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, 2008

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. 299 First Avenue North 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.

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

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

Progress Energy	Large accelerated filer	x	Accelerated filer	o
	Non-accelerated filer	o	Smaller reporting company	o
PEC	Large accelerated filer	o	Accelerated filer	o
	Non-accelerated filer	x	Smaller reporting company	o
PEF	Large accelerated filer	o	Accelerated filer	o
	Non-accelerated filer	x	Smaller reporting company	o

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

As of August 4, 2008, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	261,987,408
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

TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
PART I.  FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS
	Unaudited Condensed Interim Financial Statements:
	Progress Energy, Inc. (Progress Energy)
	Unaudited Condensed Consolidated Statements of Income
	Unaudited Condensed Consolidated Balance Sheets
	Unaudited Condensed Consolidated Statements of Cash Flows
	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
	Unaudited Condensed Consolidated Statements of Income
	Unaudited Condensed Consolidated Balance Sheets
	Unaudited Condensed Consolidated Statements of Cash Flows
	Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
	Unaudited Condensed Statements of Income
	Unaudited Condensed Balance Sheets
	Unaudited Condensed Statements of Cash Flows
	Combined Notes to Unaudited Condensed 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
ITEM 4T.	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
2007 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2007
401(k)	Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC	Allowance for funds used during construction
AHI	Affordable housing investment
ARO	Asset retirement obligation
Annual Average Price	Average wellhead price per barrel for unregulated domestic crude oil for the year
Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
Audit Committee	Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART	Best Available Retrofit Technology
Broad River	Broad River LLC’s Broad River Facility
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CCO	Competitive Commercial Operations
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Ceredo	Ceredo Synfuel LLC
CIGFUR	Carolina Industrial Group for Fair Utility Rates II
Clean Smokestacks Act	North Carolina Clean Smokestacks Act, enacted in June 2002
Coal Mining	The remaining operations of Progress Fuels subsidiaries engaged in the coal mining business
Coal and Synthetic Fuels	Former business segment that had been primarily engaged in the production and sales of coal-based solid synthetic fuels, the operation of synthetic fuels facilities for third parties and coal terminal services
the Code	Internal Revenue Code
CO2	Carbon dioxide
COL	Combined license
Colona	Colona Synfuel Limited Partnership, LLLP
Corporate and Other	Corporate and Other segment includes Corporate as well as other nonregulated businesses
CR3	PEF’s Crystal River Unit No. 3 Nuclear Plant
CR4 and CR5	PEF’s Crystal River Units No. 4 and 5 coal-fired steam turbines
CUCA	Carolina Utility Customers Association
CVO	Contingent value obligation
D.C. Court of Appeals	U.S. Court of Appeals for the District of Columbia Circuit
DeSoto	DeSoto County Generating Co., LLC
DIG Issue C20	FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”
Dixie Fuels	Dixie Fuels Limited
DOE	United States Department of Energy

4

DSM	Demand-side management
Earthco	Four Earthco coal-based solid synthetic fuels facilities purchased by subsidiaries of Florida Progress in October 1999
ECCR	Energy Conservation Cost Recovery Clause
ECRC	Environmental Cost Recovery Clause
EIA	Energy Information Agency
EIP	Equity Incentive Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPC	Engineering, procurement and construction agreement
ERO	Electric reliability organization
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FDCA	Florida Department of Community Affairs
FGT	Florida Gas Transmission Company L.L.C.
FIN 39	FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts”
FIN 45	FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIN 46R	FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51”
FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
the Florida Global Case	U.S. Global, LLC v. Progress Energy, Inc. et al
Florida Progress	Florida Progress Corporation
FPSC	Florida Public Service Commission
FRCC	Florida Reliability Coordinating Council
FSP	FASB Staff Position
FSP FIN 39-1	FASB Staff Position FIN No. 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts”
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Gas	Natural gas drilling and production business
the Georgia Contracts	Full-requirements contracts with 16 Georgia electric membership cooperatives formerly serviced by CCO
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Operations	Former reporting unit consisting of the Effingham, Monroe, Walton and Washington nonregulated generation plants in service and the Georgia Contracts
Global	U.S. Global, LLC
GridSouth	GridSouth Transco, LLC
Gulfstream	Gulfstream Gas System, L.L.C.
Harris	PEC’s Shearon Harris Nuclear Plant
IBEW	International Brotherhood of Electrical Workers
IRS	Internal Revenue Service
kV	Kilovolt
kVA	Kilovolt-ampere
kWh	Kilowatt-hours
Level 3 Communications	Level 3 Communications, Inc.
LIBOR	London Inter Bank Offering Rate
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in Part I, Item 2 of this Form 10-Q
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003

5

MGP Manufactured gas plant

MW	Megawatts
MWh	Megawatt-hours
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCDWQ	North Carolina Division of Water Quality
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
the Notes Guarantee	Florida Progress’ full and unconditional guarantee of the Subordinated Notes
NOx	Nitrogen Oxides
NOx SIP Call	EPA rule which requires 22 states including North Carolina, South Carolina and Georgia (but excluding Florida) to further reduce emissions of nitrogen oxides
NSR	New Source Review requirements by the EPA
NRC	United States Nuclear Regulatory Commission
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
O&M	Operation and maintenance expense
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income
OPC	Florida’s Office of Public Counsel
OPEB	Postretirement benefits other than pensions
the Parent	Progress Energy, Inc. holding company on an unconsolidated basis
PEC	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
PEF	Florida Power Corporation d/b/a Progress Energy Florida, Inc.
PESC	Progress Energy Service Company, LLC
the Phase-out Price	Price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits are fully eliminated
PM 2.5	EPA standard for particulate matter less than 2.5 microns in diameter
PM 2.5-10	EPA standard for particulate matter between 2.5 and 10 microns in diameter
PM 10	EPA standard for particulate matter less than 10 microns in diameter
Power Agency	North Carolina Eastern Municipal Power Agency
Preferred Securities	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Affiliates	Five affiliated coal-based solid synthetic fuels facilities
Progress Energy	Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants	The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
Progress Fuels	Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail	Progress Rail Services Corporation
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
PT LLC	Progress Telecom, LLC
PUHCA 1935	Public Utility Holding Company Act of 1935, as amended
PUHCA 2005	Public Utility Holding Company Act of 2005
PURPA	Public Utilities Regulatory Policies Act of 1978
PVI	Progress Energy Ventures, Inc., formerly referred to as Progress Ventures, Inc.
PWC	Public Works Commission of the City of Fayetteville, North Carolina
QF	Qualifying facility
RCA	Revolving credit agreement

6

REC	Renewable energy certificates
REPS	North Carolina Renewable Energy and Energy Efficiency Portfolio Standard
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity
Rowan	Rowan County Power, LLC
RSA	Restricted stock awards program
RSU	Restricted stock unit
RTO	Regional transmission organization
SCPSC	Public Service Commission of South Carolina
SEC	United States Securities and Exchange Commission
Section 29	Section 29 of the Code
Section 29/45K	General business tax credits earned after December 31, 2005, for synthetic fuels production in accordance with Section 29
Section 316(b)	Section 316(b) of the Clean Water Act
Section 45K	Section 45K of the Code
(See Note/s “#”)	For all sections, this is a cross-reference to the Combined Notes to Unaudited Condensed Interim Financial Statements contained in PART I, Item 1 of this Form 10-Q
SERC	SERC Reliability Corporation
SESH	Southeast Supply Header, L.L.C.
S&P	Standard & Poor’s Rating Services
SFAS	Statement of Financial Accounting Standards
SFAS No. 5	Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”
SFAS No. 71	Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 87	Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions”
SFAS No. 109	Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
SFAS No. 115	Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”
SFAS No. 123R	Statement of Financial Accounting Standards No. 123R, “Share-Based Payment”
SFAS No. 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS No. 141R	Statement of Financial Accounting Standards No. 141R, “Business Combinations”
SFAS No. 142	Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 143	Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 144	Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS No. 157	Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”
SFAS No. 158	Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS No. 159	Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”
SFAS No. 160	Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”
SFAS No. 161	Statement of Financial Accounting Standards No. 161, “Disclosures About Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”

7

SNG Southern Natural Gas Company

SO2	Sulfur dioxide
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
Terminals	Coal terminals and docks in West Virginia and Kentucky
the Threshold Price	Price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits begin to be reduced
the Trust	FPC Capital I
the Utilities	Collectively, PEC and PEF
Winchester Production	Winchester Production Company, Ltd.

8

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

In addition, examples of forward-looking statements discussed in this Form 10-Q include, but are not limited to, statements made in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the sub-heading “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 fuels tax credits, changes in the regulatory environment, meeting increasing energy demand in our service territories and the impact of environmental regulations.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and the Energy Policy Act of 2005 (EPACT); the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; the financial resources and capital needed to comply with environmental laws and renewable energy portfolio standards and our ability to recover related eligible costs under cost-recovery clauses or base rates; our ability to meet current and future renewable energy requirements; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the impact on our facilities and businesses from a terrorist attack; weather and drought conditions that directly influence the production, delivery and demand for electricity; recurring seasonal fluctuations in demand for electricity; the ability to recover in a timely manner, if at all, costs associated with future significant weather events through the regulatory process; economic fluctuations and the corresponding impact on our customers, including downturns in the housing and consumer credit markets; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; the Progress Registrants’ ability to control costs, including operation and maintenance expense (O&M) and large construction projects; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the ability to successfully access capital markets on favorable terms; the impact that increases in leverage may have on each of the Progress Registrants; the Progress Registrants’ ability to maintain their current credit ratings and the impact on the Progress Registrants’ financial condition and ability to meet their cash and other financial obligations in the event their credit ratings are downgraded; our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); the investment performance of our nuclear decommissioning trust funds and the assets of our pension and benefit plans; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact our nonreporting subsidiaries.

These and other risk factors are detailed from time to time in the Progress Registrants’ filings with the United States Securities and Exchange Commission (SEC). Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors section in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2007 (2007 Form 10-K), which was filed with the SEC on February 28, 2008, and is updated for material changes, if any, in this Form 10-Q and in our other SEC filings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on the Progress Registrants.

9

PART I.  FINANCIAL INFORMATION

ITEM 1.                      FINANCIAL STATEMENTS

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

June 30, 2008

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended June 30,						Six months ended June 30,
(in millions except per share data)	2008			2007			2008			2007
Operating revenues	$	2,244		$	2,129		$	4,310		$	4,201
Operating expenses
Fuel used in electric generation		696			716			1,393			1,452
Purchased power		330			283			562			504
Operation and maintenance		488			461			931			881
Depreciation and amortization		208			223			414			442
Taxes other than on income		125			125			246			249
Other		(9	)		20			(7	)		21
Total operating expenses		1,838			1,828			3,539			3,549
Operating income		406			301			771			652
Other income (expense)
Interest income		5			6			12			14
Allowance for equity funds used during construction		27			10			50			20
Other, net		3			(2	)		(2	)		(1	)
Total other income, net		35			14			60			33
Interest charges
Interest charges		154			139			315			284
Allowance for borrowed funds used during construction		(8	)		(4	)		(16	)		(7	)
Total interest charges, net		146			135			299			277
Income from continuing operations before income tax and minority interest		295			180			532			408
Income tax expense		95			41			179			113
Income from continuing operations before minority interest		200			139			353			295
Minority interest in subsidiaries’ income, net of tax		–			(1	)		(4	)		(8	)
Income from continuing operations		200			138			349			287
Discontinued operations, net of tax		5			(331	)		65			(205	)
Net income (loss)	$	205		$	(193	)	$	414		$	82
Average common shares outstanding – basic		260			256			259			255
Basic earnings per common share
Income from continuing operations	$	0.77		$	0.54		$	1.35		$	1.13
Discontinued operations, net of tax		0.02			(1.29	)		0.25			(0.81	)
Net income (loss)	$	0.79		$	(0.75	)	$	1.60		$	0.32
Diluted earnings per common share
Income from continuing operations	$	0.77		$	0.54		$	1.34		$	1.12
Discontinued operations, net of tax		0.02			(1.29	)		0.25			(0.80	)
Net income (loss)	$	0.79		$	(0.75	)	$	1.59		$	0.32
Dividends declared per common share	$	0.615		$	0.610		$	1.230		$	1.220

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

10

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	June 30, 2008			December 31, 2007
ASSETS
Utility plant
Utility plant in service	$	25,880		$	25,327
Accumulated depreciation		(11,102	)		(10,895	)
Utility plant in service, net		14,778			14,432
Held for future use		37			37
Construction work in progress		2,297			1,765
Nuclear fuel, net of amortization		389			371
Total utility plant, net		17,501			16,605
Current assets
Cash and cash equivalents		1,423			255
Receivables, net		934			1,167
Inventory		1,123			994
Deferred fuel cost		295			154
Derivative assets		520			85
Assets to be divested		–			52
Prepayments and other current assets		187			122
Total current assets		4,482			2,829
Deferred debits and other assets
Regulatory assets		854			946
Nuclear decommissioning trust funds		1,302			1,384
Miscellaneous other property and investments		464			448
Goodwill		3,655			3,655
Derivative assets		617			119
Other assets and deferred debits		417			379
Total deferred debits and other assets		7,309			6,931
Total assets	$	29,292		$	26,365
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 261 million and 260 million shares issued and outstanding, respectively	$	6,102		$	6,028
Unearned ESOP shares (1 million and 2 million shares, respectively)		(25	)		(37	)
Accumulated other comprehensive loss		(28	)		(34	)
Retained earnings		2,558			2,465
Total common stock equity		8,607			8,422
Preferred stock of subsidiaries – not subject to mandatory redemption		93			93
Minority interest		6			84
Long-term debt, affiliate		271			271
Long-term debt, net		9,886			8,466
Total capitalization		18,863			17,336
Current liabilities
Current portion of long-term debt		850			877
Short-term debt		343			201
Accounts payable		1,078			819
Interest accrued		162			173
Dividends declared		161			160
Customer deposits		268			255
Regulatory liabilities		17			173
Derivative collateral liabilities		420			108
Liabilities to be divested		–			8
Other current liabilities		568			528
Total current liabilities		3,867			3,302
Deferred credits and other liabilities
Noncurrent income tax liabilities		252			361
Accumulated deferred investment tax credits		133			139
Regulatory liabilities		3,500			2,554
Asset retirement obligations		1,417			1,378
Accrued pension and other benefits		759			763
Capital lease obligations		236			239
Other liabilities and deferred credits		265			293
Total deferred credits and other liabilities		6,562			5,727
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	29,292		$	26,365

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

11

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Six months ended June 30	2008			2007
Operating activities
Net income	$	414		$	82
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		467			504
Deferred income taxes and investment tax credits, net		98			132
Deferred fuel (credit) cost		(166	)		83
Deferred income		–			(64	)
Allowance for equity funds used during construction		(50	)		(20	)
Other adjustments to net income		(9	)		85
Cash provided (used) by changes in operating assets and liabilities
Receivables		224			13
Inventory		(116	)		(56	)
Prepayments and other current assets		(28	)		(58	)
Income taxes, net		(60	)		(508	)
Accounts payable		293			24
Derivative collateral liabilities		312			(89	)
Other current liabilities		10			202
Other assets and deferred debits		(33	)		(127	)
Other liabilities and deferred credits		1			(26	)
Net cash provided by operating activities		1,357			177
Investing activities
Gross property additions		(1,260	)		(899	)
Nuclear fuel additions		(43	)		(97	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		64			646
Purchases of available-for-sale securities and other investments		(836	)		(382	)
Proceeds from sales of available-for-sale securities and other investments		816			433
Other investing activities		(15	)		(8	)
Net cash used by investing activities		(1,274	)		(307	)
Financing activities
Issuance of common stock		42			122
Dividends paid on common stock		(320	)		(311	)
Payments of short-term debt with original maturities greater than 90 days		(176	)		–
Net increase in short-term debt		318			169
Proceeds from issuance of long-term debt, net		1,798			–
Retirement of long-term debt		(427	)		(2	)
Cash distributions to minority interests of consolidated subsidiaries		(85	)		(10	)
Other financing activities		(65	)		(17	)
Net cash provided (used) by financing activities		1,085			(49	)
Net increase (decrease) in cash and cash equivalents		1,168			(179	)
Cash and cash equivalents at beginning of period		255			265
Cash and cash equivalents at end of period	$	1,423		$	86
Supplemental disclosures
Significant noncash transactions
Capital lease obligation incurred	$	–		$	182
Note receivable for disposal of ownership interest in Ceredo		–			48
Nuclear decommissioning trust funds unrealized loss (gain)		98			(50	)
Accrued property additions		263			192
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

12

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

June 30, 2008

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended June 30,						Six months ended June 30,
(in millions)	2008			2007			2008			2007
Operating revenues	$	1,048		$	996		$	2,116		$	2,054
Operating expenses
Fuel used in electric generation		323			305			679			656
Purchased power		72			76			121			134
Operation and maintenance		275			268			523			516
Depreciation and amortization		129			118			255			235
Taxes other than on income		49			49			99			99
Other		(5	)		–			(6	)		(1	)
Total operating expenses		843			816			1,671			1,639
Operating income		205			180			445			415
Other income
Interest income		2			5			7			11
Other, net		11			7			15			10
Total other income, net		13			12			22			21
Interest charges
Interest charges		52			54			110			111
Allowance for borrowed funds used during construction		(2	)		(1	)		(4	)		(2	)
Total interest charges, net		50			53			106			109
Income before income tax		168			139			361			327
Income tax expense		64			51			134			115
Net income		104			88			227			212
Preferred stock dividend requirement		–			–			1			1
Earnings for common stock	$	104		$	88		$	226		$	211

See Notes to PEC Unaudited Condensed Consolidated Interim Financial Statements.

13

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	June 30, 2008			December 31, 2007
ASSETS
Utility plant
Utility plant in service	$	15,433		$	15,117
Accumulated depreciation		(7,225	)		(7,097	)
Utility plant in service, net		8,208			8,020
Held for future use		2			2
Construction work in progress		521			566
Nuclear fuel, net of amortization		294			292
Total utility plant, net		9,025			8,880
Current assets
Cash and cash equivalents		18			25
Receivables, net		513			491
Receivables from affiliated companies		12			42
Notes receivable from affiliated companies		39			–
Inventory		553			510
Deferred fuel cost		232			148
Prepayments and other current assets		118			50
Total current assets		1,485			1,266
Deferred debits and other assets
Regulatory assets		571			680
Nuclear decommissioning trust funds		767			804
Miscellaneous other property and investments		198			192
Derivative assets		113			19
Other assets and deferred debits		149			141
Total deferred debits and other assets		1,798			1,836
Total assets	$	12,308		$	11,982
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,076		$	2,054
Unearned ESOP common stock		(25	)		(37	)
Accumulated other comprehensive loss		(15	)		(10	)
Retained earnings		1,998			1,772
Total common stock equity		4,034			3,779
Preferred stock – not subject to mandatory redemption		59			59
Long-term debt, net		3,108			3,183
Total capitalization		7,201			7,021
Current liabilities
Current portion of long-term debt		400			300
Notes payable to affiliated companies		–			154
Accounts payable		386			308
Payables to affiliated companies		87			71
Interest accrued		60			58
Customer deposits		76			70
Income taxes accrued		–			27
Other current liabilities		208			182
Total current liabilities		1,217			1,170
Deferred credits and other liabilities
Noncurrent income tax liabilities		915			936
Accumulated deferred investment tax credits		119			122
Regulatory liabilities		1,213			1,098
Asset retirement obligations		1,094			1,063
Accrued pension and other benefits		453			459
Other liabilities and deferred credits		96			113
Total deferred credits and other liabilities		3,890			3,791
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	12,308		$	11,982

See Notes to PEC Unaudited Condensed Consolidated Interim Financial Statements.

14

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Six months ended June 30	2008			2007
Operating activities
Net income	$	227		$	212
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		304			277
Deferred income taxes and investment tax credits, net		15			27
Deferred fuel cost		30			33
Other adjustments to net income		9			(28	)
Cash (used) provided by changes in operating assets and liabilities
Receivables		(27	)		8
Receivables from affiliated companies		30			9
Inventory		(36	)		(20	)
Prepayments and other current assets		20			5
Income taxes, net		(78	)		(28	)
Accounts payable		74			(1	)
Payables to affiliated companies		16			(44	)
Other current liabilities		26			6
Other assets and deferred debits		(21	)		(4	)
Other liabilities and deferred credits		(26	)		2
Net cash provided by operating activities		563			454
Investing activities
Gross property additions		(331	)		(407	)
Nuclear fuel additions		(42	)		(75	)
Purchases of available-for-sale securities and other investments		(337	)		(226	)
Proceeds from sales of available-for-sale securities and other investments		321			260
Changes in advances to affiliated companies		(39	)		24
Other investing activities		(6	)		(2	)
Net cash used by investing activities		(434	)		(426	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		–			(72	)
Proceeds from issuance of long-term debt, net		322			–
Retirement of long-term debt		(300	)		–
Changes in advances from affiliated companies		(154	)		5
Other financing activities		(3	)		17
Net cash used by financing activities		(136	)		(51	)
Net decrease in cash and cash equivalents		(7	)		(23	)
Cash and cash equivalents at beginning of period		25			71
Cash and cash equivalents at end of period	$	18		$	48
Supplemental disclosures
Significant noncash transactions
Nuclear decommissioning trust funds unrealized loss (gain)	$	53		$	(26	)
Accrued property additions		80			81
See Notes to PEC Unaudited Condensed Consolidated Interim Financial Statements.

15

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

June 30, 2008

UNAUDITED CONDENSED STATEMENTS of INCOME
	Three months ended June 30,						Six months ended June 30,
(in millions)	2008			2007			2008			2007
Operating revenues	$	1,194		$	1,129		$	2,190		$	2,140
Operating expenses
Fuel used in electric generation		373			411			714			796
Purchased power		258			207			441			370
Operation and maintenance		217			198			420			373
Depreciation and amortization		76			100			152			197
Taxes other than on income		76			76			147			150
Other		(4	)		12			(4	)		12
Total operating expenses		996			1,004			1,870			1,898
Operating income		198			125			320			242
Other income (expense)
Interest income		1			1			2			2
Allowance for equity funds used during construction		22			8			40			16
Other, net		–			–			(1	)		(1	)
Total other income, net		23			9			41			17
Interest charges
Interest charges		45			42			95			81
Allowance for borrowed funds used during construction		(6	)		(3	)		(12	)		(5	)
Total interest charges, net		39			39			83			76
Income before income tax		182			95			278			183
Income tax expense		57			27			86			54
Net income		125			68			192			129
Preferred stock dividend requirement		–			–			1			1
Earnings for common stock	$	125		$	68		$	191		$	128

See Notes to PEF Unaudited Condensed Interim Financial Statements.

16

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	June 30, 2008			December 31, 2007
ASSETS
Utility plant
Utility plant in service	$	10,263		$	10,025
Accumulated depreciation		(3,817	)		(3,738	)
Utility plant in service, net		6,446			6,287
Held for future use		35			35
Construction work in progress		1,776			1,199
Nuclear fuel, net of amortization		95			79
Total utility plant, net		8,352			7,600
Current assets
Cash and cash equivalents		1,348			23
Receivables, net		414			351
Receivables from affiliated companies		8			8
Notes receivable from affiliated companies		–			149
Inventory		570			484
Deferred income taxes		–			39
Income taxes receivable		15			41
Derivative assets		478			83
Prepayments and other current assets		116			9
Total current assets		2,949			1,187
Deferred debits and other assets
Regulatory assets		283			266
Nuclear decommissioning trust funds		535			580
Miscellaneous other property and investments		44			46
Derivative assets		504			100
Prepaid pension cost		233			221
Other assets and deferred debits		101			63
Total deferred debits and other assets		1,700			1,276
Total assets	$	13,001		$	10,063
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,113		$	1,109
Accumulated other comprehensive loss		–			(8	)
Retained earnings		2,092			1,901
Total common stock equity		3,205			3,002
Preferred stock – not subject to mandatory redemption		34			34
Long-term debt, net		4,181			2,686
Total capitalization		7,420			5,722
Current liabilities
Current portion of long-term debt		450			532
Notes payable to affiliated companies		43			–
Accounts payable		676			473
Payables to affiliated companies		42			87
Interest accrued		47			57
Customer deposits		192			185
Derivative liabilities		2			38
Regulatory liabilities		17			173
Derivative collateral liabilities		409			–
Deferred income tax liabilities		160			–
Other current liabilities		136			92
Total current liabilities		2,174			1,637
Deferred credits and other liabilities
Noncurrent income tax liabilities		288			401
Accumulated deferred investment tax credits		14			17
Regulatory liabilities		2,164			1,330
Asset retirement obligations		323			315
Accrued pension and other benefits		304			304
Capital lease obligations		221			224
Other liabilities and deferred credits		93			113
Total deferred credits and other liabilities		3,407			2,704
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	13,001		$	10,063

See Notes to PEF Unaudited Condensed Interim Financial Statements.

17

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Six months ended June 30	2008			2007
Operating activities
Net income	$	192		$	129
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		153			210
Deferred income taxes and investment tax credits, net		48			(19	)
Deferred fuel (credit) cost		(196	)		50
Allowance for equity funds used during construction		(40	)		(16	)
Other adjustments to net income		4			39
Cash (used) provided by changes in operating assets and liabilities
Receivables		(65	)		(13	)
Receivables from affiliated companies		–			(1	)
Inventory		(85	)		(42	)
Prepayments and other current assets		(49	)		58
Income taxes, net		34			82
Accounts payable		237			104
Payables to affiliated companies		(45	)		(72	)
Derivative collateral liabilities		409			–
Other current liabilities		27			54
Other assets and deferred debits		(10	)		(1	)
Other liabilities and deferred credits		40			(15	)
Net cash provided by operating activities		654			547
Investing activities
Gross property additions		(921	)		(489	)
Nuclear fuel additions		(1	)		(22	)
Purchases of available-for-sale securities and other investments		(418	)		(103	)
Proceeds from sales of available-for-sale securities and other investments		418			103
Changes in advances to affiliated companies		149			–
Proceeds from sales of assets to affiliated companies		10			–
Other investing activities		(2	)		–
Net cash used by investing activities		(765	)		(511	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Proceeds from issuance of long-term debt, net		1,476			–
Retirement of long-term debt		(82	)		(2	)
Changes in advances from affiliated companies		43			(43	)
Other financing activities		–			1
Net cash provided (used) by financing activities		1,436			(45	)
Net increase (decrease) in cash and cash equivalents		1,325			(9	)
Cash and cash equivalents at beginning of period		23			23
Cash and cash equivalents at end of period	$	1,348		$	14
Supplemental disclosures
Significant noncash transactions
Capital lease obligation incurred	$	–		$	182
Nuclear decommissioning trust funds unrealized loss (gain)		45			(24	)
Accrued property additions		180			110
See Notes to PEF Unaudited Condensed Interim Financial Statements.

18

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

INDEX TO APPLICABLE COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS BY REGISTRANT

Each of the following combined notes to the unaudited condensed 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. The notes that are not listed below for PEC or PEF are not, and shall not be deemed to be, part of PEC’s or PEF’s financial statements contained herein.

Registrant	Applicable Notes
PEC	1, 2, 4 through 9, and 11 through 13
PEF	1, 2, 4 through 9, and 11 through 13

19

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED 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

PROGRESS ENERGY, INC.

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

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a separate business segment. See Note 10 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory provisions of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.

PEF

PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory provisions of the Florida Public Service Commission (FPSC), the NRC and the FERC.

B.           BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) 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, 2007 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, 2007 (2007 Form 10-K).

20

In accordance with the provisions of Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. The tax levelization expense or benefit recorded during the interim period, which 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 the three and six months ended June 30, 2008, are primarily due to seasonal fluctuations in energy sales and earnings from the Utilities. The fluctuations in the effective tax rate for the three and six months ended June 30, 2007, are primarily due to the recognition of synthetic fuels tax credits and seasonal fluctuations in energy sales and earnings from the Utilities. Total tax levelization adjustments increased (decreased) income tax expense for the Progress Registrants for the three and six months ended June 30, 2008 and 2007, as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2008			2007		2008			2007
Progress Energy	$	3		$	31	$	(4	)	$	23
PEC		2			–		(1	)		(1	)
PEF		(4	)		1		(3	)		1

For the three and six months ended June 30, 2007, $32 million and $22 million, respectively, of the Progress Energy net tax levelization expense was related to synthetic fuels tax credits recorded by the synthetic fuels businesses and is included in discontinued operations on the Consolidated Statements of Income, pursuant to the intraperiod tax allocation rules as set forth in Statement of Financial Accounting Standard (SFAS) No. 109, “Accounting for Income Taxes” (SFAS No. 109). When the synthetic fuels businesses were reclassified to discontinued operations in the fourth quarter of 2007 (See Note 3A), the impacts of the quarterly tax levelization adjustments associated with the synthetic fuels tax credits were not also reclassified to discontinued operations in Note 24 in the 2007 Form 10-K, including the $32 million levelization expense for the three months ended June 30, 2007 discussed above. Consequently, the presentation of the unaudited summarized quarterly financial data previously reported for Progress Energy in Note 24 in the 2007 Form 10-K was not correct. As a result, the unaudited summarized quarterly financial data has been restated. This correction does not affect our Consolidated Statements of Income for 2007 or 2006, as the quarterly tax levelization adjustments net to zero on an annual basis. The following table presents specific line item amounts for the three months ended June 30, 2007, included in Note 24 in the 2007 Form 10-K that have been restated as a result of this correction:

Progress Energy
(in millions except per share data)	As originally reported		As restated
Income from continuing operations	$	106	$	138
Common stock data
Basic earnings per common share
Income from continuing operations		0.42		0.54
Diluted earnings per common share
Income from continuing operations		0.41		0.54

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of income were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2008		2007		2008		2007
Progress Energy	$	72	$	71	$	137	$	137
PEC		25		24		50		48
PEF		47		47		87		89

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants’ financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather

21

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 future periods.

In preparing financial statements that conform to 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 2007 have been reclassified to conform to the 2008 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 March 2007, we disposed of our 100 percent ownership interest in Ceredo Synfuel LLC (Ceredo), a coal-based solid synthetic fuels production facility that qualifies for federal tax credits under Section 45K of the Internal Revenue Code (the Code), to a third-party buyer. Progress Energy, through its subsidiary Progress Fuels Corporation (Progress Fuels), is the primary beneficiary of, and continues to consolidate Ceredo. See Note 3F for additional information on the disposal of Ceredo.

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 equity investments made prior to 2005 in five entities whose operations include affordable housing and venture capital investments, research and development, or real estate activities. At June 30, 2008, the aggregate maximum loss exposure that we could be required to record in our statement of income as a result of these arrangements was $5 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, 2008, the assets of the two entities totaled $37 million, the majority of which are collateral for the entities’ obligations, and were included in miscellaneous other property and investments in the Consolidated Balance Sheets.

PEC has an interest in and consolidates one 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 was requested declined to provide the information to PEC and accordingly, PEC has applied the information scope exception in FIN 46R, paragraph 4(g), to the 17 partnerships 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. However, because PEC has not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include equity investments in 18 entities whose operations include affordable housing, venture capital investments, research and development, or real estate activities and two building leases with special-purpose entities. The majority of the arrangements were entered into prior to 2003. At June 30, 2008, the aggregate maximum loss exposure that PEC could be required to record on its statement of income as a result of these arrangements was $18 million, which primarily represents its net remaining investment in these entities. The

22

creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure.

PEF

PEF has interests in four variable interest entities for which PEF is not the primary beneficiary. These arrangements include equity investments in two entities whose operations include venture capital investments or research and development activities and one building lease and one railcar lease with special-purpose entities. All interests were entered into prior to 2008. At June 30, 2008, the aggregate maximum loss exposure that PEF could be required to record in its statement of income as a result of these arrangements was $56 million. The majority of this exposure is related to a prepayment clause in a building capital lease, of which $3 million had been prepaid at June 30, 2008. 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

Fair Value Measurements - Adoption of FASB Statements Nos. 157 and 159

Refer to Note 7 for information regarding our first quarter 2008 implementation of SFAS No. 157, “Fair Value Measurements” (SFAS No. 157).

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS No. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The decision about whether to elect the fair value option is applied on an instrument by instrument basis, is irrevocable (unless a new election date occurs) and is applied to the entire financial instrument. SFAS No. 159 was effective for us and the Utilities on January 1, 2008. We and the Utilities did not elect to adopt the fair value option for any financial instruments.

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

FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN 39), specifies what conditions must be met for an entity to have the right to offset assets and liabilities in the balance sheet and clarifies when it is appropriate to offset amounts recognized for forward, interest rate swap, currency swap, option, and other conditional or exchange contracts. FIN 39 also permits offsetting of fair value amounts recognized for multiple contracts executed with the same counterparty under a master netting arrangement. On April 30, 2007, the FASB issued FASB Staff Position (FSP) No. FIN 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1), which amended portions of FIN 39 to make certain terms consistent with those used in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). FSP FIN 39-1 also amends FIN 39 to allow for the offsetting of fair value amounts for the right to reclaim collateral assets or liabilities arising from the same master netting arrangement as the derivative instruments. We implemented the FSP as of January 1, 2008, as a retrospective change in accounting principle for all financial statements presented. We and the Utilities previously offset fair value amounts recognized for derivative instruments under master netting arrangements. As allowed under FSP FIN 39-1, we and the Utilities changed our accounting policy effective January 1, 2008, and discontinued the offset of fair value amounts for such derivatives. The change had no impact on our or the Utilities’ results of operations or equity and resulted in increases in previously-reported December 31, 2007 assets and liabilities, as follows:

(in millions)	Progress Energy		PEC		PEF
Current assets	$	54	$	19	$	35
Noncurrent assets		25		1		24
Current liabilities		54		19		35
Noncurrent liabilities		25		1		24

23

FASB Statement No. 161, Disclosures About Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133

In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161), which requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 requires significant quantitative disclosures to be presented in a tabular format, including disclosures of the location, by line item, of fair value amounts of derivative instruments in the balance sheet and the location, by line item, of amounts of derivative gains and losses reported in the income statement. SFAS No. 161 also requires entities to disclose information regarding the existence and nature of credit-risk-related contingent features included in derivative instruments that require the instrument to be settled or collateral posted in the event of a credit downgrade. SFAS No. 161 is effective for us and the Utilities on January 1, 2009. The adoption of SFAS No. 161 will change certain disclosures in the notes to the financial statements, but will have no impact on our or the Utilities' financial position or results of operations.

3.     DIVESTITURES

A.    TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky (Terminals) for $71 million in gross cash proceeds. The terminals had a total annual capacity in excess of 40 million tons for transloading, blending and storing coal and other commodities. Proceeds from the sale were used for general corporate purposes. During the six months ended June 30, 2008, we recorded an after-tax gain of $41 million on the sale of these assets. The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of Terminals as discontinued operations.

Prior to 2008, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 (Section 29) of the Code and as redesignated effective 2006 as Section 45K of the Code (Section 45K and collectively, Section 29/45K). The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. As a result of the expiration of the tax credit program, all of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007. The accompanying consolidated statements of income have been restated for all periods presented to reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

In addition, as discussed in Note 1B, the recognition of tax credits generated by the production and sale of synthetic fuels historically resulted in significant fluctuations in our effective tax rate for interim periods. Pursuant to the intraperiod tax allocation rules of SFAS No. 109, $32 million and $22 million of tax levelization expense, which is primarily related to the recognition of synthetic fuels tax credits, is included in the discontinued operations income tax benefit for the three and six months ended June 30, 2007, respectively.

Results of Terminals and the synthetic fuels businesses discontinued operations for the three and six months ended June 30 were as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
(in millions)	2008		2007			2008			2007
Revenues	$	–	$	276		$	17		$	538
(Loss) earnings before income tax and minority interest		–		(73	)		11			(58	)
Income tax benefit		8		39			12			93
Minority interest portion of synthetic fuel losses (earnings)		–		27			(1	)		29
Net earnings (loss) from discontinued operations		8		(7	)		22			64
Gain on disposal of discontinued operations, including income tax expense of $7		–		–			41			–
Earnings (loss) from discontinued operations	$	8	$	(7	)	$	63		$	64

24

B.    CCO – GEORGIA OPERATIONS

On March 9, 2007, our subsidiary, Progress Energy Ventures, Inc. (PVI), entered into a series of transactions to sell or assign substantially all of its Competitive Commercial Operations (CCO) physical and commercial assets and liabilities. Assets divested include approximately 1,900 megawatts (MW) of gas-fired generation assets in Georgia. The sale of the generation assets closed on June 11, 2007, for a net sales price of $615 million. We recorded an estimated loss of $226 million in December 2006. Based on the terms of the final agreement, during the three and six months ended June 30, 2007, we reversed $1 million and $17 million, respectively, after-tax of the impairment recorded in 2006.

Additionally, on June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of full-requirements contracts with 16 Georgia electric membership cooperatives (the Georgia Contracts), forward gas and power contracts, gas transportation, structured power and other contracts to a third party. This represents substantially all of our nonregulated energy marketing and trading operations. As a result of the assignments, PVI made a net cash payment of $347 million, which represents the net cost to assign the Georgia Contracts and other related contracts. In the quarter ended June 30, 2007, we recorded a charge associated with the costs to exit the Georgia Contracts, and other related contracts, of $349 million after-tax (charge included in the net loss from discontinued operations in the table below). We used the net proceeds from these transactions for general corporate purposes.

The accompanying consolidated financial statements reflect the operations of CCO as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the three and six months ended June 30, 2007, was $5 million and $11 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in December 2006. Results of CCO discontinued operations for the three and six months ended June 30 were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Revenues	$	–		$	154		$	–		$	406
Loss before income tax		(5	)		(513	)		(5	)		(443	)
Income tax benefit		2			191			2			164
Net loss from discontinued operations		(3	)		(322	)		(3	)		(279	)
Gain on disposal of discontinued operations, including income tax benefit of $5 and $7, respectively		–			1			–			17
Loss from discontinued operations	$	(3	)	$	(321	)	$	(3	)	$	(262	)

C.   COAL MINING BUSINESSES

On March 7, 2008, we sold the remaining operations of Progress Fuels subsidiaries engaged in the coal mining business (Coal Mining) for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. These assets included Powell Mountain Coal Co. and Dulcimer Land Co., which consisted of approximately 30,000 acres in Lee County, Va. and Harlan County, Ky. As a result of the sale, during the six months ended June 30, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.

25

The accompanying consolidated financial statements reflect Coal Mining as discontinued operations. Results of Coal Mining discontinued operations for the three and six months ended June 30 were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Revenues	$	–		$	7		$	2		$	14
Loss before income tax		(2	)		(5	)		(6	)		(11	)
Income tax benefit		1			1			2			3
Net loss from discontinued operations		(1	)		(4	)		(4	)		(8	)
Gain on disposal of discontinued operations, including income tax expense of $2		–			–			7			–
(Loss) earnings from discontinued operations	$	(1	)	$	(4	)	$	3		$	(8	)

D.    OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations are amounts related to our sales of other diversified businesses, primarily related to the sale of our natural gas drilling and production business (Gas) and the sale of Progress Rail Services Corporation (Progress Rail). These adjustments are mainly due to the finalization of working capital adjustments and adjustments in connection with guarantees and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters (See Note 13B). The ultimate resolution of these matters could result in additional adjustments in future periods. For the three and six months ended June 30, 2008, we recorded additional gains of $1 million and $2 million, respectively, net of tax. For each of the three and six months ended June 30, 2007, we recorded additional gains of $1 million, net of tax.

E.   NET ASSETS OF DISCONTINUED OPERATIONS

At December 31, 2007, the assets and liabilities of Terminals and the remaining assets and liabilities of Coal Mining operations were included in net assets to be divested. The major balance sheet classes included in assets and liabilities to be divested in the Consolidated Balance Sheets were as follows:

(in millions)	December 31, 2007
Inventory	$	6
Other current assets		2
Total property, plant and equipment, net		38
Total other assets		6
Assets to be divested	$	52
Accrued expenses	$	3
Long-term liabilities		5
Liabilities to be divested	$	8

F.   CEREDO SYNTHETIC FUELS INTERESTS

On March 30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership interest in Ceredo, a subsidiary that produced and sold qualifying coal-based solid synthetic fuels, to a third-party buyer. In addition, we entered into an agreement to operate the Ceredo facility on behalf of the buyer. At closing, we received cash proceeds of $10 million and a non-recourse note receivable of $54 million. Payments on the note were due as we produced and sold qualifying synthetic fuels on behalf of the buyer. In accordance with the terms of the agreement, we received payments on the note related to 2007 production of $49 million during the year ended December 31, 2007, and a final payment of $5 million during the three months ended March 31, 2008. The note had an interest rate equal to the three-month London Inter Bank Offering Rate (LIBOR) rate plus 1%. The estimated fair value of the note at the inception of the transaction was $48 million. Under the terms of the agreement, the purchase price was reduced by $7 million during the six months ended June 30, 2008, based on the final value of the 2007 Section 29/45K tax credits.

26

During the six months ended June 30, 2008, we recorded gains on disposal of $5 million based on the final value of the 2007 Section 29/45K tax credits. The operations of Ceredo ceased as of December 31, 2007, and are recorded as discontinued operations for all periods presented. See discussion of the abandonment of our synthetic fuels operations at Note 3A.

4.     REGULATORY MATTERS

A.           PEC RETAIL RATE MATTERS

BASE RATES

PEC’s base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC. In June 2002, the North Carolina Clean Smokestacks Act (Clean Smokestacks Act) was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) from their North Carolina coal-fired power plants in  phases by 2013. The Clean Smokestacks Act froze North Carolina electric utility  base rates for a five-year period, which ended December 31, 2007, unless there were

extraordinary events beyond the control of the utilities or unless the utilities persistently earned a return substantially in excess of the rate of return established and found reasonable by the NCUC in the respective utility’s last general rate case. There were no adjustments to PEC’s base rates during the five-year period ended December 31, 2007. Subsequent to 2007, PEC’s current North Carolina base rates are continuing subject to traditional cost-based rate regulation.

During the rate freeze period, the legislation provided for a minimum amortization and recovery of 70 percent of the original estimated compliance costs of $813 million (or $569 million) while providing significant flexibility in the amount of annual amortization recorded from none up to $174 million per year. On March 23, 2007, PEC filed a petition with the NCUC requesting that it be allowed to amortize the remaining 30 percent (or $244 million) of the original estimated compliance costs for the Clean Smokestacks Act during 2008 and 2009, with discretion to amortize up to $174 million in either year. For the three months ended June 30, 2008, PEC did not recognize any amortization. For the six months ended June 30, 2008, PEC recognized amortization of $15 million. For the three and six months ended June 30, 2007, PEC recognized amortization of $8 million and $17 million, respectively. PEC has recognized $584 million in cumulative amortization through June 30, 2008.

Additionally, among other things, PEC requested in its March 23, 2007 petition that the NCUC allow PEC to include in its rate base those eligible compliance costs exceeding the original estimated compliance costs and that PEC be allowed to accrue allowance for funds used during construction (AFUDC) on all eligible compliance costs in excess of the original estimated compliance costs. PEC also requested that any prudency review of PEC’s environmental compliance costs be deferred until PEC’s next ratemaking proceeding in which PEC seeks to adjust its base rates. On October 22, 2007, PEC filed with the NCUC a settlement agreement with the NCUC Public Staff, the Carolina Utility Customers Association (CUCA) and the Carolina Industrial Group for Fair Utility Rates II (CIGFUR) supporting PEC’s proposal. The NCUC held a hearing on this matter on October 30, 2007. On December 20, 2007, the NCUC approved the settlement agreement on a provisional basis, with the NCUC indicating that it intended to initiate a review in 2009 to consider all reasonable alternatives and proposals related to PEC’s recovery of its Clean Smokestacks Act compliance costs in excess of the original estimated costs of $813 million. Additionally, the NCUC ordered that no portion of Clean Smokestacks Act compliance costs directly assigned, allocated or otherwise attributable to another jurisdiction shall be recovered from PEC’s retail North Carolina customers, even if recovery of these costs is disallowed or denied, in whole or in part, in another jurisdiction.

On July 10, 2008, PEC filed a petition with the NCUC requesting that the NCUC reconsider its order issued December 20, 2007, and terminate the requirement that PEC amortize any Clean Smokestacks Act compliance costs in excess of $569 million, and instead allow PEC to place into rate base all capital costs associated with its compliance with the Clean Smokestacks Act in excess of $569 million. The NCUC Public Staff, CUCA, CIGFUR and the North Carolina Attorney General have advised PEC that they do not object to the relief PEC is requesting in the filed petition. On July 18, 2008, the NCUC requested that all parties file a response to PEC’s petition by August 1, 2008. The NCUC further established that PEC may file reply comments to the initial comments by August 8, 2008, or, if there is no opposition to the petition, the parties shall file a joint proposed order for consideration by the NCUC by August 8, 2008. If the NCUC approves PEC’s petition, PEC would not be required to amortize $244

27

million of the original estimated compliance costs for the Clean Smokestacks Act during 2008 and 2009, but would record depreciation over the useful life of the assets. However, we cannot predict the outcome of these matters.

See Note 12B for additional information about the Clean Smokestacks Act.

FUEL COST RECOVERY

On April 30, 2008, PEC filed with the SCPSC for an increase in the fuel rate charged to its South Carolina ratepayers. PEC asked the SCPSC to approve a $39 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements and to meet future expected fuel costs. On June 26, 2008, the SCPSC approved PEC’s request. Effective July 1, 2008, residential electric bills increased by $5.86 per 1,000 kilowatt-hours (kWh), or 6.1 percent, for fuel cost recovery.

On June 6, 2008, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. PEC asked the NCUC to approve a $424 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements and to meet future expected fuel costs. In addition, PEC asked the NCUC for approval of demand-side management (DSM) and energy-efficiency and North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (REPS) clauses to recover the costs of these programs as further discussed below. If the filings are approved, the increases would take effect on or about December 1, 2008, and would increase residential electric bills in total by $15.71 per 1,000 kWh, or 16.2 percent. A hearing on the fuel filing has been scheduled by the NCUC for September 16, 2008. We cannot predict the outcome of this matter.

OTHER MATTERS

During 2007, the North Carolina legislature passed comprehensive energy legislation, which became law on August 20, 2007. Among other provisions, the law allows the utility to recover the costs of new DSM and energy-efficiency programs through an annual DSM clause. The law allows PEC to capitalize those costs that are intended to produce future benefits and authorizes the NCUC to approve other forms of financial incentives to the utility for DSM and energy-efficiency programs. DSM programs include, but are not limited to, any program or initiative that shifts the timing of electricity use from peak to nonpeak periods and includes load management, electricity system and operating controls, direct load control, interruptible load and electric system equipment and operating controls. Energy-efficiency programs help our customers reduce energy use and reduce the emissions that contribute to global climate change. PEC has begun implementing a series of DSM and energy-efficiency programs and, as of June 30, 2008, has deferred $4 million of implementation and program costs for future recovery. On April 29 and May 1, 2008, PEC filed for NCUC approval of a total of five DSM and energy-efficiency programs, including the EnergyWise™ and distribution system demand response programs discussed below.

On April 29, 2008, PEC filed for approval by the NCUC of its EnergyWise™ program, which is a residential program that offers customers an incentive to permit PEC to remotely adjust central air conditioning and heat pumps in PEC’s eastern control area and electric resistance heating and water heaters in PEC’s western control area in order to reduce peak demand. PEC’s goal for EnergyWise™ is to have the capability to reduce peak electricity demand by 200 MW by 2017.

Also on April 29, 2008, PEC filed for NCUC approval of its distribution system demand response program, which will provide additional capability for reducing and shifting peak electricity demand. The program also will reduce the level of natural electricity loss experienced over long distribution feeder lines, thereby eliminating the need for additional power generation to compensate for the line losses. PEC anticipates that the program will require an investment of approximately $260 million over five years and is expected to reduce peak electricity demand by 250 MW. This distribution system investment is part of PEC’s broader “Smart Grid” strategy and is expected to provide a foundation for additional initiatives, including enhanced system reliability (through faster outage isolation and response) and new capabilities for incorporating renewable energy resources and other distributed generation into PEC’s energy mix. Such costs are expected to be recovered under the provisions of the North Carolina comprehensive energy legislation. A hearing for the application for approval of the proposed distribution system demand response program has been scheduled by the NCUC for September 17, 2008.

We cannot predict the outcome of the April 29 and May 1, 2008 filings or whether the proposed programs will produce the expected operational and economic results.

28

PEC filed a petition on November 30, 2007, with the SCPSC seeking authorization to create a deferred account for DSM and energy-efficiency expenses. On December 21, 2007, the SCPSC issued an order granting PEC’s petition. As a result, PEC has deferred an immaterial amount of implementation and program costs for future recovery in the South Carolina jurisdiction. On June 27, 2008, PEC filed an application with the SCPSC to establish procedures that encourage investment in cost-effective energy efficient technologies and energy conservation programs and approve the establishment of an annual rider to allow recovery for all costs associated with such programs as well as the recovery of appropriate incentives for investing in such programs. We cannot predict the outcome of this matter.

On June 6, 2008, PEC filed an application with the NCUC for approval of a DSM and energy-efficiency clause to recover the costs of these programs. If approved, the increase would take effect on or about December 1, 2008, and would increase customer electric bills by $1.96 per 1,000 kWh, or 2.0 percent. A hearing on the matter has been scheduled by the NCUC for September 17, 2008. We cannot predict the outcome of this matter.

On February 29, 2008, the NCUC issued an order adopting final rules for implementing North Carolina’s comprehensive energy legislation. These rules provide filing requirements associated with the legislation. The order requires PEC to submit its first annual REPS compliance plan by September 1, 2008, as part of its integrated resource plan. Under the new rules, beginning in 2009, PEC will also be required to file an annual REPS compliance report demonstrating the actions it has taken to comply with the REPS requirement. The rules measure compliance with the REPS requirement via renewable energy certificates (REC) earned after January 1, 2008. The NCUC will pursue a third-party REC tracking system, but will not develop or require participation in a REC trading platform at this time. The order also establishes a schedule and filing requirements for DSM and energy-efficiency cost recovery and financial incentives. Rates for the DSM and energy-efficiency clause and the REPS clause will be set based on projected costs with true-up provisions. On June 6, 2008, PEC filed an application with the NCUC for approval of a REPS clause to recover the costs of this program. If approved, the increase would take effect on or about December 1, 2008, and would increase customer electric bills by $0.46 per 1,000 kWh, or 0.5 percent. A hearing on the matter has been scheduled by the NCUC for September 17, 2008. We cannot predict the outcome of this matter.

On April 30, 2008, PEC filed an Application for Certificate of Public Convenience and Necessity with the NCUC to construct a 600-MW combined cycle dual fuel capable generating facility at its Richmond County generation site. A hearing on this matter has been scheduled by the NCUC for September 3, 2008. We cannot predict the outcome of this matter.

On April 30, 2008, PEC submitted a revised Open Access Transmission Tariff (OATT) filing, including a settlement agreement, with the FERC requesting an increase in transmission rates. The purpose of the filing was to implement formula rates for the PEC OATT in order to more accurately reflect the costs that PEC incurs in providing transmission service. In the filing, PEC proposed to move from a fixed revenue requirement to a formula rate, which allows for transmission rates to be updated each year based on the prior year’s actual costs. Settlement discussions were held with major customers prior to the filing and a settlement agreement was reached on all issues. The settlement proposed a formula rate with a rate of return on equity of 10.8 percent as well as recovery of the wholesale portion of the terminated GridSouth Transco, LLC (GridSouth) project startup costs over five years. On June 27, 2008, the FERC approved the settlement. The new rates were effective July 1, 2008, and PEC estimates the impact of the new rates will increase 2008 revenues by $6 million to $8 million.

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

29

On November 16, 2007, PEC petitioned the NCUC to allow it to establish a regulatory asset for PEC’s development costs of GridSouth pending disposition in a general rate proceeding. On January 14, 2008, the NCUC issued an order requesting interested parties to file comments regarding PEC’s petition on or before January 28, 2008. On February 11, 2008, PEC filed response comments. On December 20, 2007, the NCUC issued an order for one of the other GridSouth partners. As part of that order, the NCUC ruled that the utility’s GridSouth development costs should be amortized and recovered over a 10-year period beginning June 2002. On June 4, 2008, the NCUC issued an order granting PEC the same accounting treatment to its GridSouth development costs. In accordance with the OATT settlement discussed above, in July 2008, PEC began amortization and recovery of the wholesale portion of PEC’s GridSouth development costs over a five-year period. PEC estimates the impact of this amortization to be $1 million in 2008 and $2 million annually during the remaining amortization period. PEC’s recorded investment in GridSouth totaled $21 million and $22 million at June 30, 2008 and December 31, 2007, respectively.

The NCUC and SCPSC approved proposals to accelerate cost recovery of PEC’s nuclear generating assets beginning January 1, 2000, and continuing through 2009. The aggregate minimum and maximum amounts of cost recovery are $530 million and $750 million, respectively, with flexibility in the amount of annual depreciation recorded, from none to $150 million per year. Accelerated cost recovery of these assets resulted in additional depreciation expense of $15 million for the three and six months ended June 30, 2008. No additional depreciation expense from accelerated cost recovery was recorded for the same periods in 2007. Through June 30, 2008, PEC recorded total accelerated depreciation of $455 million, of which $378 million was recorded for the North Carolina jurisdiction and $77 million was recorded for the South Carolina jurisdiction.

B.           PEF RETAIL RATE MATTERS

PASS-THROUGH CLAUSE COST RECOVERY

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus interest, of alleged excessive past fuel recovery charges and SO2 allowance costs during the period 1996 to 2005. The OPC subsequently revised its claim to $135 million, plus interest. The OPC claimed that although Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) were designed to burn a blend of coals, PEF failed to act to lower ratepayers’ costs by purchasing the most economical blends of coal. During the period specified in the petition, PEF’s costs recovered through fuel recovery clauses were annually reviewed for prudence and approval by the FPSC. On July 31, 2007, the FPSC heard this matter. On October 10, 2007, the FPSC issued its order rejecting most of the OPC’s contentions. However, the 4-1 majority found that PEF had not been prudent in purchasing a portion of its coal requirements during the period from 2003 to 2005. Accordingly, the FPSC ordered PEF to refund its ratepayers approximately $14 million, including interest, over a 12-month period beginning January 1, 2008. For the year ended December 31, 2007, PEF recorded a pre-tax other operating expense of $12 million, interest expense of $2 million and an associated $14 million regulatory liability included within PEF’s deferred fuel cost at December 31, 2007. On October 25, 2007, the OPC requested the FPSC to reconsider its October 10, 2007 order asserting that the FPSC erred in not ordering a larger refund. PEF filed its opposition to the OPC’s request on November 1, 2007. On February 12, 2008, the FPSC denied the OPC’s request for reconsideration. Neither PEF nor OPC filed an appeal to the Florida Supreme Court of the FPSC’s October 10, 2007 order. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish a separate docket on the prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. The OPC filed testimony in support of its position to require PEF to refund at least $14 million for alleged excessive fuel recovery charges for 2006 coal purchases. PEF believes its coal procurement practices have been prudent. We anticipate that a hearing will be held on the 2006 and 2007 coal purchases in 2009. We cannot predict the outcome of this matter.

On May 30, 2008, PEF filed a petition with the FPSC requesting a mid-course correction to its fuel cost recovery factors to recover an additional $213 million in 2008, primarily due to rising fuel costs. In accordance with a FPSC order, investor owned utilities must file a notice with the FPSC if the year-end projected over- or under-recovery of fuel costs is expected to be greater than 10% of projected fuel revenues. The mid-course correction would have resulted in a residential fuel rate increase of $12.07 per 1,000 kWh for the period August through December 2008. On  July 1, 2008, the FPSC approved recovery of the $213 million projected year-end under-recovery, but allowed PEF to  recover 50 percent in 2008 and 50 percent in 2009. Therefore, the increase in the fuel rate for the period

30

August through December 2008 is $6.03 per 1,000 kWh. This increase is partially offset by the expiration of PEF’s storm cost recovery surcharge of $3.61 per 1,000 kWh effective August 2008. Consequently, beginning with the first billing cycle in August and including gross receipts tax, residential electric bills will increase by $2.48 per 1,000 kWh, or 2.29 percent.

On September 22, 2006, PEF filed a petition with the FPSC for Determination of Need to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) and bid rule exemption. The multi-stage uprate will increase CR3’s gross output by approximately 180 MW by 2012. PEF received NRC approval for a license amendment and implemented the first stage’s design modification on January 31, 2008, and will apply for the required license amendment for the third stage’s design modification. The petition filed with the FPSC included estimated project costs of approximately $382 million. These cost estimates may continue to change depending upon the results of more detailed engineering and development work and increased material, labor and equipment costs. On February 8, 2007, the FPSC issued an order approving the need certification petition and bid rule exemption. On February 29, 2008, PEF filed a petition for recovery of costs incurred in 2007 and 2006 under Florida’s comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule based on the regulatory precedence established by a FPSC order to an unaffiliated Florida utility for a nuclear uprate project. The FPSC is expected to vote on this matter by October 2008. We cannot predict the outcome of this matter.

On May 1, 2008, PEF filed with the FPSC for an increase in the capacity cost-recovery charge of estimated costs incurred in 2008 and projected costs to be incurred in 2009 under the FPSC nuclear cost-recovery rule. PEF is asking the FPSC to approve a $25 million increase in the capacity cost recovery revenue requirement for costs associated with the CR3 uprate. If approved, the increase would take effect with the first billing cycle for 2009 and would increase residential electric bills by $0.70 per 1,000 kWh. After PEF’s completion of a transmission study and additional engineering studies, the current project estimate of fully loaded costs is $364 million. A hearing on the matter has been scheduled by the FPSC for September 2008, and the FPSC is expected to vote on this matter by October 2008. We cannot predict the outcome of this matter.

OTHER MATTERS

On March 11, 2008, PEF filed a petition for an affirmative Determination of Need for its proposed Levy Units 1 and 2 nuclear power plants, together with the associated facilities, including transmission lines and substation facilities. Levy Units 1 and 2 are needed to maintain electric system reliability and integrity, fuel and generating diversity and to continue to provide adequate electricity to its ratepayers at a reasonable cost. Levy Units 1 and 2 will be advanced passive light water nuclear reactors, each with a generating capacity of approximately 1,092 MW (summer rating). PEF proposes to place Levy Unit 1 in service by June 2016 and Levy Unit 2 in service by June 2017. The filed, non-binding project cost estimate for Levy Units 1 and 2 is approximately $14 billion for generating facilities and approximately $3 billion for associated transmission facilities. The hearing was held on May 21-23, 2008, and the FPSC voted unanimously in favor of the Determination of Need on July 15, 2008.

On March 11, 2008, PEF also filed a petition with the FPSC to open a discovery docket regarding the actual and projected costs of the proposed Levy nuclear project. PEF filed the petition to assist the FPSC in the timely and adequate review of the project’s cost recoverable under the FPSC nuclear cost-recovery rule. On May 1, 2008, PEF filed a petition for recovery of both preconstruction and carrying charges on construction costs incurred or anticipated to be incurred during 2008 and 2009. Additionally, the filing included site selection costs of $38 million. Based on the affirmative vote by the FPSC on the Determination of Need for the Levy nuclear project, PEF filed a petition on July 18, 2008, to recover all prudently incurred costs under the FPSC nuclear cost-recovery rule. A decision by the FPSC on PEF’s 2008 cost-recovery filing is expected by October 1, 2008. We cannot predict the outcome of this matter.

31

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)	2008		2007		2008		2007
Weighted-average common shares - basic		260		256		259		255
Net effect of dilutive stock-based compensation plans		–		1		1		1
Weighted-average shares – full dilutive		260		257		260		256

B.          COMPREHENSIVE INCOME

Progress Energy
	Three Months Ended June 30,
(in millions)	2008		2007
Net income (loss)	$	205	$	(193	)
Other comprehensive income
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $2)		–		3
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $- and $-, respectively)		1		1
Net unrealized gains on cash flow hedges (net of tax expense of $8 and $2, respectively)		13		2
Other comprehensive income		14		6
Comprehensive income (loss)	$	219	$	(187	)

	Six Months Ended June 30,
(in millions)	2008		2007
Net income	$	414	$	82
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $2, respectively)		1		3
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $- and $-, respectively)		1		2
Net unrealized gains on cash flow hedges (net of tax expense of $2 and $2, respectively)		4		2
Other (net of tax benefit of $3)		–		(2	)
Other comprehensive income		6		5
Comprehensive income	$	420	$	87

32

PEC
	Three Months Ended June 30,
(in millions)	2008		2007
Net income	$	104	$	88
Other comprehensive income
Net unrealized gains on cash flow hedges (net of tax expense of $1)		–		2
Other comprehensive income		–		2
Comprehensive income	$	104	$	90

	Six Months Ended June 30,
(in millions)	2008			2007
Net income	$	227		$	212
Other comprehensive (loss) income
Net unrealized (losses) gains on cash flow hedges (net of tax benefit of $3 and $-, respectively)		(5	)		1
Other (net of tax benefit of $1)		–			(4	)
Other comprehensive loss		(5	)		(3	)
Comprehensive income	$	222		$	209

PEF
	Three Months Ended June 30,
(in millions)	2008		2007
Net income	$	125	$	68
Other comprehensive income
Net unrealized gains on cash flow hedges (net of tax expense of $8 and $1, respectively)		12		2
Other comprehensive income		12		2
Comprehensive income	$	137	$	70

	Six Months Ended June 30,
(in millions)	2008		2007
Net income	$	192	$	129
Other comprehensive income
Net unrealized gains on cash flow hedges (net of tax expense of $5 and $1, respectively)		8		2
Other comprehensive income		8		2
Comprehensive income	$	200	$	131

C.           COMMON STOCK

At December 31, 2007, we had 500 million shares of common stock authorized under our charter, of which approximately 260 million were outstanding. At December 31, 2007, we had approximately 50 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 Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan with original issue shares. For the three and six months ended June 30, 2008, respectively, we issued approximately 0.5 million shares and 1.0 million shares of common stock resulting in approximately $22 million and $42 million in proceeds. Included in these amounts were approximately 0.5 million shares and 0.9 million shares for proceeds of approximately $22 million and $41 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. For the three and six months

33

ended June 30, 2007, respectively, we issued approximately 1.2 million shares and 2.7 million shares of common stock resulting in approximately $57 million and $122 million in proceeds. Included in these amounts were approximately 0.3 million shares and 0.5 million shares for proceeds of approximately $12 million and $23 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan.

6.      DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES

Material changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2007, are described below.

On January 8, 2008, PEF’s shelf registration statement became effective with the United States Securities and Exchange Commission (SEC). The registration statement initially allowed PEF to issue up to $4 billion in first mortgage bonds, debt securities and preferred stock in addition to $250 million of previously registered but unsold securities.

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

On March 12, 2008, PEC and PEF amended their revolving credit agreements (RCA) with a syndication of financial institutions to extend the termination date by one year. The extensions were effective for both utilities on March 28, 2008. PEC’s RCA is now scheduled to expire on June 28, 2011, and PEF’s RCA is now scheduled to expire on March 28, 2011.

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

On April 14, 2008, we amended our RCA with a syndication of financial institutions to extend the termination date by one year. The extension was effective on May 3, 2008. Our RCA is now scheduled to expire on May 3, 2012.

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

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

7.      FAIR VALUE MEASUREMENTS

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value under GAAP, and requires enhanced disclosures about assets and liabilities carried at fair value. SFAS No. 157 also establishes a fair value hierarchy that categorizes and prioritizes the inputs that should be used to estimate fair value. In February 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which delays for us the effective date of SFAS No. 157 until January 1, 2009, for all nonfinancial assets and nonfinancial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

We implemented SFAS No. 157 as of January 1, 2008, for all recurring financial assets and liabilities. The adoption of SFAS No. 157 for recurring financial assets and liabilities did not have a material impact on our or the Utilities' financial position or results of operations. We utilized the deferral provision of FSP No. FAS 157-2 for all nonrecurring nonfinancial assets and liabilities within its scope. Major categories of our assets and liabilities to which the deferral applies include reporting units and long-lived asset groups measured at fair value for impairment purposes, asset retirement obligations initially recognized at fair value, and nonfinancial liabilities for exit and disposal costs and indemnifications initially measured at fair value. We do not expect the January 1, 2009, adoption

34

of SFAS No. 157 for nonrecurring nonfinancial assets and liabilities to have a material impact on our or the Utilities' financial position or results of operations.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). SFAS No. 157 permits the use of a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient and requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. SFAS No. 157 requires that valuation techniques maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets.

Level 3 – The pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods where quoted prices or other observable inputs are not available. At each balance sheet date, we perform an analysis of all instruments subject to SFAS No. 157 and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

35

The following tables set forth by level within the fair value hierarchy our and the Utilities’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Progress Energy
(in millions)	Level 1		Level 2			Level 3		Total
Assets:
Commodity derivatives	$	–	$	974		$	163	$	1,137
Nuclear decommissioning trust funds		786		516			–		1,302
Other marketable securities		13		44			–		57
Total assets	$	799	$	1,534		$	163	$	2,496
Liabilities:
Commodity derivatives	$	–	$	(3	)	$	–	$	(3	)
CVO derivatives		–		(36	)		–		(36	)
Total liabilities	$	–	$	(39	)	$	–	$	(39	)

PEC
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivatives	$	–	$	119	$	36	$	155
Nuclear decommissioning trust funds		454		313		–		767
Other marketable securities		6		–		–		6
Total assets	$	460	$	432	$	36	$	928

PEF
(in millions)	Level 1		Level 2			Level 3		Total
Assets:
Commodity derivatives	$	–	$	855		$	127	$	982
Nuclear decommissioning trust funds		332		203			–		535
Other marketable securities		2		–			–		2
Total assets	$	334	$	1,058		$	127	$	1,519
Liabilities:
Commodity derivatives	$	–	$	(3	)	$	–	$	(3	)

The determination of the fair values above incorporates various factors required under SFAS No. 157, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities’ credit risk on our liabilities.

Commodity derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity and interest rate derivatives are valued using financial models which utilize observable inputs for similar instruments, and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 9 for discussion of risk management activities and derivative transactions.

36

Nuclear decommissioning trust funds reflect the assets of the Utilities’ nuclear decommissioning trusts, as discussed in Note 13 of the 2007 Form 10-K. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments, and are classified within Level 2.

Other marketable securities represent available-for-sale debt and equity securities used to fund certain employee benefit costs.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the 2007 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less than active market, and are classified as Level 2.

The following tables set forth a reconciliation of changes in the fair value of our and the Utilities’ commodity derivatives classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2008.

Progress Energy
	Three Months Ended		Six Months Ended
(in millions)	June 30, 2008		June 30, 2008
Derivatives, net at beginning of period	$	55	$	26
Total gains (losses), realized and unrealized:
Included in earnings		–		–
Included in other comprehensive income		–		–
Deferred as regulatory assets and liabilities, net		108		137
Purchases, issuances and settlements, net		–		–
Transfers in (out) of Level 3, net		–		–
Derivatives, net at end of period	$	163	$	163

PEC
	Three Months Ended		Six Months Ended
(in millions)	June 30, 2008		June 30, 2008
Derivatives, net at beginning of period	$	12	$	6
Total gains (losses), realized and unrealized:
Included in earnings		–		–
Included in other comprehensive income		–		–
Deferred as regulatory assets and liabilities, net		24		30
Purchases, issuances and settlements, net		–		–
Transfers in (out) of Level 3, net		–		–
Derivatives, net at end of period	$	36	$	36

PEF
	Three Months Ended		Six Months Ended
(in millions)	June 30, 2008		June 30, 2008
Derivatives, net at beginning of period	$	43	$	20
Total gains (losses), realized and unrealized:
Included in earnings		–		–
Included in other comprehensive income		–		–
Deferred as regulatory assets and liabilities, net		84		107
Purchases, issuances and settlements, net		–		–
Transfers in (out) of Level 3, net		–		–
Derivatives, net at end of period	$	127	$	127

Unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment.

37

Transfers in (out) of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers into or out of Level 3 during the three and six months ended June 30, 2008.

8.     BENEFIT PLANS

We have noncontributory defined benefit retirement plans that provide pension benefits for substantially all full-time employees. We also have supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, we provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the respective Progress Registrants for the three and six months ended June 30 were:

Progress Energy
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2008			2007			2008			2007
Service cost	$	12		$	11		$	2		$	2
Interest cost		31			30			8			9
Expected return on plan assets		(41	)		(39	)		(2	)		(1	)
Amortization of actuarial loss (a)		3			4			1			1
Other amortization, net (a)		–			–			1			1
Net periodic cost	$	5		$	6		$	10		$	12

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Service cost	$	24		$	22		$	4		$	4
Interest cost		62			61			16			18
Expected return on plan assets		(82	)		(78	)		(3	)		(3	)
Amortization of actuarial loss (a)		5			7			1			3
Other amortization, net (a)		1			1			2			2
Net periodic cost	$	10		$	13		$	20		$	24

(a)    Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2007 Form 10-K.

38

PEC
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2008			2007			2008			2007
Service cost	$	6		$	5		$	1		$	1
Interest cost		14			14			4			5
Expected return on plan assets		(16	)		(15	)		(1	)		(1	)
Amortization of actuarial loss		2			3			–			1
Net periodic cost	$	6		$	7		$	4		$	6

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Service cost	$	12		$	11		$	2		$	2
Interest cost		28			27			8			9
Expected return on plan assets		(32	)		(30	)		(2	)		(2	)
Amortization of actuarial loss		4			5			–			2
Other amortization, net		1			1			1			1
Net periodic cost	$	13		$	14		$	9		$	12

PEF
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,
(in millions)	2008			2007			2008		2007
Service cost	$	4		$	4		$	1	$	1
Interest cost		13			13			3		3
Expected return on plan assets		(21	)		(21	)		–		–
Other amortization, net		–			–			1		1
Net periodic (benefit) cost	$	(4	)	$	(4	)	$	5	$	5

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Service cost	$	9		$	8		$	1		$	1
Interest cost		26			25			7			7
Expected return on plan assets		(44	)		(42	)		(1	)		(1	)
Amortization of actuarial loss		–			–			1			1
Other amortization, net		–			–			2			2
Net periodic (benefit) cost	$	(9	)	$	(9	)	$	10		$	10

39

9.     RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations.

As discussed in Note 7, in connection with the acquisition of Florida Progress during 2000, the Parent issued 98.6 million CVOs. The CVOs are derivatives and are recorded at fair value. The unrealized loss/gain recognized due to changes in fair value is recorded in other, net on the Consolidated Statements of Income. At June 30, 2008 and December 31, 2007, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $36 million and $34 million, respectively.

A.           COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify and are elected 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 11). At June 30, 2008, and December 31, 2007, the remaining liability was $9 million and $10 million, respectively.

DISCONTINUED OPERATIONS

In January 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge instruments was 25 million barrels and provided protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts were marked-to-market with changes in fair value recorded through earnings. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed in Notes 1C and 3F, we disposed of our 100 percent ownership interest in Ceredo in March 2007. Progress Energy remains the primary beneficiary of, and consolidates Ceredo in accordance with FIN 46R, with a 100 percent minority interest. Consequently, subsequent to the disposal there was no net earnings impact from Ceredo’s operations, which ceased as of December 31, 2007. At December 31, 2007, the $234 million fair value of these contracts, including $79 million at Ceredo, was included in receivables, net on the Consolidated Balance Sheet. The contracts ended on December 31, 2007, and were settled for cash on January 8, 2008, with no material impact to 2008 earnings. For the three months ended June 30, 2007, we recorded net pre-tax losses of $14 million related to these contracts, including $5 million attributable to Ceredo, which was attributed to minority interest for the portion of the loss subsequent to disposal. For the six months ended June 30, 2007, we recorded net pre-tax gains of $31 million related to these contracts, including $10 million attributable to Ceredo, of which losses of $5 million were attributed to minority interest for the portion of the loss subsequent to disposal.

ECONOMIC DERIVATIVES

Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

40

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets on the Balance Sheets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause. During the three and six months ended June 30, 2008, PEC recorded a net realized gain of $6 million. During the three and six months ended June 30, 2007, PEC recorded a net realized loss of less than $1 million. During the three and six months ended June 30, 2008, PEF recorded a net realized gain of $103 million and $119 million, respectively. During the three and six months ended June 30, 2007, PEF recorded a net realized loss of $5 million and $22 million, respectively.

The December 31, 2007 balances presented below reflect the retrospective adoption of FSP FIN 39-1 (See Note 2).

At June 30, 2008, the fair value of PEC’s commodity derivative instruments was recorded as a $42 million short-term derivative asset position included in prepayments and other current assets and a $113 million long-term derivative asset position included in derivative assets on the PEC Consolidated Balance Sheet. At December 31, 2007, the fair value of such instruments was recorded as a $4 million short-term derivative liability included in other current liabilities and a $19 million long-term derivative asset position included in derivative assets on the PEC Consolidated Balance Sheet. Certain counterparties have posted cash collateral with PEC in support of these instruments. PEC had an $11 million cash collateral liability at June 30, 2008, included in other current liabilities on the PEC Consolidated Balance Sheet, and no cash collateral position at December 31, 2007. At June 30, 2008, $5 million of the cash collateral was restricted as to usage and was included in prepayments and other current assets on the PEC Consolidated Balance Sheet. Collateral received is returned when counterparty collateral thresholds are no longer exceeded.

At June 30, 2008, the fair value of PEF’s commodity derivative instruments was recorded as a $478 million short-term derivative asset position included in current derivative assets, a $504 million long-term derivative asset position included in derivative assets, a $2 million short-term liability position included in derivative liabilities, and a $1 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. At December 31, 2007, the fair value of such instruments was recorded as an $83 million short-term derivative asset position included in current derivative assets, a $100 million long-term derivative asset position included in derivative assets, a $38 million short-term liability position included in derivative liabilities, and a $9 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. Certain counterparties have posted cash collateral with PEF in support of these instruments. PEF had a $409 million cash collateral liability at June 30, 2008, included in derivative collateral liabilities on the PEF Balance Sheet, and no cash collateral position at December 31, 2007. At June 30, 2008, $46 million of the cash collateral was restricted as to usage and was included in prepayments and other current assets on the PEF Balance Sheet. Collateral received is returned when counterparty thresholds are no longer exceeded.

CASH FLOW HEDGES

PEC designates a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. At June 30, 2008, and December 31, 2007, neither we nor the Utilities had material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for the three and six months ended June 30, 2008 and 2007.

At June 30, 2008 and December 31, 2007, neither we nor the Utilities had amounts recorded in accumulated other comprehensive income 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 exposure in these transactions is the cost of replacing the agreements at current market rates.

41

CASH FLOW HEDGES

There were no open interest rate hedges at June 30, 2008. The fair values of open interest rate hedges at December 31, 2007, were as follows:

(in millions)	Progress Energy			PEC			PEF
Fair value of liabilities	$	(12	)	$	(12	)	$	–

Gains and losses from cash flow hedges are recorded in accumulated other comprehensive income and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in accumulated other comprehensive income related to terminated hedges are reclassified to earnings as the interest expense is recorded. The ineffective portion of interest rate cash flow hedges for the three and six months ended June 30, 2008 and 2007, was not material to our or the Utilities’ results of operations.

The following table presents selected information related to our interest rate cash flow hedges included in accumulated other comprehensive income at June 30, 2008:

(term in years/millions of dollars)	Progress Energy			PEC			PEF
Maximum term		–			–			–
Accumulated other comprehensive loss, net of tax(a)	$	(18	)	$	(14	)	$	–
Portion expected to be reclassified to earnings during the next 12 months(b)	$	(3	)	$	(1	)	$	–

(a)     Includes amounts related to terminated hedges.

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

At December 31, 2007, including amounts related to terminated hedges, we had $24 million of after-tax deferred losses, including $12 million of after-tax deferred losses at PEC and $8 million of after-tax deferred losses at PEF, recorded in accumulated other comprehensive income related to interest rate cash flow hedges.

At December 31, 2007, PEC had $200 million notional of interest rate cash flow hedges. All of PEC’s forward starting swaps were terminated on March 13, 2008, in conjunction with PEC’s issuance of $325 million of First Mortgage Bonds, 6.30% Series due 2038. The effective portion of the hedges is included in accumulated other comprehensive income and will be amortized to interest expense over the life of the related debt.

In January 2008, PEF entered into a combined $200 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. In May 2008, PEF entered into a combined $250 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. In June 2008, PEF entered into a combined $100 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. All of PEF’s forward starting swaps were terminated on June 11, 2008, in conjunction with PEF’s issuance of $500 million of First Mortgage Bonds, 5.65% Series due 2018 and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038.

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, 2008, and December 31, 2007, we and the Utilities had no open interest rate fair value hedges.

10.     FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable PEC and PEF business segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

42

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and PESC and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” as a separate business segment. The profit or loss of our reportable segments plus the profit or loss of Corporate and Other represents our total income from continuing operations.

Income of discontinued operations is 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 following information is for the three and six months ended June 30:

									Income (Loss)
	Revenues								From Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
Three Months Ended June 30, 2008
PEC	$	1,048	$	–		$	1,048		$	104		$	12,308
PEF		1,194		–			1,194			125			13,001
Corporate and Other		2		94			96			(29	)		16,969
Eliminations		–		(94	)		(94	)		–			(12,986	)
Totals	$	2,244	$	–		$	2,244		$	200		$	29,292
Three Months Ended June 30, 2007
PEC	$	996	$	–		$	996		$	88
PEF		1,129		–			1,129			68
Corporate and Other		4		103			107			(18	)
Eliminations		–		(103	)		(103	)		–
Totals	$	2,129	$	–		$	2,129		$	138

									Income (Loss)
	Revenues								From Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
Six Months Ended June 30, 2008
PEC	$	2,116	$	–		$	2,116		$	226		$	12,308
PEF		2,190		–			2,190			191			13,001
Corporate and Other		4		176			180			(68	)		16,969
Eliminations		–		(176	)		(176	)		–			(12,986	)
Totals	$	4,310	$	–		$	4,310		$	349		$	29,292
Six Months Ended June 30, 2007
PEC	$	2,054	$	–		$	2,054		$	211
PEF		2,140		–			2,140			128
Corporate and Other		7		189			196			(52	)
Eliminations		–		(189	)		(189	)		–
Totals	$	4,201	$	–		$	4,201		$	287

11.     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. CVOs unrealized gain or loss is due to changes in fair value. See Note 15 in the 2007 Form 10-K for more information on CVOs. AFUDC equity represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets.

43

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)	2008		2007			2008			2007
Other income
Nonregulated energy and delivery services income	$	15	$	13		$	22		$	22
DIG Issue C20 amortization (see Note 9A)		–		1			1			2
CVOs unrealized gain		–		–			–			1
Investment gains		3		2			4			3
Income from equity investments		–		–			–			2
Derivative mark-to-market gain		4		–			4			–
Other		3		3			6			7
Total other income		25		19			37			37
Other expense
Nonregulated energy and delivery services expenses		5		5			9			12
Donations		7		5			11			9
Loss on sale of property		–		1			–			1
Investment losses		4		–			7			–
Loss from equity investments		1		–			3			1
CVOs unrealized loss		2		4			2			4
Other		3		6			7			11
Total other expense		22		21			39			38
Other, net	$	3	$	(2	)	$	(2	)	$	(1	)

PEC
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2008		2007		2008		2007
Other income
Nonregulated energy and delivery services income	$	9	$	7	$	12	$	9
DIG Issue C20 amortization (see Note 9A)		–		1		1		2
Investment gains		–		–		1		1
Income from equity investments		–		–		–		2
AFUDC equity		5		2		10		4
Derivative mark-to-market gain		4		–		4		–
Other		3		2		5		5
Total other income		21		12		33		23
Other expense
Nonregulated energy and delivery services expenses		2		1		3		3
Donations		4		3		6		5
Investment losses		3		–		3		–
Loss from equity investments		–		–		2		1
Other		1		1		4		4
Total other expense		10		5		18		13
Other, net	$	11	$	7	$	15	$	10

44

PEF
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2008		2007		2008			2007
Other income
Nonregulated energy and delivery services income	$	6	$	6	$	10		$	13
Investment gains		1		2		1			2
Other		–		–		2			–
Total other income		7		8		13			15
Other expense
Nonregulated energy and delivery services expenses		3		4		6			9
Donations		3		2		5			4
Investment losses		–		–		2			–
Loss from equity investments		1		–		1			1
Other		–		2		–			2
Total other expense		7		8		14			16
Other, net	$	–	$	–	$	(1	)	$	(1	)

12.    ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

A.           HAZARDOUS AND SOLID WASTE

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the United States Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of these potential claims cannot be predicted. No material claims are currently pending. A discussion of sites by legal entity follows.

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

45

The following table contains information about accruals for environmental remediation expenses described below. Accruals for probable and estimable costs related to various environmental sites, which were primarily included in other liabilities and deferred credits on the Balance Sheets, were:

(in millions)	June 30, 2008		December 31, 2007
PEC
MGP and other sites(a)	$	18	$	16
PEF
Remediation of distribution and substation transformers		29		31
MGP and other sites		16		17
Total PEF environmental remediation accruals(b)		45		48
Total Progress Energy environmental remediation accruals	$	63	$	64

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

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

PROGRESS ENERGY

In addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See Note 13B).

PEC

Including the Ward Transformer site and MGP sites discussed below, for the three months ended June 30, 2008, PEC accrued approximately $5 million, primarily related to the Ward Transformer site, and spent approximately $2 million, and for the six months ended June 30, 2008, PEC accrued approximately $6 million, primarily related to the Ward Transformer site, and spent approximately $4 million. Including the Ward Transformer site and MGP sites discussed below, for the three months ended June 30, 2007, PEC accrued approximately $1 million, primarily related to the Ward Transformer site, and spent approximately $1 million and for the six months ended June 30, 2007, PEC reduced its accrual by approximately $4 million, primarily related to the Ward Transformer site, and spent approximately $2 million. PEC defers and amortizes certain environmental remediation expenses in accordance with orders received from the NCUC and SCPSC.

PEC has recorded a minimum estimated total remediation cost for all of its remaining MGP sites based upon its historical experience with remediation of several of its MGP sites. The maximum amount of the range for all the sites cannot be determined at this time as one of the remaining sites is significantly larger than the sites for which we have historical experience. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC and a number of other PRPs the opportunity to negotiate cleanup of the site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the site. During 2007, the PRP agreement was amended to include an additional participating PRP, which reduced PEC’s proportionate responsibility for funding the remediation. During 2008, PEC increased its accrual due to an increase in the estimated scope of work. At June 30, 2008 and December 31, 2007, PEC’s recorded liability for the site was approximately $9 million and $6 million, respectively. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. The outcome of this matter cannot be predicted.

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

46

PEF

PEF has received approval from the FPSC for recovery through the Environmental Cost Recovery Clause (ECRC) of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed the majority of distribution transformer sites and all substation sites for mineral oil impacted soil caused by equipment integrity issues. PEF currently expects to have completed this review by the end of 2008. Should further sites be identified outside of this population, the expenses will not be recoverable through the ECRC. Based on historical experience, PEF projects costs will be between approximately $2 million and $3 million per year. For the three and six months ended June 30, 2008, PEF accrued approximately $10 million and $12 million, respectively, due to the identification of additional transformer sites and an increase in estimated remediation costs, and spent approximately $8 million and $14 million, respectively, related to the remediation of transformers. For the three and six months ended June 30, 2007, PEF accrued approximately $3 million and $5 million, respectively, due to an increase in estimated remediation costs and spent approximately $6 million and $11 million, respectively, related to the remediation of transformers. At June 30, 2008, PEF had recorded 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, 2008, PEF made no additional accruals and spent approximately $1 million. For the three and six months ended June 30, 2007, PEF made no additional accruals or material expenditures.

B.           AIR AND WATER QUALITY

At June 30, 2008, we were subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call), the Clean Smokestacks Act and mercury regulation. PEC’s and PEF’s environmental compliance capital expenditures related to these regulations began in 2002 and 2005, respectively. At June 30, 2008, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.944 billion, including $1.319 billion at PEC of which $14 million related to in-process CAIR projects, and $625 million at PEF, which related entirely to in-process CAIR projects. At December 31, 2007, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.567 billion, including $1.244 billion at PEC and $323 million at PEF.

On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Court of Appeals) issued its decision in litigation challenging the EPA’s CAIR. The decision vacated the CAIR and the related federal implementation plan in their entirety. The decision vacating the CAIR will negate the EPA's determination that implementation of the CAIR satisfies best available retrofit technology (BART) for SO2 and NOx for BART-affected units under the CAVR. As a result, for BART-affected units, CAVR compliance will require consideration of SO2 and NOx emissions in addition to particulate matter emissions. On February 8, 2008, the D. C. Court of Appeals vacated the delisting determination and the CAMR. We are currently evaluating the impact of these decisions.

The Utilities are considering continuing construction of in-process CAIR projects. We believe our historical costs related to CAIR compliance are prudent and will be recoverable under base rates or applicable cost recovery clauses as the costs were incurred in pursuit of compliance with a mandatory law or regulation. Although the Utilities have not made a final determination whether to continue the in-process CAIR projects or whether the schedule for these projects should be modified, it is likely that they will be completed. In making this decision, the Utilities will take into account the status of the projects, the probability of regulatory changes to replace the vacated CAIR requirements and the need to comply with environmental rules and regulations other than the CAIR.

We account for emission allowances as inventory using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As a result of the decision to vacate the CAIR, the SO2 and

47

annual NOx emission allowances markets have been very volatile andthe market prices for emission allowances have declined. At June 30, 2008, PEC had approximately $1 million in NOx seasonal emission allowances, which will be utilized to comply with existing NOx SIP Call requirements, and approximately $29 million in SO2 emission allowances, which will be utilized to comply with existing Clean Air Act requirements. PEC currently has no purchased CAIR seasonal or annual NOx allowances in its emission inventory balances. In order to achieve compliance with the requirements of the CAIR pursuant to its Integrated Clean Air Compliance Plan, PEF needed to purchase CAIR seasonal and annual NOx allowances. At June 30, 2008, PEF had approximately $59 million in annual NOx emission allowance inventory, approximately $7 million in seasonal NOx emission allowance inventory and approximately $18 million in SO2 emission allowance inventory. PEF believes the purchases of NOx emission allowances to comply with the requirements of the CAIR were prudent and continues to expect to recover the costs of these allowances through its ECRC. PEF’s SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements.

As discussed in Note 4A, in June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. Two of PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements, the joint owners are required to pay a portion of the costs of owning and operating these plants. PEC has determined that the most cost-effective Clean Smokestacks Act compliance strategy is to maximize the SO2 removal from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to avoid the installation of expensive emission controls on its smaller coal-fired units. In order to address the joint owner's concerns that such a compliance strategy would result in a disproportionate share of the cost of compliance for the jointly owned units, PEC entered into an agreement with the joint owner to limit its aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act to approximately $38 million. PEC recorded a related liability for the joint owner's share of estimated costs in excess of the contract amount. At June 30, 2008 and December 31, 2007, the amount of the liability was $20 million and $30 million, respectively, based upon the respective estimates for the remaining Clean Smokestacks Act compliance costs. During the three months ended June 30, 2008, PEC made no additional accruals and spent approximately $5 million that exceeded the joint owner limit. During the six months ended June 30, 2008, PEC made no additional accruals and spent approximately $10 million that exceeded the joint owner limit. Because PEC has taken a system-wide compliance approach, its North Carolina retail ratepayers have significantly benefited from the strategy of focusing emission reduction efforts on the jointly owned units, and, therefore, PEC believes that any costs in excess of the joint owner’s share should be recovered from North Carolina retail ratepayers, consistent with other capital expenditures associated with PEC’s compliance with the Clean Smokestacks Act. On July 10, 2008, PEC filed a petition with the NCUC requesting that the NCUC reconsider the settlement agreement provisionally approved on December 20, 2007, and allow PEC to place into rate base all capital costs associated with PEC’s compliance with the Clean Smokestacks Act in excess of $569 million, including eligible compliance costs in excess of the joint owner’s share (See Note 4A).

13.     COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2007 Form 10-K are described below.

A.           PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2007 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. The commitment amounts discussed below are estimates and therefore, actual purchase amounts will likely differ. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs.

48

PROGRESS ENERGY

Through June 30, 2008, contracts procured through our subsidiaries have increased our aggregate purchase obligations for fuel and purchased power by $9.214 billion from $17.644 billion, as stated in Note 22A in the 2007 Form 10-K. This increase is discussed under “PEC” and “PEF” below.

PEC

Through June 30, 2008, PEC’s fuel and purchased power commitments increased by $5.697 billion from $5.078 billion, as stated in Note 22A in the 2007 Form 10-K. This increase is primarily related to coal purchase commitments, of which approximately $3.199 billion will be incurred through 2012, with the remainder incurred through 2018. The increase in coal purchase commitments includes new contracts along with the impact of price increases on certain existing contracts that are market price indexed.

In June 2008, PEC entered into a conditional contract with an interstate pipeline for firm pipeline transportation capacity to support PEC’s gas supply needs for the period from May 2011 through April 2031. The estimated total cost to PEC associated with this agreement is approximately $461 million. The transaction is subject to several conditions precedent, including various state regulatory approvals, the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions, and other contractual provisions. Due to the conditions of this agreement, the estimated costs associated with this agreement are not included in the increase in PEC’s fuel and purchased power commitments discussed above.

PEF

Through June 30, 2008, PEF’s fuel and purchased power commitments increased by $3.517 billion from $12.566 billion as stated in Note 22A in the 2007 Form 10-K. Approximately $1.689 billion of this increase is due to coal purchase commitments, of which approximately $588 million will be incurred through 2012, with the remainder incurred through 2030. The increase in coal purchase commitments includes new contracts along with the impact of price increases on certain existing contracts that are market price indexed. Additionally, approximately $1.398 billion of the increase is due to the impact of rising natural gas prices under a long-term gas supply agreement that was entered into in December 2004. Approximately $216 million of this increase will be incurred through 2012, with the remainder incurred through 2027. Payments under this agreement are based on a published market price index. Contractual obligations under this contract are based on estimated future market prices.

In April 2008, PEF entered into a conditional contract with Florida Gas Transmission Company, L.L.C. (FGT) for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with this agreement is estimated to be approximately $2.000 billion. The transaction is subject to several conditions precedent, including various state regulatory approvals, the completion and commencement of operation of necessary related interstate natural pipeline system expansions, and other contractual provisions. In addition to the FGT contract, during the second quarter of 2008, PEF entered into additional gas supply and transportation arrangements for the period from 2010 through 2025 that are subject to certain conditions. The total current notional cost of these additional agreements is estimated to be approximately $1.390 billion. Due to the conditions of these agreements, the estimated costs associated with these agreements are not included in the increase in PEF’s fuel and purchased power commitments discussed above.

B.           GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). Such agreements include guarantees, standby letters of credit and surety bonds. At June 30, 2008, 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, 2008, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, which are within the scope of FIN 45. Related to the sales of businesses, the latest specified notice period extends

49

until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. In 2005, PEC entered into an agreement with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 12B). PEC’s maximum exposure cannot be determined. At June 30, 2008, the estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $458 million, including $32 million at PEF. At June 30, 2008 and December 31, 2007, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $71 million and $80 million, respectively. These amounts include $20 million and $30 million, respectively, for PEC and $8 million for PEF at June 30, 2008, and December 31, 2007. During the three months ended June 30, 2008, PEC made no additional accruals and spent approximately $5 million that exceeded the joint owner limit. During the six months ended June 30, 2008, PEC made no additional accruals and spent approximately $10 million that exceeded the joint owner limit. 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 and a subsidiary have issued $300 million of guarantees for certain payments of two wholly owned indirect subsidiaries. See Note 14 for additional information.

C.           OTHER COMMITMENTS AND CONTINGENCIES

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts with the United States Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities on or before January 31, 1998. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. The Utilities have asserted nearly $91 million in damages incurred between January 31, 1998 and December 31, 2005; the time period set by the court for damages in this case. The Utilities will be free to file subsequent damages claims as they incur additional costs.

A trial was held in November 2007, and closing arguments presented on April 4, 2008. On May 19, 2008, the Utilities received a ruling from the United States Court of Federal Claims awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. The United States Department of Justice requested that the Trial Court reconsider its ruling. The Trial Court did reconsider its ruling and reduced the damage award by an immaterial amount. The Utilities anticipate the DOE will appeal. In the event that the Utilities recover damages in this matter, such recovery is not expected to have a material impact on the Utilities’ results of operations given the anticipated regulatory and accounting treatment. However, the Utilities cannot predict the outcome of this matter.

In July 2002, Congress passed an override resolution to Nevada’s veto of the DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.; and the city of Las Vegas petitioned the D.C. Court of Appeals for review of the Congressional override resolution. These same parties also challenged the EPA’s radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. In August 2005, the EPA issued new proposed standards. The proposed standards include a 1,000,000-year compliance period in the radiation protection standard. Comments were due November 21, 2005, and are being reviewed by the EPA. The DOE submitted the license application on June 4, 2008. Following a 90-day acceptance review by the NRC, the DOE believes the license application will be docketed, thus beginning the formal licensing phase that is anticipated to take three to four years.

50

On October 19, 2007, the DOE certified the regulatory compliance of the document database that will be used by all parties involved in the federal licensing process for the Yucca Mountain facility. The NRC did not uphold the DOE’s prior certification in 2004 in response to challenges from the state of Nevada. The state again is expected to challenge the DOE’s certification process. The DOE has recently stated that the earliest date the repository may be able to start accepting spent nuclear fuel is 2020. The Utilities cannot predict the outcome of this matter.

On August 5, 2008, the DOE announced that its estimated cost to build and commence operations at the Yucca Mountain facility has increased from $57.5 billion to $96.2 billion due to an increase in material costs, an increase in the quantity of spent fuel to store and a refinement of the repository's design.

With certain modifications and additional approvals by the NRC, including the installation of on-site dry cask storage facilities at PEC’s Robinson Nuclear Plant, PEC’s Brunswick Nuclear Plant and CR3, the Utilities’ spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on their respective systems through the expiration of the operating licenses, including any license extensions, for their nuclear generating units. PEC’s Shearon Harris Nuclear Plant (Harris) has sufficient storage capacity in its spent fuel pools through the expiration of its operating license, including any license extensions.

SYNTHETIC FUELS MATTERS

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

The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al. (the Florida Global Case), asserts the above claims in a case filed in the Circuit Court for Broward County, Fla., in March 2003, and requests an unspecified amount of compensatory damages, as well as declaratory relief. The Progress Affiliates have answered the Complaint by generally denying all of Global’s substantive allegations and asserting numerous substantial affirmative defenses. The case is at issue, but neither party has requested a trial. The parties are currently engaged in discovery in the Florida Global Case.

The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), was filed by the Progress Affiliates in the Superior Court for Wake County, N.C., seeking declaratory relief consistent with our interpretation of the Asset Purchase Agreement. Global was served with the North Carolina Global Case on April 17, 2003.

On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates’ declaratory judgment action. On August 7, 2003, the Wake County Superior Court denied Global’s motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court’s order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal. Since that time, the parties have been engaged in discovery in the Florida Global Case.

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

51

In January 2008, Global agreed to simplify the Florida action by dismissing the tort claims. The Florida Global Case continues now under contract theories alone. The case is scheduled to go to trial in April 2009. We cannot predict the outcome of this matter.

OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, we have made accruals and disclosures in accordance with SFAS No. 5, “Accounting for Contingencies,” 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.

14.     CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2007 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. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 12B in the 2007 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 46R. 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 consolidated financial results of Florida Progress only, which is primarily comprised of its wholly owned subsidiary PEF. The Other column includes the consolidated financial results of all other non-guarantor subsidiaries, primarily our wholly owned subsidiary PEC, and elimination entries for all intercompany transactions. Financial statements for PEC and PEF are separately presented elsewhere in this Form 10-Q. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities. The accompanying condensed consolidating financial statements have been restated for all periods presented to reflect the operations of Terminals and the synthetic fuels businesses as discontinued operations as described in Note 3A.

52

Condensed Consolidating Statement of Income Three months ended June 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	1,196		$	1,048		$	2,244
Operating expenses
Fuel used in electric generation		–			373			323			696
Purchased power		–			258			72			330
Operation and maintenance		2			217			269			488
Depreciation and amortization		–			76			132			208
Taxes other than on income		–			76			49			125
Other		–			(4	)		(5	)		(9	)
Total operating expenses		2			996			840			1,838
Operating (loss) income		(2	)		200			208			406
Other income, net		–			24			11			35
Interest charges, net		50			46			50			146
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(52	)		178			169			295
Income tax (benefit) expense		(22	)		53			64			95
Equity in earnings of consolidated subsidiaries		235			–			(235	)		–
Income (loss) from continuing operations		205			125			(130	)		200
Discontinued operations, net of tax		–			7			(2	)		5
Net income (loss)	$	205		$	132		$	(132	)	$	205

53

Condensed Consolidating Statement of Income Three months ended June 30, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	1,132		$	997		$	2,129
Operating expenses
Fuel used in electric generation		–			411			305			716
Purchased power		–			207			76			283
Operation and maintenance		2			198			261			461
Depreciation and amortization		–			101			122			223
Taxes other than on income		–			76			49			125
Other		–			15			5			20
Total operating expenses		2			1,008			818			1,828
Operating (loss) income		(2	)		124			179			301
Other income, net		3			6			5			14
Interest charges, net		50			38			47			135
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(49	)		92			137			180
Income tax (benefit) expense		(23	)		11			53			41
Equity in earnings of consolidated subsidiaries		(170	)		–			170			–
Minority interest in subsidiaries’ income, net of tax		–			(1	)		–			(1	)
(Loss) income from continuing operations		(196	)		80			254			138
Discontinued operations, net of tax		3			3			(337	)		(331	)
Net (loss) income	$	(193	)	$	83		$	(83	)	$	(193	)

54

Condensed Consolidating Statement of Income Six months ended June 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	2,194		$	2,116		$	4,310
Operating expenses
Fuel used in electric generation		–			714			679			1,393
Purchased power		–			441			121			562
Operation and maintenance		2			420			509			931
Depreciation and amortization		–			152			262			414
Taxes other than on income		–			147			99			246
Other		–			(2	)		(5	)		(7	)
Total operating expenses		2			1,872			1,665			3,539
Operating (loss) income		(2	)		322			451			771
Other income, net		4			39			17			60
Interest charges, net		98			97			104			299
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(96	)		264			364			532
Income tax (benefit) expense		(40	)		80			139			179
Equity in earnings of consolidated subsidiaries		470			–			(470	)		–
Minority interest in subsidiaries’ income, net of tax		–			(4	)		–			(4	)
Income (loss) from continuing operations		414			180			(245	)		349
Discontinued operations, net of tax		–			63			2			65
Net income (loss)	$	414		$	243		$	(243	)	$	414

55

Condensed Consolidating Statement of Income Six months ended June 30, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	2,146		$	2,055		$	4,201
Operating expenses
Fuel used in electric generation		–			796			656			1,452
Purchased power		–			370			134			504
Operation and maintenance		7			373			501			881
Depreciation and amortization		–			198			244			442
Taxes other than on income		–			150			99			249
Other		–			14			7			21
Total operating expenses		7			1,901			1,641			3,549
Operating (loss) income		(7	)		245			414			652
Other income, net		9			14			10			33
Interest charges, net		99			82			96			277
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(97	)		177			328			408
Income tax (benefit) expense		(43	)		36			120			113
Equity in earnings of consolidated subsidiaries		132			–			(132	)		–
Minority interest in subsidiaries’ income, net of tax		–			(8	)		–			(8	)
Income from continuing operations		78			133			76			287
Discontinued operations, net of tax		4			32			(241	)		(205	)
Net income (loss)	$	82		$	165		$	(165	)	$	82

56

Condensed Consolidating Balance Sheet June 30, 2008
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	8,352	$	9,149		$	17,501
Current assets
Cash and cash equivalents		20		1,383		20			1,423
Receivables, net		–		420		514			934
Notes receivable from affiliated companies		28		118		(146	)		–
Derivative assets		–		478		42			520
Prepayments and other current assets		24		698		883			1,605
Total current assets		72		3,097		1,313			4,482
Deferred debits and other assets
Investment in consolidated subsidiaries		11,582		–		(11,582	)		–
Goodwill		–		–		3,655			3,655
Derivative assets		–		504		113			617
Other assets and deferred debits		154		1,544		1,339			3,037
Total deferred debits and other assets		11,736		2,048		(6,475	)		7,309
Total assets	$	11,808	$	13,497	$	3,987		$	29,292
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity	$	8,607	$	3,390	$	(3,390	)	$	8,607
Preferred stock of subsidiaries – not subject to mandatory redemption		–		34		59			93
Minority interest		–		2		4			6
Long-term debt, affiliate		–		309		(38	)		271
Long-term debt, net		2,597		4,181		3,108			9,886
Total capitalization		11,204		7,916		(257	)		18,863
Current liabilities
Current portion of long-term debt		–		450		400			850
Short-term debt		343		–		–			343
Accounts payable		–		676		402			1,078
Notes payable to affiliated companies		–		171		(171	)		–
Derivative collateral liabilities		–		409		11			420
Other current liabilities		215		615		346			1,176
Total current liabilities		558		2,321		988			3,867
Deferred credits and other liabilities
Noncurrent income tax liabilities		1		39		212			252
Regulatory liabilities		–		2,164		1,336			3,500
Other liabilities and deferred credits		45		1,057		1,708			2,810
Total deferred credits and other liabilities		46		3,260		3,256			6,562
Total capitalization and liabilities	$	11,808	$	13,497	$	3,987		$	29,292

57

Condensed Consolidating Balance Sheet December 31, 2007
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	7,600	$	9,005		$	16,605
Current assets
Cash and cash equivalents		185		43		27			255
Receivables, net		–		574		593			1,167
Notes receivable from affiliated companies		157		149		(306	)		–
Derivative assets		–		83		2			85
Assets to be divested		–		48		4			52
Prepayments and other current assets		21		595		654			1,270
Total current assets		363		1,492		974			2,829
Deferred debits and other assets
Investment in consolidated subsidiaries		10,969		–		(10,969	)		–
Goodwill		–		1		3,654			3,655
Derivative assets		–		100		19			119
Other assets and deferred debits		149		1,475		1,533			3,157
Total deferred debits and other assets		11,118		1,576		(5,763	)		6,931
Total assets	$	11,481	$	10,668	$	4,216		$	26,365
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity	$	8,422	$	3,052	$	(3,052	)	$	8,422
Preferred stock of subsidiaries – not subject to mandatory redemption		–		34		59			93
Minority interest		–		81		3			84
Long-term debt, affiliate		–		309		(38	)		271
Long-term debt, net		2,597		2,686		3,183			8,466
Total capitalization		11,019		6,162		155			17,336
Current liabilities
Current portion of long-term debt		–		577		300			877
Short-term debt		201		–		–			201
Accounts payable		–		484		335			819
Notes payable to affiliated companies		–		227		(227	)		–
Derivative collateral liabilities		–		38		70			108
Liabilities to be divested		–		8		–			8
Other current liabilities		215		715		359			1,289
Total current liabilities		416		2,049		837			3,302
Deferred credits and other liabilities
Noncurrent income tax liabilities		–		59		302			361
Regulatory liabilities		–		1,330		1,224			2,554
Other liabilities and deferred credits		46		1,068		1,698			2,812
Total deferred credits and other liabilities		46		2,457		3,224			5,727
Total capitalization and liabilities	$	11,481	$	10,668	$	4,216		$	26,365

58

Condensed Consolidating Statement of Cash Flows Six months ended June 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(53	)	$	856		$	554		$	1,357
Investing activities
Gross property additions		–			(921	)		(339	)		(1,260	)
Nuclear fuel additions		–			(1	)		(42	)		(43	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			61			3			64
Proceeds from sales of assets to affiliated companies		–			10			(10	)		–
Purchases of available-for-sale securities and other investments		–			(418	)		(418	)		(836	)
Proceeds from sales of available-for-sale securities and other investments		–			418			398			816
Contributions to consolidated subsidiaries		(98	)		–			98			–
Changes in advances to affiliates		129			31			(160	)		–
Other investing activities		(7	)		13			(21	)		(15	)
Net cash provided (used) by investing activities		24			(807	)		(491	)		(1,274	)
Financing activities
Issuance of common stock		42			–			–			42
Dividends paid on common stock		(320	)		–			–			(320	)
Payments of short-term debt with original maturities greater than 90 days		(176	)		–			–			(176	)
Net increase in short-term debt		318			–			–			318
Proceeds from issuance of long-term debt, net		–			1,476			322			1,798
Retirement of long-term debt		–			(127	)		(300	)		(427	)
Cash distributions to minority interests of consolidated subsidiaries		–			(85	)		–			(85	)
Contributions from parent		–			85			(85	)		–
Dividends paid to parent		–			(3	)		3			–
Changes in advances from affiliates		–			(56	)		56			–
Other financing activities		–			1			(66	)		(65	)
Net cash (used) provided by financing activities		(136	)		1,291			(70	)		1,085
Net (decrease) increase in cash and cash equivalents		(165	)		1,340			(7	)		1,168
Cash and cash equivalents at beginning of period		185			43			27			255
Cash and cash equivalents at end of period	$	20		$	1,383		$	20		$	1,423

59

Condensed Consolidating Statement of Cash Flows Six months ended June 30, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided (used) by operating activities	$	38		$	205		$	(66	)	$	177
Investing activities
Gross property additions		–			(491	)		(408	)		(899	)
Nuclear fuel additions		–			(22	)		(75	)		(97	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			25			621			646
Purchases of available-for-sale securities and other investments		–			(103	)		(279	)		(382	)
Proceeds from sales of available-for-sale securities and other investments		21			103			309			433
Changes in advances to affiliates		(187	)		37			150			–
Other investing activities		(4	)		(9	)		5			(8	)
Net cash (used) provided by investing activities		(170	)		(460	)		323			(307	)
Financing activities
Issuance of common stock		122			–			–			122
Dividends paid on common stock		(311	)		–			–			(311	)
Net increase in short-term debt		169			–			–			169
Retirement of long-term debt		–			(2	)		–			(2	)
Cash distributions to minority interests of consolidated subsidiaries		–			(10	)		–			(10	)
Dividends paid to parent		–			(10	)		10			–
Changes in advances from affiliates		–			233			(233	)		–
Other financing activities		(1	)		32			(48	)		(17	)
Net cash (used) provided by financing activities		(21	)		243			(271	)		(49	)
Net decrease in cash and cash equivalents		(153	)		(12	)		(14	)		(179	)
Cash and cash equivalents at beginning of period		153			40			72			265
Cash and cash equivalents at end of period	$	–		$	28		$	58		$	86

60

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS

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

The following MD&A contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors” found within Part II of this Form 10-Q and Item 1A, “Risk Factors” to the Progress Registrant’s annual report on Form 10-K for the fiscal year ended December 31, 2007 (2007 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 weather variations and the timing of outages of electric generating units, especially nuclear-fueled 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 2007 Form 10-K.

PROGRESS ENERGY

RESULTS OF OPERATIONS

Our reportable operating business segments are PEC and PEF, which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina, and Florida, respectively.

Our “Corporate and Other” segment primarily includes the operations of the Parent, Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a separate business segment.

As discussed more fully in Note 3 and “Results of Operations – Discontinued Operations,” in accordance with our business strategy to reduce our business risk and to focus on the core operations of the Utilities, the majority of our nonregulated business operations have been divested. These operations have been classified as discontinued operations in the accompanying financial statements. Consequently, the composition of other continuing segments has been impacted by these divestitures. For comparative purposes, prior year results have been restated to conform to the current presentation. In this section, earnings and the factors affecting earnings for the three and six months ended June 30, 2008, are compared to the same periods in 2007. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

61

OVERVIEW

For the quarter ended June 30, 2008, our net income was $205 million, or $0.79 per share, compared to net loss of $193 million, or $0.75 per share, for the same period in 2007. For the quarter ended June 30, 2008, our income from continuing operations was $200 million compared to $138 million for the same period in 2007. The increase in income from continuing operations as compared to prior year was primarily due to:

·   favorable allowance for funds used during construction (AFUDC) at the Utilities;

·   higher wholesale revenues at the Utilities;

·   favorable weather at PEF;

·   increased retail rates at PEF;

·   lower other operating expenses due to disallowed fuel costs in 2007 at PEF;

·   favorable retail customer growth and usage at PEC;

·   increased gains from land sales at the Utilities; and

·   lower purchased power expense at PEC due to the expiration of a power buyback agreement.

Partially offsetting these items were:

·   higher income tax expense due to the benefit from the closure of certain federal tax years and positions in 2007;

·   higher depreciation and amortization expense at the Utilities excluding prior year recoverable storm amortization at PEF; and

·   unfavorable retail customer growth and usage at PEF.

For the six months ended June 30, 2008, our net income was $414 million, or $1.60 per share, compared to net income of $82 million, or $0.32 per share, for the same period in 2007. For the six months ended June 30, 2008, our income from continuing operations was $349 million compared to $287 million for the same period in 2007. The increase in income from continuing operations as compared to prior year was primarily due to:

·   favorable AFUDC at the Utilities;

·   higher wholesale revenues at PEF;

·   increased retail rates at PEF;

·   favorable retail customer growth and usage at PEC;

·   lower purchased power expense at PEC due to the expiration of a power buyback agreement;

·   decreased legal expenses at Corporate and Other; and

·   favorable weather at PEF.

Partially offsetting these items were:

·   higher income tax expense due to the benefit from the closure of certain federal tax years and positions in 2007;

·   higher depreciation and amortization expense at the Utilities excluding prior year recoverable storm amortization at PEF;

·   unfavorable retail customer growth and usage at PEF; and

·   unfavorable weather at PEC.

62

Our segments contributed the following profits or losses for the three and six months ended June 30, 2008 and 2007:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Business Segment
PEC	$	104		$	88		$	226		$	211
PEF		125			68			191			128
Total segment profit		229			156			417			339
Corporate and Other		(29	)		(18	)		(68	)		(52	)
Income from continuing operations		200			138			349			287
Discontinued operations, net of tax		5			(331	)		65			(205	)
Net income (loss)	$	205		$	(193	)	$	414		$	82

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $104 million and $88 million for the three months ended June 30, 2008 and 2007, respectively. The increase in profits for the three months ended June 30, 2008, compared to the same period in 2007, was primarily due to the favorable impact of retail customer growth and usage, higher wholesale revenues, lower purchased power expense due to the expiration of a power buyback agreement, favorable AFUDC and higher gains from land sales, partially offset by higher depreciation and amortization.

PEC contributed segment profits of $226 million and $211 million for the six months ended June 30, 2008 and 2007, respectively. The increase in profits for the six months ended June 30, 2008, compared to the same period in 2007, was primarily due to the favorable impact of retail customer growth and usage and lower purchased power expense due to the expiration of a power buyback agreement, partially offset by higher depreciation and amortization.

The revenue tables below present the total amount and percentage change of revenues excluding fuel. Revenues excluding fuel is defined as total electric revenues less fuel revenues. We and PEC consider revenues excluding fuel a useful measure to evaluate PEC’s electric operations because fuel revenues primarily represent the recovery of fuel and a portion of purchased power expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. We and PEC have included the analysis below as a complement to the financial information we provide in accordance with accounting principles generally accepted in the United States of America (GAAP). However, revenues excluding fuel is not defined under GAAP, and the presentation may not be comparable to other companies’ presentation or more useful than the GAAP information provided elsewhere in this report.

63

Three Months Ended June 30, 2008, Compared to Three Months Ended June 30, 2007

REVENUES

PEC’s electric revenues for the three months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended June 30,
Customer Class	2008			Change			% Change			2007
Residential	$	334		$	7			2.1		$	327
Commercial		269			8			3.1			261
Industrial		187			13			7.5			174
Governmental		23			1			4.5			22
Total retail revenues		813			29			3.7			784
Wholesale		189			31			19.6			158
Unbilled		24			(4	)		–			28
Miscellaneous		22			(4	)		(15.4	)		26
Total electric revenues		1,048			52			5.2			996
Less: Fuel revenues		(379	)		(36	)		–			(343	)
Revenues excluding fuel	$	669		$	16			2.5		$	653

PEC’s electric energy sales for the three months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended June 30,
Customer Class	2008		Change			% Change		2007
Residential		3,586		11			0.3		3,575
Commercial		3,384		37			1.1		3,347
Industrial		3,122		136			4.6		2,986
Governmental		335		3			0.9		332
Total retail energy sales		10,427		187			1.8		10,240
Wholesale		3,441		275			8.7		3,166
Unbilled		245		(158	)		–		403
Total kWh sales		14,113		304			2.2		13,809

PEC’s revenues, excluding fuel revenues of $379 million and $343 million for the three months ended June 30, 2008 and 2007, respectively, increased $16 million. The increase in revenues excluding fuel is primarily due to the $11 million favorable impact of retail customer growth and usage and $9 million higher wholesale revenues, partially offset by lower miscellaneous revenues of $4 million and the $1 million unfavorable impact of weather. Favorable retail customer growth and usage was driven by a net 25,000 customer increase in PEC’s average number of customers for the three months ended June 30, 2008, compared to the same period in 2007, and by an increase in the average usage per retail customer. The higher wholesale revenues are primarily due to increased energy rates and sales with a major customer. Miscellaneous revenues decreased due to lower electric property rental revenues.

The decline in general economic conditions, including weakness in the housing markets in both Florida and the United States, has contributed to a slowdown in customer growth and usage in PEF’s service territory (See “Progress Energy Florida – Revenues”).PEC has not been as significantly impacted by the decline in general economic conditions as PEF. However, PEC has experienced a slight decline in residential and commercial sales growth.

64

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 $395 million for the three months ended June 30, 2008, which represents a $14 million increase compared to the same period in 2007. Fuel used in electric generation increased $18 million to $323 million compared to the same period in 2007. The increase was primarily due to higher fuel costs. Additionally, deferred fuel expense decreased $12 million due to the implementation of the North Carolina comprehensive energy legislation (See “Other Matters – Regulatory Environment”), which was offset by an increase in deferred fuel of $12 million primarily due to a change in the collection of the current year’s under-recovery in each respective period. Current year purchased power costs were $4 million lower than the three months ended June 30, 2007, primarily due to the $9 million impact from the expiration of a power buyback agreement with North Carolina Eastern Municipal Power Agency (Power Agency). This decrease in purchased power costs was partially offset by $6 million increased purchases in the current year compared to lower purchases in 2007 due to an outage that impacted a purchased power contract.

Operation and Maintenance

Operation and maintenance (O&M) expenses were $275 million for the three months ended June 30, 2008, which represents a $7 million increase compared to the same period in 2007. O&M expenses increased primarily due to a $21 million increase in nuclear expenses, of which $16 million relates to refurbishments, preventative maintenance and incremental outage expenses at Brunswick Nuclear Plant (Brunswick), and an increase in estimated environmental remediation expenses (See Note 12A) of $4 million, partially offset by outage expenses of $18 million at Robinson Nuclear Plant (Robinson) in 2007.

Depreciation and Amortization

Depreciation and amortization expense was $129 million for the three months ended June 30, 2008, which represents an $11 million increase compared to the same period in 2007. Depreciation and amortization expense increased primarily due to $15 million additional depreciation associated with the accelerated cost-recovery program for nuclear generating assets (See Note 4A) and the $4 million impact of depreciable asset base increases, partially offset by $8 million lower Clean Smokestacks Act amortization.

Other

Other operating expenses consisted of gains of $5 million for the three months ended June 30, 2008, primarily due to land sales. There were no gains from land sales for the same period in 2007.

Total Other Income, net

Total other income, net of $13 million increased $1 million for the three months ended June 30, 2008, compared to the same period in 2007, primarily due to $4 million derivative mark-to-market gains and $3 million favorable AFUDC equity related to costs associated with eligible construction projects. These increases were offset by $4 million investment losses and $3 million lower interest income. The derivative mark-to-market gains relate to commodity instruments that are not subject to retail regulatory treatment. We expect AFUDC equity to continue to increase for the remainder of 2008, primarily due to increased spending on eligible construction projects.

Income Tax Expense

Income tax expense increased $13 million for the three months ended June 30, 2008, as compared to the same period in 2007, primarily due to the $12 million tax impact of higher pre-tax earnings and the $2 million impact of tax levelization. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is

65

consistent with the estimated annual effective tax rate. PEC’s income tax expense was increased by $2 million for the three months ended June 30, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate, compared to no impact for the three months ended June 30, 2007. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can 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, 2008, Compared to Six Months Ended June 30, 2007

REVENUES

PEC’s electric revenues for the six months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions)	Six Months Ended June 30,
Customer Class	2008			Change			% Change			2007
Residential	$	760		$	9			1.2		$	751
Commercial		531			16			3.1			515
Industrial		355			16			4.7			339
Governmental		46			2			4.5			44
Total retail revenues		1,692			43			2.6			1,649
Wholesale		370			18			5.1			352
Unbilled		7			4			–			3
Miscellaneous		46			(3	)		(6.1	)		49
Total electric revenues		2,115			62			3.0			2,053
Less: Fuel revenues		(773	)		(51	)		–			(722	)
Revenues excluding fuel	$	1,342		$	11			0.8		$	1,331

PEC’s electric energy sales for the six months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Six Months Ended June 30,
Customer Class	2008		Change			% Change			2007
Residential		8,264		(52	)		(0.6	)		8,316
Commercial		6,662		71			1.1			6,591
Industrial		5,894		87			1.5			5,807
Governmental		668		9			1.4			659
Total retail energy sales		21,488		115			0.5			21,373
Wholesale		7,213		91			1.3			7,122
Unbilled		4		(56	)		–			60
Total kWh sales		28,705		150			0.5			28,555

PEC’s revenues, excluding fuel revenues of $773 million and $722 million for the six months ended June 30, 2008 and 2007, respectively, increased $11 million. The increase in revenues excluding fuel is primarily due to the $25 million favorable impact of retail customer growth and usage and $7 million higher wholesale revenues, partially offset by $8 million lower excess generation revenues, the $8 million unfavorable impact of weather and $3 million lower miscellaneous revenues. Favorable retail customer growth and usage was driven by a net 25,000 customer increase in PEC’s average number of customers for the six months ended June 30, 2008, compared to the same period in 2007, and by an increase in the average usage per retail customer. Higher wholesale revenues are primarily due to increased energy rates and sales with a major customer. Lower excess generation revenues were primarily driven by unfavorable market conditions in 2008 resulting from higher fuel costs compared to 2007. The unfavorable impact of weather was driven by lower heating degree days than 2007. Miscellaneous revenues decreased due to lower electric property rental revenues.

As discussed previously in “Revenues” for the three months ended June 30, 2008 and 2007, PEC has not been as significantly impacted by the decline in general economic conditions as PEF. However, PEC has experienced a slight decline in residential and commercial sales growth.

66

Residential revenues increased for the six months ended June 30, 2008, despite a decrease in residential energy sales for the same period primarily due to the impact of increased fuel revenues as a result of higher energy costs and the recovery of prior year fuel costs.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $800 million for the six months ended June 30, 2008, which represents a $10 million increase compared to the same period in 2007. Fuel used in electric generation increased $23 million to $679 million compared to the same period in 2007. This increase was primarily due to higher fuel costs. Additionally, deferred fuel expense decreased $24 million due to the implementation of the North Carolina comprehensive energy legislation (See “Other Matters – Regulatory Environment”), which was offset by an increase in deferred fuel of $24 million due to a change in the collection of the current year’s under-recovery in each respective period. Current year purchased power costs were $13 million lower than the six months ended June 30, 2007, primarily due to the $19 million impact from the expiration of a power buyback agreement with Power Agency. This decrease in purchased power costs was partially offset by $4 million increased purchases in the current year compared to lower purchases in 2007 due to an outage that impacted a purchased power contract.

Operation and Maintenance

O&M expenses were $523 million for the six months ended June 30, 2008, which represents a $7 million increase compared to the same period in 2007. O&M expenses increased primarily due to an $18 million increase in nuclear expenses, of which $10 million relates to refurbishments, preventative maintenance and incremental outage expenses at Brunswick, an increase in estimated environmental remediation expenses (See Note 12A) of $5 million, increased spending of $3 million on vegetation management in compliance with federal regulations and increased nuclear license fees of $3 million, partially offset by outage expenses of $24 million at Robinson in 2007.

Depreciation and Amortization

Depreciation and amortization expense was $255 million for the six months ended June 30, 2008, which represents a $20 million increase compared to the same period in 2007. Depreciation and amortization expense increased primarily due to $15 million additional depreciation associated with the accelerated cost-recovery program for nuclear generating assets (See Note 4A) and the $7 million impact of depreciable asset base increases, partially offset by $2 million lower Clean Smokestacks Act amortization.

Other

Other operating expenses consisted of gains of $6 million and $1 million for the six months ended June 30, 2008 and 2007, respectively, primarily due to land sales.

Total Other Income, net

Total other income, net of $22 million increased $1 million for the six months ended June 30, 2008, compared to the same period in 2007, primarily due to $5 million favorable AFUDC equity related to costs associated with eligible construction projects and $4 million derivative mark-to-market gains. These increases were partially offset by $4 million investment losses and $4 million lower interest income. The derivative mark-to-market gains relate to commodity instruments that are not subject to retail regulatory treatment. We expect AFUDC equity to continue to increase for the remainder of 2008, primarily due to increased spending on eligible construction projects.

67

Income Tax Expense

Income tax expense increased $19 million for the six months ended June 30, 2008, as compared to the same period in 2007, primarily due to the $14 million tax impact of higher pre-tax earnings, $4 million prior year changes in tax estimates, and the $3 million unfavorable tax impact of stock-based compensation.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $125 million and $68 million for the three months ended June 30, 2008 and 2007, respectively. The increase in profits for the three months ended June 30, 2008, compared to the same period in 2007, was primarily due to favorable AFUDC, higher wholesale revenues, the favorable impact of weather, an increase in retail rates and lower other operating expenses due to disallowed fuel costs in 2007, partially offset by the unfavorable impact of retail customer growth and usage.

PEF contributed segment profits of $191 million and $128 million for the six months ended June 30, 2008 and 2007, respectively. The increase in profits for the six months ended June 30, 2008, compared to the same period in 2007, was primarily due to favorable AFUDC, higher wholesale revenues, an increase in retail rates and the favorable impact of weather, partially offset by the unfavorable impact of retail customer growth and usage.

The revenue tables below present the total amount and percentage change of revenues excluding fuel and other pass-through revenues. Revenues excluding fuel and other pass-through revenues is defined as total electric revenues less fuel and other pass-through revenues. We and PEF consider revenues excluding fuel and other pass-through revenues a useful measure to evaluate PEF’s electric operations because fuel and other pass-through revenues primarily represent the recovery of fuel, purchased power and other pass-through expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. We and PEF have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, revenues excluding fuel and other pass-through revenues is not defined under GAAP, and the presentation may not be comparable to other companies’ presentation or more useful than the GAAP information provided elsewhere in this report.

Three Months Ended June 30, 2008, Compared to Three Months Ended June 30, 2007

REVENUES

PEF’s electric revenues for the three months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended June 30,
Customer Class	2008			Change			% Change			2007
Residential	$	553		$	20			3.8		$	533
Commercial		281			–			–			281
Industrial		80			2			2.6			78
Governmental		70			(4	)		(5.4	)		74
Total retail revenues		984			18			1.9			966
Wholesale		141			39			38.2			102
Unbilled		27			8			–			19
Miscellaneous		42			–			–			42
Total electric revenues		1,194			65			5.8			1,129
Less: Fuel and other pass-through revenues		(732	)		(8	)		–			(724	)
Revenues excluding fuel and other pass-through revenues	$	462		$	57			14.1		$	405

68

PEF’s electric energy sales for the three months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended June 30,
Customer Class	2008		Change			% Change			2007
Residential		4,755		253			5.6			4,502
Commercial		3,069		122			4.1			2,947
Industrial		1,009		71			7.6			938
Governmental		800		(11	)		(1.4	)		811
Total retail energy sales		9,633		435			4.7			9,198
Wholesale		1,930		483			33.4			1,447
Unbilled		715		(36	)		–			751
Total kWh sales		12,278		882			7.7			11,396

PEF’s revenues, excluding fuel and other pass-through revenues of $732 million and $724 million for the three months ended June 30, 2008 and 2007, respectively, increased $57 million. The increase in revenues was primarily due to base rate increases, increased wholesale revenues and the favorable impact of weather, partially offset by unfavorable retail customer growth and usage. The increase in base rates was $24 million; Hines 4 being placed in service contributed $14 million in additional revenues and the transfer of Hines 2 cost recovery from the fuel clause to base rates contributed $10 million. These base rate changes occurred in accordance with PEF’s most recent base rate agreement. Wholesale revenues, excluding fuel and other pass-through revenues, increased $20 million primarily due to two new contracts with one major customer. The $15 million favorable impact of weather was driven by higher cooling degree days. PEF’s base rate, wholesale revenue and weather favorability was partially offset by the unfavorable retail customer growth and usage impact of $5 million.

PEF believes that the decline in general economic conditions, including weakness in the housing markets in both Florida and the United States, has contributed to a slowdown in customer growth and usage in its service territory. In addition to lower average usage per customer, PEF experienced significantly lower customer growth in 2008 than had been experienced in recent periods. PEF’s average number of customers for the three months ended June 30, 2008, compared to the same period in 2007 increased a net 2,000 customers. In comparison, PEF’s average number of customers for the three months ended June 30, 2007, compared to the same period in 2006 increased a net 28,000 customers.

PEF has secured and is pursuing additional wholesale contracts that will mitigate, to a certain extent, the impact of lower retail revenues. PEF cannot predict whether or to what extent the trends of declining usage per customer and lower customer growth will continue to negatively impact retail revenues or, if they do continue, the extent to which increased wholesale revenues may offset such a negative impact.

EXPENSES

Fuel and Purchased Power

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

Fuel and purchased power expenses were $631 million for the three months ended June 30, 2008, which represents a $13 million increase compared to the same period in 2007. Purchased power costs were $51 million higher for the three months ended June 30, 2008, primarily due to increased current year purchases of $39 million as a result of higher fuel costs and an increase in the recovery of deferred capacity costs of $11 million. Fuel used in electric generation decreased $38 million to $373 million compared to the same period in 2007. This decrease was due to lower deferred fuel expense of $180 million, partially offset by increased current year fuel costs of $142 million. The lower deferred fuel expense was primarily due to the regulatory approval to lower the fuel factor for customers effective January 2008 as a result of over-recovery of fuel costs in the prior year. The increase in current year fuel

69

costs was primarily due to an increase in the percentage of generation supplied by natural gas, increased fuel prices and higher system requirements.

With the higher fuel costs experienced in 2008 and the anticipated high fuel costs for the remainder of 2008, PEF filed a petition with the Florida Public Service Commission (FPSC) requesting a mid-course correction to its fuel cost recovery factors (See Note 4B).

Operation and Maintenance

O&M expenses were $217 million for the three months ended June 30, 2008, which represents a $19 million increase when compared to the same period in 2007. O&M expenses increased $30 million related to an increase in storm damage reserves, which began in August 2007 and will continue through August 2008, partially offset by a $4 million sales and use tax audit adjustment and $4 million lower environmental cost recovery (ECRC) costs due to deferral of expenses. The storm damage reserve and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. Therefore, O&M expenses recoverable through base rates decreased approximately $7 million compared to the same period in 2007.

Depreciation and Amortization

Depreciation and amortization expense was $76 million for the three months ended June 30, 2008, which represents a $24 million decrease compared to the same period in 2007. Depreciation and amortization expense decreased $28 million due to lower amortization of unrecovered storm restoration costs, partially offset by the $5 million impact of depreciable asset base increases. Storm restoration costs, which were fully amortized in August 2007, were recovered through a cost-recovery clause and, therefore, had no material impact on earnings.

Other

Other operating income of $4 million for the three months ended June 30, 2008, compared to other operating expenses of $12 million for the same period in 2007, represents a $16 million change. The other operating income of $4 million for the three months ended June 30, 2008, consists of a gain on a land sale. The other operating expenses of $12 million for the three months ended June 30, 2007, consist of the impact of a FPSC order requiring PEF to refund disallowed fuel costs to its ratepayers (See Note 4B).

Total Other Income, net

Total other income, net of $23 million increased $14 million for the three months ended June 30, 2008, compared to the same period in 2007, primarily due to $14 million favorable AFUDC equity related to costs associated with eligible construction projects. We expect AFUDC equity to continue to increase for the remainder of 2008, primarily due to increased spending on environmental initiatives and other eligible construction projects.

Total Interest Charges, net

Total interest charges, net were $39 million for the three months ended June 30, 2008, which represents no change compared to the same period in 2007. However, total interest charges, net were impacted by a $7 million interest benefit resulting from the resolution of tax matters and $3 million favorable AFUDC debt related to costs associated with eligible construction projects, partially offset by $9 million higher interest as a result of higher average debt outstanding.

Income Tax Expense

Income tax expense increased $30 million for the three months ended June 30, 2008, compared to the same period in 2007, primarily due to the $34 million tax impact of higher pre-tax income compared to the prior year and the $5 million prior year benefit related to the closure of certain federal tax years and positions, partially offset by the $5 million impact of the increase in AFUDC equity discussed above and the $5 million impact of tax levelization discussed below. AFUDC equity is excluded from the calculation of income tax expense. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was decreased by $4 million for the three months ended June 30, 2008 compared to an increase of $1 million for the three months ended June 30, 2007, in order to maintain an

70

effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can 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, 2008, Compared to Six Months Ended June 30, 2007

REVENUES

PEF’s electric revenues for the six months ended June 30, 2008 and 2007, and the amount and percentage change by customer class were as follows:

(in millions)	Six Months Ended June 30,
Customer Class	2008			Change			% Change			2007
Residential	$	1,016		$	(9	)		(0.9	)	$	1,025
Commercial		524			(4	)		(0.8	)		528
Industrial		148			(4	)		(2.6	)		152
Governmental		137			(4	)		(2.8	)		141
Total retail revenues		1,825			(21	)		(1.1	)		1,846
Wholesale		245			64			35.4			181
Unbilled		33			6			–			27
Miscellaneous		87			1			1.2			86
Total electric revenues		2,190			50			2.3			2,140
Less: Fuel and other pass-through revenues		(1,340	)		29			–			(1,369	)
Revenues excluding fuel and other pass-through revenues	$	850		$	79			10.2		$	771

PEF’s electric energy sales for the six months ended June 30, 2008 and 2007, and the amount and percentage change by customer class are as follows:

(in millions of kWh)	Six Months Ended June 30,
Customer Class	2008		Change			% Change		2007
Residential		8,760		103			1.2		8,657
Commercial		5,729		159			2.9		5,570
Industrial		1,874		41			2.2		1,833
Governmental		1,567		7			0.4		1,560
Total retail energy sales		17,930		310			1.8		17,620
Wholesale		3,320		703			26.9		2,617
Unbilled		935		(6	)		–		941
Total kWh sales		22,185		1,007			4.8		21,178

PEF’s revenues, excluding fuel and other pass-through revenues of $1.340 billion and $1.369 billion for the six months ended June 30, 2008 and 2007, respectively, increased $79 million. The increase in revenues was primarily due to base rate increases, increased wholesale revenues and the favorable impact of weather, partially offset by unfavorable retail customer growth and usage. The increase in base rates was $44 million; Hines 4 being placed in service contributed $26 million in additional revenues and the transfer of Hines 2 cost recovery from the fuel clause to base rates contributed $18 million. These base rate changes occurred in accordance with PEF’s most recent base rate agreement. Wholesale revenues, excluding fuel and other pass-through revenues, increased $28 million primarily due to two new contracts with one major customer and a contract amendment with another major customer. The $16 million favorable impact of weather was driven by higher cooling degree days. PEF’s base rate, wholesale revenue and weather favorability was partially offset by the unfavorable retail customer growth and usage impact of $12 million.

As discussed above, PEF has experienced a slowdown in customer growth and usage in its service territory. In addition to lower average usage per customer, PEF experienced significantly lower customer growth in the first six months of 2008 than had been experienced in recent periods. PEF’s average number of customers for the six months ended June 30, 2008, compared to the same period in 2007 increased a net 4,000 customers. In comparison, PEF’s

71

average number of customers for the six months ended June 30, 2007, compared to the same period in 2006, increased a net 29,000 customers.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.155 billion for the six months ended June 30, 2008, which represents an $11 million decrease compared to the same period in 2007. Fuel used in electric generation decreased $82 million to $714 million compared to the same period in 2007. This decrease was due to lower deferred fuel expense of $268 million, partially offset by increased current year fuel costs of $186 million. The lower deferred fuel expense was primarily due to the regulatory approval to lower the fuel factor for customers effective January 2008 as a result of over-recovery of fuel costs in the prior year. The increase in current year fuel costs was primarily due to an increase in the percentage of generation supplied by natural gas, increased fuel prices and higher system requirements. Purchased power costs were $71 million higher for the six months ended June 30, 2008, primarily due to increased current year purchases of $58 million as a result of higher fuel costs and an increase in the recovery of deferred capacity costs of $13 million.

As discussed earlier, PEF filed a petition with the FPSC requesting a mid-course correction to its fuel cost recovery factors (See Note 4B).

Operation and Maintenance

O&M expenses were $420 million for the six months ended June 30, 2008, which represents a $47 million increase when compared to the same period in 2007. O&M expenses increased $55 million related to an increase in storm damage reserves, which began in August 2007 and will continue through August 2008, and $5 million primarily related to higher outage restoration, partially offset by a $9 million sales and use tax audit adjustment and $8 million lower ECRC costs due to deferral of expenses. The storm damage reserve and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. Therefore, O&M expenses recoverable through base rates were approximately the same as 2007.

Depreciation and Amortization

Depreciation and amortization expense was $152 million for the six months ended June 30, 2008, which represents a $45 million decrease compared to the same period in 2007. Depreciation and amortization expense decreased $54 million due to lower amortization of unrecovered storm restoration costs, partially offset by the $11 million impact of depreciable asset base increases. Storm restoration costs, which were fully amortized in August 2007, were recovered through a cost-recovery clause and, therefore, had no material impact on earnings.

Other

Other operating income of $4 million for the six months ended June 30, 2008, compared to other operating expenses of $12 million for the same period in 2007, represents a $16 million change. The other operating income of $4 million for the six months ended June 30, 2008, consists of a gain on a land sale. The other operating expenses of $12 million for the six months ended June 30, 2007, consist of the impact of a FPSC order requiring PEF to refund disallowed fuel costs to its ratepayers (See Note 4B).

Total Other Income, net

Total other income, net of $41 million increased $24 million for the six months ended June 30, 2008, compared to the same period in 2007, primarily due to $24 million favorable AFUDC equity related to costs associated with eligible construction projects. We expect AFUDC equity to continue to increase for the remainder of 2008, primarily due to increased spending on environmental initiatives and other eligible construction projects.

Total Interest Charges, net

Total interest charges, net were $83 million for the six months ended June 30, 2008, which represents a $7 million increase compared to the same period in 2007. The increase was primarily due to $18 million higher interest as a result of higher average debt outstanding. Partially offsetting this increase was $7 million favorable AFUDC debt

72

related to costs associated with eligible construction projects and a $7 million interest benefit resulting from the resolution of tax matters.

Income Tax Expense

Income tax expense increased $32 million for the six months ended June 30, 2008, compared to the same period in 2007, primarily due to the $37 million tax impact of higher pre-tax income compared to the prior year and the $5 million prior year benefit related to the closure of certain federal tax years and positions, partially offset by the $10 million impact of the increase in AFUDC equity discussed above and the $4 million impact of tax levelization, discussed below. AFUDC equity is excluded from the calculation of income tax expense. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was decreased by $3 million for the six months ended June 30, 2008 compared to an increase of $1 million for the six months ended June 30, 2007, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can 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.

CORPORATE AND OTHER

The Corporate and Other segment primarily includes the operations of the Parent, PESC and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a separate business segment. Corporate and Other expense is summarized below:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2008			2007			2008			2007
Other interest expense	$	(57	)	$	(43	)	$	(111	)	$	(91	)
Contingent value obligations		(2	)		(4	)		(2	)		(3	)
Tax levelization		1			1			–			(2	)
Other income tax benefit		24			36			41			58
Other		5			(8	)		4			(14	)
Corporate and Other after-tax expense	$	(29	)	$	(18	)	$	(68	)	$	(52	)

Other interest expense increased $14 million for the three months ended June 30, 2008, and increased $20 million for the six months ended June 30, 2008, compared to the same periods in 2007. The increase for the three and six months ended June 30, 2008, was primarily due to a $6 million prior year benefit related to the closure of certain federal tax years and positions and a decrease in the interest allocated to discontinued operations. The decrease in interest expense allocated to discontinued operations resulted from the allocations of interest expense in early 2007 for operations that were sold later in 2007. No interest expense was allocated to discontinued operations for the three or six months ended June 30, 2008, compared to $5 million and $12 million of interest expense allocated to discontinued operations for the three and six months ended June 30, 2007, respectively.

Progress Energy issued 98.6 million Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress) in 2000. Each CVO represents the right of the holder to receive contingent payments based on the performance of four Earthco coal-based solid synthetic fuels facilities purchased by subsidiaries of Florida Progress in October 1999. The payments, if any, are based on the net after-tax cash flows the facilities generate. At June 30, 2008 and 2007, the CVOs had fair values of approximately $36 million and $35 million, respectively, and average unit prices of $0.37 and $0.36 at June 30, 2008 and 2007, respectively. We recorded unrealized losses of $2 million and $4 million for the three months ended June, 2008 and 2007, respectively, to record the changes in fair value of the CVOs. We recorded unrealized losses of $2 million and $3 million for the six months ended June 30, 2008 and 2007, respectively.

GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $1 million for the three months ended June 30, 2008 and 2007, respectively, and had no impact for the six months ended June 30, 2008, compared to an increase of $2 million for the six months ended June 30, 2007, in order to maintain an effective rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of

73

income or deduction can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

Other income tax benefit decreased $12 million and $17 million for the three and six months ended June 30, 2008, respectively, primarily due to the $14 million prior year benefit related to the closure of certain federal tax years and positions.

Other decreased $13 million for the three months ended June 30, 2008, compared to the same period in 2007, primarily due to $5 million decreased indirect corporate overhead due to divestitures completed in 2007, $2 million decreased legal expenses, lower depreciation and increased investment gains. Other decreased $18 million for the six months ended June 30, 2008, compared to the same period in 2007, primarily due to $11 million decreased legal expenses and $8 million decreased indirect corporate overhead due to divestitures completed in 2007.

DISCONTINUED OPERATIONS

We divested multiple nonregulated businesses during 2008 and 2007 in accordance with our business strategy to reduce our business risk and to focus on the core operations of the Utilities.

TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky (Terminals) for $71 million in gross cash proceeds. The terminals had a total annual capacity in excess of 40 million tons for transloading, blending and storing coal and other commodities. Proceeds from the sale were used for general corporate purposes. During the six months ended June 30, 2008, we recorded an after-tax gain of $41 million on the sale of these assets.

Prior to 2008, we had substantial operations associated with the production of coal-based solid synthetic fuels. The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. As a result of the expiration of the tax credit program, all of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007. All periods have been restated to reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

Terminals and the synthetic fuels businesses collectively generated net earnings from discontinued operations of $8 million and net losses from discontinued operations of $7 million for the three months ended June 30, 2008 and 2007, respectively, and net earnings from discontinued operations of $22 million and $64 million for the six months ended June 30, 2008 and 2007, respectively. The decrease in net earnings from discontinued operations for the six months ended June 30, 2008, is primarily due to the 2007 expiration of the tax credit program.

CCO – GEORGIA OPERATIONS

On March 9, 2007, our subsidiary, Progress Energy Ventures, Inc. (PVI), entered into a series of transactions to sell or assign substantially all of its Competitive Commercial Operations (CCO) physical and commercial assets and liabilities. Assets divested include approximately 1,900 megawatts (MW) of gas-fired generation assets in Georgia. The sale of the generation assets closed on June 11, 2007, for a net sales price of $615 million. We recorded an estimated loss of $226 million in December 2006. Based on the terms of the final agreement, during the three and six months ended June 30, 2007, we reversed $1 million and $17 million, respectively, after-tax of the impairment recorded in 2006.

Additionally, on June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of full-requirements contracts with 16 Georgia electric membership cooperatives (the Georgia Contracts), forward gas and power contracts, gas transportation, structured power and other contracts to a third party. This represents substantially all of our nonregulated energy marketing and trading operations. As a result of the assignments, PVI made a net cash payment of $347 million, which represented the net cost to assign the Georgia Contracts and other related contracts. In the quarter ended June 30, 2007, we recorded a charge associated with the costs to exit the Georgia Contracts, and other related contracts, of $349 million after-tax. We used the net proceeds from these transactions for general corporate purposes.

74

CCO’s operations generated net losses from discontinued operations of $3 million and $322 million for the three months ended June 30, 2008 and 2007, respectively, and $3 million and $279 million for the six months ended June 30, 2008 and 2007, respectively. The decrease in net losses from discontinued operations for both the three and six months ended June 30, 2008, compared to the same period in 2007 is primarily due to the after-tax charge of $349 million associated with the costs to exit the Georgia Contracts, and other related contracts recorded in 2007, partially offset by the unrealized mark-to-market gains related to the increase in natural gas prices in 2007.

COAL MINING BUSINESSES

On March 7, 2008, we sold the remaining operations of Progress Fuels subsidiaries engaged in the coal mining business (Coal Mining) for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. These assets included Powell Mountain Coal Co. and Dulcimer Land Co., which consisted of approximately 30,000 acres in Lee County, Va. and Harlan County, Ky. As a result of the sale, during the six months ended June 30, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.

Net losses from discontinued operations for Coal Mining, excluding gain on disposal, were $1 million and $4 million for the three months ended June 30, 2008 and 2007, respectively, and $4 million and $8 million for the six months ended June 30, 2008 and 2007, respectively.

OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations are amounts related to our sales of other diversified businesses, primarily related to the sale of our natural gas drilling and production business (Gas) and the sale of Progress Rail Services Corporation (Progress Rail). These adjustments are mainly due to the finalization of working capital adjustments and adjustments in connection with guarantees and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters (See Note 13B). The ultimate resolution of these matters could result in additional adjustments in future periods. For the three and six months ended June 30, 2008, we recorded additional gains of $1 million and $2 million, respectively, net of tax. For each of the three and six months ended June 30, 2007, we recorded additional gains of $1 million, net of tax.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Progress Energy, Inc. is a holding company and, as such, has no revenue-generating operations of its own. Our primary cash needs at the Parent level are our common stock dividend and interest and principal payments on our $2.6 billion of senior unsecured debt. Our ability to meet these needs is dependent on the earnings and cash flows of the Utilities, and the ability of the Utilities to pay dividends or repay funds to us. As discussed under “Future Liquidity and Capital Resources” below, synthetic fuels tax credits provide an additional source of liquidity as those credits are realized. Our other significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations, including expenditures for environmental compliance. We rely upon our operating cash flow, substantially all of which is generated by the Utilities, commercial paper and bank facilities, and our ability to access the long-term debt and equity capital markets for sources of liquidity.

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

As a registered holding company, we are subject to regulation by the Federal Energy Regulatory Commission (FERC), including for the issuance and sale of securities as well as the establishment of intercompany extensions of credit (utility and non-utility money pools). PEC and PEF participate in the utility money pool, which allows the two utilities to lend to and borrow from each other. A non-utility money pool allows our nonregulated operations

75

to lend to and borrow from each other. The Parent can lend money to the utility and non-utility money pools but cannot borrow funds.

Cash from operations, short-term and long-term debt, limited ongoing equity sales from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans, and proceeds from the sale of the remainder of our nonregulated businesses completed in the first quarter, are expected to fund capital expenditures and common stock dividends for 2008. For the fiscal year 2008, we anticipate realizing an aggregate amount of approximately $300 million from the sale of stock through these plans.

We believe our internal and external liquidity resources will be sufficient to fund our current business plans. Risk factors associated with credit facilities and credit ratings are discussed in Item 1A, “Risk Factors” in the 2007 Form 10-K.

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

HISTORICAL FOR 2008 AS COMPARED TO 2007

CASH FLOWS FROM OPERATIONS

Cash from operations is the primary source used to meet operating requirements and capital expenditures. Net cash provided by operating activities increased by $1.180 billion for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to $448 million in income tax impacts, largely driven by the prior year costs to exit the Georgia Contracts and income tax payments related to the sale of Gas; the $401 million change in derivative collateral liabilities largely driven by the increase at PEF due to higher prices for fuel oil and natural gas; a $269 million increase from the change in accounts payable primarily due to the timing and volume of payments and purchases for fuel and purchased power at the Utilities; and the settlement of $247 million of derivative receivables primarily related to derivative contracts for our former synthetic fuels businesses (see Note 9A). These impacts were partially offset by a $246 million decrease in the recovery of fuel costs at PEF due to the current year under-recovery driven by rising fuel costs, compared to an over-recovery of fuel costs during the corresponding period in the prior year.

INVESTING ACTIVITIES

Net cash used by investing activities increased by $967 million for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. This is due primarily to a $582 million decrease in proceeds from sales of discontinued operations and other assets, net of cash divested; a $432 million increase in capital expenditures for utility property additions at PEF, partially offset by a $76 million decrease in utility property additions at PEC; and a $71 million decrease in net proceeds from short-term investments included in available-for-sale securities and other investments. These impacts were partially offset by a $54 million decrease in nuclear fuel additions. At PEF, the increase in utility property additions was primarily due to a $255 million increase in environmental compliance expenditures and a $157 million increase in nuclear project expenditures. Available-for-sale securities and other investments include marketable debt and equity securities and investments held in nuclear decommissioning and benefit investment trusts.

During the six months ended June 30, 2008, proceeds from sales of discontinued operations and other assets of $64 million primarily included proceeds from the sale of Terminals and Coal Mining (see Notes 3A and 3C). During the six months ended June 30, 2007, proceeds from sales of discontinued operations and other assets, net of cash divested, primarily included approximately $615 million from the sale of PVI’s CCO generation assets (See Note 3B), working capital adjustments for Gas, and the sale of poles at Progress Telecommunications Corporation.

FINANCING ACTIVITIES

Net cash provided by financing activities was $1.085 billion for the six months ended June 30, 2008, compared to net cash used by financing activities of $49 million for the six months ended June 30, 2007, for a net increase of $1.134 billion. The increase in net cash provided by financing activities was primarily due to PEF’s $1.476 billion net proceeds from issuance of long-term debt discussed below, partially offset by $176 million in payments on short-term debt, and $85 million in cash distributions to minority interests of consolidated subsidiaries primarily related to the settlement of Ceredo Synfuel LLC’s (Ceredo) synthetic fuels derivatives contracts (See Note 9A).

76

On January 8, 2008, PEF’s shelf registration statement became effective with the SEC. The registration statement initially allowed PEF to issue up to $4 billion in first mortgage bonds, debt securities and preferred stock in addition to $250 million of previously registered but unsold securities.

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

On March 12, 2008, PEC and PEF amended their revolving credit agreements (RCA) with a syndication of financial institutions to extend the termination date by one year. The extensions were effective for both utilities on March 28, 2008. PEC’s RCA is now scheduled to expire on June 28, 2011, and PEF’s RCA is now scheduled to expire on March 28, 2011.

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

On April 14, 2008, we amended our RCA with a syndication of financial institutions to extend the termination date by one year. The extension was effective on May 3, 2008. Our RCA is now scheduled to expire on May 3, 2012.

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

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

At December 31, 2007, we had 500 million shares of common stock authorized under our charter, of which 260 million shares were outstanding. For the three and six months ended June 30, 2008, respectively, we issued approximately 0.5 million shares and 1.0 million shares of common stock resulting in approximately $22 million and $42 million in proceeds. Included in these amounts were approximately 0.5 million shares and 0.9 million shares for proceeds of approximately $22 million and $41 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. For the three and six months ended June 30, 2007, respectively, we issued approximately 1.2 million shares and 2.7 million shares of common stock resulting in approximately $57 million and $122 million in proceeds. Included in these amounts were approximately 0.3 million shares and 0.5 million shares for proceeds of approximately $12 million and $23 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2008, 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 to the 2007 Form 10-K, other than as described below and under “Credit Rating Matters”, “Regulatory Matters and Recovery of Costs” and “Financing Activities.”

The Utilities produce substantially all of our consolidated cash from operations. We expect that the Utilities will continue to produce substantially all of the consolidated cash flows from operations over the next several years. Our synthetic fuels businesses, whose operations have been abandoned and reclassified to discontinued operations, have historically produced significant earnings from the generation of tax credits (See “Other Matters – Synthetic Fuels Tax Credits”). These tax credits have yet to be realized in cash due to the difference in timing of when tax credits are recognized for financial reporting purposes and realized for tax purposes. At June 30, 2008, we have carried forward $773 million of deferred tax credits. Realization of these tax credits is dependent upon our future taxable income, which is expected to be generated primarily by the Utilities.

77

With the exception of the proceeds in the first quarter of 2008 from the sale of Terminals and Coal Mining (See Notes 3A and 3C), the absence of cash flow resulting from divested businesses is not expected to impact our future liquidity or capital resources as these businesses in the aggregate have been largely cash flow neutral over the last several years.

Cash from operations plus availability under our credit facilities and shelf registration statements is expected to be sufficient to meet our requirements in the near term. To the extent necessary, we may also use limited ongoing equity sales from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans to meet our liquidity requirements.

We issue commercial paper to meet short-term liquidity needs. In the latter half of 2007, the short-term credit markets tightened, resulting in higher interest rate spreads and shorter durations. In the latter half of the first quarter of 2008 and continuing into the second quarter of 2008, the market has improved; however, there has been volatility on commercial paper spreads. If liquidity conditions deteriorate and negatively impact the commercial paper market, we will need to evaluate other, potentially more expensive, options for meeting our short-term liquidity needs, which may include borrowing from our RCAs, issuing short-term floating rate notes, and/or issuing long-term debt.

Progress Energy has approximately $11.0 billion in outstanding debt. Currently, $860 million of our Utility debt obligations are tax-exempt auction rate securities insured by bond insurance. Bond insurance generally allows companies to issue tax-exempt bonds with the insurance company’s higher credit rating. Ambac Assurance Corporation (Ambac) insures approximately $620 million of the bonds and XL Capital Assurance, Inc. (XL) insures the remaining $240 million. To date, auctions for the Utilities’ bonds have seen an increase in failures and the relative level of the interest rates that are periodically reset at each auction. In the event of a failed auction, the bond holders cannot sell their bonds and the interest rate is calculated based on a multiple of a standard market index such as the Securities Industry and Financial Markets Association’s Municipal Swap Index or the London Interbank Offer Rate (LIBOR). The multiple on our auction rate bonds is stable as long as the bonds are rated A3 or higher by Moody’s Investors Service, Inc. (Moody’s) or A- or higher by Standard & Poor’s Rating Services (S&P). If the insurance company’s rating falls below the Utilities’ ratings then the bonds will be rated at the Utilities’ senior secured debt rating, which is currently A2 by Moody’s and A- by S&P for both Utilities. The downgrades of XL in February 2008 by Moody’s and S&P caused an initial increase in market volatility and an increase in interest rates. When most auctions in the market began failing in late February 2008, we experienced higher interest rates due to failed auctions and the increase in the underlying indices supporting our reset interest rates. Since then, we are continuing to experience failed auctions, but the interest rates have decreased as the underlying indices have decreased. The June 2008 downgrades of XL by Moody’s and S&P to B2 and BBB-, respectively, and Ambac by Moody’s and S&P to Aa3 and AA, respectively, have not materially impacted the reset rates of the Utilities’ tax-exempt bonds. Volatility in the indices that support our interest rate resets and ratings downgrades that move our tax-exempt bonds below A3/A- could result in higher interest rate resets. We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

As discussed in “Capital Expenditures,” under LIQUIDITY AND CAPITAL RESOURCES and “Strategy” under INTRODUCTION in Item 7 to the 2007 Form 10-K and in “Other Matters – Environmental Matters” of this Form 10-Q, over the long term, compliance with environmental regulations and meeting the anticipated load growth at the Utilities as described under “Other Matters – Increasing Energy Demand” will require the Utilities to make significant capital investments. These anticipated capital investments are expected to be funded through a combination of cash from operations and issuance of long-term debt, preferred stock and common equity, which are dependent on our ability to successfully access capital markets. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation. As discussed in "Environmental Matters - Environmental Compliance Cost Estimates", we are evaluating the impact that the July 11, 2008 court decision vacating the Clean Air Interstate Rule (CAIR) will have on our compliance with other environmental regulations and will reassess our plans and estimated costs to comply.

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

78

At June 30, 2008, the current portion of our long-term debt was $850 million, which we expect to fund with a combination of cash from operations, investments, commercial paper borrowings and long-term debt.

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, as further discussed in Note 4 and “Other Matters – Regulatory Environment”, and filings for recovery of environmental costs, as discussed in Note 12 and in “Other Matters – Environmental Matters” of this filing and in Note 21 and in “Other Matters – Regulatory Environment” and “Other Matters – Environmental Matters” of the 2007 Form 10-K may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Developments since our 2007 Form 10-K are discussed below.

As discussed further in Note 4 and in “Other Matters – Regulatory Environment,” the Florida legislature passed comprehensive energy legislation that became law in 2008 and the South Carolina and North Carolina state legislatures passed energy legislation that became law in 2007. These laws may impact our liquidity over the long term. We cannot currently predict the impacts to our liquidity of complying with Florida’s comprehensive energy legislation.

Among other provisions, the North Carolina and South Carolina state energy laws provide mechanisms for recovery of certain baseload generation construction costs and expand annual fuel clause mechanisms so that additional costs may be recovered annually. On February 29, 2008, the North Carolina Utilities Commission (NCUC) issued an order adopting final rules for implementing North Carolina’s comprehensive energy legislation. Rates for the demand-side management (DSM) and energy-efficiency clause and the North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (REPS) clause will be set based on projected costs with true-up provisions.

PEC Pass-through Clause Cost Recovery

On June 26, 2008, the South Carolina Public Service Commission (SCPSC) approved PEC’s request for an increase in the fuel rate charged to its South Carolina ratepayers, which provided for a $39 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements and to meet future expected fuel costs. Residential electric bills increased by $5.86 per 1,000 kWh, or 6.1 percent, for fuel cost recovery effective July 1, 2008.

On June 6, 2008, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. PEC asked the NCUC to approve a $424 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements and to meet future expected fuel costs. In addition, in filings made on June 6, 2008, PEC asked the NCUC for approval of DSM and energy-efficiency and REPS clauses to recover the costs of these programs. If the filings are approved, the increases would take effect on or about December 1, 2008, and would increase residential electric bills in total by $15.71 per 1,000 kWh, or 16.2 percent. A hearing on the fuel filing has been scheduled by the NCUC for September 16, 2008, followed by hearings on the DSM and REPS filings on September 17, 2008. We cannot predict the outcome of this matter.

PEC has begun implementing a series of DSM and energy-efficiency programs and has deferred $4 million of implementation and program costs for future recovery. On April 29 and May 1, 2008, PEC filed for NCUC approval of a total of five DSM and energy-efficiency programs, including a distribution system demand response program. PEC anticipates that the distribution system demand response program will require an investment of approximately $260 million over five years. As discussed above, PEC has filed an application to recover the cost of the program. We cannot predict the outcome of these filings or whether the proposed programs will produce the expected operational and economic results.

On December 21, 2007, the SCPSC issued an order granting PEC’s petition seeking authorization to create a deferred account for DSM and energy-efficiency expenses. As a result, PEC has deferred an immaterial amount of implementation and program costs for future recovery in the South Carolina jurisdiction. On June 27, 2008, PEC filed an application with the SCPSC to establish procedures that encourage investment in cost-effective energy efficient technologies and energy conservation programs and approve the establishment of an annual rider to allow recovery for all costs associated with such programs as well as the recovery of appropriate incentives for investing in such programs. We cannot predict the outcome of this matter.

79

PEC Other Regulatory Matters

On April 30, 2008, PEC submitted a revised Open Access Transmission Tariff (OATT) filing, including a settlement agreement, with the FERC requesting an increase in transmission rates. The purpose of the filing was to implement formula rates for the PEC OATT in order to more accurately reflect the costs that PEC incurs in providing transmission service. In the filing, PEC proposed to move from a fixed revenue requirement to a formula rate, which allows for transmission rates to be updated each year based on the prior year’s actual costs. Settlement discussions were held with major customers prior to the filing and a settlement agreement was reached on all issues. The settlement proposed a formula rate with a rate of return on equity of 10.8 percent as well as recovery of the wholesale portion of the terminated GridSouth Transco, LLC (GridSouth) project startup costs over five years. On June 27, 2008, the FERC approved the settlement. The new rates were effective July 1, 2008, and PEC estimates the impact of the new rates will increase 2008 revenues by $6 million to $8 million.

PEF Pass-through Clause Cost Recovery

On October 10, 2007, the Florida Public Service Commission (FPSC) issued an order requiring PEF to refund its ratepayers approximately $14 million, including interest, over a 12-month period beginning January 1, 2008. Neither PEF nor Florida’s Office of the Public Counsel (OPC) filed an appeal to the Florida Supreme Court of the FPSC’s October 10, 2007 order. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for Crystal River Units No. 4 and 5 coal-fired steam turbines (CR4 and CR5). PEF believes its coal procurement practices have been prudent. We anticipate that a hearing will be held on the 2006 and 2007 coal purchases in 2009. We cannot predict the outcome of this matter.

On February 29, 2008, PEF filed a petition for recovery of costs incurred to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) in 2007 and 2006 under Florida’s comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule based on the regulatory precedence established by a FPSC order to an unaffiliated Florida utility for a nuclear uprate project. The FPSC is scheduled to vote on this matter by October 2008. We cannot predict the outcome of this matter.

On May 1, 2008, PEF filed with the FPSC for an increase in the capacity cost-recovery charge of estimated costs incurred in 2008 and projected costs to be incurred in 2009 under the FPSC nuclear cost-recovery rule. PEF is asking the FPSC to approve a $25 million increase in the capacity cost recovery rate for costs associated with the CR3 uprate. If approved, the increase would take effect with the first billing cycle for 2009 and would increase residential electric bills by $0.70 per 1,000 kWh. After PEF’s completion of a transmission study and additional engineering studies, the current project estimate of fully loaded costs is $364 million. A hearing on the matter has been scheduled by the FPSC for September 2008, and the FPSC is expected to vote on this matter by October 2008. We cannot predict the outcome of this matter.

On May 30, 2008, PEF filed a petition with the FPSC requesting a mid-course correction to its fuel cost recovery factors to recover an additional $213 million in 2008, primarily due to rising fuel costs. In accordance with a FPSC order, investor owned utilities must file a notice with the FPSC if the year-end projected over- or under-recovery of fuel costs is expected to be greater than 10% of projected fuel revenues. The mid-course correction would have resulted in a residential fuel rate increase of $12.07 per 1,000 kWh for the period August through December 2008. On July 1, 2008, the FPSC approved recovery of the $213 million projected year-end under-recovery, but allowed PEF to recover 50 percent in 2008 and 50 percent in 2009. Therefore, the increase in the fuel rate for the period August through December 2008 is $6.03 per 1,000 kWh. This increase is partially offset by the expiration of PEF’s storm cost recovery surcharge of $3.61 per 1,000 kWh effective August 2008. Consequently, beginning with the first billing cycle in August and including gross receipts tax, residential electric bills will increase by $2.48 per 1,000 kWh, or 2.29 percent.

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of distribution and substation transformers, which were estimated to be $29 million at June 30, 2008. Additionally, on November 6, 2006, the FPSC approved PEF’s petition for its integrated strategy to address compliance with the CAIR, the Clean Air Mercury Rule (CAMR) and the Clean Air Visibility Rule (CAVR) through the ECRC. The FPSC also approved cost recovery of prudently incurred costs necessary to achieve this

80

strategy, which are currently estimated to be $1.2 billion for in-process CAIR projects (see “Other Matters – Environmental Matters” for discussion regarding the CAIR, CAMR and CAVR).

Nuclear Cost Recovery

The FPSC approved new rules on February 13, 2007, that allow PEF to recover prudently incurred siting, preconstruction costs and AFUDC on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in PEF’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility.

As discussed further in Note 4 and “Other Matters – Nuclear”, on July 15, 2008, the FPSC voted unanimously in favor of PEF’s need certification petition for its proposed Levy Units 1 and 2 nuclear power plants, together with the associated facilities, including transmission lines and substation facilities. The filed, non-binding project cost estimate for Levy Units 1 and 2 is approximately $14 billion for generating facilities and approximately $3 billion for associated transmission facilities. On March 11, 2008, PEF also filed a petition with the FPSC to open a discovery docket regarding the actual and projected costs of the proposed Levy nuclear project. PEF filed the petition to assist the FPSC in the timely and adequate review of the projects costs recoverable under the FPSC nuclear cost-recovery rule. On May 1, 2008, PEF filed a petition for recovery of both preconstruction and carrying charges on construction costs incurred or anticipated to be incurred during 2008 and 2009. Additionally, the filing included site selection costs of $38 million. Based on the affirmative vote by the FPSC in the Determination of Need on the Levy nuclear project, PEF filed a petition on July 18, 2008, to recover all prudently incurred costs under the FPSC nuclear cost-recovery rule. A decision by the FPSC on PEF’s 2008 cost-recovery filing is expected by October 1, 2008. We cannot predict the outcome of this matter.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include standby letters of credit, surety bonds, performance obligations for trading operations and guarantees of certain subsidiary credit obligations. At June 30, 2008, we have issued $385 million of guarantees for future financial or performance assurance, including $11 million at PEC and $2 million at PEF. Included in this amount is $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries issued by the Parent (See Note 14). We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

At June 30, 2008, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations (See Note 13B).

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

81

CONTRACTUAL OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2007 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. The commitment amounts discussed below are estimates and therefore, actual purchase amounts will likely differ. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs.

PROGRESS ENERGY

Through June 30, 2008, contracts procured though our subsidiaries have increased our aggregate purchase obligations for fuel and purchased power by $9.214 billion from $17.644 billion, as stated in Note 22A in the 2007 Form 10-K. In March 2008, PEC issued long-term debt totaling $325 million. In June 2008, PEF issued long-term debt totaling $1.500 billion. These increases are discussed under “PEC” and “PEF” below.

PEC

Through June 30, 2008, PEC’s fuel and purchased power commitments increased by $5.697 billion from $5.078 billion, as stated in Note 22A in the 2007 Form 10-K. This increase is primarily related to coal purchase commitments, of which approximately $3.199 billion will be incurred through 2012, with the remainder incurred through 2018. The increase in coal purchase commitments includes new contracts along with the impact of price increases on certain existing contracts that are market price indexed.

In June 2008, PEC entered into a conditional contract with an interstate pipeline for firm pipeline transportation capacity to support PEC’s gas supply needs for the period from May 2011 through April 2031. The estimated total cost to PEC associated with this agreement is approximately $461 million. The transaction is subject to several conditions precedent, including various state regulatory approvals, the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions, and other contractual provisions. Due to the conditions of this agreement, the estimated costs associated with this agreement are not included in the increase in PEC’s fuel and purchased power commitments discussed above.

On March 13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due 2038 (See Note 6).

PEF

Through June 30, 2008, PEF’s fuel and purchased power commitments increased by $3.517 billion from $12.566 billion, as stated in Note 22A in the 2007 Form 10-K. Approximately $1.689 billion of this increase is due to coal purchase commitments, of which approximately $588 million will be incurred through 2012, with the remainder incurred through 2030. The increase in coal purchase commitments includes new contracts along with the impact of price increases on certain existing contracts that are market price indexed. Additionally, approximately $1.398 billion of the increase is due to the impact of rising natural gas prices under a long-term gas supply agreement that was entered into in December 2004. Approximately $216 million of this increase will be incurred through 2012, with the remainder incurred through 2027. Payments under this agreement are based on a published market price index. Contractual obligations under this contract are based on estimated future market prices.

In April 2008, PEF entered into a conditional contract with Florida Gas Transmission Company, L.L.C. (FGT) for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with this agreement is estimated to be approximately $2.000 billion. The transaction is subject to several conditions precedent, including various state regulatory approvals, the completion and commencement of operation of necessary related interstate natural pipeline system expansions, and other contractual provisions. In addition to the FGT contract, during the second quarter of 2008, PEF entered into additional gas supply and transportation arrangements for the period from 2010 through 2025 that are subject to certain conditions. The total current notional cost of these additional agreements is estimated to be approximately $1.390 billion. Due to the conditions of these agreements, the estimated costs associated with these agreements are not included in the increase in PEF’s fuel and purchased power commitments discussed above.

82

On June 18, 2008, PEF issued $500 million of First Mortgage Bonds, 5.65% Series due 2018 and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038 (See Note 6).

OTHER MATTERS

SYNTHETIC FUELS TAX CREDITS

Prior to 2008, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Internal Revenue Code (the Code) (Section 29) and as redesignated effective 2006 as Section 45K of the Code (Section 45K and collectively, Section 29/45K) as discussed below. The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied, including a requirement that the synthetic fuels differ significantly in chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced from a facility that was placed in service before July 1, 1998. Qualifying synthetic fuels facilities entitled their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The tax credits associated with synthetic fuels in a particular year were phased out when annual average market prices for crude oil exceeded certain prices. The synthetic fuels tax credit program expired at the end of 2007.

TAX CREDITS

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

Total Section 29/45K credits generated through December 31, 2007 (including those generated by Florida Progress prior to our acquisition), were $1.891 billion. As of June 30, 2008, $1.118 billion of tax credits had been used to offset regular federal income tax liability and $773 million are being carried forward as deferred tax credits.

IMPACT OF CRUDE OIL PRICES

Section 29 provided that if the average wellhead price per barrel for unregulated domestic crude oil for the year (Annual Average Price) exceeded a certain threshold value (the Threshold Price), the amount of Section 29/45K tax credits were reduced for that year. Also, if the Annual Average Price exceeded the price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits were fully eliminated (Phase-out Price), the Section 29/45K tax credits were eliminated for that year. The Threshold Price and the Phase-out Price were adjusted annually for inflation.

When the Annual Average Price fell between the Threshold Price and the Phase-out Price for a year, the amount by which Section 29/45K tax credits were reduced depended on where the Annual Average Price fell in that continuum. The Department of the Treasury calculated the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA published its information on a three-month lag, the secretary of the Treasury finalized the calculations three months after the year in question ended. Thus, the Annual Average Price for calendar year 2007 was published on April 1, 2008. Based on the Annual Average Price for calendar year 2007 of $66.52, our $205 million of synthetic fuels tax credits generated during 2007 were reduced by 67 percent, or approximately $138 million.

In January 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge instruments was 25 million barrels and provided protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production and was marked-to-market with changes in fair value recorded through earnings. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed below in “Sales of Partnership Interests” and in Notes 1C and 3F, we disposed of our 100 percent ownership interest in Ceredo in

83

March 2007. For the three months ended June 30, 2007, we recorded net pre-tax losses of $14 million related to these contracts, including $5 million attributable to Ceredo which was attributed to minority interest for the portion of the loss subsequent to disposal. For the six months ended June 30, 2007, we recorded net pre-tax gains of $31 million related to these contracts, including $10 million attributable to Ceredo, of which losses of $5 million were attributed to minority interest for the portion of the loss subsequent to disposal. The derivative contracts ended on December 31, 2007, and were settled for cash on January 8, 2008, with no material impact on 2008 earnings.

SALES OF PARTNERSHIP INTERESTS

In March 2007, we disposed of, through our subsidiary Progress Fuels, our 100 percent ownership interest in Ceredo, a subsidiary that produced and sold qualifying coal-based solid synthetic fuels, to a third-party buyer. In addition, we entered into an agreement to operate the Ceredo facility on behalf of the buyer. At closing, we received cash proceeds of $10 million and a non-recourse note receivable of $54 million. Payments on the note were received as we produced and sold qualifying coal-based solid synthetic fuels on behalf of the buyer. We received final payment on the note related to 2007 production of $5 million during the three months ended March 31, 2008. The total amount of the proceeds was subject to adjustment once the final value of the 2007 Section 29/45K credits was known. This adjustment resulted in a $7 million reduction of the purchase price during the three months ended March 31, 2008. For the six months ended June 30, 2008, we recorded gains on disposal of $5 million based on the value of the 2007 Section 29/45K tax credits. The operations of Ceredo were reclassified to discontinued operations, net of tax on the Consolidated Statements of Income. Subsequent to the disposal, we remain the primary beneficiary of Ceredo and consolidate Ceredo in accordance with FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51”, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there was no net earnings impact from Ceredo’s operations, which ceased as of December 31, 2007. In connection with the disposal, Progress Fuels and Progress Energy provided guarantees and indemnifications for certain legal and tax matters to the buyer, which reduces any gain. The ultimate resolution of these matters could result in adjustments to the gain on disposal in future periods. See Note 3F for additional discussion of this transaction and Note 13B for a general discussion of guarantees.

See Note 13C for additional discussion related to our synthetic fuels businesses.

REGULATORY ENVIRONMENT

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

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

The retail rate matters affected by state regulatory authorities are discussed in detail in Notes 4A and 4B. This discussion identifies specific retail rate matters, the status of the issues and the associated effects on our consolidated financial statements.

During the 2008 session, the Florida legislature passed comprehensive energy legislation, which became law on June 26, 2008. The legislation includes provisions that would, among other things, (1) help enhance the ability to cost-effectively site transmission lines; (2) require the FPSC to develop a renewable portfolio standard that the FPSC would present to the legislature for ratification in 2009; (3) direct the Florida Department of Environmental Protection (FDEP) to develop rules establishing a cap and trade program to regulate greenhouse gas emissions that the FDEP would present to the legislature no earlier than January 2010 for ratification by the legislature; (4) establish a new Florida Energy and Climate Commission as the principal governmental body to develop energy and climate policy for the State and to make recommendations to the governor and legislature on energy and climate issues; and (5) require the FPSC to analyze utility revenue decoupling and provide a report and recommendation to

84

the Governor and legislature by January 1, 2009. PEF would be able to recover its reasonable prudent compliance costs. Until the rulemaking processes are completed, we cannot predict the costs of complying with the law.

During 2007, the North Carolina legislature passed comprehensive energy legislation, which became law on August 20, 2007. The law includes provisions for renewable energy portfolio standards, expansion of the definition of the traditional fuel clause and recovery of the costs of new DSM and energy-efficiency programs through an annual DSM clause.

On February 29, 2008, the NCUC issued an order adopting final rules for implementing North Carolina’s comprehensive energy legislation. These rules provide filing requirements associated with the legislation. The order requires PEC to submit its first annual REPS compliance plan by September 1, 2008, as part of its integrated resource plan. Under the new rules, beginning in 2009, PEC will also be required to file an annual REPS compliance report demonstrating the actions it has taken to comply with the REPS requirement. The rules measure compliance with the REPS requirement via renewable energy certificates (REC) earned after January 1, 2008. The NCUC will pursue a third-party REC tracking system, but will not develop or require participation in a REC trading platform at this time. The order also establishes a schedule and filing requirements for DSM and energy-efficiency cost recovery and financial incentives. Rates for the DSM and energy-efficiency clause and the REPS clause will be set based on projected costs with true-up provisions. On April 29 and May 1, 2008, PEC filed for NCUC approval of a total of five DSM and energy-efficiency programs, including the EnergyWise™ and distribution system demand response programs discussed below.

On April 29, 2008, PEC filed for approval by the NCUC of its EnergyWise™ program, which is a residential program that offers customers an incentive to permit PEC to remotely adjust central air conditioning and heat pumps in PEC’s eastern control area and electric resistance heating and water heaters in PEC’s western control area in order to reduce peak demand. PEC’s goal for EnergyWise™ is to have the capability to reduce peak electricity demand by 200 MW by 2017.

Also on April 29, 2008, PEC filed for NCUC approval of its distribution system demand response program, which will provide additional capability for reducing and shifting peak electricity demand. The program also will reduce the level of natural electricity loss experienced over long distribution feeder lines, thereby eliminating the need for additional power generation to compensate for the line losses. PEC anticipates that the program will require an investment of approximately $260 million over five years and is expected to reduce peak electricity demand by 250 MW. This distribution system investment is part of PEC’s broader “Smart Grid” strategy and is expected to provide a foundation for additional initiatives, including enhanced system reliability (through faster outage isolation and response) and new capabilities for incorporating renewable energy resources and other distributed generation into PEC’s energy mix. Such costs are expected to be recovered under the provisions of the North Carolina comprehensive energy legislation. A hearing for the application for approval of the proposed distribution system demand response program has been scheduled by the NCUC for September 17, 2008.

We cannot predict the outcome of the April 29 and May 1, 2008 filings or whether the proposed programs will produce the expected operational and economic results.

On July 13, 2007, the governor of Florida issued executive orders to address reduction of greenhouse gas emissions. The executive orders call for the first Southeastern state cap-and-trade program and include adoption of a maximum allowable emissions level of greenhouse gases for Florida utilities. The standard will require, at a minimum, the following three reduction milestones: by 2017, emissions not greater than Year 2000 utility sector emissions; by 2025, emissions not greater than Year 1990 utility sector emissions; and by 2050, emissions not greater than 20 percent of Year 1990 utility sector emissions.

Among other things, the executive orders also requested that the FPSC initiate a rulemaking by September 1, 2007 that would (1) require Florida utilities to produce at least 20 percent of their electricity from renewable sources; (2) reduce the cost of connecting solar and other renewable energy technologies to Florida’s power grid by adopting uniform statewide interconnection standards for all utilities; and (3) authorize a uniform, statewide method to enable residential and commercial customers, who generate electricity from on-site renewable technologies of up to 1 MW in capacity, to offset their consumption over a billing period by allowing their electric meters to turn backwards when they generate electricity (net metering). The FPSC has held meetings regarding the renewable portfolio

85

standard but no actions have been taken or rules issued. The Energy and Climate Action Team appointed by the governor submitted its initial recommendations for implementation of the governor’s executive orders on November 1, 2007. The recommendations encourage the development and implementation of energy-efficiency and conservation measures, implementation of a climate registry, and consideration of a cap-and-trade approach to reducing the state’s greenhouse gas emissions. Additional development and discussion of the recommendations will occur through a stakeholder process in 2008.The FDEP held its first workshop on the greenhouse gas emissions cap on August 22, 2007, but we anticipate drafts of the rule to be issued later in 2008. We cannot currently predict the costs of complying with the laws and regulations that may ultimately result from these executive orders. Our balanced solution, as described in “Increasing Energy Demand,” includes greater investment in energy efficiency, renewable energy and state-of-the-art generation and demonstrates our commitment to environmental responsibility.

LEGAL

We are subject to federal, state and local legislation and court orders. The specific issues, the status of the issues, accruals associated with issue resolutions and our associated exposures are discussed in detail in Note 13C.

INCREASING ENERGY DEMAND

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

We are actively pursuing expansion of our energy-efficiency and conservation programs as energy efficiency is one of the most effective ways to reduce energy costs, offset the need for new power plants and protect the environment. Our energy-efficiency program provides simple, low-cost options for residential customers to reduce energy use, promotes home energy checks, provides tools and programs for large and small businesses to minimize their energy use and provides an interactive internet Web site with online calculators, programs and efficiency tips.

We are actively engaged in a variety of alternative energy projects, including solar, hydrogen, biomass and landfill-gas technologies. We are evaluating the feasibility of producing electricity from hog waste and other plant or animal sources.

In the coming years, we will continue to invest in existing plants and consider plans for building new generating plants. Due to the anticipated long-term growth in our service territories, we estimate that we will require new generation facilities in both Florida and the Carolinas toward the end of the next decade, and we are evaluating the best available options for this generation, including advanced design nuclear and gas technologies. At this time, no definitive decisions have been made to construct new nuclear plants. While we pursue expansion of energy- efficiency and conservation programs, PEC announced in 2007 a two-year moratorium on constructing new coal-fired plants and that if PEC goes ahead with a new nuclear plant, the new plant would not be online until at least 2018 (see “Nuclear” below).

As authorized under the Energy Policy Act of 2005 (EPACT), on October 4, 2007, the United States Department of Energy (DOE) published final regulations for the disbursement of up to $13 billion in loan guarantees for clean-energy projects using innovative technologies. The guarantees, which will cover up to 100 percent of the amount of any loan for no more than 80 percent of the project cost, are expected to spur development of nuclear, clean-coal and ethanol projects.

In 2008, Congress authorized $38.5 billion in loan guarantee authority for innovative energy projects. Of the total provided, $18.5 billion is set aside for nuclear power facilities, $2 billion for advanced nuclear facilities for the "front-end" of the nuclear fuel cycle, $10 billion for renewable and/or energy efficient systems and manufacturing and distributed energy generation/transmission and distribution, $6 billion for coal-based power generation and industrial gasification at retrofitted and new facilities that incorporate carbon capture and sequestration or other beneficial uses of carbon and $2 billion for advanced coal gasification. We cannot predict if we will pursue these loan guarantees.

86

In June 2008, the DOE announced solicitations for a total of up to $30.5 billion of the amount authorized by Congress in federal loan guarantees for projects that employ advanced energy technologies that avoid, reduce or sequester air pollutants or greenhouse gas emissions and advanced nuclear facilities for the “front-end” of the nuclear fuel cycle.

NUCLEAR

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

On November 14, 2006, PEC filed an application with the NRC for a 20-year extension of the Shearon Harris Nuclear Plant (Harris) operating license. The license renewal application for Harris is currently under review by the NRC with a decision expected in 2008.

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

We previously announced that we are pursuing development of combined license (COL) applications to potentially construct new nuclear plants in North Carolina and Florida. Filing of a COL application is not a commitment to build a nuclear plant but is a necessary step to keep open the option of building a plant or plants. The NRC estimates that it will take approximately three to four years to review and process the COL applications.

On January 23, 2006, we announced that PEC selected a site at Harris to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. On February 19, 2008, PEC filed its COL application with the NRC for two additional reactors at Harris. On April 17, 2008, the NRC docketed, or accepted for review, the Harris application. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will issue the license. On June 4, 2008, the NRC published the Petition for Leave to Intervene. Petitions to intervene may be filed within 60 days of the notice by anyone whose interest may be affected by the proposed license and who wishes to participate as a party in the proceeding. One petition to intervene was filed with the NRC within the 60-day notice period. We cannot predict the outcome of this matter. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, a new plant would not be online until at least 2018 (See “Increasing Energy Demand” above).

On December 12, 2006, we announced that PEF selected a site in Levy County, Fla., to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application submission. On July 30, 2008, PEF filed its COL application with the NRC for two reactors. In 2007, PEF completed the purchase of approximately 5,000 acres for the Levy County site and associated transmission needs. PEF filed a Determination of Need petition with the FPSC on March 11, 2008. The hearing was held on May 21-23, 2008, and the FPSC voted unanimously in favor of the Determination of Need on July 15, 2008. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, safety-related construction activities could begin as early as 2012, and a new plant could be online in 2016 (See “Increasing Energy Demand” above).

In 2007, both the Levy County Planning Commission and the Board of Commissioners voted unanimously in favor of PEF’s requests to change the comprehensive land use plan. The Florida Department of Community Affairs (FDCA) reviewed the proposed changes to the comprehensive land use plan and in their report, the FDCA expressed concerns related to the intensity of use and environmental suitability for some of the proposed amendments impacting PEF’s proposed Levy County nuclear site. We anticipate that the Levy County Planning Commission will resolve the FDCA’s concerns without impact to the potential project schedule. We cannot predict the outcome of this matter.

In addition, PEF filed its application for Site Certification with the FDEP on June 2, 2008. A decision on PEF’s FDEP Site Certification Application is expected in 2009.

87

On March 11, 2008, PEF also filed a petition with the FPSC to open a discovery docket regarding the actual and projected costs of the proposed Levy nuclear project. PEF filed the petition to assist the FPSC in the timely and adequate review of the projects costs recoverable under the FPSC nuclear cost-recovery rule. On May 1, 2008, PEF filed a petition for recovery of both preconstruction and carrying charges on construction costs incurred or anticipated to be incurred during 2008 and 2009. Additionally, the filing included site selection costs of $38 million. Based on the affirmative vote by the FPSC on the Determination of Need for the Levy nuclear project, PEF filed a petition on July 18, 2008, to recover all prudently incurred costs under the FPSC nuclear cost-recovery rule. A decision by the FPSC on PEF’s 2008 cost-recovery filing is expected by October 1, 2008. We cannot predict the outcome of this matter.

PEF signed a letter of intent dated March 28, 2008, with the Shaw Group Inc. and Westinghouse Electric Co. to complete negotiations toward an engineering, procurement and construction (EPC) agreement for up to two Westinghouse AP1000 nuclear reactors planned for construction at the Levy County, Fla. site. The letter of intent authorizes the purchase of long-lead materials for the reactors. In 2008, PEF has made payments toward long-lead equipment related to the EPC agreement. At this time, no definitive decisions have been made to construct new nuclear plants.

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

In accordance with provisions of Florida’s energy legislation enacted in 2006, the FPSC ordered new rules in December 2006 that would allow investor-owned utilities such as PEF to request recovery of certain planning and construction costs of a nuclear power plant prior to commercial operation. The FPSC issued a final rule on February 13, 2007, under which utilities will be allowed to recover prudently incurred siting, preconstruction costs and AFUDC on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in a utility’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule will require the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility. Also, on February 1, 2007, the FPSC amended its power plant bid rules to, among other things, exempt nuclear power plants from existing bid requirements.

In 2007, the South Carolina legislature ratified new energy legislation, which includes provisions for cost-recovery mechanisms associated with nuclear baseload generation. In 2007, the North Carolina legislature also passed new energy legislation, which authorizes the NCUC to allow annual prudence reviews of baseload generating plant construction costs and removes the requirement that a public utility prove financial distress before it may include construction work in progress in rate base and adjust rates, accordingly, in a general rate case while a baseload generating plant is under construction (See “Other Matters – Regulatory Environment”).

ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations.

88

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, the state of Florida or potentially responsible parties (PRP) groups. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 4 and 12). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of these potential claims cannot be predicted. No material claims are currently pending. Hazardous and solid waste management matters are discussed in detail in Note 12A.

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

AIR QUALITY AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which likely would result in increased capital expenditures and O&M expenses. Additionally, Congress is considering legislation that would require additional reductions in air emissions of nitrogen oxides (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 multipollutant approach to air pollution control could involve significant capital costs that could be material to our financial position or results of operations. Control equipment that is installed pursuant to the provisions of the Clean Smokestacks Act, the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR) and mercury regulation, which are discussed below, may address some of the issues outlined above. PEC and PEF have each been developing an integrated compliance strategy to meet the requirements of the CAIR, CAVR and mercury regulation (see discussion of the court decisions that impacted the CAIR, the delisting determination and the Clean Air Mercury Rule (CAMR) below). The CAVR requires the installation of best available retrofit technology (BART) on certain units. However, the outcome of these matters cannot be predicted.

Clean Smokestacks Act

In 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 5,000 MW of coal-fired generation capacity in North Carolina that is affected by the Clean Smokestacks Act. In March 2008, PEC filed its annual estimate with the NCUC of the total capital expenditures to meet emission targets under the Clean Smokestacks Act by the end of 2013, which were approximately $1.5 billion to $1.6 billion at the time of the filing. The increase in estimated total capital expenditures from the original 2002 estimate of $813 million is primarily due to the higher cost and revised quantities of construction materials, such as concrete and steel, refinement of cost and scope estimates for the current projects, increases in the estimated inflation factor applied to future project costs, and the impact of additional planning for Sutton Unit No. 3 and Cape Fear Units No. 5 and No. 6. We are continuing to evaluate various design, technology and new generation options that could further change expenditures required by the Clean Smokestacks Act. Changes in projected fuel sources may require us to incur costs, which are not currently estimable, to install additional controls subsequent to 2013 in order to remain compliant with the requirements of the Clean Smokestacks Act. O&M expenses will significantly increase due to the cost of reagents, additional personnel and general maintenance associated with the pollution control equipment. Recent legislation in North

89

Carolina and South Carolina expanded the traditional fuel clause to include the annual recovery of reagents and certain other costs; all other O&M expenses are currently recoverable through base rates. See discussion regarding future recovery of costs to comply with the Clean Smokestacks Act in Note 4A. We cannot predict the outcome of this matter.

Two of PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. In 2005, PEC entered into an agreement with the joint owner to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 12B).

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

Clean Air Interstate Rule

On March 10, 2005, the EPA issued the final CAIR. The EPA’s rule required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions in order to reduce levels of fine particulate matter and impacts to visibility. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2. States were required to adopt rules implementing the CAIR and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR in 2007.

PEF joined a coalition of Florida utilities that filed a challenge to the CAIR as it applied to Florida. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) issued its decision on multiple challenges to the CAIR, including the Florida challenge, which vacated the CAIR in its entirety. The Court will not issue its mandate for at least 45 days following the date of the decision, pending whether petitions for rehearing are submitted and granted. The outcome of this matter cannot be predicted.

The Utilities are considering continuing construction of in-process CAIR projects. We believe our historical costs related to CAIR compliance are prudent and will be recoverable under base rates or applicable cost recovery clauses as the costs were incurred in pursuit of compliance with a mandatory law or regulation. Although the Utilities have not made a final determination whether to continue the in-process CAIR projects or whether the schedule for these projects should be modified, it is likely that they will be completed. In making this decision, the Utilities will take into account the status of the projects, the probability of regulatory changes to replace the vacated CAIR requirements and the need to comply with environmental rules and regulations other than the CAIR.

We account for emission allowances as inventory using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As a result of the decision to vacate the CAIR, the SO2 and annual NOx emission allowances markets have been very volatile andthe market prices for emission allowances have declined. At June 30, 2008, PEC had approximately $1 million in NOx seasonal emission allowances, which will be utilized to comply with existing requirements for the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call), and approximately $29 million in SO2 emission allowances, which will be utilized to comply with existing Clean Air Act requirements. PEC currently has no purchased CAIR seasonal or annual NOx allowances in its emission inventory balances. In order to achieve compliance with the requirements of the CAIR pursuant to its Integrated Clean Air Compliance Plan, PEF needed to purchase CAIR seasonal and annual NOx allowances. At June 30, 2008, PEF had approximately $59 million in annual NOx emission allowance inventory, approximately $7 million in seasonal NOx emission allowance inventory and approximately $18 million in SO2 emission allowance inventory. PEF believes the purchases of NOx emission allowances to comply with the requirements of the CAIR were prudent and continues to expect to recover the costs of these allowances through its ECRC. PEF’s SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements.

90

Clean Air Mercury Rule

On March 15, 2005, the EPA finalized two separate but related rules: the CAMR that set mercury emissions limits to be met in two phases beginning in 2010 and 2018, respectively, and encouraged a cap-and-trade approach to achieving those caps, and a delisting rule that eliminated any requirement to pursue a maximum achievable control technology approach for limiting mercury emissions from coal-fired power plants. Sixteen states subsequently petitioned for a review of the EPA’s determination confirming the delisting. On February 8, 2008, the D. C. Court of Appeals decided in favor of the petitioners and vacated the delisting determination and the CAMR. On March 24, 2008, the EPA and the Utility Air Regulatory Group, of which PEC and PEF are members, filed petitions for rehearing by the full court of appeals, which were denied on May 20, 2008. The three states in which the Utilities operate adopted mercury regulations implementing CAMR and submitted their state implementation rules to the EPA. It is uncertain how the decision that vacated the federal CAMR and the petitions for rehearing will affect the state rules; however, state-specific provisions are likely to remain in effect. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. The outcome of this matter cannot be predicted.

Clean Air Visibility Rule

On June 15, 2005, the EPA issued the final CAVR. The EPA’s rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in 156 specially protected areas, including national parks and wilderness areas, designated as Class I areas. To help restore visibility in those areas, states must require the identified facilities to install BART to control their emissions. PEC’s BART-eligible units are Asheville Units No. 1 and No. 2, Roxboro Units No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Units No. 1 and No. 2, Bartow Unit No. 3 and Crystal River Units No. 1 and No. 2. The reductions associated with BART begin in 2013. The CAVR included the EPA’s determination that compliance with the NOx and SO2 requirements of the CAIR could be used by states as a BART substitute to fulfill BART obligations, but the states could require the installation of additional air quality controls if they did not achieve reasonable progress in improving visibility. The decision vacating the CAIR will negate the EPA's determination that implementation of the CAIR satisfies BART for SO2 and NOx for BART-affected units under the CAVR. As a result, for BART-affected units, CAVR compliance will require consideration of NOx and SO2 emissions in addition to particulate matter emissions. As a result, BART for SO2 and NOx may now specifically apply to PEC's and PEF's affected units. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. On December 4, 2007, the FDEP finalized a Regional Haze implementation rule that requires sources significantly impacting visibility in Class I areas to install additional controls by December 31, 2017. However, the FDEP has not determined the level of additional controls PEF may have to implement. The outcome of these matters cannot be predicted.

Compliance Strategy

Both PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, CAVR and mercury regulation. The air quality controls installed to comply with the NOx SIP Call and Clean Smokestacks Act resulted in a reduction of the costs to meet the CAIR requirements for our North Carolina units at PEC.

PEC has completed installation of controls to meet the NOx SIP Call requirements. The NOx SIP Call is not applicable to Florida. Expenditures for the NOx SIP Call included the cost to install NOx controls under North Carolina’s and South Carolina’s programs to comply with the federal eight-hour ozone standard.

On October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs associated with the development and implementation of an Integrated Clean Air Compliance Plan to comply with the CAIR, CAMR and CAVR through the ECRC (see discussion above regarding the vacating of the CAIR and CAMR). On March 31, 2006, PEF filed a series of compliance alternatives with the FPSC to meet these federal environmental rules. At the time, PEF’s recommended proposed compliance plan included approximately $740 million of estimated capital costs expected to be spent through 2016, to plan, design, build and install pollution control equipment at the Anclote and Crystal River plants. On November 6, 2006, the FPSC approved PEF’s petition for its integrated strategy to address compliance with the CAIR, CAMR and CAVR. They also approved cost recovery of prudently incurred costs necessary to achieve this strategy. On June 1, 2007, PEF filed a supplemental petition for approval of its

91

recommended compliance plan and associated contracts and recovery of costs for air pollution control projects. The estimated capital cost for the recommended plan was $1.26 billion in the June 1, 2007 filing. The increase from the estimates filed in March 2006 is primarily due to the higher cost of labor and construction materials, such as concrete and steel, and refinement of cost and scope estimates for the current projects. On April 2, 2008, PEF filed a petition for approval true-up of final environmental costs for the period January 2007 to December 2007 and a review of the integrated clean air compliance plan, which reconfirmed the efficacy of the recommended plan. Additional costs may be incurred if pollution controls are required in order to comply with the requirements of the CAVR, as discussed above, or to meet compliance requirements of a revised or new implementing rule for clean air. Subsequent rule interpretations, increases in the underlying material, labor and equipment costs, equipment availability, or the unexpected acceleration of compliance dates, among other things, could result in significant increases in our estimated costs to comply and acceleration of some projects. The outcome of this matter cannot be predicted.

Environmental Compliance Cost Estimates

Environmental compliance cost estimates are dependent upon a variety of factors and as such are highly uncertain and subject to change. Factors impacting our environmental compliance cost estimates include new and frequently changing laws and regulations; the impact of legal decisions on environmental laws and regulations; changes in the demand for, supply of and costs of labor and materials; changes in the scope and timing of projects; various design, technology and new generation options; and projections of fuel sources, prices, availability and security. The following tables contain information about our current estimates of capital expenditures to comply with environmental laws and regulations described above. Costs to comply with environmental laws and regulations are eligible for regulatory recovery through either base rates or cost-recovery clauses. The outcome of future petitions for recovery cannot be predicted. Our estimates of capital expenditures to comply with environmental laws and regulations are subject to periodic review and revision and may vary significantly. We are evaluating the impact that vacating the CAIR will have on our compliance with the CAVR requirements and will reassess our plans and estimated costs to comply with the CAVR. Our previous estimated costs to comply with the CAVR were approximately $100 million at PEC and $1.0 billion at PEF. The timing and extent of the costs for future projects will depend upon final compliance strategies.

Progress Energy
Air and Water Quality Estimated Required Environmental Expenditures  (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through June 30, 2008
Clean Smokestacks Act		2002–2013	$	1,500 – 1,600	$	958
In-process CAIR projects(a)		2005–2010		1,200		639
CAVR(b)		–2017		–		–
Mercury regulation(c)		2006–2017		–		4
Total air quality				2,700 – 2,800		1,601
Clean Water Act Section 316(b) (d)				–		–
Total air and water quality			$	2,700 – 2,800	$	1,601

PEC
Air and Water Quality Estimated Required Environmental Expenditures  (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through June 30, 2008
Clean Smokestacks Act		2002–2013	$	1,500 – 1,600	$	958
In-process CAIR projects(a)		2005–2008		–		14
CAVR(b)		–2017		–		–
Mercury regulation(c)		2006–2017		–		4
Total air quality				1,500 – 1,600		976
Clean Water Act Section 316(b) (d)				–		–
Total air and water quality			$	1,500 – 1,600	$	976

92

PEF
Air and Water Quality Estimated Required Environmental Expenditures  (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through June 30, 2008
In-process CAIR projects(a)		2005–2010	$	1,200	$	625
CAVR(b)		–2017		–		–
Mercury regulation(c)				–		–
Total air quality				1,200		625
Clean Water Act Section 316(b) (d)				–		–
Total air and water quality			$	1,200	$	625

(a) The Utilities are considering continuing construction on in-process CAIR projects. Additional compliance plans to meet the requirements of a revised or new implementing rule will be determined upon finalization of the rule. See discussion under “Clean Air Interstate Rule.”

(b) As a result of the decision vacating the CAIR, compliance plans and costs to meet the requirements of the CAVR are being reassessed. See discussion under “Clean Air Visibility Rule.”

(c) Compliance plans to meet the requirements of a revised or new implementing rule will be determined upon finalization of the rule. See discussion under “Clean Air Mercury Rule.”

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

To date, under the first phase of Clean Smokestacks Act emission reductions, all environmental compliance projects at PEC’s Asheville and Lee plants and several projects at PEC’s Roxboro plant have been placed in service. The remaining projects at PEC’s two largest plants, Roxboro and Mayo, are under construction and are expected to be completed in 2008 and 2009, respectively. The remaining projects to comply with the second phase of emission reductions, which are smaller in scope, have not yet begun. These estimates are conceptual in nature and subject to change. As discussed above, our Clean Smokestacks Act compliance costs have increased from December 31, 2007.PEC's in-process CAIR project is not expected to require additional material expenditures. However, additional compliance projects requiring material environmental compliance costs may be implemented in the future.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects under construction at CR5 and CR4, which are expected to be placed in service in 2009 and 2010, respectively. As a result of changes in the scope of work related to estimation of costs for compliance with the CAIR and the court decisions that vacated the CAIR, the delisting determination and the CAMR discussed above, PEF is currently unable to estimate certain costs of compliance and consequently, its estimated total air and water quality compliance expenditures have decreased from December 31, 2007. However, PEF believes that future costs to comply with new or subsequent rule interpretations could be significant. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when those new regulations are finalized.

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 the 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 D.C. Court of Appeals seeking a review of the agency’s final action on the petition. This case is being held in abeyance until the challenges to the CAIR have been resolved. The outcome of this matter cannot be predicted.

National Ambient Air Quality Standards

On December 21, 2005, the EPA announced proposed changes to the National Ambient Air Quality Standards (NAAQS) for particulate matter. The EPA proposed to lower the 24-hour standard for particulate matter less than

93

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

On March 12, 2008, the EPA announced changes to the NAAQS for ground-level ozone. The EPA revised the 8-hour primary and secondary standards from 0.08 parts per million to 0.075 parts per million. Depending on air quality improvements expected over the next several years as current federal requirements are implemented, additional nonattainment areas may be designated in PEC’s and PEF’s service territories. Should additional nonattainment areas be designated in our service territories, we may be required to install additional emission controls at some of our facilities. On May 27, 2008, a number of states, environmental groups and industry associations filed petitions against the revised NAAQS in the D.C. Court of Appeals. The outcome of this matter cannot be predicted.

On May 20, 2008, the EPA proposed a revision to the NAAQS for lead to a level in the 0.10 to 0.30 micrograms per cubic meter range. The current standard is 1.5 micrograms per cubic meter, calendar quarter average. The EPA is also requesting comment on the averaging time options of calendar quarter or monthly. The outcome of this matter cannot be predicted; however, the proposed revision is not expected to have a material impact on our or the Utilities results of operations or financial position.

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 has undertaken civil enforcement actions against unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements requiring expenditures by these unaffiliated utilities, several of which were 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.

Water Quality

1. General

As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on the Utilities in the immediate and extended future.

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

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

94

Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued an opinion and order remanding many provisions of the rule to the EPA. On July 9, 2007, the EPA suspended the rule pending further rulemaking, with the exception of the requirement that permitted facilities must meet any requirements under Section 316(b) as determined by the permitting authorities on a case-by-case, best professional judgment basis. On April 14, 2008, the U.S. Supreme Court agreed to review a portion of the U.S. Court of Appeals decision and hear arguments related to whether the EPA is authorized to compare costs with benefits in determining the “best technology available for minimizing adverse environmental impact” at cooling water intake structures. As a result of these developments, our plans and associated estimated costs to comply with Section 316(b) will need to be reassessed and determined in accordance with any revised or new implementing rule once it is established by the EPA. Costs of compliance with a new implementing rule are expected to be higher, and could be significantly higher, than estimated costs under the July 2004 rule. Our most recent cost estimates to comply with the July 2004 implementing rule were $60 million to $90 million, including $5 million to $10 million at PEC and $55 million to $80 million at PEF. The outcome of this matter cannot be predicted.

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. There are proposals and ongoing studies at the state and federal levels, including the state of Florida, to address global climate change that would regulate CO2 and other greenhouse gases. See further discussion of the executive orders issued by the governor of Florida to address reduction of greenhouse gas emissions under “Other Matters – Regulatory Environment.”

Reductions in CO2 emissions to the levels specified by the Kyoto Protocol and some additional proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from ratepayers. The cost impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time. As discussed under “Other Matters – Regulatory Environment”, in 2008 the state of Florida passed comprehensive energy legislation, which includes a directive that the FDEP develop rules to establish a cap and trade program to regulate greenhouse gas emissions that would be presented to the legislature no earlier than January 2010. 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 action on this important issue as discussed under “Other Matters – Increasing Energy Demand.” In addition to a report issued in 2006, we issued an updated report on global climate change in the second quarter of 2008, which further evaluates and states our position on this dynamic issue. 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.

On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority under the Clean Air Act to regulate CO2 emissions from new automobiles. On April 2, 2008, 18 states and 11 environmental groups filed an action in the D. C. Circuit Court against the EPA Administrator seeking an order requiring EPA to make a determination within 60 days of whether greenhouse gas emissions endanger public health and welfare. The D. C. Circuit Court denied the petition on June 26, 2008. On July 11, 2008, the EPA issued an Advance Notice of Proposed Rulemaking inviting public comment on the issues and options that should be considered in development of comprehensive greenhouse gas regulation under the Clean Air Act. The impact of these developments cannot be predicted.

NEW ACCOUNTING STANDARDS

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

95

PEC

The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q and Item 1A, “Risk Factors” to the 2007 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

RESULTS OF OPERATIONS

This information is incorporated herein by reference to “Results of Operations” in Progress Energy’s MD&A, insofar as it relates to PEC.

LIQUIDITY AND CAPITAL RESOURCES

This information is incorporated herein by reference to “Liquidity and Capital Resources” in Progress Energy’s MD&A, insofar as it relates to PEC.

Cash provided by operating activities increased $109 million for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to the $75 million increase from the change in accounts payable largely driven by the timing and volume of payments and purchases for fuel and the $60 million increase from payables to affiliated companies primarily related to timing of settlements with affiliates.

Cash used by investing activities increased $8 million for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. The increase in cash used in investing activities was primarily due to a $63 million change in advances to affiliated companies and a $50 million decrease in net proceeds from short-term investments included in available-for-sale securities and other investments. These impacts were partially offset by a $76 million decrease in utility property additions, primarily related to lower environmental compliance expenditures, and a $33 million decrease in 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.

Net cash used by financing activities increased by $85 million for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. The increase in net cash used by financing activities was due primarily to a $159 million decrease related to advances from affiliates, partially offset by the $72 million in dividends paid to the Parent in 2007. PEC’s 2008 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources”.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

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 9 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

This information is incorporated herein by reference to “Contractual Obligations” in Progress Energy’s MD&A, insofar as it relates to PEC.

96

OTHER MATTERS

This information is incorporated herein by reference to “Other Matters” in Progress Energy’s MD&A, insofar as it relates to PEC.

97

PEF

The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q and Item 1A, “Risk Factors” to the 2007 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

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

RESULTS OF OPERATIONS

This information is incorporated herein by reference to “Results of Operations” in Progress Energy’s MD&A, insofar as it relates to PEF.

LIQUIDITY AND CAPITAL RESOURCES

This information is incorporated herein by reference to “Liquidity and Capital Resources” in Progress Energy’s MD&A, insofar as it relates to PEF.

Cash provided by operating activities increased $107 million for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to the $409 million change in derivative collateral liabilities largely driven by increases in the prices of fuel oil and natural gas, and a $133 million increase from the change in accounts payable primarily due to the timing and volume of payments and purchases for fuel and purchased power. These impacts were partially offset by a $246 million decrease in the recovery of fuel costs due to the current year under-recovery driven by rising fuel costs, compared to an over-recovery of fuel costs during the corresponding period in the prior year; a $107 million decrease from prepayments and other current assets primarily related to derivative collateral; and a $52 million decrease from the change in receivables driven by the timing of receipts and increased revenues.

Cash used by investing activities increased $254 million for the six months ended June 30, 2008, when compared to the corresponding period in the prior year. The increase in cash used in investing activities was primarily due to a $432 million increase in capital expenditures for utility property additions, including a $255 million increase in environmental compliance expenditures and a $157 million increase in nuclear project expenditures, partially offset by a $149 million decrease from changes in advances to affiliated companies.

Net cash provided by financing activities was $1.436 billion for the six months ended June 30, 2008, compared to net cash used by financing activities of $45 million for the six months ended June 30, 2007, for a net increase of $1.481 billion. The increase in cash provided by financing activities was primarily due to PEF’s $1.476 billion net proceeds from issuance of long-term debt as described under Progress Energy’s MD&A, “Liquidity and Capital Resources”.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

MARKET RISK AND DERIVATIVES

Under its risk management policy, PEF may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 9 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

This information is incorporated herein by reference to “Contractual Obligations” in Progress Energy’s MD&A, insofar as it relates to PEF.

98

OTHER MATTERS

This information is incorporated herein by reference to “Other Matters” in Progress Energy’s MD&A, insofar as it relates to PEF.

99

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various risks related to changes in market conditions. Market risk represents the potential loss arising from adverse changes in market rates and prices. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk to the extent that the counterparty fails to perform under the contract. We mitigate such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties (See Note 9).

The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors” included within this Form 10-Q and Item 1A, “Risk Factors” to the 2007 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

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

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

PROGRESS ENERGY

Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2007.

INTEREST RATE RISK

Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at June 30, 2008, has changed from December 31, 2007. The total notional amount of fixed rate long-term debt at June 30, 2008, was $9.345 billion, with an average interest rate of 6.17% and fair market value of $9.5 billion. The total notional amount of fixed rate long-term debt at December 31, 2007, was $7.947 billion, with an average interest rate of 6.20% and fair market value of $8.2 billion. The total notional amount of variable rate long-term debt at June 30, 2008, was $1.411 billion, with an average interest rate of 3.45% and fair market value of $1.4 billion. The total notional amount of variable rate long-term debt at December 31, 2007, was $1.411 billion, with an average interest rate of 4.80% and fair market value of $1.4 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, 2008 and December 31, 2007, approximately 15 percent of consolidated debt was in floating rate mode, including interest rate swaps.

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

The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. We only enter into interest rate derivative agreements with banks with credit ratings of single A or better.

100

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

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), interest rate derivatives that qualify as hedges are separated into one of two categories, cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest rate changes.

The following tables summarize the terms, fair market values and exposures of our interest rate derivative instruments.

CASH FLOW HEDGES

PEC had no open interest rate cash flow hedges at June 30, 2008. At December 31, 2007, PEC had $200 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions. Under terms of these swap agreements, we will pay a fixed rate and receive a floating rate based on the 3-month LIBOR. PEF and the Parent had no open interest rate cash flow hedges at June 30, 2008, and December 31, 2007.

(dollars in millions)	Notional Amount		Pay			Receive (a)	Fair Value			Exposure (b)
PEC
Risk hedged at June 30, 2008	None
Risk hedged at December 31, 2007
Anticipated 10-year debt issue (c)	$	100		5.32	%	3-month LIBOR	$	(5	)	$	(2	)
Anticipated 30-year debt issue (d)		100		5.50	%	3-month LIBOR		(7	)		(4	)
Total	$	200		5.41	%		$	(12	)	$	(6	)

(a) 3-month LIBOR rate was 4.70% at December 31, 2007.

(b) Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.

(c) Anticipated 10-year debt issue hedges were terminated on March 10, 2008, in conjunction with PEC’s issuance of $325 million 6.30% First Mortgage Bonds.

(d) Anticipated 30-year debt issue hedges were terminated on March 10, 2008, in conjunction with PEC’s issuance of $325 million 6.30% First Mortgage Bonds.

During 2008, PEF entered into a series of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. On January 8, 2008, PEF entered into a $100 million notional 10-year forward starting swap and a $100 million notional 30-year forward starting swap. On May 1, 2008, PEF entered into a $50 million notional 10-year forward starting swap and a $100 million notional 30-year forward starting swap. On May 16, 2008, PEF entered into a $50 million notional 10-year forward starting swap and a $50 million notional 30-year forward starting swap. On June 2, 2008, PEF entered into a $50 million notional 30-year forward starting swap. On June 3, 2008, PEF entered into a $50 million notional 30-year forward starting swap. On June 11, 2008, PEF terminated the anticipated 10-year and 30-year debt issue hedges in conjunction with PEF’s issuance of $500 million 5.65% 10-year First Mortgage Bonds and $1.000 billion 6.40% 30-year First Mortgage Bonds.

MARKETABLE SECURITIES PRICE RISK

At June 30, 2008 and December 31, 2007, the fair value of our nuclear decommissioning trust funds was $1.302 billion and $1.384 billion, respectively, including $767 million and $804 million, respectively, for PEC and $535 million and $580 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.

101

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, 2008 and December 31, 2007, the fair value of CVOs was $36 million and $34 million, respectively. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analysis performed on the CVOs uses quoted prices obtained from brokers or quote services to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. A hypothetical 10 percent increase in the June 30, 2008, market price would result in a $4 million increase in the fair value of the CVOs.

COMMODITY PRICE RISK

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

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

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments that are not subject to retail regulatory treatment. At June 30, 2008, substantially all derivative commodity instrument positions were subject to retail regulatory treatment.

See Note 9 for additional information with regard to our commodity contracts and use of derivative financial instruments.

DISCONTINUED OPERATIONS

In January 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge instruments was 25 million barrels and provided protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts were marked-to-market with changes in fair value recorded through earnings. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed in Notes 1C and 3F, we disposed of our 100 percent ownership interest in Ceredo in March 2007. Progress Energy remains the primary beneficiary of, and consolidates Ceredo in accordance with FIN 46R, with a 100 percent minority interest. Consequently, subsequent to the disposal there was no net earnings impact from Ceredo’s operations, which ceased as of December 31, 2007. At December 31, 2007, the $234 million fair value of these contracts, including $79 million at Ceredo, was included in receivables, net on the Consolidated Balance Sheet. The contracts ended on December 31, 2007, and were settled for cash on January 8, 2008, with no material impact to 2008 earnings. For the three months ended June 30, 2007, we recorded net pre-tax losses of $14 million related to these contracts, including $5 million attributable to Ceredo, which was attributed to minority interest for the portion of the loss subsequent to disposal. For the six months ended June 30, 2007, we recorded net pre-tax gains of $31 million related to these contracts, including $10 million attributable to Ceredo, of which losses of $5 million were attributed to minority interest for the portion of the loss subsequent to disposal.

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

102

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

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets on the Balance Sheets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause. During the three and six months ended June 30, 2008, PEC recorded a net realized gain of $6 million. During the three and six months ended June 30, 2007, PEC recorded a net realized loss of less than $1 million. During the three and six months ended June 30, 2008, PEF recorded net realized gains of $103 million and $119 million, respectively. During the three and six months ended June 30, 2007, PEF recorded net realized losses of $5 million and $22 million, respectively.

The December 31, 2007 balances presented below reflect the retrospective adoption of FSP FIN 39-1 (See Note 2).

At June 30, 2008, the fair value of PEC’s commodity derivative instruments was recorded as a $42 million short-term derivative asset position included in prepayments and other current assets and a $113 million long-term derivative asset position included in derivative assets on the PEC Consolidated Balance Sheet. At December 31, 2007, the fair value of such instruments were recorded as a $4 million short-term derivative liability included in other current liabilities and a $19 million long-term derivative asset position included in derivative assets on the PEC Consolidated Balance Sheet. Certain counterparties have posted cash collateral with PEC in support of these instruments. PEC had an $11 million cash collateral liability at June 30, 2008, included in other current liabilities on the PEC Consolidated Balance sheet, and no cash collateral position at December 31, 2007.

At June 30, 2008, the fair value of PEF’s commodity derivative instruments was recorded as a $478 million short-term derivative asset position included in current derivative assets, a $504 million long-term derivative asset position included in derivative assets, a $2 million short-term liability position included in derivative liabilities, and a $1 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. At December 31, 2007, the fair value of such instruments were recorded as an $83 million short-term derivative asset position included in current derivative assets, a $100 million long-term derivative asset position included in derivative assets, a $38 million short-term liability position included in derivative liabilities, and a $9 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. Certain counterparties have posted cash collateral with PEF in support of these instruments. PEF had a $409 million cash collateral liability at June 30, 2008, included in derivative collateral liabilities on the PEF Balance Sheet, and no cash collateral position at December 31, 2007.

CASH FLOW HEDGES

PEC designates a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. At June 30, 2008 and December 31, 2007, neither we nor the Utilities had material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for the three and six months ended June 30, 2008 and 2007.

At June 30, 2008 and December 31, 2007, neither we nor the Utilities had amounts recorded in accumulated other comprehensive income related to commodity cash flow hedges.

103

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, 2007.

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).

104

ITEM 4.CONTROLS AND PROCEDURES

PROGRESS ENERGY

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

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2008, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES 

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, 2008, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

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

There has been no change in PEF’s internal control over financial reporting during the quarter ended June 30, 2008, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

105

PART II.  OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 13C).

ITEM 1A.RISKFACTORS

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 to the 2007 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in the 2007 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.

With the 2008 divestiture of Terminals and Coal Mining, we are no longer subject to operational and financial risks from operating nonregulated businesses as disclosed in the 2007 Form 10-K.

ITEM 2.                      UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a)   Securities Delivered. On June 30, 2008, 1,018 shares of our common stock were delivered to a former employee pursuant to the terms of the Progress Energy 2002 Equity Incentive Plan (EIP), which was approved by the Progress Energy’s shareholders on May 8, 2002. Additionally, on June 23, 2008, 262 shares of our common stock were delivered to a current employee pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

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

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

ISSUER PURCHASES OF EQUITY SECURITIES FOR SECOND QUARTER OF 2008

No purchases of our common stock were made by or on behalf of Progress Energy pursuant to a publicly announced plan or otherwise during the period ended June 30, 2008.

106

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 14, 2008.

(b)   The meeting involved the election of twelve directors for one-year terms. 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 total votes for the election of directors were as follows:

Director	Shares Voted For	Shares Voted Against	Shares Abstaining
James E. Bostic, Jr.	212,031,798	2,884,311	3,152,163
David L. Burner	211,680,031	3,236,751	3,151,490
Harris E. DeLoach, Jr.	211,250,636	3,652,473	3,165,163
William D. Johnson	211,529,523	3,404,311	3,134,438
Robert W. Jones	211,665,570	3,245,676	3,157,026
W. Steven Jones	211,424,984	3,454,718	3,188,570
E. Marie McKee	198,152,557	16,746,374	3,169,341
John H. Mullin, III	211,524,715	3,347,779	3,195,778
Charles W. Pryor, Jr.	211,786,481	3,114,968	3,166,823
Carlos A. Saladrigas	211,884,374	3,030,450	3,153,448
Theresa M. Stone	211,783,964	2,666,624	3,617,684
Alfred C. Tollison, Jr.	211,755,092	3,156,595	3,156,585

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 213,254,479

The number of shares voted against the proposal was 2,095,923

The number of abstaining votes was 2,717,870

The shareholder proposal relating to the policy regarding executive compensation was rejected by the shareholders.

The number of shares voted for the proposal was 68,199,339

The number of shares voted against the proposal was 96,451,104

The number of abstaining votes was 6,668,829

The number of broker non-votes was 46,749,000

PEC

(a)   The Annual Meeting of the Shareholders of Carolina Power & Light Company was held on May 14, 2008.

(b)   The meeting involved the election of two Class I directors (term expiring in 2011). 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 total votes for the election of directors were as follows:

Director	Votes For	Votes Withheld
Class I (Term Expiring in 2011)
John R. McArthur	160,107,236	2,506
Peter M. Scott III	160,107,083	2,659

107

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 160,107,981

The number of shares voted against the proposal was 591

The number of abstaining votes was 1,170

108

ITEM 6.      EXHIBITS

(a)   Exhibits

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

109

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 d/b/a PROGRESS ENERGY CAROLINAS, INC.
	FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
Date: August 8, 2008	(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 d/b/a Progress Energy Carolinas, Inc.
	Florida Power Corporation d/b/a Progress Energy Florida, Inc.

110