792
Net decrease in short-term indebtedness		(175	)		(281	)
Retirement of long-term debt		(802	)		(517	)
Dividends paid on common stock		(303	)		(289	)
Cash distributions to minority interests of consolidated subsidiary		(74	)		-
Other financing activities		(41	)		(24	)
Net cash used in financing activities		(938	)		(148	)
Cash provided (used) by discontinued operations
Operating activities		4			(1	)
Investing activities		(7	)		(14	)
Financing activities		-			-
Net (decrease) increase in cash and cash equivalents		(342	)		85
Cash and cash equivalents at beginning of period		606			56
Cash and cash equivalents at end of period	$	264		$	141

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

11

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

June 30, 2006

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Operating revenues
Electric	$	935		$	860		$	1,913		$	1,795
Diversified business		1			1			1			1
Total operating revenues		936			861			1,914			1,796
Operating expenses
Fuel used in electric generation		262			216			558			464
Purchased power		80			73			144			140
Operation and maintenance		248			260			504			484
Depreciation and amortization		129			130			255			259
Taxes other than on income		44			42			90			88
Other		(1	)		−			−			−
Total operating expenses		762			721			1,551			1,435
Operating income		174			140			363			361
Other income (expense)
Interest income		4			1			11			3
Other, net		(1	)		(2	)		(2	)		(1	)
Total other income (expense)		3			(1	)		9			2
Interest charges
Interest charges		57			50			114			102
Allowance for borrowed funds used during construction		−			(2	)		(1	)		(3	)
Total interest charges, net		57			48			113			99
Income before income tax		120			91			259			264
Income tax expense		44			24			97			81
Net income		76			67			162			183
Preferred stock dividend requirement		−			−			1			1
Earnings for common stock	$	76		$	67		$	161		$	182

See Notes to PEC Consolidated Interim Financial Statements.

12

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	June 30, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	14,184		$	13,994
Accumulated depreciation		(6,298	)		(6,120	)
Utility plant in service, net		7,886			7,874
Held for future use		3			3
Construction work in progress		463			399
Nuclear fuel, net of amortization		185			203
Total utility plant, net		8,537			8,479
Current assets
Cash and cash equivalents		156			125
Short-term investments		50			191
Receivables, net		441			518
Receivables from affiliated companies		14			24
Inventory		481			451
Deferred fuel cost		271			261
Prepayments and other current assets		42			20
Total current assets		1,455			1,590
Deferred debits and other assets
Regulatory assets		395			421
Nuclear decommissioning trust funds		669			640
Miscellaneous other property and investments		194			188
Other assets and deferred debits		174			184
Total deferred debits and other assets		1,432			1,433
Total assets	$	11,424		$	11,502
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$	2,002		$	1,981
Unearned ESOP common stock		(50	)		(63	)
Accumulated other comprehensive loss		(122	)		(120	)
Retained earnings		1,311			1,320
Total common stock equity		3,141			3,118
Preferred stock - not subject to mandatory redemption		59			59
Long-term debt, net		3,668			3,667
Total capitalization		6,868			6,844
Current liabilities
Accounts payable		221			247
Payables to affiliated companies		64			73
Notes payable to affiliated companies		23			11
Interest accrued		75			73
Short-term obligations		−			73
Customer deposits		56			52
Taxes accrued		10			100
Other current liabilities		294			255
Total current liabilities		743			884
Deferred credits and other liabilities
Noncurrent income tax liabilities		803			814
Accumulated deferred investment tax credits		130			133
Regulatory liabilities		1,207			1,196
Asset retirement obligations		978			949
Accrued pension and other benefits		531			511
Other liabilities and deferred credits		164			171
Total deferred credits and other liabilities		3,813			3,774
Commitments and contingencies (Note 14)
Total capitalization and liabilities	$	11,424		$	11,502

See Notes to PEC Consolidated Interim Financial Statements.

13

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Six Months Ended June 30	2006			2005
Operating activities
Net income	$	162		$	183
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program		−			42
Depreciation and amortization		295			301
Deferred income taxes and investment tax credits, net		36			4
Deferred fuel cost (credit)		7			(36	)
Other adjustments to net income		69			42
Cash provided (used) by changes in operating assets and liabilities
Receivables		76			3
Receivables from affiliated companies		20			17
Inventories		(36	)		(64	)
Prepayments and other current assets		5			1
Accounts payable		11			(3	)
Payables to affiliated companies		(11	)		(16	)
Other current liabilities		(115	)		35
Other operating activities		(16	)		(54	)
Net cash provided by operating activities		503			455
Investing activities
Gross utility property additions		(307	)		(303	)
Nuclear fuel additions		(56	)		(33	)
Purchases of available-for-sale securities and other investments		(453	)		(1,344	)
Proceeds from sales of available-for-sale securities and other investments		578			1,390
Other investing activities		(3	)		(6	)
Net cash used in investing activities		(241	)		(296	)
Financing activities
Proceeds from issuance of long-term debt, net		−			495
Net decrease in short-term indebtedness		(73	)		(79	)
Changes in advances from affiliates		12			(49	)
Retirement of long-term debt		−			(300	)
Dividends paid to parent		(169	)		(229	)
Dividends paid on preferred stock		(1	)		(1	)
Net cash used in financing activities		(231	)		(163	)
Net increase (decrease) in cash and cash equivalents		31			(4	)
Cash and cash equivalents at beginning of period		125			18
Cash and cash equivalents at end of period	$	156		$	14

See Notes to PEC Consolidated Interim Financial Statements.

14

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

INTERIM FINANCIAL STATEMENTS

June 30, 2006

UNAUDITED STATEMENTS of INCOME
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Operating revenues	$	1,147		$	908		$	2,154		$	1,756
Operating expenses
Fuel used in electric generation		447			313			841			615
Purchased power		180			144			345			275
Operation and maintenance		178			288			344			477
Depreciation and amortization		98			71			193			141
Taxes other than on income		76			66			149			133
Other		1			(25	)		(2	)		(25	)
Total operating expenses		980			857			1,870			1,616
Operating income		167			51			284			140
Other income (expense)
Interest income		3			−			8			−
Other, net		3			(1	)		2			2
Total other income (expense)		6			(1	)		10			2
Interest charges
Interest charges		40			34			80			68
Allowance for borrowed funds used during construction		(2	)		(2	)		(3	)		(4	)
Total interest charges, net		38			32			77			64
Income before income taxes		135			18			217			78
Income tax expense		48			8			77			24
Net income		87			10			140			54
Preferred stock dividend requirement		−			−			1			1
Earnings for common stock	$	87		$	10		$	139		$	53

See Notes to PEF Interim Financial Statements.

15

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED BALANCE SHEETS
(in millions)	June 30, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	8,872		$	8,756
Accumulated depreciation		(3,506	)		(3,434	)
Utility plant in service, net		5,366			5,322
Held for future use		9			9
Construction work in progress		597			414
Nuclear fuel, net of amortization		64			76
Total utility plant, net		6,036			5,821
Current assets
Cash and cash equivalents		77			218
Short-term investments		45			-
Receivables, net		368			331
Receivables from affiliated companies		10			11
Deferred income taxes		30			12
Inventory		397			311
Deferred fuel cost		178			341
Prepayments and other current assets		71			100
Total current assets		1,176			1,324
Deferred debits and other assets
Regulatory assets		343			351
Debt issuance costs		21			22
Nuclear decommissioning trust funds		512			493
Miscellaneous other property and investments		45			47
Prepaid pension costs		208			200
Other assets and deferred debits		65			60
Total deferred debits and other assets		1,194			1,173
Total assets	$	8,406		$	8,318
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$	1,098		$	1,097
Retained earnings		1,519			1,498
Total common stock equity		2,617			2,595
Preferred stock - not subject to mandatory redemption		34			34
Long-term debt, net		2,554			2,554
Total capitalization		5,205			5,183
Current liabilities
Current portion of long-term debt		48			48
Accounts payable		303			237
Payables to affiliated companies		80			101
Notes payable to affiliated companies		24			13
Short-term obligations		−			102
Customer deposits		158			148
Interest accrued		38			42
Other current liabilities		194			101
Total current liabilities		845			792
Deferred credits and other liabilities
Noncurrent income tax liabilities		432			433
Accumulated deferred investment tax credits		27			30
Regulatory liabilities		1,159			1,189
Asset retirement obligations		291			290
Accrued pension and other benefits		268			257
Other liabilities and deferred credits		179			144
Total deferred credits and other liabilities		2,356			2,343
Commitments and contingencies (Note 14)
Total capitalization and liabilities	$	8,406		$	8,318

See Notes to PEF Interim Financial Statements.

16

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED STATEMENTS of CASH FLOWS
(in millions)
Six Months Ended June 30	2006			2005
Operating activities
Net income	$	140		$	54
Adjustments to reconcile net income to net cash provided by operating activities
Charges for voluntary enhanced retirement program		−			90
Depreciation and amortization		207			158
Deferred income taxes and investment tax credits, net		(22	)		(55	)
Deferred fuel cost		163			36
Other adjustments to net income		10			23
Cash (used) provided by changes in operating assets and liabilities
Receivables		(43	)		(42	)
Receivables from affiliated companies		2			5
Inventories		(87	)		(35	)
Prepayments and other current assets		8			(4	)
Accounts payable		51			34
Payables to affiliated companies		(21	)		10
Other current liabilities		81			18
Regulatory assets and liabilities		2			(54	)
Other operating activities		(4	)		6
Net cash provided by operating activities		487			244
Investing activities
Gross utility property additions		(371	)		(253	)
Nuclear fuel additions		(6	)		(34	)
Proceeds from sale of assets		3			42
Purchases of available-for-sale securities and other investments		(329	)		(177	)
Proceeds from sales of available-for-sale securities and other investments		284			177
Changes in advances to affiliates		−			(26	)
Other investing activities		1			(4	)
Net cash used in investing activities		(418	)		(275	)
Financing activities
Proceeds from issuance of long-term debt, net		−			297
Net decrease in short-term indebtedness		(102	)		(32	)
Retirement of long-term debt		(2	)		(57	)
Changes in advances from affiliates		11			(178	)
Dividends paid to parent		(118	)		−
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		2			−
Net cash (used) provided by financing activities		(210	)		29
Net decrease in cash and cash equivalents		(141	)		(2	)
Cash and cash equivalents at beginning of period		218			12
Cash and cash equivalents at end of period	$	77		$	10

See Notes to PEF Interim Financial Statements.

17

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 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

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.

COMBINED NOTES TO 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, energy marketing activities and natural gas drilling and production. 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. On May 22, 2006, we idled our synthetic fuel facilities (See Note 6). 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. Income tax expense was increased (decreased) for the Progress Registrants for the three and six months ended June 30, 2006 and 2005, as follows:

19

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2006			2005		2006			2005
Progress Energy	$	3		$	60	$	19		$	63
PEC		(2	)		3		(1	)		3
PEF		-			8		-			8

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 of income are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2006		2005		2006		2005
Progress Energy	$	69	$	58	$	134	$	114
PEC		21		20		43		41
PEF		48		38		91		73

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 June 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 approximately $8 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 June 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 plant owner are variable interest entities or to identify the primary beneficiaries; all entities from which the necessary financial information

20

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 approximately 20 limited liability partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. At June 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 approximately $23 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 two variable interest entities for which PEF is not the primary beneficiary. These arrangements include investments in one venture capital fund and one building lease with a special-purpose entity. At June 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 approximately $1 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 an 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 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 have not yet evaluated how FIN 48 will impact our various income tax positions and results of operations.

3.DIVESTITURES

A.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, Florida 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 expect to use the proceeds from the sales to reduce debt and for other corporate purposes.

The sale of DeSoto closed in the second quarter of 2006. The sale of Rowan is expected to close during the third quarter of 2006 and is subject to state and federal regulatory approvals and customary closing conditions. We recorded an after-tax loss on the sale of DeSoto of $30 million and an estimated after-tax loss on the sale of Rowan of $32 million.

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

21

months ended June 30, 2006 and 2005 was $3 million and $4 million, respectively. Interest expense allocated for each of the six months ended June 30, 2006 and 2005 was $7 million. 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 June 30, 2006 and 2005 totaled $1 million and $2 million, respectively. After-tax depreciation expense recorded by DeSoto and Rowan during the six months ended June 30, 2006 and 2005 totaled $3 million and $4 million, respectively. Results of discontinued operations were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Revenues	$	8		$	15		$	14		$	25
(Loss) Earnings before income taxes		(2	)		1			(7	)		(1	)
Income tax benefit (expense)		1			(2	)		1			(2	)
Net loss from discontinued operations		(1	)		(1	)		(6	)		(3	)
Estimated loss on disposal of discontinued operations, including income tax benefit of $38		(62	)		-			(62	)		-
Loss from discontinued operations	$	(63	)	$	(1	)	$	(68	)	$	(3	)

B.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 resulting in a total after-tax gain of $29 million for the six months ended June 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 six months ended June 30, 2005 was $1 million. Interest expense allocated for the three months ended June 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 six months ended June 30, 2006 and 2005 was $1 million and $4 million, respectively. After-tax depreciation expense recorded for the three months ended June 30, 2005 was $2 million. Results of discontinued operations were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Revenues	$	-		$	16		$	18		$	32
Earnings before income taxes and minority interest		2			3			3			3
Income tax expense		-			-			(4	)		-
Minority interest		(1	)		(1	)		(4	)		(1	)
Net earnings (loss) from discontinued operations		1			2			(5	)		2
Estimated gain on disposal of discontinued operations, including income tax benefit (expense) of $4 and $(9), respectively, and minority interest of $36		5			-			29			-
Earnings from discontinued operations	$	6		$	2		$	24		$	2

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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.

C.Progress Rail Divestiture

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 $24 million during the six months ended June 30, 2005. During the remainder of 2005, we recorded an additional loss of $1 million after finalizing the working capital adjustment and other operating estimates. During the six months ended June 30, 2006, we recorded an additional after-tax loss on disposal of $3 million in connection with guarantees and indemnifications provided by Progress Fuels Corporation (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 six months ended June 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 six months ended June 30, 2005 was $3 million. Results of discontinued operations were as follows:

	Three Months Ended June 30,						Six Months Ended June 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 $2 and $2 for 2006, respectively, and $- and $14 for 2005, respectively		(3	)		(7	)		(3	)		(24	)
Loss from discontinued operations	$	(3	)	$	(7	)	$	(3	)	$	(19	)

D.Coal Mines Divestiture

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 an estimated $4 million working capital adjustment. As a result, during the six months ended June 30, 2006, we recorded an after-tax loss of $17 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 June 30, 2005. Interest expense allocated was $1 million for each of the six months ended June 30, 2006 and 2005. 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 six months ended June 30, 2005 was $3 million and $5 million, respectively. Results of discontinued operations were as follows:

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	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Revenues	$	24		$	44		$	59		$	94
Earnings (loss) before income taxes		1			(2	)		(6	)		(1	)
Income tax benefit		-			1			2			1
Net earnings (loss) from discontinued operations		1			(1	)		(4	)		-
Estimated loss on disposal of discontinued operations, including income tax benefit of $5 and $13		(2	)		-			(17	)		-
Loss from discontinued operations	$	(1	)	$	(1	)	$	(21	)	$	-

E.   Net Assets of Discontinued Operations

Included in net assets of discontinued operations are the assets and liabilities of Rowan and the remaining coal mining operations at June 30, 2006 and the assets and liabilities of DeSoto and Rowan, PT LLC and the five coal mining operations at December 31, 2005. The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheet were as follows:

(in millions)	June 30, 2006		December 31, 2005
Accounts receivable	$	14	$	18
Inventory		16		25
Other current assets		2		5
Total property, plant and equipment, net		341		659
Total other assets		11		15
Assets of discontinued operations	$	384	$	722
Accounts payable	$	2	$	12
Accrued expenses		10		21
Long-term liabilities		20		58
Liabilities of discontinued operations	$	32	$	91

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 proceedings. 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. PEC asked the NCUC to approve a $292 million, or 11.0 percent, increase in rates. PEC requested the increase for under-recovered fuel costs and to meet future expected fuel costs. If the fuel rate increase is approved, residential electric bills would increase by $8.04 per 1,000 kWhs for fuel cost recovery beginning October 1, 2006. We cannot predict the outcome of this matter.

On July 25, 2006, PEC, the NCUC Public Staff and Carolinas Industrial Group for Fair Utility Rates II jointly filed a proposed settlement agreement with the NCUC to resolve issues concerning PEC’s 2006 North Carolina fuel adjustment proceeding. Other intervening parties to the fuel proceeding have not agreed to the proposed settlement. The settlement proposes that PEC collect its fuel cost undercollection over a three-year period beginning October 1,

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2006. Under the proposed settlement, PEC agreed to reduce its proposed billing rate during the year ending September 30, 2007. PEC would be allowed to calculate and collect interest at 6% on the difference between its collection factor in the original request to the NCUC and the factor included in the proposed settlement agreement. Also included in the settlement are increased billing rates for the 2007 and 2008 proceedings that will recover the undercollected fuel balance over the three-year period. These rates are subject to change based upon market conditions. Hearings on this matter are scheduled for August 9, 2006 with an order expected in September 2006. If approved, the increase would take effect October 1, 2006. We cannot predict the outcome of this matter.

B.PEF Retail Rate Matters

STORM COST RECOVERY

On June 1, 2005, the governor of Florida signed into law a bill that allows utilities to petition the FPSC to use securitized bonds to recover storm-related costs. PEF has decided not to pursue the issuance of securitized bonds either to recover its 2004 storm-related costs or to replenish its storm reserve fund. PEF’s base rates provide $6 million annually for storm reserve replenishment. On April 25, 2006, PEF entered into a settlement agreement with the 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 would replenish the existing storm reserve by an estimated additional $130 million. In the event future storms cause the reserve to be depleted, the settlement would further allow PEF to automatically collect from customers 80 percent of any future depletion of the storm reserve pending the FPSC’s ultimate review and determination of the actual costs incurred and recoverable by PEF. The FPSC has the right to review PEF’s storm costs for prudence and has the authority to determine the manner and timing of recovery. The parties have sought the FPSC’s approval of the settlement and the matter is scheduled for the FPSC’s August 29, 2006 meeting. We cannot predict the outcome of this matter.

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 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 it is not probable that recovery of these costs will be disallowed by the FPSC in subsequent proceedings. We cannot predict the outcome of this matter.

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

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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 June 30,				Six Months Ended June 30,
(in millions)	2006		2005		2006		2005
Weighted-average common shares - basic		250		246		250		245
Net effect of dilutive stock-based compensation plans		1		1		-		1
Weighted-average shares - fully dilutive		251		247		250		246

B.Comprehensive Income

Progress Energy

	Three Months Ended June 30,
(in millions)	2006			2005
Net loss	$	(47	)	$	(1	)
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $2, respectively)		3			3
Changes in net unrealized gains on cash flow hedges (net of tax expense of $9 and $26, respectively)		5			44
Other (net of tax (benefit) expense of ($2) and $1, respectively)		(5	)		(1	)
Other comprehensive income		3			46
Comprehensive (loss) income	$	(44	)	$	45

	Six Months Ended June 30,
(in millions)	2006			2005
Net (loss) income	$	(2	)	$	92
Other comprehensive (loss) income
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax (benefit) expense of ($1) and $3, respectively)		(1	)		5
Foreign currency translation adjustments included in discontinued operations		−			(6	)
Minimum pension liability adjustment included in discontinued operations (net of tax expense of $1)		−			1
Changes in net unrealized gains on cash flow hedges (net of tax expense of $16 and $31, respectively)		18			50
Other (net of tax expense of $− and $1, respectively)		−			1
Other comprehensive income		17			51
Comprehensive income	$	15		$	143

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PEC

	Three Months Ended June 30,
(in millions)	2006			2005
Net income	$	76		$	67
Other comprehensive (loss) income
Changes in net unrealized gains on cash flow hedges (net of tax benefit of $1)		(2	)		−
Other (net of tax benefit of $− and $−, respectively)		(1	)		1
Other comprehensive (loss) income		(3	)		1
Comprehensive income	$	73		$	68

	Six Months Ended June 30,
(in millions)	2006			2005
Net income	$	162		$	183
Other comprehensive (loss) income
Changes in net unrealized gains on cash flow hedges (net of tax (benefit) expense of ($1) and $1, respectively)		(2	)		2
Other (net of tax benefit of $− and $−, respectively)		−			1
Other comprehensive (loss) income		(2	)		3
Comprehensive income	$	160		$	186

PEF

Comprehensive income and net income for PEF for the three months ended June 30, 2006 and 2005 were $87 million and $10 million, respectively, and for the six months ended June 30, 2006 and 2005 were $140 million and $54 million, respectively.

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 June 30, 2006 and 2005, respectively, we issued approximately 0.7 million shares and 2.6 million shares of common stock resulting in approximately $32 million and $111 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 six months ended June 30, 2006 and 2005, respectively, we issued approximately 1.4 million shares and 4.0 million shares of common stock resulting in approximately $60 million and $171 million in proceeds, net of purchases of restricted shares. Included in these amounts were approximately 1.0 million shares and 3.9 million shares for net proceeds of approximately $46 million and $169 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.

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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 three and six months ended June 30, 2005:

(in millions except per share data)	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
Net (loss) income, as reported	$	(1	)	$	92
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1			2
Pro forma net (loss) income	$	(2	)	$	90
(Loss) Earnings per share
Basic - as reported	$	(0.01	)	$	0.37
Basic - pro forma	$	(0.01	)	$	0.36
Diluted - as reported	$	(0.01	)	$	0.37
Diluted - pro forma	$	(0.01	)	$	0.36

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 three and six months ended June 30, 2005:

(in millions )	Three Months Ended June 30, 2005		Six Months Ended June 30, 2005
Net income, as reported	$	67	$	183
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1		2
Pro forma net income	$	66	$	181

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 three and six months ended June 30, 2005:

(in millions)	Three Months Ended June 30, 2005		Six Months Ended June 30, 2005
Net income, as reported	$	10	$	54
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		-		1
Pro forma net income	$	10	$	53

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

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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:

(in millions)	PEC		PEF		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 June 30, 2006	$	1,922	$	1,733	$	-		$	3,655

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

	June 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		(27	)		188		(19	)
Other		86		(13	)		84		(12	)
Total	$	381	$	(147	)	$	406	$	(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 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 continued “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.

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.

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8. DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES

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 this new shelf registration statement, in addition to the $679 million of various securities which were not sold from our prior shelf registration statement. Therefore, effective March 31, 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 is replacing 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 and BBB- by 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.

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 and six months ended June 30 were:

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Progress Energy

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2006			2005			2006			2005
Service cost	$	12		$	15		$	2		$	3
Interest cost		29			29			9			8
Expected return on plan assets		(36	)		(37	)		(1	)		(1	)
Amortization of actuarial loss		9			6			2			1
Other amortization, net		-			1			-			-
Net periodic cost		14			14			12			11
Additional (benefit) cost recognition (a)		(3	)		(4	)		1			1
Net periodic cost recognized	$	11		$	10		$	13		$	12

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Service cost	$	23		$	30		$	4		$	6
Interest cost		58			57			17			16
Expected return on plan assets		(72	)		(73	)		(3	)		(3	)
Amortization of actuarial loss		18			12			5			2
Other amortization, net		1			1			1			1
Net periodic cost		28			27			24			22
Additional (benefit) cost recognition (a)		(7	)		(8	)		1			1
Net periodic cost recognized	$	21		$	19		$	25		$	23

^(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, the Company recorded costs for special termination benefits related to its voluntary enhanced retirement program of approximately $122 million for pension benefits and $19 million for other postretirement benefits.

PEC

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2006			2005			2006			2005
Service cost	$	6		$	7		$	1		$	2
Interest cost		13			13			5			4
Expected return on plan assets		(15	)		(16	)		(1	)		(1	)
Amortization of actuarial loss		3			1			1			-
Other amortization, net		-			1			-			-
Net periodic cost	$	7		$	6		$	6		$	5

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	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Service cost	$	11		$	13		$	2		$	3
Interest cost		25			27			9			8
Expected return on plan assets		(29	)		(31	)		(2	)		(2	)
Amortization of actuarial loss		7			2			2			1
Other amortization, net		1			2			1			-
Net periodic cost	$	15		$	13		$	12		$	10

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 June 30,
(in millions)	2006			2005			2006		2005
Service cost	$	4		$	6		$	1	$	1
Interest cost		12			11			3		3
Expected return on plan assets		(19	)		(18	)		-		-
Amortization of actuarial loss		2			-			-		-
Other amortization, net		-			-			1		1
Net periodic (benefit) cost	$	(1	)	$	(1	)	$	5	$	5

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Service cost	$	8		$	11		$	2		$	2
Interest cost		25			22			7			7
Expected return on plan assets		(37	)		(36	)		(1	)		-
Amortization of actuarial loss		3			1			1			-
Other amortization, net		(1	)		-			2			2
Net periodic (benefit) cost	$	(2	)	$	(2	)	$	11		$	11

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.

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

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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. See Note 18 to the 2005 Form 10-K.

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 June 30, 2006 and December 31, 2005, the remaining liability was $17 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. Gains and losses from such contracts were not material to our or the Utilities’ results of operations for the three and six months ended June 30, 2006 and 2005. PEC did not have material outstanding positions in such contracts at June 30, 2006 or December 31, 2005. We and PEF did not have material outstanding positions in such contracts at June 30, 2006 or December 31, 2005, other than those receiving regulatory accounting treatment at PEF, 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 clause. At June 30, 2006, the fair values of these instruments were a $55 million short-term derivative asset position included in other current assets, a $48 million long-term derivative asset position included in other assets and deferred debits, a $15 million short-term derivative liability position included in other current liabilities and a $53 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 and power for our forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate. During the three months ending June 30, 2006, $7 million in after-tax deferred losses were reclassified to earnings due to discontinuance of the related cash flow hedges in anticipation of the sale of our gas business (See Note 16). The ineffective portion of commodity cash flow hedges for the three and six months ended June 30, 2006 and 2005, was not material to our or the Utilities’ results of operations.

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

	June 30, 2006							December 31, 2005
(in millions)	Progress Energy			PEC		PEF		Progress Energy			PEC			PEF
Fair value of assets	$	145		$	-	$	-	$	170		$	7		$	-
Fair value of liabilities		(1	)		-		-		(58	)		(4	)		-
Fair value, net	$	144		$	-	$	-	$	112		$	3		$	-

The following table presents selected information related to our commodity cash flow hedges at June 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		9		-		-	$	78	$	-	$	-	$	(6	)	$	-	$	-

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

^(b) Includes amounts related to de-designated 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 - Fair Value or Cash Flow Hedges

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

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

	June 30, 2006							December 31, 2005
(in millions)	Progress Energy			PEC		PEF		Progress Energy			PEC		PEF
Interest rate cash flow hedges	$	-		$	-	$	-	$	1		$	-	$	-
Interest rate fair value hedges		(5	)		-		-		(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 ended June 30, 2006 and 2005, was not material to our or the Utilities’ results of operations.

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The following table presents selected information related to interest rate cash flow hedges at June 30, 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		-		-		-	$	(12	)	$	(5	)	$	-	$	(2	)	$	(1	)	$	-

^(a) Amounts relate to terminated hedges.

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. The fair value of these swaps was not material at June 30, 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 June 30, 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, energy marketing activities and natural gas drilling and production (See Note 16).

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. 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, 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 and 3B, respectively), the operations of (i) DeSoto and Rowan and (ii) PT LLC were reclassified to discontinued operations in the second and first quarters of 2006, respectively, and therefore are not included in the results from continuing operations

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during the periods reported. During the fourth quarter of 2005, we reclassified our coal mining operations as discontinued operations (See Note 3D). Income 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 and six months ended June 30:

											Income (loss)
	Revenues								Cost		from			Assets of
(in millions)	Unaffiliated		Intersegment			Total			Management Initiative		Continuing Operations			Continuing Operations
Three Months Ended June 30, 2006
PEC	$	936	$	-		$	936		$	-	$	76		$	11,424
PEF		1,147		-			1,147			-		87			8,406
Progress Ventures		189		-			189			-		(8	)		1,738
Coal and Synthetic Fuels		222		84			306			-		(91	)		252
Corporate and Other		5		103			108			-		(50	)		17,244
Eliminations		-		(187	)		(187	)		-		-			(13,294	)
Totals	$	2,499	$	-		$	2,499		$	-	$	14		$	25,770
Three Months Ended June 30, 2005
PEC	$	861	$	-		$	861		$	46	$	67
PEF		908		-			908			93		10
Progress Ventures		178		-			178			1		6
Coal and Synthetic Fuels		318		100			418			4		23
Corporate and Other		-		124			124			1		(100	)
Eliminations		-		(224	)		(224	)		-		-
Totals	$	2,265	$	-		$	2,265		$	145	$	6

											Income (loss)
	Revenues								Cost		from			Assets of
(in millions)	Unaffiliated		Intersegment			Total			Management Initiative		Continuing Operations			Continuing Operations
Six Months Ended June 30, 2006
PEC	$	1,914	$	-		$	1,914		$	-	$	161		$	11,424
PEF		2,154		-			2,154			-		139			8,406
Progress Ventures		393		-			393			-		(43	)		1,738
Coal and Synthetic Fuels		456		162			618			-		(77	)		252
Corporate and Other		8		192			200			-		(114	)		17,244
Eliminations		-		(354	)		(354	)		-		-			(13,294	)
Totals	$	4,925	$	-		$	4,925		$	-	$	66		$	25,770
Six Months Ended June 30, 2005
PEC	$	1,796	$	-		$	1,796		$	60	$	182
PEF		1,756		-			1,756			107		53
Progress Ventures		265		-			265			2		12
Coal and Synthetic Fuels		590		185			775			6		20
Corporate and Other		-		224			224			1		(155	)
Eliminations		-		(409	)		(409	)		-		-
Totals	$	4,407	$	-		$	4,407		$	176	$	112

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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:

Progress Energy

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2006		2005			2006		2005
Other income
Nonregulated energy and delivery services income	$	15	$	11		$	23	$	17
DIG Issue C20 amortization (see Note 10)		1		2			2		3
CVOs unrealized gain		3		-			3		-
Gain on sale of Level 3 stock (a)		8		-			32		-
Investment gains		-		-			3		1
AFUDC equity		4		5			7		9
Other		3		4			7		12
Total other income		34		22			77		42
Other expense
Nonregulated energy and delivery services expenses		7		5			13		10
Donations		5		5			12		11
CVOs unrealized loss		-		-			25		-
Loss from equity investments		1		2			1		4
FERC audit settlement		-		7			-		7
Other		10		9			17		15
Total other expense		23		28			68		47
Other, net - Progress Energy	$	11	$	(6	)	$	9	$	(5	)

^(a)   Other income includes gains of $8 million and $32 million for the three-month and six-month periods ending June 30, 2006, respectively, 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 3B). These gains are prior to the consideration of minority interest.

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PEC

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Other income
Nonregulated energy and delivery services income	$	8		$	7		$	10		$	9
DIG Issue C20 amortization (see Note 10)		1			2			2			3
AFUDC equity		1			1			2			2
Other		-			2			3			5
Total other income		10			12			17			19
Other expense
Nonregulated energy and delivery services expenses		2			2			3			4
Donations		3			2			6			5
FERC audit settlement		-			4			-			4
Other		6			6			10			7
Total other expense		11			14			19			20
Other, net - PEC	$	(1	)	$	(2	)	$	(2	)	$	(1	)

PEF

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2006		2005			2006		2005
Other income
Nonregulated energy and delivery services income	$	7	$	4		$	13	$	8
AFUDC equity		3		4			5		7
Other		-		-			1		1
Total other income		10		8			19		16
Other expense
Nonregulated energy and delivery services expenses		5		3			10		6
Donations		2		3			6		5
FERC audit settlement		-		3			-		3
Other		-		-			1		-
Total other expense		7		9			17		14
Other, net - PEF	$	3	$	(1	)	$	2	$	2

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.

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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.

The following table contains information about accruals for environmental remediation expenses described below. At June 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)	June 30, 2006		December 31, 2005
PEC
MGP and other sites(a)	$	24	$	7
PEF
Remediation of distribution and substation transformers		53		20
MGP and other sites		18		18
Total PEF environmental remediation accruals(b)		71		38
Progress Energy nonregulated operations		3		3
Total Progress Energy environmental remediation accruals	$	98	$	48

^(a)   Expected to be paid out over one to five years. PEC is planning to request orders from both the NCUC and SCPSC to defer and amortize the retail portion of certain of these costs, net of insurance proceeds, over a period of years. We cannot predict the outcome of this matter.

^(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 June 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 and six months ended June 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.

For the three months ended June 30, 2006, PEC made no additional accruals and spent approximately $1 million, and for the six months ended June 30, 2006, PEC accrued approximately $21 million and spent approximately $4

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million related to environmental remediation. For the three and six months ended June 30, 2005, PEC made no additional accruals and spent approximately $1 million and $3 million, respectively, related to environmental remediation.

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 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. 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 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 and six months ended June 30, 2006, PEF accrued approximately $1 million and $39 million, respectively, due to additional sites expected to require remediation and spent approximately $5 million and $6 million, respectively, related to the remediation of transformers. For the three and six months ended June 30, 2005, PEF made no additional accruals and spent approximately $3 million and $5 million, respectively, related to the remediation of transformers. 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 and six months ended June 30, 2006 and 2005, PEF made no additional accruals or material expenditures and received no insurance proceeds.

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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), and the Clean Air Mercury Rule (CAMR), which are discussed below, may address some of the issues outlined above. However, the outcome of the matter cannot be predicted.

The following tables contain information about 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 needed to meet compliance with the NOx SIP Call and Clean Smokestacks Act will reduce 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	Spent through June 30, 2006
NOx SIP Call	2002-2006	$355	$344
Clean Smokestacks Act	2002-2013	$1,100 - $1,400	404
CAIR/CAMR	2005-2018	$700 - $1,600	7
Incremental CAVR BART(a)		$-	-
Incremental NAAQS(b)		$-	-
Total air quality		$2,155 - $3,355	755
Clean Water Act Section 316(b)	2005-2010	$70 - $95	1
Total air and water quality		$2,225 - $3,450	$756

PEC

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Spent through June 30, 2006
NOx SIP Call	2002-2006	$355	$344
Clean Smokestacks Act	2002-2013	$1,100 - $1,400	404
CAIR/CAMR	2005-2018	$100 - $200	1
Incremental CAVR BART(a)		$-	-
Incremental NAAQS(b)		$-	-
Total air quality		$1,555 - $1,955	749
Clean Water Act Section 316(b)	2005-2010	$5 - $10	-
Total air and water quality		$1,560 - $1,965	$749

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PEF

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Spent through June 30, 2006
CAIR/CAMR	2005-2018	$600 - $1,400	$6
Incremental CAVR BART(a)		$-	-
Incremental NAAQS(b)		$-	-
Total air quality		$600 - $1,400	6
Clean Water Act Section 316(b)	2005-2010	$65 - $85	1
Total air and water quality		$665 - $1,485	$7

^(a)   Plans for compliance with the CAIR and CAMR are expected to fulfill the Best Available Retrofit Technology (BART) obligations of the Clean Air Visibility Rule (CAVR).

^(b)   Compliance plans will be determined upon finalization of the proposed changes to the National Ambient Air Quality Standards (NAAQS) for particulate matter.

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 EPA initiated civil enforcement actions against unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for 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. On May 15, 2006, the U.S. Supreme Court agreed to hear 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 nitrogen oxide 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 unrelated to 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 to 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, as shown in the above tables. The increase in estimated total capital expenditures from the original estimate of $813 million is primarily due

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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 evaluating various design, technology, and new generation options that could reduce expenditures required by the Clean Smokestacks Act.

Two of the coal-fired generation plants impacted by the Clean Smokestacks Act are jointly owned. The joint owners pay their ownership share of construction costs. In 2005, PEC entered into a contract 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 to approximately $38 million and recognized a related liability. At June 30, 2006 and December 31, 2005, the amount of the liability was $21 million and $16 million, respectively, based upon the current estimates for Clean Smokestacks Act compliance. As capital cost projections change, it is reasonably possible that additional losses, which could be material, may be incurred in the future.

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 $22 million and $44 million, respectively, for the three and six months ended June 30 2006, and has recognized $439 million in cumulative amortization through June 30, 2006. PEC recognized amortization of $27 million and $54 million, respectively, for the three and six months ended June 30 2005. The remaining amortization requirement of $130 million will be recorded over the 18-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.

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, MERCURY RULE AND CLEAN AIR VISIBILITY RULE

On March 10, 2005, the EPA issued the final CAIR. The EPA’s rule requires 28 states, including North Carolina, South Carolina, Georgia and Florida, and the District of Columbia 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 DC 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. The outcome of this matter 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

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and SO₂ under CAIR. States are required to adopt mercury rules implementing the CAMR by November 11, 2006, which must be reviewed and approved by the EPA. At June 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 summer and fall of 2006. The outcome of this matter cannot be 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. We expect that our plans for compliance with the CAIR and CAMR will 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 Unit No. 1, 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 for the CAIR and CAMR rules because NOx and SO₂ controls are effective in reducing mercury emissions. We are evaluating various design, technology, and new generation options that could reduce PEC’s and PEF’s costs required by the CAIR and CAMR.

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 and CAMR through the ECRC. On March 31, 2006, PEF filed a series of compliance alternatives with the FPSC to meet these federal environmental rules. PEF’s recommended proposed compliance plan includes 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. 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 increase or decrease depending upon the results of the engineering and strategy development work 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 and therefore result in additional costs in 2006.

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.

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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 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. The EPA also proposed to eliminate the current standards for particulate matter less than 10 microns in diameter. The EPA is scheduled to finalize the NAAQS standards by September 27, 2006. The changes could ultimately result in increased costs for installation of additional pollution controls at facilities operated by PEC and PEF. The outcome of this matter cannot be predicted.

WATER QUALITY

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. Section 316(b) of the Clean Water Act requires assessment of the environmental effect of withdrawal of water at our facilities. The outcome of this matter 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 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. On December 2, 2005, the U.S. Court of Appeals denied the request for rehearing. On March 2, 2006, the petitioners filed a petition for writ of certiorari with the U.S. Supreme Court, seeking a review of the U.S. Court of Appeals decision. On June 26, 2006, the U.S. Supreme Court agreed to review the decision. The outcome of this matter cannot be predicted.

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

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

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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 June 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 June 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 a contract 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 June 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 June 30, 2006 and December 31, 2005, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $59 million and $41 million, respectively. These amounts include $21 million and $16 million, respectively, for PEC at June 30, 2006 and December 31, 2005, and $8 million for PEF at June 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 predecessors to 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 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 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

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County, Nev.; and 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 recently 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 acknowledged that a working repository will not be operational until sometime after 2010. The DOE has not identified a new target date for placing the repository in service, but they have stated that they expect it to be open by 2020. 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 Crystal River Unit No. 3 (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 case is now resolved and dismissed.

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.

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 owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuel facilities, (2) that it is entitled to damages because Progress Affiliates prohibited it from procuring purchasers for the synthetic fuel facilities, and (3) that 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.

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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.

We have escrowed $41 million that otherwise would have been paid to Global through June 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 have sent communication to Global regarding the negotiation of 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 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 the coal mines, PT LLC, DeSoto and Rowan as discontinued operations as described in Note 3.

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Condensed Consolidating Statement of Income Three Months Ended June 30, 2006
(in millions)	Parent			Subsidiary Guarantor		Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,147	$	935		$	2,082
Diversified business		−			274		143			417
Total operating revenues		−			1,421		1,078			2,499
Operating expenses
Utility
Fuel used in electric generation		−			447		262			709
Purchased power		−			180		80			260
Operation and maintenance		3			178		236			417
Depreciation and amortization		−			98		136			234
Taxes other than on income		−			76		44			120
Other		−			1		(1	)		−
Diversified business
Cost of sales		−			226		172			398
Depreciation and amortization		−			17		16			33
Impairment of assets		−			44		47			91
Other		−			17		11			28
Total operating expenses		3			1,284		1,003			2,290
Operating (loss) income		(3	)		137		75			209
Other income (expense), net		12			9		(3	)		18
Interest charges, net		69			49		53			171
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(60	)		97		19			56
Income tax (benefit) expense		(26	)		36		25			35
Equity in earnings of consolidated subsidiaries		(13	)		−		13			−
Minority interest in subsidiaries’ income, net of tax		−			7		−			7
(Loss) income from continuing operations		(47	)		54		7			14
Discontinued operations, net of tax		−			2		(63	)		(61	)
Net (loss) income	$	(47	)	$	56	$	(56	)	$	(47	)

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Condensed Consolidating Statement of Income Three Months Ended June 30, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	908		$	860		$	1,768
Diversified business		−			364			133			497
Total operating revenues		−			1,272			993			2,265
Operating expenses
Utility
Fuel used in electric generation		−			313			216			529
Purchased power		−			144			73			217
Operation and maintenance		5			288			250			543
Depreciation and amortization		−			71			136			207
Taxes other than on income		−			66			42			108
Other		−			(25	)		−			(25	)
Diversified business
Cost of sales		−			344			148			492
Depreciation and amortization		−			16			16			32
Other		−			17			9			26
Total operating expenses		5			1,234			890			2,129
Operating (loss) income		(5	)		38			103			136
Other income (expense), net		14			(4	)		(12	)		(2	)
Interest charges, net		75			46			38			159
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(66	)		(12	)		53			(25	)
Income tax benefit		19			4			−			23
Equity in earnings of consolidated subsidiaries		46			−			(46	)		−
Minority interest in subsidiaries’ loss, net of tax		−			8			−			8
(Loss) income from continuing operations		(1	)		−			7			6
Discontinued operations, net of tax		−			(8	)		1			(7	)
Net (loss) income	$	(1	)	$	(8	)	$	8		$	(1	)

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Condensed Consolidating Statement of Income Six Months Ended June 30, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	2,154		$	1,913		$	4,067
Diversified business		−			556			302			858
Total operating revenues		−			2,710			2,215			4,925
Operating expenses
Utility
Fuel used in electric generation		−			841			558			1,399
Purchased power		−			345			144			489
Operation and maintenance		7			344			482			833
Depreciation and amortization		−			193			269			462
Taxes other than on income		−			149			90			239
Other		−			(2	)		−			(2	)
Diversified business
Cost of sales		−			482			318			800
Depreciation and amortization		−			35			30			65
Impairment of assets		−			44			111			155
Other		−			24			19			43
Total operating expenses		7			2,455			2,021			4,483
Operating (loss) income		(7	)		255			194			442
Other income (expense), net		2			38			(7	)		33
Interest charges, net		146			101			100			347
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(151	)		192			87			128
Income tax (benefit) expense		(59	)		63			44			48
Equity in earnings of consolidated subsidiaries		90			−			(90	)		−
Minority interest in subsidiaries’ income, net of tax		−			14			−			14
(Loss) income from continuing operations		(2	)		115			(47	)		66
Discontinued operations, net of tax		−			1			(69	)		(68	)
Net (loss) income	$	(2	)	$	116		$	(116	)	$	(2	)

51

Condensed Consolidating Statement of Income Six Months Ended June 30, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,756		$	1,795		$	3,551
Diversified business		−			663			193			856
Total operating revenues		−			2,419			1,988			4,407
Operating expenses
Utility
Fuel used in electric generation		−			615			464			1,079
Purchased power		−			275			140			415
Operation and maintenance		9			477			463			949
Depreciation and amortization		−			141			274			415
Taxes other than on income		4			133			88			225
Other		−			(25	)		−			(25	)
Diversified business
Cost of sales		−			625			228			853
Depreciation and amortization		−			32			27			59
Other		−			33			18			51
Total operating expenses		13			2,306			1,702			4,021
Operating (loss) income		(13	)		113			286			386
Other income (expense), net		32			(5	)		(24	)		3
Interest charges, net		154			90			74			318
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(135	)		18			188			71
Income tax (benefit) expense		(38	)		(10	)		23			(25	)
Equity in earnings of consolidated subsidiaries		189			−			(189	)		−
Minority interest in subsidiaries’ loss, net of tax		−			16			−			16
Income (loss) from continuing operations		92			44			(24	)		112
Discontinued operations, net of tax		−			(34	)		14			(20	)
Net income (loss)	$	92		$	10		$	(10	)	$	92

52

Condensed Consolidating Balance Sheet June 30, 2006
(in millions)	Parent			Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−		$	6,036	$	8,671		$	14,707
Current assets
Cash and cash equivalents		−			107		157			264
Short-term investments		−			45		50			95
Notes receivables from affiliated companies		310			15		(325	)		−
Deferred fuel cost		−			178		271			449
Assets of discontinued operations		−			42		342			384
Other current assets		13			1,105		1,026			2,144
Total current assets		323			1,492		1,521			3,336
Deferred debits and other assets
Investment in consolidated subsidiaries		11,415			−		(11,415	)		−
Goodwill		−			2		3,653			3,655
Other assets and deferred debits		256			2,027		2,173			4,456
Total deferred debits and other assets		11,671			2,029		(5,589	)		8,111
Total assets	$	11,994		$	9,557	$	4,603		$	26,154
Capitalization
Common stock equity	$	7,844		$	3,028	$	(3,028	)	$	7,844
Preferred stock of subsidiaries - not subject to mandatory redemption		−			34		59			93
Minority interest		−	��		11		5			16
Long-term debt, affiliate		−			440		(170	)		270
Long-term debt, net		3,520			2,634		3,668			9,822
Total capitalization		11,364			6,147		534			18,045
Current liabilities
Current portion of long-term debt		351			109		−			460
Notes payable to affiliated companies		−			205		(205	)		−
Liabilities of discontinued operations		−			22		10			32
Other current liabilities		233			969		826			2,028
Total current liabilities		584			1,305		631			2,520
Deferred credits and other liabilities
Noncurrent income tax liabilities		−			12		234			246
Regulatory liabilities		−			1,159		1,341			2,500
Accrued pension and other benefits		12			318		574			904
Other liabilities and deferred credits		34			616		1,289			1,939
Total deferred credits and other liabilities		46			2,105		3,438			5,589
Total capitalization and liabilities	$	11,994		$	9,557	$	4,603		$	26,154

53

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		241		126			606
Short-term investments		−		−		191			191
Notes receivables from affiliated companies		467		−		(467	)		−
Deferred fuel cost		−		341		261			602
Assets of discontinued operations		−		223		499			722
Other current assets		22		1,057		1,127			2,206
Total current assets		728		1,862		1,737			4,327
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		2,072		2,205			4,536
Total deferred debits and other assets		11,853		2,074		(5,672	)		8,255
Total assets	$	12,581	$	9,757	$	4,686		$	27,024
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		−		38		5			43
Long-term debt, affiliate		−		440		(170	)		270
Long-term debt, net		3,873		2,636		3,667			10,176
Total capitalization		11,911		6,187		522			18,620
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		−		87		4			91
Other current liabilities		245		843		1,019			2,107
Total current liabilities		649		1,456		781			2,886
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		62		215			277
Regulatory liabilities		−		1,189		1,338			2,527
Accrued pension and other benefits		12		307		551			870
Other liabilities and deferred credits		9		556		1,279			1,844
Total deferred credits and other liabilities		21		2,114		3,383			5,518
Total capitalization and liabilities	$	12,581	$	9,757	$	4,686		$	27,024

54

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	254		$	598		$	193		$	1,045
Investing activities
Gross utility property additions		-			(362	)		(307	)		(669	)
Diversified business property additions		-			(92	)		-			(92	)
Nuclear fuel additions		-			(6	)		(56	)		(62	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		-			137			84			221
Purchases of available-for-sale securities and other investments		(163	)		(329	)		(464	)		(956	)
Proceeds from sales of available-for-sale securities and other investments		163			383			580			1,126
Changes in advances to affiliates		164			(2	)		(162	)		-
Other investing activities		(4	)		(2	)		(8	)		(14	)
Net cash provided (used) by investing activities		160			(273	)		(333	)		(446	)
Financing activities
Issuance of common stock		60			-			-			60
Proceeds from issuance of long-term debt		397			-			-			397
Net decrease in short-term indebtedness		-			(102	)		(73	)		(175	)
Retirement of long-term debt		(800	)		(2	)		-			(802	)
Dividends paid on common stock		(303	)		-			-			(303	)
Dividends paid to parent		-			(163	)		163			-
Cash distributions to minority interests of consolidated subsidiary		-			(74	)		-			(74	)
Changes in advances from affiliates		-			(114	)		114			-
Other financing activities		(7	)		8			(42	)		(41	)
Net cash (used ) provided by financing activities		(653	)		(447	)		162			(938	)
Cash (used) provided by discontinued operations
Operating activities		-			(6	)		10			4
Investing activities		-			(6	)		(1	)		(7	)
Financing activities		-			-			-			-
Net (decrease) increase in cash and cash equivalents		(239	)		(134	)		31			(342	)
Cash and cash equivalents at beginning of period		239			241			126			606
Cash and cash equivalents at end of period	$	-		$	107		$	157		$	264

55

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	125		$	170		$	234		$	529
Investing activities
Gross utility property additions		-			(253	)		(286	)		(539	)
Diversified business property additions		-			(103	)		(17	)		(120	)
Nuclear fuel additions		-			(34	)		(33	)		(67	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		-			443			1			444
Purchases of available-for-sale securities and other investments		(1,665	)		(177	)		(1,363	)		(3,205	)
Proceeds from sales of available-for-sale securities and other investments		1,643			177			1,409			3,229
Changes in advances to affiliates		90			(31	)		(59	)		-
Proceeds from repayment of long-term affiliate debt		369			-			(369	)		-
Other investing activities		(11	)		(10	)		(2	)		(23	)
Net cash provided (used) by investing activities		426			12			(719	)		(281	)
Financing activities
Issuance of common stock		171			-			-			171
Proceeds from issuance of long-term debt		-			297			495			792
Net decrease in short-term indebtedness		(170	)		(32	)		(79	)		(281	)
Retirement of long-term debt		(160	)		(57	)		(300	)		(517	)
Retirement of long-term affiliate debt		-			(369	)		369			-
Dividends paid on common stock		(289	)		-			-			(289	)
Changes in advances from affiliates		-			(26	)		26			-
Other financing activities		(8	)		32			(48	)		(24	)
Net cash (used) provided by financing activities		(456	)		(155	)		463			(148	)
Cash (used) provided by discontinued operations
Operating activities		-			(15	)		14			(1	)
Investing activities		-			(13	)		(1	)		(14	)
Financing activities		-			-			-			-
Net increase (decrease) in cash and cash equivalents		95			(1	)		(9	)		85
Cash and cash equivalents at beginning of period		5			24			27			56
Cash and cash equivalents at end of period	$	100		$	23		$	18		$	141

16.SUBSEQUENT EVENT

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, Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets. On July 22, 2006, we entered into a definitive agreement to sell Gas to Dallas, Texas-based EXCO Resources, Inc. for $1.2 billion in gross cash proceeds. Proceeds from the sale will be used to reduce holding company debt and for other corporate purposes.

The transaction is expected to close in October 2006 and is subject to customary closing provisions and adjustments. We expect to report Gas, which is included within our Progress Ventures segment, as discontinued operations in the third quarter of 2006. The carrying amounts for the assets and liabilities of Gas included in the Consolidated Balance Sheet were as follows:

(in millions)	June 30, 2006		December 31, 2005
Total current assets	$	38	$	52
Total property, plant and equipment, net		528		469
Total other assets		8		8
Total current liabilities		44		68
Total long-term liabilities		93		66
Total capitalization		437		395

56

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 in the 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, as well as natural gas drilling and production in Texas and Louisiana. We have subsequently entered into a definitive agreement to sell our natural gas drilling and production business (See Note 16); 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 synthetic fuel production (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, with the sale of our share of Progress Telecom, LLC (PT LLC) in the first quarter of 2006, we reclassified PT LLC’s operations as discontinued operations and in the second quarter of 2006, we reclassified two generating facilities’ operations previously included in Progress Ventures as discontinued operations. These reportable segment changes reflect the current reporting structure. For comparative purposes, prior year results have been restated to conform to the current presentation. On July 22, 2006, we entered into a definitive agreement to sell our natural gas drilling and production business. As a result we expect to reclassify this portion of Progress Ventures as discontinued operations in the third quarter (See Note 16).

57

In this section, earnings and the factors affecting earnings for the three and six months ended June 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.

OVERVIEW

For the quarter ended June 30, 2006, our net loss was $47 million, or $(0.19) per share, compared to net loss of $1 million, or $(0.01) per share, for the same period in 2005. The increase in net loss as compared to prior year was due primarily to:

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

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

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

·     Additional outage expenses at PEC.

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

Partially offsetting these items were:

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

·     The impact of tax levelization.

·     Favorable retail margin at the Utilities.

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

For the six months ended June 30, 2006, our net loss was $2 million, or $(0.01) per share, compared to net income of $92 million, or $0.37 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 due to lower synthetic fuel production and higher oil prices.

·     The estimated loss on sale of two of our nonregulated plants and the associated valuation allowance recorded against the deferred tax assets for 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.

·     Additional outage expenses at PEC.

·     Unrealized losses recorded on contingent value obligations.

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

·     Additional estimated environmental remediation expenses at PEC.

Partially offsetting these items were:

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

·    The impact of tax levelization.

·    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 margin at PEF.

·    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.

58

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Business Segment
PEC	$	76		$	67		$	161		$	182
PEF		87			10			139			53
Progress Ventures		(8	)		6			(43	)		12
Coal and synthetic fuels		(91	)		23			(77	)		20
Total segment profit		64			106			180			267
Corporate and Other		(50	)		(100	)		(114	)		(155	)
Income from continuing operations		14			6			66			112
Discontinued operations, net of tax		(61	)		(7	)		(68	)		(20	)
Net (loss) income	$	(47	)	$	(1	)	$	(2	)	$	92

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $76 million and $67 million for the three months ended June 30, 2006 and 2005, respectively. The increase in profits for the three months ended June 30, 2006, when compared to the same period in 2005, was primarily due to postretirement and severance expenses incurred in 2005 and favorable retail and wholesale margins. These were partially offset by higher O&M expenses related to outages at nuclear facilities.

PEC contributed segment profits of $161 million and $182 million for the six months ended June 30, 2006 and 2005, respectively. The decrease in profits for the six months ended June 30, 2006, when compared to the same period in 2005, was primarily due to higher O&M expenses related to outages at nuclear facilities, additional estimated environmental remediation expenses and unfavorable weather. These were partially offset by postretirement and severance expenses incurred in 2005, favorable wholesale sales and favorable retail customer growth and usage.

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

Revenues

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

(in millions)	Three Months Ended June 30,
Customer Class	2006			Change			% Change		2005
Residential	$	299		$	27			9.9	$	272
Commercial		236			22			10.3		214
Industrial		173			9			5.5		164
Governmental		21			3			16.7		18
Total retail revenues		729			61			9.1		668
Wholesale		167			13			8.4		154
Unbilled		14			(1	)		-		15
Miscellaneous		25			2			8.7		23
Total electric revenues		935			75			8.7		860
Less: Fuel revenues		(294	)		(56	)		-		(238	)
Revenues excluding fuel	$	641		$	19			3.1	$	622

59

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

(in millions of kWh)	Three Months Ended June 30,
Customer Class	2006		Change			% Change			2005
Residential		3,438		153			4.7			3,285
Commercial		3,218		131			4.2			3,087
Industrial		3,139		(91	)		(2.8	)		3,230
Governmental		333		19			6.1			314
Total retail energy sales		10,128		212			2.1			9,916
Wholesale		3,328		(13	)		(0.4	)		3,341
Unbilled		232		(3	)		-			235
Total kWh sales		13,688		196			1.5			13,492

PEC’s electric revenues, excluding fuel revenues of $294 million and $238 million for the three months ended June 30, 2006 and 2005, respectively, increased $19 million. The increase in revenues is attributable primarily to favorable retail growth and usage, increased wholesale revenues less fuel and favorable weather. Favorable retail growth and usage of $10 million was driven by an approximate increase in the average number of customers of 30,000 as of June 30, 2006, compared to June 30, 2005. The increase in wholesale revenues less fuel of $9 million was driven primarily by the impact of increased capacity under contract, higher excess generation margin due to favorable market conditions and gains on forward sales of excess generation. The impact of weather was $2 million favorable with cooling degree days 17 percent greater than prior year partially offset by heating degree days 25 percent below 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 $342 million for the three months ended June 30, 2006, which represents a $53 million increase compared to the same period in the prior year. Fuel used in electric generation increased $46 million to $262 million compared to the prior year. This increase is due to a $41 million increase in fuel used in generation due primarily to higher fuel costs which are being driven by higher coal, oil and natural gas prices and a change in generation mix primarily due to lower nuclear generation related to nuclear outages. In addition, deferred fuel expense increased $5 million due to an increase in the fuel recovery rates for North Carolina and South Carolina. Current year purchased power costs were $7 million higher than the three months ended June 30, 2005, primarily due to higher system requirements and market prices in the second quarter of 2006.

Operation and Maintenance

O&M expenses were $248 million for the three months ended June 30, 2006, which represents a $12 million decrease compared to the same period in 2005. O&M expenses decreased $46 million due to postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative partially offset by $26 million related to outages at nuclear facilities and $2 million due to higher United States Nuclear Regulatory Commission (NRC) fees in 2006.

Total Other Income

Total other income of $3 million increased $4 million compared to the three months ended June 30, 2005 primarily due to $4 million related to the Federal Energy Regulatory Commission (FERC) Code of Conduct audit settlement recorded in the prior year and a $3 million increase in interest income related to temporary investments partially offset by a $5 million increase in the indemnification liability recorded for estimated capital costs associated with the

60

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 increased $9 million for the three months ended June 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to 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 $20 million for the three months ended June 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. Accounting principles generally accepted in the United States (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 decreased by $2 million for the three months ended June 30, 2006 compared to an increase of $3 million for the three months ended June 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 and temporary deductions 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.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Revenues

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

(in millions)	Six Months Ended June 30,
Customer Class	2006			Change			% Change		2005
Residential	$	675		$	29			4.5	$	646
Commercial		462			34			7.9		428
Industrial		336			23			7.3		313
Governmental		41			3			7.9		38
Total retail revenues		1,514			89			6.2		1,425
Wholesale		360			32			9.8		328
Unbilled		(13	)		(10	)		-		(3	)
Miscellaneous		52			7			15.6		45
Total electric revenues		1,913			118			6.6		1,795
Less: Fuel revenues		(612	)		(103	)		-		(509	)
Revenues excluding fuel	$	1,301		$	15			1.2	$	1,286

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

(in millions of kWh)	Six Months Ended June 30,
Customer Class	2006			Change			% Change			2005
Residential		7,856			(101	)		(1.3	)		7,957
Commercial		6,270			103			1.7			6,167
Industrial		6,071			(90	)		(1.5	)		6,161
Governmental		653			11			1.7			642
Total retail energy sales		20,850			(77	)		(0.4	)		20,927
Wholesale		7,286			8			0.1			7,278
Unbilled		(146	)		(79	)		-			(67	)
Total kWh sales		27,990			(148	)		(0.5	)		28,138

PEC’s electric revenues, excluding fuel revenues of $612 million and $509 million for the six months ended June 30, 2006 and 2005, respectively, increased $15 million. The increase in revenues is attributable primarily to increased wholesale revenues less fuel and favorable retail growth and usage, partially offset by unfavorable weather. The increase in wholesale revenues less fuel of $30 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. Favorable retail growth and usage of $6 million was driven by an approximate increase in the average number of customers of 30,000 as of June 30, 2006, compared to June 30, 2005. The impact of weather was $13 million unfavorable with heating degree days 12 percent below prior year partially offset by cooling degree days 20 percent greater than last year.

Expenses

Fuel and Purchased Power

Fuel and purchased power expenses were $702 million for the six months ended June 30, 2006, which represents a $98 million increase compared to the same period in the prior year. Fuel used in electric generation increased $94 million to $558 million compared to the prior year. This increase is due to a $46 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 $48 million due primarily to higher fuel costs which are being driven by higher coal, oil and natural gas prices and a change in generation mix primarily due to lower nuclear generation related to nuclear outages. Current year purchased power costs were $4 million higher than the six months ended June 30, 2005, primarily due to higher prices during the first half of 2006 partially offset by lower system requirements.

Operation and Maintenance

O&M expenses were $504 million for the six months ended June 30, 2006, which represents a $20 million increase compared to the same period in 2005. O&M expenses increased $46 million due to outages at nuclear facilities and $21 million due to additional estimated environmental remediation expenses (See Note 13A) and $4 million due to higher NRC fees in 2006. These were partially offset by $60 million of postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative.

Depreciation and Amortization

Depreciation and amortization expense was $255 million for the six months ended June 30, 2006, which represents a $4 million decrease compared to the same period in 2005. Depreciation expense decreased $10 million due to lower Clean Smokestacks Act amortization, partially offset by the impact of an increase in the depreciable base.

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Total Other Income

Total other income of $9 million increased $7 million compared to the six months ended June 30, 2005 primarily due to a $8 million increase in interest income related to temporary investments and $4 million related to FERC Code of Conduct audit settlement recorded in the prior year partially offset by a $5 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 increased $14 million for the six months ended June 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to 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 $16 million for the six months ended June 30, 2006, as compared to the same period in the prior year, primarily due to the allocation of $11 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 that is no longer allocated in 2006 and the $3 million impact of a 2005 tax credit 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 decreased by $1 million for the six months ended June 30, 2006 compared to an increase of $3 million for the six months ended June 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 and temporary deductions 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 $87 million and $10 million for the three months ended June 30, 2006 and 2005, respectively. The increase in profits for the three months ended June 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, favorable weather and customer growth and usage partially offset by the gain on sale of utility distribution assets in the prior year and higher interest expense.

PEF contributed segment profits of $139 million and $53 million for the six months ended June 30, 2006 and 2005, respectively. The increase in profits for the six months ended June 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, favorable weather and customer growth and usage partially offset by the gain on sale of utility distribution assets in the prior year and higher interest expense.

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

Revenues

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

(in millions)	Three Months Ended June 30,
Customer Class	2006			Change			% Change		2005
Residential	$	559		$	128			29.7	$	431
Commercial		291			64			28.2		227
Industrial		91			20			28.2		71
Governmental		74			17			29.8		57
Retail revenue sharing		-			(2	)		-		2
Total retail revenues		1,015			227			28.8		788
Wholesale		69			1			1.5		68
Unbilled		23			5			-		18
Miscellaneous		40			6			17.6		34
Total electric revenues		1,147			239			26.3		908
Less: Fuel and other pass-through revenues		(736	)		(209	)		-		(527	)
Revenues excluding fuel and pass-through revenues	$	411		$	30			7.9	$	381

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

(in millions of kWh)	Three Months Ended June 30,
Customer Class	2006		Change			% Change			2005
Residential		4,745		404			9.3			4,341
Commercial		3,010		122			4.2			2,888
Industrial		1,100		60			5.8			1,040
Governmental		806		44			5.8			762
Total retail energy sales		9,661		630			7.0			9,031
Wholesale		962		(356	)		(27.0	)		1,318
Unbilled		779		351			-			428
Total kWh sales		11,402		625			5.8			10,777

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $736 million and $527 million for the three months ended June 30, 2006 and 2005, respectively, increased $30 million. The increase in revenues is primarily due to favorable weather of $17 million and favorable growth and usage of $8 million driven by an approximate average net increase in the number of customers of 35,000 for the three months ended June 30, 2006, compared to the three months ended June 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. In addition, wholesale revenues excluding fuel increased by $2 million due to new contracts in 2005 and 2006, including the addition of Winter Park, and higher demand charges partially offset by the expiration of certain contracts in 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.

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Fuel and purchased power expenses were $627 million for the three months ended June 30, 2006, which represents a $170 million increase compared to the same period in the prior year. Fuel used in electric generation increased $134 million to $447 million compared to the prior year. This increase is due to an $87 million increase in fuel used in generation due primarily to higher fuel costs which are being driven by higher coal, oil and natural gas prices and an increase in the volume of fuel purchases. In addition, deferred fuel expense increased $47 million due to an increase in the fuel recovery rates on January 1, 2006. Current year purchased power costs were $36 million higher than the three months ended June 30, 2005, primarily due to higher system requirements and market prices in the second quarter of 2006 and 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 $178 million for the three months ended June 30, 2006, which represents a decrease of $110 million, when compared to the $288 million incurred during the three months ended June 30, 2005. O&M expenses decreased $93 million due to postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative, $17 million related to the prior year write-off of unrecoverable storm restoration costs and $5 million related to lower ECRC costs. ECRC costs are pass-through expenses and have no material impact on earnings. These decreases were partially offset by additional expenses related to reliability programs.

Depreciation and Amortization

Depreciation and amortization expense increased $27 million to $98 million for the three months ended June 30, 2006. The increase is primarily due to the amortization of $30 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 $2 million to due increases in the depreciable base. These increases were partially offset by the $4 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 $10 million to $76 million compared to the three months ended June 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 $26 million from a gain of $25 million for the three months ended June 30, 2005 to an expense of $1 million for the three months ended June 30, 2006. The increase is primarily due to the $25 million prior year gain on the sale of Winter Park distribution assets.

Total Other Income

Total other income increased $7 million to $6 million compared to the three months ended June 30, 2005 primarily due to a $3 million increase in interest income driven by temporary investments and interest on unrecovered storm costs and $3 million related to FERC Code of Conduct audit settlement recorded in the prior year.

Total Interest Charges, net

Total interest charges, net increased $6 million for the three months ended June 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to the impact of long-term debt balances on interest expense.

Income Tax Expense

Income tax expense increased $40 million for the three months ended June 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 $3 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 that

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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 not materially impacted for the three months ended June 30, 2006 compared to an increase of $8 million for the three months ended June 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 and temporary deductions 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.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Revenues

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

(in millions)	Six Months Ended June 30,
Customer Class	2006			Change			% Change			2005
Residential	$	1,066		$	205			23.8		$	861
Commercial		536			108			25.2			428
Industrial		174			40			29.9			134
Governmental		140			30			27.3			110
Retail revenue sharing		1			1			-			-
Total retail revenues		1,917			384			25.0			1,533
Wholesale		137			(5	)		(3.5	)		142
Unbilled		24			11			-			13
Miscellaneous		76			8			11.8			68
Total electric revenues		2,154			398			22.7			1,756
Less: Fuel and other pass-through revenues		(1,390	)		(362	)		-			(1,028	)
Revenues excluding fuel and pass-through revenues	$	764		$	36			4.9		$	728

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

(in millions of kWh)	Six Months Ended June 30,
Customer Class	2006		Change			% Change			2005
Residential		9,056		368			4.2			8,688
Commercial		5,560		101			1.9			5,459
Industrial		2,105		124			6.3			1,981
Governmental		1,527		56			3.8			1,471
Total retail energy sales		18,248		649			3.7			17,599
Wholesale		1,970		(685	)		(25.8	)		2,655
Unbilled		629		304			-			325
Total kWh sales		20,847		268			1.3			20,579

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $1.390 billion and $1.028 billion for the six months ended June 30, 2006 and 2005, respectively, increased $36 million. The increase in revenues is primarily due to favorable weather of $18 million, favorable retail growth and usage of $11 million driven by an approximate average net increase in the number of customers of 33,000 for the six months ended June 30, 2006, compared to the six months ended June 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. These increases were partially offset by a $2 million decrease in wholesale revenues excluding fuel due to the expiration of certain contracts in 2005 partially offset by new contracts in 2005 and 2006, including the addition of Winter Park, and higher demand charges.

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Expenses

Fuel and Purchased Power

Fuel and purchased power expenses were $1.186 billion for the six months ended June 30, 2006, which represents a $296 million increase compared to the same period in the prior year. Fuel used in electric generation increased $226 million to $841 million compared to the prior year. This increase is due to a $115 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 $111 million due primarily to higher fuel costs which are being driven by higher coal, oil and natural gas prices and an increase in the volume of fuel purchases. Current year purchased power costs were $70 million higher than the six months ended June 30, 2005, primarily due to higher system requirements and market prices in the current year as a result of increased fuel costs and an increase in capacity recovery rates under the capacity cost recovery clause. The FPSC allows capacity payments to be recovered through a capacity costs 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 $344 million for the six months ended June 30, 2006, which represents a decrease of $133 million, when compared to the $477 million incurred during the six months ended June 30, 2005. O&M expenses decreased $107 million due to postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative, $17 million related to the prior year write-off of unrecovered storm restoration costs and $10 million related to lower ECRC costs in the current year. ECRC costs are pass-through expenses and have no material impact on earnings.

Depreciation and Amortization

Depreciation and amortization expense increased $52 million to $193 million for the six months ended June 30, 2006. The increase is primarily due to the amortization of $57 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 $10 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 $16 million to $149 million compared to the six months ended June 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 $23 million from a gain of $25 million for the six months ended June 30, 2005 to a gain of $2 million for the six months ended June 30, 2006. The decrease is primarily due to the $25 million prior year gain on the sale of Winter Park distribution assets.

Total Other Income

Total other income increased $8 million to $10 million compared to the six months ended June 30, 2005 primarily due to an $8 million increase in interest income driven by temporary investments and interest on unrecovered storm costs and $3 million related to FERC Code of Conduct audit settlement recorded in the prior year. These were partially offset by a $2 million reduction in AFUDC equity primarily due to the completion of Hines Unit 3 during 2005.

Total Interest Charges, net

Total interest charges, net increased $13 million for the six months ended June 30, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to the impact of higher long-term debt balances on interest expense.

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Income Tax Expense

Income tax expense increased $53 million for the six months ended June 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 $7 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 not materially impacted for the six months ended June 30, 2006 compared to an increase of $8 million for the six months ended June 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 and temporary deductions 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, energy marketing activities and natural gas drilling and production (Gas). The nonregulated electric generation operations are primarily located in Georgia and service multiple fixed price full-requirements contracts, one of which has a term of 2003 through 2015 with the remaining running from 2005 through 2010. These contracts are primarily served by callable resources from a number of external and Progress Ventures’ internal sources. Progress Ventures has also entered into an agreement to provide capacity and associated energy to Georgia Power 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 Gas operations are primarily located in Texas and Louisiana. As described under Recent Developments, we have entered into a definitive agreement to sell Gas.

The following summarizes the quarterly and year-to-date gas production in Bcf equivalent, revenues, gross margin and segment (losses) profits for Progress Ventures:

	Three Months Ended June 30,						Six Months Ended June 30,
($ in millions)	2006			2005			2006			2005
Gas production in Bcf equivalent		7			6			14			11
Electric revenues	$	151		$	139		$	286		$	193
Gas revenues		38			39			107			72
Total revenues	$	189		$	178		$	393		$	265
Gross margin
In millions of $	$	36		$	47		$	94		$	87
As a % of revenues		19	%		26	%		24	%		33	%
Segment (losses) profits	$	(8	)	$	6		$	(43	)	$	12

Progress Ventures revenues increased $11 million to $189 million for the three months ended June 30, 2006 compared to same period in 2005. Electric revenues increased $12 million primarily due to serving an increased load at higher rates on our Georgia contracts. Although electric revenues increased for the three months ended June 30, 2006 due to fixed price full-requirements contracts, margins from these contracts decreased primarily due to higher fuel and power prices. Gas revenues decreased $1 million primarily due to mark-to-market losses on gas hedges partially offset by increased gas production and higher market prices. The increased mark-to-market losses on the gas hedges are primarily due to the reclassification of deferred losses caused by the discontinuance of the related cash flow hedge accounting due to the anticipated sale of Gas as discussed below in Recent Developments (See Note 10A). The decreased margins on the Georgia contracts and the mark-to-market losses at Gas were the main drivers of

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the $14 million decrease in Progress Venture’s segment earnings for the three months ended June 30, 2006 compared to the three months ended June 30, 2005.

Progress Ventures revenues increased $128 million to $393 million for the six months ended June 30, 2006 compared to same period in 2005. Electric revenues increased $93 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. Although electric revenues increased for the six months ended June 30, 2006 due to fixed price full-requirements contracts, margins from these contracts decreased primarily due to higher fuel and power prices. Gas revenues increased $35 million primarily due to increased gas production and higher market prices partially offset by mark-to-market losses on gas hedges. The increased mark-to-market losses on the gas hedges are primarily due to the reclassification of deferred losses caused by the discontinuance of the related cash flow hedge accounting due to the anticipated sale of Gas as discussed below in Recent Developments (See Note 10A). In addition to the decreased margins on the Georgia contracts and the mark-to-market losses at Gas, the $55 million decrease in Progress Venture’s segment earnings for the six months ended June 30, 2006 compared to the six months ended June 30, 2006 was unfavorably impacted by the $64 million pre-tax impairment loss ($39 million after-tax) on goodwill described below.

In accordance with accounting standards for goodwill, we have monitored the carrying value of our goodwill associated with our Progress Ventures operations. The Progress Ventures electric generation operations were divided into three regions where it had generation plants: South Florida, North Carolina and Georgia. As part 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. As a result of this test, we recognized a pre-tax goodwill impairment loss of $64 million ($39 million after-tax), the entire amount of goodwill assigned to Progress Ventures (See Note 6). We also entered into a definitive agreement to sell our operations in South Florida and North Carolina and these operations were classified as discontinued operations during the second quarter of 2006 (See Note 3A).

In accordance with accounting standards for long-lived assets, we monitor the carrying value of our long-lived assets associated with our Progress Ventures operations. 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 strategic alternatives that management is pursuing, could require future impairment evaluations of the $920 million of remaining long-lived and intangible assets, which could result in a material non-cash impairment charge against earnings.

RECENT DEVELOPMENTS

As part of our strategy to reduce our risk profile and continue our efforts to reduce holding company debt through selected asset sales, we entered into a definitive agreement to sell Gas to Dallas, Texas-based EXCO Resources, Inc. for $1.2 billion in gross cash proceeds. Proceeds from the sale will be used to reduce holding company debt and for other corporate purposes.

The transaction is expected to close in October 2006 and is subject to customary closing provisions and adjustments. We expect to report Gas as discontinued operations in the third quarter of 2006. As part of this transaction, we will divest of our holdings in Winchester Production Company, Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets. Specific assets include 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 are located in Texas and Louisiana.

The following summarizes Progress Ventures’ segment (losses) profits by operation and the goodwill impairment discussed above for the three months and six months ended June 30, 2006 and 2005:

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	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Competitive Commercial Operations excluding goodwill impairment	$	(15	)	$	(6	)	$	(31	)	$	(12	)
Goodwill impairment		-			-			(39	)		-
Gas operations		7			12			27			24
Segment (losses) profits	$	(8	)	$	6		$	(43	)	$	12

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 June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Synthetic fuel operations	$	(82	)	$	23		$	(79	)	$	22
Coal terminals and marketing		(1	)		9			16			17
Corporate overhead and other operations		(8	)		(9	)		(14	)		(19	)
Segment (losses) profits	$	(91	)	$	23		$	(77	)	$	20

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 June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Tons sold		0.5			2.3			1.7			4.3
After-tax losses, excluding tax credits	$	(25	)	$	(39	)	$	(50	)	$	(77	)
After-tax impairment charge		(45	)		-			(45	)		-
Valuation allowance		(7	)		-			(7	)		-
Tax credits generated		13			62			48			116
Tax credit inflation adjustment		-			-			10			-
Tax credits reserved due to potential phase-out		(18	)		-			(35	)		-
Tax credits reversed		-			-			-			(17	)
Net (loss) profit	$	(82	)	$	23		$	(79	)	$	22

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 June 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 an additional $18 million tax credit reserve at June 30, 2006 due to high oil prices which increased the potential for a 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. These were partially offset by lower 2006 production which resulted in lower pre-tax losses.

Synthetic fuels’ earnings for the six months ended June 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 $35 million tax credit reserve at June 30, 2006 due to high oil prices which increased the potential for a 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. These were partially offset by the reversal of $17 million of tax credits in the first quarter of 2005 due to

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the loss on sale of Progress Rail, 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 $12 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 $1 million for the three months ended June 30, 2006 compared to earnings of $9 million for the three months ended June 30, 2005. The 2006 loss is driven 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) for the three months ended June 30, 2006. As a result of this impairment, approximately $6 million of depreciation expense associated with the impaired assets will not be recorded during the remainder of 2006.

Coal operations contributed earnings of $16 million and $17 million for the six months ended June 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 and a $3 million pre-tax gain on the sale of Dixie Fuels Limited (Dixie Fuels). 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 six months ended June 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.

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

On March 1, 2006, we sold our 65 percent interest in Dixie Fuels for $16 million to Kirby Corporation which owned the remaining 35 percent interest. Dixie Fuels operated four barge and tugboat units under long-term contracts with PEF and an outside party. Proceeds from the sale were used for debt reduction and other corporate purposes.

CORPORATE OVERHEAD AND OTHER OPERATIONS

Corporate overhead and other operations resulted in after-tax expenses of $8 million and $9 million for the three months ended March 31, 2006 and 2005, respectively. The decrease in after-tax expenses for 2006 is primarily due to postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative. Corporate overhead and other operations recorded after-tax expenses of $14 million and $19 million for the six months ended June 30, 2006 and 2005, respectively. The decrease in after-tax expenses for 2006 is primarily due to postretirement and severance expense recorded in the prior year related to the 2005 cost-management initiative.

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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 June 30,						Six Months Ended June 30,
(in millions)	2006			2005			2006			2005
Other interest expense	$	(70	)	$	(69	)	$	(142	)	$	(137	)
Contingent value obligations		3			-			(22	)		-
Tax levelization		(5	)		(49	)		(19	)		(52	)
Tax reallocation		-			(9	)		-			(19	)
Other income tax benefit		21			32			51			62
Other		1			(5	)		18			(9	)
Corporate and Other after-tax expense	$	(50	)	$	(100	)	$	(114	)	$	(155	)

Other interest expense, which includes intercompany elimination entries, increased $1 million to $70 million for the three months ended June 30, 2006 compared to $69 million for the three months ended June 30, 2005. Other interest expense, which includes elimination entries, increased $5 million to $142 million for the six months ended June 30, 2006 compared to $137 million for the six months ended June 30, 2005. Interest expense increased primarily due to a decrease in the elimination of intercompany interest expense resulting from lower intercompany debt balances. This was partially offset by having no revolving credit agreement (RCA) balances outstanding or related interest during the six months ended June 30, 2006 compared to $3 million of interest expense related to outstanding RCA balances during the six months ended June 30, 2005.

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 June 30, 2006 and 2005, the CVOs had fair market values of approximately $30 million and $13 million, respectively. We recorded unrealized gains of $3 million for the three months ended June 30, 2006 and an immaterial unrealized loss for the three months ended June 30, 2005, to record the changes in fair value of the CVOs, which had average unit prices of $0.30 and $0.14 at June 30, 2006 and 2005, respectively. We recorded an unrealized loss of $22 million for the six months ended June 30, 2006. The CVO values at June 30, 2005 were unchanged from the December 31, 2004 values, thus requiring no recognition of unrealized gain or loss for the six months ended June 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 increased by $5 million and $49 million for the three months ended June 30, 2006 and 2005, respectively, and $19 million and $52 million for the six months ended June 30, 2006 and 2005, respectively, 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 and six months ended June 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 June 30, 2005, income tax expense was increased by $9 million and for the six months ended June 30, 2005, income tax expense was increased by $19 million due to the allocation of the Parent’s income tax benefit.

For the three months end June 30, 2006, other contributed $1 million to earnings compared to $5 million of expense for the same period in 2005. The $6 million change is primarily due to the pre-tax gain, net of minority interest, on the sale of our remaining interest in Level 3 stock subsequent to the sale of PT LLC (See Notes 3B and 12). For the

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six months ended June 30, 2006, other contributed $18 million to earnings compared to $9 million of expense in 2005. The $27 million change is primarily due to the $17 million pre-tax gain, net of minority interest, on the sale of Level 3 stock. In addition, other changed due to a $2 million increase in interest income on temporary investments and expenses in 2005 included $4 million for South Carolina corporate license related to the South Carolina audit settlement.

DISCONTINUED OPERATIONS

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 was and Rowan is a subsidiary of Progress Energy Ventures, Inc. DeSoto owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Florida 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 expect to use the proceeds from the sales to reduce debt and for other corporate purposes (See Note 3A).

The sale of DeSoto closed in the second quarter of 2006. The sale of Rowan is expected to close during the third quarter of 2006 and is subject to state and federal regulatory approvals and customary closing conditions. We recorded an after-tax loss on the sale of DeSoto of $30 million and an estimated after-tax loss on the sale of Rowan of $32 million. Discontinued DeSoto and Rowan operations had combined losses of $63 million for the three months ended June 30, 2006 compared to losses of $1 million for the same period in 2005 and combined losses of $68 million for the six months ended June 30, 2006 compared to combined losses of $3 million for the same period in 2005.

PROGRESS TELECOM LLC

On March 20, 2006, we completed the sale of Progress Telecom, LLC (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 3B).

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 $29 million during the six months ended June 30, 2006. Discontinued PT LLC operations had earnings of $6 million for the three months ended June 30, 2006 compared to $2 million for the same period in 2005 and earnings of $24 million for the six months ended June 30, 2006 compared to $2 million for the same period in 2005.

COAL MINING OPERATIONS

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 six months ended June 30, 2006 we recorded an estimated after-tax loss of $17 million for the sale of these assets. The remaining coal mining operations are expected to be sold by the end of 2006 (See Note 3D).

Discontinued coal mining operations incurred a net loss of $1 million for both the three months ended June 30, 2006 and 2005 and a net loss of $21 million for the six months ended June 30, 2006 compared to earnings of less than a million for the same period in 2005. The net loss for the six months ended June 30, 2006 is primarily due to recording a $17 million after-tax loss on the sale.

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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 (See Note 3C).

Rail discontinued operations resulted in losses of $3 million for the three months ended June 30, 2006 compared to $7 million for the same period in 2005 and losses of $3 million for the six months ended June 30, 2006 compared to $19 million for the same period in 2005.

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, if any, 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 $516 million for the six months ended June 30, 2006, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to a $170 million increase in the recovery of fuel costs at the Utilities, $185 million net decrease in working capital and other operating activity needs, and $64 million of storm restoration costs incurred in the prior year at PEF. 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

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decreases from the change in accounts receivable of $73 million at PEC and approximately $80 million at our nonregulated operations primarily due to cessation of our synthetic fuel operations, approximately $103 million of proceeds received from the restructuring of a long-term coal supply contract, and $52 million due to fluctuations in emission allowance inventory at PEC. These impacts were partially offset by an $81 million decrease from the change in accounts payable, primarily driven by reduced purchases at our nonregulated operations.

INVESTING ACTIVITIES

Net cash used in investing activities increased by $165 million for the six months ended June 30, 2006, when compared to the corresponding period in the prior year. This is due primarily to a $223 million decrease in 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 decreased approximately $58 million in 2006 when compared with 2005. The decrease is due primarily to a $146 million increase in net proceeds from available-for-sale securities and other investments, including approximately $98 million in net proceeds from the sale of Level 3 stock (See Notes 3B and 12), partially offset by $97 million in additional capital expenditures for property and nuclear fuel additions. Available-for-sale securities and other investments include marketable debt and equity securities and investments held in nuclear decommissioning and benefit investment trusts. The increase in property additions is primarily due to higher spending at the Hines 4 facility and distribution projects at PEF, partially offset by lower spending at the Hines 3 facility.

During the six months ended June 30, 2006, proceeds from sales of discontinued operations and other assets, net of cash divested primarily included approximately $80 million from the sale of DeSoto (See Note 3A), approximately $70 million from the sale of PT LLC (See Note 3B), approximately $27 million from the sale of certain net assets of the coal mining business (See Note 3D), and approximately $15 million from the sale of Dixie Fuels. 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 3C).

FINANCING ACTIVITIES

Net cash used in financing activities increased by $790 million for the six months ended June 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. Therefore, effective March 31, 2006,

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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 is replacing 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 and BBB- by S&P.

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

For the three months ended June 30, 2006 and 2005, respectively, we issued approximately 0.7 million shares and 2.6 million shares of common stock resulting in approximately $32 million and $111 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 six months ended June 30, 2006 and 2005, respectively, we issued approximately 1.4 million shares and 4.0 million shares of common stock resulting in approximately $60 million and $171 million in proceeds, net of purchases of restricted shares. Included in these amounts were approximately 1.0 million shares and 3.9 million shares for net proceeds of approximately $46 million and $169 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 approximately $100 million aggregate amount from the sale of stock through these plans.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At June 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 June 30, 2006, the current portion of our long-term debt was $460 million, which we expect to fund with cash from operations, proceeds from sales of assets and/or commercial paper borrowings. See Notes 3 and 16 for additional information on asset sales.

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 are unaffected. The placement of PGN's ratings on Rating Watch Positive is 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. Should Fitch take a rating action, a one notch upgrade of the holding company's ratings is likely following completion of a rating review, closing of the sales of the DeSoto and Rowan plants and the application of the associated $405 million of proceeds to parent debt

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reduction. The rating review is expected to occur during the third quarter of 2006. 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 the Progress Energy's business risk profile to 5 from 6 due to the recently announced 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. We do not expect these changes to have a material impact on our borrowing costs or overall liquidity.

The following regulatory matters may impact our future liquidity and financing activities: PEC’s fuel cost recovery as discussed in Note 4, PEF’s recovery of storm costs as discussed in Note 4, and filings for recovery of environmental costs as discussed in Note 13.

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 June 30, 2006, we have issued $1.83 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 June 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 $639 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 June 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.

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

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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. Resumption of synthetic fuel production would be dependent upon a number of factors, including a reduction in oil prices, the enactment of future federal tax legislation and/or the duration of the current idling.

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 June 30, 2006 (including those generated by Florida Progress prior to our acquisition), were approximately $1.8 billion, of which $869 million has been used to offset regular federal income tax liability, $896 million is being carried forward as deferred tax credits and $35 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 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.

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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 $6 lower than the corresponding monthly New York Mercantile Exchange (NYMEX) settlement price for light sweet crude oil. Through June 30, 2006, the average NYMEX settlement price for light sweet crude oil was $67.13 per barrel, and as of June 30, 2006, the average NYMEX futures price for light sweet crude oil for the remainder of calendar year 2006 was $75.12 per barrel. This results in a weighted-average annual price for light sweet crude oil of approximately $71.16 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 $71.16 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 72 percent. Therefore, we reserved 72 percent or approximately $35 million of the $48 million in tax credits generated during the first six months of 2006. The NYMEX price of oil for the remainder of 2006 would have to be $55.16 to have no reduction in value of tax credits generated during 2006 and would have to be $83.04 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 the end of 2006 when final 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.

If our synthetic fuel operations remain idle for the balance of 2006 and the 2006 credits earned to date were completely phased out due to high oil prices, then the estimated current year losses through June 30, 2006 from our synthetic fuel operations would be approximately $92 million, which includes after-tax impairment losses of $55 million and a reversal of $13 million of income related to tax credits recorded during the first six months of 2006.

IMPAIRMENT OF SYNTHETIC FUEL AND OTHER RELATED LONG-LIVED ASSETS

We have monitored our synthetic fuel and other related operating long-lived assets for impairment and previously determined that no impairment of these assets was required.With the idling of these facilities during the second quarter of 2006, we performed another impairment evaluation. 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 continued “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 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.

SALE OF PARTNERSHIP INTEREST

In June 2004, through our subsidiary Progress Fuels, we sold in two transactions a combined 49.8 percent partnership interest in Colona, one of our synthetic 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

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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 in the first, second and/or third quarters of each 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. With an extended idling of our production, the amount of proceeds realized from the sale could be significantly impacted. As of June 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. In addition, until February 8, 2006, we were subject to SEC regulation as a registered holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Subsequent to the repeal of PUHCA, we became subject to additional regulation by the FERC. 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. The 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 in the third 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.

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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.

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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.

Cash provided by operating activities increased $48 million for the six months ended June 30, 2006, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to a $43 million increase in the recovery of fuel costs and a $38 million increase from other operating activities, primarily related to fluctuations in long-term emission allowance inventory. 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. These impacts were partially offset by lower net income and a $23 million net increase in working capital needs. The increase in working capital needs was primarily driven by a $122 million increase resulting from tax payments, largely offset by decreases of $73 million related to accounts receivable and $28 million related to fluctuations in inventory, primarily emission allowances.

Cash used in investing activities decreased $55 million for the six months ended June 30, 2006, when compared to the corresponding period in the prior year primarily due to an increase in net proceeds from available-for-sale securities and other investments for the period in 2006, partially offset by an increase in nuclear fuel additions related to nuclear facility 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 June 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 June 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.

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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 $243 million for the six months ended June 30, 2006, when compared to the corresponding period in the prior year. The increase was due primarily to higher net income, a $127 million increase in the recovery of fuel costs, $64 million of storm restoration costs incurred in the prior year, and $56 million related to lower tax payments and higher income tax provision. 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 decreases of $52 million from fluctuations in inventory, primarily coal, and $31 million from the timing of purchases and payments to affiliates.

Cash used in investing activities increased $143 million for the six months ended June 30, 2006, when compared to the corresponding period in the prior year. The increase in cash used in investing activities is primarily due to $118 million of property additions, primarily related to higher spending to construct the Hines 4 facility and distribution projects partially offset by lower spending to construct the Hines 3 facility and a $45 million increase in net purchases of short-term investments included in available-for-sale securities and other investments. These impacts were partially offset by a $28 million decrease in nuclear fuel additions. 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 PEF’s financing activities.

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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 (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, INC.

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 June 30, 2006, has changed from December 31, 2005. The total notional amount of fixed rate long-term debt at June 30, 2006, was $9.240 billion, with an average interest rate of 6.29% and fair market value of $9.269 billion. The total notional amount of variable rate long-term debt at June 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 June 30, 2006, approximately 14.7 percent of consolidated debt, including interest rate swaps, was in floating rate mode 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.

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CASH FLOW HEDGES

During the six months ended June 30, 2006, we settled the previous $100 million of forward starting swaps in conjunction with our issuance of $300 million of 5.625% Senior Notes due 2016. Under terms of these swap agreements, we paid a fixed rate and received a floating rate based on 3-month London Inter Bank Offering Rate (LIBOR). The Utilities had no open interest rate cash flow hedges at June 30, 2006 and December 31, 2005.

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

^(a) 3-month LIBOR rate was 4.54% at December 31, 2005.

^(b) Sensitivity indicates change in value due to 25 basis point 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. The fair value of these swaps was not material at June 30, 2006.

FAIR VALUE HEDGES

At June 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 June 30, 2006 and December 31, 2005, the Utilities had no open interest rate fair value hedges.

Fair Value Hedges (dollars in millions)	Notional Amount		Receive			Pay(b)		Fair Value			Sensitivity(c)
Progress Energy, Inc.
Risk hedged at June 30, 2006:
5.85% Notes due 10/30/2008	$	100		4.10	%		3-month LIBOR	$	(3	)	$	(1	)
7.10% Notes due 3/1/2011		50		4.65	%		3-month LIBOR		(2	)		-
Total	$	150		4.28	%	(a)		$	(5	)	$	(1	)
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 5.48% at June 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.

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MARKETABLE SECURITIES PRICE RISK

At June 30, 2006 and December 31, 2005, the fair value of our nuclear decommissioning trust funds was $1.181 billion and $1.133 billion, respectively, including $669 million and $640 million, respectively, for PEC and $512 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 June 30, 2006 and December 31, 2005, the fair value of CVOs was $30 million and $7 million, respectively. At June 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

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.

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. Our exposure to commodity price risk has not changed materially since December 31, 2005. A hypothetical 10 percent increase or decrease in quoted market prices in the near term on our derivative commodity instruments would not have a material effect on our financial position, results of operations or cash flows at June 30, 2006.

See Note 10 for additional information with regard to our commodity contracts and use of derivative financial instruments.

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.

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. Gains and losses from such contracts were not material to our or the Utilities’ results of operations for the three and six months ended June 30, 2006 and 2005. PEC did not have material outstanding positions in such contracts at June 30, 2006 and December 31, 2005. We and PEF did not have material outstanding positions in such contracts at June 30, 2006 and December 31, 2005, other than those receiving regulatory accounting treatment at PEF, 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 clause. At June 30, 2006, the fair values of these instruments were a $55 million short-term derivative asset position included in other current assets, a $48 million long-term derivative asset position

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included in other assets and deferred debits, a $15 million short-term derivative liability position included in other current liabilities and a $53 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 and power for our forecasted purchases and sales.

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

	June 30, 2006					December 31, 2005
(in millions)	Progress Energy			PEC		Progress Energy			PEC
Fair value of assets	$	145		$	-	$	170		$	7
Fair value of liabilities		(1	)		-		(58	)		(4	)
Fair value, net	$	144		$	-	$	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).

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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 June 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 June 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.

On March 21, 2006, Progress Energy announced that Jeffrey J. Lyash was appointed to the position of President and Chief Executive Officer of PEF, effective June 1, 2006. This position was previously held by H. William Habermeyer, Jr. who retired on May 31, 2006.

Other than the above-referenced item, there has been no change in PEF’s internal control over financial reporting during the quarter ended June 30, 2006, that has materially affected, or is reasonably likely to materially affect, PEF’s internal control over financial reporting.

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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 June 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. Resumption of synthetic fuel production would be dependent upon a number of factors, including a reduction in oil prices, the enactment of future federal tax legislation and/or the duration of the current idling.

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 our synthetic fuel operations remain idle for the remainder of 2006 and 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 ($79 million through June 30, 2006) plus the reversal of income related to Section 29/45 tax credits recorded during the year ($13 million through June 30, 2006).

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

(a) RESTRICTED STOCK AWARDS

(a)   Securities Delivered. On April 1, 2006, 62,200 restricted shares of our common stock were granted to certain key employees 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. Section 9 of the EIP provides for the granting of Restricted Stock by the Organization and Compensation Committee of the Board of Directors, (the Committee) to key employees, including our Affiliates or any successor, and to our outside directors. The shares of common stock delivered pursuant to the EIP were acquired in market transactions directly for the accounts of the recipients and do not represent 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. The shares were delivered to certain key employees. The EIP defines "key employee" as an officer or other employee of Progress Energy who is selected for participation in the EIP.

(c)   Consideration. The shares of our common stock were delivered to provide an incentive to the employee recipients to exert their 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 on the basis of an exemption from registration under Section 4(2) of the Securities Act of 1933. Receipt of the shares of our common stock required no investment decision on the part of the recipients.

(c)ISSUER PURCHASES OF EQUITY SECURITIES FOR SECOND 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)
April 1 - April 30	62,200	$44.63	N/A	N/A
May 1- May 31	-	N/A	N/A	N/A
June 1 - June 30	-	N/A	N/A	N/A
Total	62,200	$44.63	N/A	N/A

(1) As of June 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 to purchase 62,200 shares of our common stock at an average price of $44.63 in connection with restricted stock awards that were granted to certain key employees pursuant to the terms of the EIP.

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Item 4.Submission of Matters to a Vote of Security Holders

Progress Energy

 (a)   The Annual Meeting of the Shareholders of Progress Energy, Inc. was held on May 10, 2006.

 (b)   The meeting involved the election of three Class I directors to serve for two-year terms; four Class II directors to serve for three-year terms and one Class III director to serve for a one-year term. Proxies for the meeting were solicited pursuant to Regulation 14, there was no solicitation in opposition to management’s nominees as listed below, and all nominees were elected.

(c)   The matters voted upon at the meeting and the votes cast for, against or withheld were as follows:

The total votes for the election of directors were as follows:

	Term Expiration	Votes For	Votes Withheld
Class I
W. D. Frederick, Jr.	2008	215,490,208	4,585,104
W. Steven Jones	2008	215,798,985	4,276,327
Theresa M. Stone	2008	215,265,406	4,809,906
Class II
Edwin B. Borden	2009	214,832,442	5,242,870
James E. Bostic, Jr.	2009	214,914,154	5,161,157
David L. Burner	2009	212,469,262	7,606,050
Richard L. Daugherty	2009	214,700,956	5,374,356
Class III
Harris E. DeLoach, Jr.	2007	215,543,794	4,531,517

The Board of Directors’ proposal to ratify the selection of Deloitte & Touche LLP as Progress Energy’s independent registered public accounting firm was approved by the shareholders.

The number of shares voted for the proposal was 215,064,154

The number of shares voted against the proposal was 2,807,547

The number of abstaining votes was 2,203,610

The Board of Directors’ proposal to require the annual election of all members of the Board of Directors was approved by the shareholders.

The number of shares voted for the proposal was 212,102,971

The number of shares voted against the proposal was 4,770,946

The number of abstaining votes was 3,201,394

The Board of Directors’ proposal to require director election by majority vote was approved by the shareholders.

The number of shares voted for the proposal was 213,274,850

The number of shares voted against the proposal was 3,289,843

The number of abstaining votes was 3,510,618

The shareholder proposal relating to Progress Energy’s policies on the hiring of contractors was not approved by the shareholders.

The number of shares voted for the proposal was 14,544,287

The number of shares voted against the proposal was 135,213,222

The number of abstaining votes was 18,601,530

The number of broker non-votes was 51,716,272

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PEC

(a) The Annual Meeting of the Shareholders of Progress Energy, Inc. was held on May 10, 2006.

 

(b) The meeting involved the election of three Class I directors to serve for two-year terms; four Class II directors to serve for three-year terms and one Class III director to serve for a one-year term. Proxies for the meeting were solicited pursuant to Regulation 14, there was no solicitation in opposition to management’s nominees as listed below, and all nominees were elected.

(c) The matters voted upon at the meeting and the votes cast for, against or withheld were as follows:

The total votes for the election of directors were as follows:

	Term Expiration	Votes For	Votes Withheld
Class I
W. D. Frederick, Jr.	2008	159,934,661	3,228
W. Steven Jones	2008	159,935,316	2,573
Theresa M. Stone	2008	159,935,278	2,611
Class II
Edwin B. Borden	2009	159,934,847	3,042
James E. Bostic, Jr.	2009	159,935,400	2,489
David L. Burner	2009	159,935,134	2,755
Richard L. Daugherty	2009	159,934,814	3,075
Class III
Harris E. DeLoach, Jr.	2007	159,934,780	3,109

The Board of Directors’ proposal to ratify the selection of Deloitte & Touche LLP as PEC’s independent registered public accounting firm was approved by the shareholders.

The number of shares voted for the proposal was 159,936,932

The number of shares voted against the proposal was 591

The number of abstaining votes was 366

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Item 6.Exhibits

(a) Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
3(a)	Articles of Amendment effective May 12, 2006 to the Progress Energy, Inc. Articles of Incorporation	X
3(b)	By-Laws of Progress Energy, Inc. as amended on May 10, 2006	X
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

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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: August 9, 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

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