UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 October 31, 2008, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	263,087,236
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 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
Ambac	Ambac Assurance Corporation
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

DSDR DSM	Distribution system demand response 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 No. FIN 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts”
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Gas	Natural gas drilling and production business
the Georgia Contracts	Full-requirements contracts with 16 Georgia electric membership cooperatives formerly serviced by CCO
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Operations	Former reporting unit consisting of the Effingham, Monroe, Walton and Washington nonregulated generation plants in service and the Georgia Contracts
Global	U.S. Global, LLC
GridSouth	GridSouth Transco, LLC
Gulfstream	Gulfstream Gas System, L.L.C.
Harris	PEC’s Shearon Harris Nuclear Plant
IBEW	International Brotherhood of Electrical Workers
IRS	Internal Revenue Service
kV	Kilovolt
kVA	Kilovolt-ampere
kWh	Kilowatt-hours
Level 3 Communications	Level 3 Communications, Inc.
LIBOR	London Interbank Offered 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
MGP	Manufactured gas plant

5

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	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
RPS	Renewable portfolio standard
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”
SIFMA	Securities Industry and Financial Markets Association’s Municipal Swap Index

7

SNG	Southern Natural Gas Company
SO2	Sulfur dioxide
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Syncora	Syncora Guarantee Inc., formerly XL Capital Assurance, Inc.
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
Ward	Ward Transformer site located in Raleigh, N.C.
Ward OU1	Operable unit for stream segments downstream from the Ward site
Ward OU2	Operable unit for further investigation at the Ward facility and certain adjacent areas
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 length and severity of the current financial market distress that began in September 2008; the ability to successfully access capital markets on favorable terms; the stability of commercial credit markets and our access to short-term and long-term credit; 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

September 30, 2008

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended September 30,						Nine months ended September 30,
(in millions except per share data)	2008			2007			2008			2007
Operating revenues	$	2,696		$	2,750		$	7,006		$	6,951
Operating expenses
Fuel used in electric generation		869			929			2,262			2,381
Purchased power		450			390			1,012			894
Operation and maintenance		439			456			1,370			1,337
Depreciation and amortization		205			223			619			665
Taxes other than on income		141			135			387			384
Other		1			7			(6	)		28
Total operating expenses		2,105			2,140			5,644			5,689
Operating income		591			610			1,362			1,262
Other income (expense)
Interest income		8			6			20			20
Allowance for equity funds used during construction		34			14			84			34
Other, net		(7	)		(5	)		(9	)		(6	)
Total other income, net		35			15			95			48
Interest charges
Interest charges		178			159			493			443
Allowance for borrowed funds used during construction		(11	)		(5	)		(27	)		(12	)
Total interest charges, net		167			154			466			431
Income from continuing operations before income tax and minority interest		459			471			991			879
Income tax expense		150			160			329			273
Income from continuing operations before minority interest		309			311			662			606
Minority interest in subsidiaries’ income, net of tax		(1	)		–			(5	)		(8	)
Income from continuing operations		308			311			657			598
Discontinued operations, net of tax		1			8			66			(197	)
Net income	$	309		$	319		$	723		$	401
Average common shares outstanding – basic		261			257			260			256
Basic earnings per common share
Income from continuing operations	$	1.18		$	1.21		$	2.52		$	2.34
Discontinued operations, net of tax		0.01			0.03			0.26			(0.77	)
Net income	$	1.19		$	1.24		$	2.78		$	1.57
Diluted earnings per common share
Income from continuing operations	$	1.18		$	1.21		$	2.52		$	2.33
Discontinued operations, net of tax		–			0.03			0.26			(0.77	)
Net income	$	1.18		$	1.24		$	2.78		$	1.56
Dividends declared per common share	$	0.615		$	0.610		$	1.845		$	1.830

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

10

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2008			December 31, 2007
ASSETS
Utility plant
Utility plant in service	$	25,987		$	25,327
Accumulated depreciation		(11,208	)		(10,895	)
Utility plant in service, net		14,779			14,432
Held for future use		38			37
Construction work in progress		2,672			1,765
Nuclear fuel, net of amortization		426			371
Total utility plant, net		17,915			16,605
Current assets
Cash and cash equivalents		403			255
Receivables, net		996			1,167
Inventory		1,117			994
Deferred fuel cost		291			154
Derivative assets		64			85
Assets to be divested		–			52
Prepayments and other current assets		278			122
Total current assets		3,149			2,829
Deferred debits and other assets
Regulatory assets		1,347			946
Nuclear decommissioning trust funds		1,210			1,384
Miscellaneous other property and investments		460			448
Goodwill		3,655			3,655
Derivative assets		109			119
Other assets and deferred debits		392			379
Total deferred debits and other assets		7,173			6,931
Total assets	$	28,237		$	26,365
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 263 million and 260 million shares issued and outstanding, respectively	$	6,173		$	6,028
Unearned ESOP shares (1 million and 2 million shares, respectively)		(25	)		(37	)
Accumulated other comprehensive loss		(26	)		(34	)
Retained earnings		2,705			2,465
Total common stock equity		8,827			8,422
Preferred stock of subsidiaries – not subject to mandatory redemption		93			93
Minority interest		6			84
Long-term debt, affiliate		272			271
Long-term debt, net		9,886			8,466
Total capitalization		19,084			17,336
Current liabilities
Current portion of long-term debt		400			877
Short-term debt		495			201
Accounts payable		944			819
Interest accrued		144			173
Dividends declared		162			160
Customer deposits		272			255
Regulatory liabilities		15			173
Liabilities to be divested		–			8
Other current liabilities		635			636
Total current liabilities		3,067			3,302
Deferred credits and other liabilities
Noncurrent income tax liabilities		726			361
Accumulated deferred investment tax credits		130			139
Regulatory liabilities		2,457			2,554
Asset retirement obligations		1,437			1,378
Accrued pension and other benefits		761			763
Capital lease obligations		231			239
Other liabilities and deferred credits		344			293
Total deferred credits and other liabilities		6,086			5,727
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	28,237		$	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)
Nine months ended September 30	2008			2007
Operating activities
Net income	$	723		$	401
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		703			756
Deferred income taxes and investment tax credits, net		270			157
Deferred fuel (credit) cost		(330	)		28
Deferred income		–			(98	)
Allowance for equity funds used during construction		(84	)		(34	)
Other adjustments to net income		29			127
Cash provided (used) by changes in operating assets and liabilities
Receivables		150			(153	)
Inventory		(124	)		(14	)
Prepayments and other current assets		26			(73	)
Income taxes, net		(92	)		(343	)
Accounts payable		181			63
Other current liabilities		(24	)		103
Other assets and deferred debits		(62	)		(148	)
Other liabilities and deferred credits		(7	)		(34	)
Net cash provided by operating activities		1,359			738
Investing activities
Gross property additions		(1,760	)		(1,411	)
Nuclear fuel additions		(158	)		(198	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		63			658
Purchases of available-for-sale securities and other investments		(1,190	)		(1,072	)
Proceeds from sales of available-for-sale securities and other investments		1,154			939
Other investing activities		(3	)		16
Net cash used by investing activities		(1,894	)		(1,068	)
Financing activities
Issuance of common stock		106			134
Dividends paid on common stock		(481	)		(469	)
Payments of short-term debt with original maturities greater than 90 days		(176	)		–
Net increase in short-term debt		470			550
Proceeds from issuance of long-term debt, net		1,797			742
Retirement of long-term debt		(877	)		(287	)
Cash distributions to minority interests of consolidated subsidiaries		(85	)		(10	)
Other financing activities		(71	)		22
Net cash provided by financing activities		683			682
Net increase in cash and cash equivalents		148			352
Cash and cash equivalents at beginning of period		255			265
Cash and cash equivalents at end of period	$	403		$	617
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)		198			(14	)
Accrued property additions		266			239

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

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CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2008

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended September 30,						Nine months ended September 30,
(in millions)	2008			2007			2008			2007
Operating revenues	$	1,266		$	1,286		$	3,382		$	3,340
Operating expenses
Fuel used in electric generation		348			385			1,027			1,041
Purchased power		145			109			266			243
Operation and maintenance		243			246			766			762
Depreciation and amortization		124			118			379			353
Taxes other than on income		53			52			152			151
Other		–			1			(6	)		–
Total operating expenses		913			911			2,584			2,550
Operating income		353			375			798			790
Other income (expense)
Interest income		2			5			9			16
Allowance for equity funds used during construction		9			2			19			7
Other, net		(5	)		(3	)		–			2
Total other income, net		6			4			28			25
Interest charges
Interest charges		54			58			164			169
Allowance for borrowed funds used during construction		(4	)		(2	)		(8	)		(4	)
Total interest charges, net		50			56			156			165
Income before income tax		309			323			670			650
Income tax expense		108			119			242			234
Net income		201			204			428			416
Preferred stock dividend requirement		1			1			2			2
Earnings for common stock	$	200		$	203		$	426		$	414

See Notes to PEC Unaudited Condensed Consolidated Interim Financial Statements.

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CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2008			December 31, 2007
ASSETS
Utility plant
Utility plant in service	$	15,491		$	15,117
Accumulated depreciation		(7,292	)		(7,097	)
Utility plant in service, net		8,199			8,020
Held for future use		3			2
Construction work in progress		641			566
Nuclear fuel, net of amortization		331			292
Total utility plant, net		9,174			8,880
Current assets
Cash and cash equivalents		145			25
Receivables, net		532			491
Receivables from affiliated companies		19			42
Inventory		573			510
Deferred fuel cost		143			148
Prepayments and other current assets		53			50
Total current assets		1,465			1,266
Deferred debits and other assets
Regulatory assets		769			680
Nuclear decommissioning trust funds		723			804
Miscellaneous other property and investments		197			192
Other assets and deferred debits		164			160
Total deferred debits and other assets		1,853			1,836
Total assets	$	12,492		$	11,982
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,079		$	2,054
Unearned ESOP common stock		(25	)		(37	)
Accumulated other comprehensive loss		(13	)		(10	)
Retained earnings		2,200			1,772
Total common stock equity		4,241			3,779
Preferred stock – not subject to mandatory redemption		59			59
Long-term debt, net		3,109			3,183
Total capitalization		7,409			7,021
Current liabilities
Current portion of long-term debt		400			300
Notes payable to affiliated companies		1			154
Accounts payable		354			308
Payables to affiliated companies		71			71
Interest accrued		52			58
Customer deposits		79			70
Other current liabilities		229			209
Total current liabilities		1,186			1,170
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,065			936
Accumulated deferred investment tax credits		117			122
Regulatory liabilities		1,053			1,098
Asset retirement obligations		1,109			1,063
Accrued pension and other benefits		448			459
Other liabilities and deferred credits		105			113
Total deferred credits and other liabilities		3,897			3,791
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	12,492		$	11,982

See Notes to PEC Unaudited Condensed Consolidated Interim Financial Statements.

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CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2008			2007
Operating activities
Net income	$	428		$	416
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		454			419
Deferred income taxes and investment tax credits, net		113			62
Deferred fuel (credit) cost		(30	)		7
Allowance for equity funds used during construction		(19	)		(7	)
Other adjustments to net income		42			(30	)
Cash (used) provided by changes in operating assets and liabilities
Receivables		(48	)		(65	)
Receivables from affiliated companies		23			(34	)
Inventory		(55	)		(2	)
Prepayments and other current assets		23			(2	)
Income taxes, net		(35	)		64
Accounts payable		48			19
Payables to affiliated companies		–			23
Other current liabilities		47			13
Other assets and deferred debits		(7	)		(19	)
Other liabilities and deferred credits		(52	)		11
Net cash provided by operating activities		932			875
Investing activities
Gross property additions		(518	)		(587	)
Nuclear fuel additions		(131	)		(159	)
Purchases of available-for-sale securities and other investments		(464	)		(472	)
Proceeds from sales of available-for-sale securities and other investments		433			498
Other investing activities		3			3
Net cash used by investing activities		(677	)		(717	)
Financing activities
Dividends paid on preferred stock		(2	)		(2	)
Dividends paid to parent		–			(108	)
Net increase in short-term debt		–			150
Proceeds from issuance of long-term debt, net		322			–
Retirement of long-term debt		(300	)		(200	)
Changes in advances from affiliated companies		(153	)		–
Other financing activities		(2	)		20
Net cash used by financing activities		(135	)		(140	)
Net increase in cash and cash equivalents		120			18
Cash and cash equivalents at beginning of period		25			71
Cash and cash equivalents at end of period	$	145		$	89
Supplemental disclosures
Significant noncash transactions
Nuclear decommissioning trust funds unrealized loss (gain)	$	104		$	(9	)
Accrued property additions		87			74

See Notes to PEC Unaudited Condensed Consolidated Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

September 30, 2008

UNAUDITED CONDENSED STATEMENTS of INCOME
	Three months ended September 30,						Nine months endedSeptember 30,
(in millions)	2008			2007			2008			2007
Operating revenues	$	1,428		$	1,456		$	3,618		$	3,596
Operating expenses
Fuel used in electric generation		521			544			1,235			1,340
Purchased power		305			281			746			651
Operation and maintenance		201			213			621			586
Depreciation and amortization		77			100			229			297
Taxes other than on income		88			83			235			233
Other		–			–			(4	)		12
Total operating expenses		1,192			1,221			3,062			3,119
Operating income		236			235			556			477
Other income (expense)
Interest income		5			1			7			3
Allowance for equity funds used during construction		25			12			65			27
Other, net		–			–			(1	)		–
Total other income, net		30			13			71			30
Interest charges
Interest charges		68			45			163			126
Allowance for borrowed funds used during construction		(7	)		(3	)		(19	)		(8	)
Total interest charges, net		61			42			144			118
Income before income tax		205			206			483			389
Income tax expense		62			68			148			122
Net income		143			138			335			267
Preferred stock dividend requirement		–			–			1			1
Earnings for common stock	$	143		$	138		$	334		$	266

See Notes to PEF Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	September 30, 2008			December 31, 2007
ASSETS
Utility plant
Utility plant in service	$	10,312		$	10,025
Accumulated depreciation		(3,854	)		(3,738	)
Utility plant in service, net		6,458			6,287
Held for future use		35			35
Construction work in progress		2,031			1,199
Nuclear fuel, net of amortization		95			79
Total utility plant, net		8,619			7,600
Current assets
Cash and cash equivalents		223			23
Receivables, net		460			351
Receivables from affiliated companies		9			8
Notes receivable from affiliated companies		–			149
Inventory		544			484
Deferred income taxes		71			39
Derivative assets		59			83
Prepayments and other current assets		175			50
Total current assets		1,541			1,187
Deferred debits and other assets
Regulatory assets		578			266
Nuclear decommissioning trust funds		487			580
Miscellaneous other property and investments		43			46
Derivative assets		90			100
Prepaid pension cost		240			221
Other assets and deferred debits		60			63
Total deferred debits and other assets		1,498			1,276
Total assets	$	11,658		$	10,063
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,115		$	1,109
Accumulated other comprehensive loss		–			(8	)
Retained earnings		2,234			1,901
Total common stock equity		3,349			3,002
Preferred stock – not subject to mandatory redemption		34			34
Long-term debt, net		4,182			2,686
Total capitalization		7,565			5,722
Current liabilities
Current portion of long-term debt		–			532
Notes payable to affiliated companies		2			–
Accounts payable		571			473
Payables to affiliated companies		49			87
Interest accrued		51			57
Customer deposits		193			185
Derivative liabilities		133			38
Regulatory liabilities		15			173
Other current liabilities		195			92
Total current liabilities		1,209			1,637
Deferred credits and other liabilities
Noncurrent income tax liabilities		578			401
Accumulated deferred investment tax credits		13			17
Regulatory liabilities		1,282			1,330
Asset retirement obligations		328			315
Accrued pension and other benefits		303			304
Capital lease obligations		216			224
Other liabilities and deferred credits		164			113
Total deferred credits and other liabilities		2,884			2,704
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	11,658		$	10,063

See Notes to PEF Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2008			2007
Operating activities
Net income	$	335		$	267
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		234			313
Deferred income taxes and investment tax credits, net		90			(50	)
Deferred fuel (credit) cost		(300	)		21
Allowance for equity funds used during construction		(65	)		(27	)
Other adjustments to net income		17			54
Cash (used) provided by changes in operating assets and liabilities
Receivables		(120	)		(100	)
Receivables from affiliated companies		(1	)		(2	)
Inventory		(73	)		(22	)
Prepayments and other current assets		(9	)		56
Income taxes, net		48			98
Accounts payable		147			127
Payables to affiliated companies		(38	)		(46	)
Other current liabilities		74			69
Other assets and deferred debits		(21	)		(25	)
Other liabilities and deferred credits		37			(6	)
Net cash provided by operating activities		355			727
Investing activities
Gross property additions		(1,229	)		(819	)
Nuclear fuel additions		(27	)		(39	)
Purchases of available-for-sale securities and other investments		(616	)		(457	)
Proceeds from sales of available-for-sale securities and other investments		618			279
Changes in advances to affiliated companies		149			–
Proceeds from sales of assets to affiliated companies		12			–
Other investing activities		(6	)		–
Net cash used by investing activities		(1,099	)		(1,036	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Proceeds from issuance of long-term debt, net		1,475			742
Retirement of long-term debt		(532	)		(87	)
Changes in advances from affiliated companies		2			(45	)
Other financing activities		–			2
Net cash provided by financing activities		944			611
Net increase in cash and cash equivalents		200			302
Cash and cash equivalents at beginning of period		23			23
Cash and cash equivalents at end of period	$	223		$	325
Supplemental disclosures
Significant noncash transactions
Capital lease obligation incurred	$	–		$	182
Nuclear decommissioning trust funds unrealized loss (gain)		94			(5	)
Accrued property additions		176			165

See Notes to PEF Unaudited Condensed Interim Financial Statements.

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO 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

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO 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), the 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 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 nine months ended September 30, 2008, are primarily due to timing of permanent tax items and seasonal fluctuations in energy sales and earnings from the Utilities. The fluctuations in the effective tax rate for the three and nine months ended September 30, 2007, are primarily due to the recognition of synthetic fuels tax credits, timing of permanent tax items 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 nine months ended September 30, 2008 and 2007, as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Progress Energy	$	(2	)	$	(26	)	$	(6	)	$	(3	)
PEC		3			(1	)		2			(2	)
PEF		(4	)		(4	)		(7	)		(3	)

For the three and nine months ended September 30, 2007, $16 million income and $6 million expense, respectively, of the Progress Energy net tax levelization 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 $16 million levelization income for the three months ended September 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 September 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	$	327	$	311
Common stock data
Basic earnings per common share
Income from continuing operations		1.27		1.21
Diluted earnings per common share
Income from continuing operations		1.27		1.21

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 September 30,				Nine Months Ended September 30,
(in millions)	2008		2007		2008		2007
Progress Energy	$	89	$	92	$	226	$	229
PEC		30		30		80		78
PEF		59		62		146		151

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 September 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 September 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 September 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 $17 million, which primarily represents its net remaining investment in these entities. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure.

22

PEF

PEF has interests in five variable interest entities for which PEF is not the primary beneficiary. These arrangements include equity investments or commitments to invest in three entities whose operations include venture capital investments, research and development or environmental remediation activities, and one building lease and one railcar lease with special-purpose entities. The majority of these interests were entered into prior to 2008. At September 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 $71 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 September 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. FIN 39-1, An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts

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

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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 nine months ended September 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, $(16) million and $6 million of tax levelization (benefit) 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 nine months ended September 30, 2007, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Revenues	$	–		$	350		$	17		$	888
(Loss) earnings before income tax and minority interest		(1	)		15			9			(43	)
Income tax benefit		1			5			13			98
Minority interest portion of synthetic fuel (earnings) losses		–			(12	)		(1	)		17
Net earnings from discontinued operations		–			8			21			72
Gain on disposal of discontinued operations, including income tax expense of $7		–			–			41			–
Earnings from discontinued operations	$	–		$	8		$	62		$	72

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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 nine months ended September 30, 2007, we reversed $1 million and $18 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 loss associated with the costs to exit the Georgia Contracts, and other related contracts, of $349 million after-tax (loss included in the net earnings (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 nine months ended September 30, 2007, was $11 million. We ceased recording depreciation upon classification of the assets as discontinued operations in December 2006. Results of CCO discontinued operations for the three and nine months ended September 30 were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2008		2007			2008			2007
Revenues	$	–	$	1		$	–		$	407
Loss before income tax		–		(1	)		(5	)		(444	)
Income tax benefit		2		–			4			164
Net earnings (loss) from discontinued operations		2		(1	)		(1	)		(280	)
Gain on disposal of discontinued operations, including income tax benefit of $1 and $8, respectively		–		1			–			18
Earnings (loss) from discontinued operations	$	2	$	–		$	(1	)	$	(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 nine months ended September 30, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Revenues	$	–		$	8		$	2		$	22
Loss before income tax		(1	)		(2	)		(7	)		(13	)
Income tax benefit		–			1			2			4
Net loss from discontinued operations		(1	)		(1	)		(5	)		(9	)
Gain on disposal of discontinued operations, including income tax expense of $2		–			–			7			–
(Loss) earnings from discontinued operations	$	(1	)	$	(1	)	$	2		$	(9	)

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 nine months ended September 30, 2008, we recorded additional gains of $3 million, net of tax. For the three and nine months ended September 30, 2007, we recorded additional gains of $1 million and $2 million, respectively, 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 Interbank Offered 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 nine months ended September 30, 2008, based on the final value of the 2007 Section 29/45K tax credits.

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During the nine months ended September 30, 2008, we recognized previously deferred 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 the 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. 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 compliance 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.

On September 5, 2008, the NCUC approved PEC’s request to terminate any further accelerated amortization of its Clean Smokestacks Act compliance costs. The NCUC ordered that PEC shall be allowed to include in rate base all reasonable and prudently incurred environmental compliance costs in excess of $584 million as the projects are closed to plant in service. As a result of this order, PEC will not amortize $229 million of the original estimated compliance costs for the Clean Smokestacks Act during 2008 and 2009, but will record depreciation over the useful life of the assets.

For the three months ended September 30, 2008, PEC did not recognize any amortization. For the nine months ended September 30, 2008, PEC recognized amortization of $15 million. For the three and nine months ended September 30, 2007, PEC recognized amortization of $8 million and $25 million, respectively. PEC has recognized $584 million in cumulative amortization through September 30, 2008.

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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. Subsequently, PEC jointly filed a settlement agreement with CIGFUR, CUCA and the NCUC Public Staff. Under the terms of the settlement agreement, PEC would collect $203 million of deferred fuel costs ratably over a three-year period beginning December 1, 2008, compared with a one-year recovery period proposed in PEC’s original request. Amounts to be collected in years beginning December 1, 2009 and 2010, will bear interest at a rate equal to the five-year United States Treasury Note plus 150 basis points. If the settlement agreement is approved, the increase would take effect on or about December 1, 2008, and would increase residential electric bills by $8.79 per 1,000 kWh, or 9.1 percent. A hearing on the settlement agreement was held on September 16, 2008, and an order is expected in November 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 demand-side management (DSM) and energy-efficiency programs through an annual DSM clause. The law allows PEC to capitalize those costs that are intended to produce future benefits and authorizes the NCUC to approve other forms of financial incentives to the utility for DSM and energy-efficiency programs. DSM programs include, 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. PEC has begun implementing a series of DSM and energy-efficiency programs and, as of September 30, 2008, has deferred $6 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 (DSDR) 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. On October 14, 2008, the NCUC approved PEC’s request for its EnergyWise™ program as well as three other DSM and energy-efficiency programs.

Also on April 29, 2008, PEC filed for NCUC approval of its DSDR 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 DSDR program has been scheduled by the NCUC for December 17, 2008.

On October 31, 2008, PEC filed with the NCUC for approval of two energy-efficiency programs and request for modifications to three of its approved energy-efficiency programs.

We cannot predict the outcome of PEC's DSM and energy-efficiency filings or whether the programs will produce the expected operational and economic results.

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On June 6, 2008, and as amended on August 20, 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, residential electric bills would increase by $1.92 per 1,000 kWh, or 2.0 percent. A hearing on the matter has been scheduled by the NCUC for December 17, 2008. Although the NCUC is not expected to make a decision on this filing until the first quarter of 2009, PEC has petitioned the NCUC to allow PEC to begin collecting the DSM and energy-efficiency related costs of these programs on December 1, 2008 subject to true-up in future proceedings. We cannot predict the outcome of this matter.

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. A hearing on this matter is anticipated to occur in the first quarter of 2009. 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 required PEC to submit its first annual renewable energy and energy efficiency portfolio standard (REPS) compliance plan as part of its integrated resource plan, which was filed on September 2, 2008. 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, and as amended on August 22, 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 residential electric bills by $0.45 per 1,000 kWh, or 0.5 percent. A hearing on the matter was held on September 17, 2008. The NCUC is expected to make a decision on this matter in November 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 public hearing on this matter was held by the NCUC on September 3, 2008. On October 13, 2008, the NCUC issued a Certificate of Public Convenience and Necessity allowing PEC to proceed with plans to provide additional generating and transmission capacity to meet the growing energy demands of southern and eastern North Carolina. PEC expects that the new generating and transmission capacity will be online by the second quarter of 2011. 

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

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United States engage in mediation to develop a plan for a single RTO. PEC participated in the mediation; no consensus was reached on creating a southeast RTO. On August 11, 2005, the GridSouth participants notified the FERC that they had terminated the GridSouth project. By order issued October 20, 2005, the FERC terminated the GridSouth proceeding.

On November 16, 2007, PEC petitioned the NCUC to allow it to establish a regulatory asset for PEC’s development costs of GridSouth pending disposition in a general rate proceeding. On January 14, 2008, the NCUC issued an order requesting interested parties to file comments regarding PEC’s petition on or before January 28, 2008. On 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 wholesale amortization to be $1 million in 2008 and $2 million annually during the remaining amortization period. PEC’s recorded investment in GridSouth totaled $20 million and $22 million at September 30, 2008 and December 31, 2007, respectively.

The NCUC and the 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 $10 million and $25 million for the three and nine months ended September 30, 2008, respectively. No additional depreciation expense from accelerated cost recovery was recorded for the same periods in 2007. Through September 30, 2008, PEC recorded cumulative accelerated depreciation of $465 million, of which $388 million was recorded for the North Carolina jurisdiction and $77 million was recorded for the South Carolina jurisdiction.

In October 2008, PEC filed, and the SCPSC approved, a petition to terminate PEC’s remaining obligation to accelerate the cost recovery of PEC’s nuclear generating assets. As a result of the approval of this petition, PEC will not be required to recognize the remaining $38 million of accelerated depreciation required to reach the minimum amount of cost recovery for the South Carolina jurisdiction, but will record depreciation over the useful life of the assets.

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

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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. A hearing on PEF’s 2006 and 2007 coal purchases has been scheduled for April 13-15, 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 percent 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 increased by $2.48 per 1,000 kWh, or 2.29 percent.

On October 15, 2008, PEF filed a request with the FPSC to seek approval of a cost adjustment for the under-recovery of fuel costs in 2008 and other recovery-clause factors. PEF asked the FPSC to approve an increase in residential electric bills by $27.28 per 1,000 kWh, or 24.7 percent, effective January 1, 2009. The increase in residential bills is primarily due to increases of $14.09 per 1,000 kWh for the projected recovery of fuel costs, $9.74 per 1,000 kWh for the projected recovery through the capacity cost-recovery clause and $2.50 per 1,000 kWh for the projected recovery through the environmental cost-recovery clause (ECRC). The increase in the capacity cost-recovery clause is primarily the result of projected costs to be incurred in 2009 under the nuclear cost-recovery rule discussed below for the proposed Levy Units 1 and 2 and the Crystal River Unit No. 3 Nuclear Plant (CR3) uprate less the projected reduction in capacity costs. The increase in the ECRC is primarily due to the recovery of emission allowance costs (See Note 12B) and the return on assets expected to be placed in service in 2009. The FPSC is scheduled to hold hearings on the cost adjustment proposal November 4-6, 2008. We cannot predict the outcome of this matter.

CR3 Uprate

On September 22, 2006, PEF filed a petition with the FPSC for Determination of Need to uprate CR3 and bid rule exemption, and for recovery of the revenue requirements of the uprate through PEF’s fuel recovery clause. To the extent the expenditures are prudently incurred, PEF’s investment in the CR3 uprate is eligible for recovery through base rates. PEF’s petition would allow for more prompt recovery. The 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. The multi-stage uprate will increase CR3’s gross output by approximately 180 MW by 2012. On February 8, 2007, the FPSC issued an order approving the need certification petition and bid rule exemption. PEF received NRC approval for a license amendment and implemented the first stage’s design modification on January 31, 2008, at a cost of $9 million. PEF will apply for the required license amendment for the third stage’s design modification.

On February 29, 2008, PEF filed a petition amending its recovery request and asked for recovery of costs incurred in 2007 and 2006 through the capacity cost-recovery clause under Florida’s comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule. This request was based on the regulatory precedence established by a FPSC order to an unaffiliated Florida utility for a nuclear uprate project. On May 1, 2008, PEF filed with the FPSC for an increase in the capacity cost-recovery clause for estimated costs incurred in 2008 and projected costs to be incurred in 2009 under the FPSC nuclear cost-recovery rule. PEF petitioned the FPSC to approve a $25 million increase in the capacity cost-recovery revenue requirement for costs associated with subsequent stages of 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. On August 19, 2008, the FPSC granted PEF’s petition to amend its request to recover costs for the nuclear uprate project under the nuclear cost-recovery rule.

On September 19, 2008, PEF filed a petition with the FPSC to approve a base rate increase for the remaining revenue requirements for the first stage costs. PEF’s 2008 revenue requirements for recovery of the first stage’s

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costs were included in the capacity cost-recovery clause. On October 28, 2008, the FPSC approved a $1 million base rate increase for costs associated with the first stage of the CR3 uprate. Base rates will increase for residential customers by $0.04 per 1,000 kWh, or 0.1 percent, beginning in January 2009.  On October 14, 2008, the FPSC voted to approve $24 million for costs associated with the CR3 uprate in establishing PEF's 2009 capacity cost-recovery clause factor.

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 issued the final order granting the petition for the Determination of Need for the proposed nuclear power plants on August 12, 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 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 under the nuclear cost-recovery rule. 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 nuclear cost-recovery rule. On October 14, 2008, the FPSC voted to approve the inclusion of preconstruction and carrying charges of $357 million as well as site selection costs of $38 million in establishing PEF's 2009 capacity cost-recovery clause factor.

5.   EQUITY AND COMPREHENSIVE INCOME

A.           EARNINGS PER COMMON SHARE

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2008		2007		2008		2007
Weighted-average common shares – basic		261		257		260		256
Net effect of dilutive stock-based compensation plans		–		–		–		–
Weighted-average shares – fully dilutive		261		257		260		256

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B.           COMPREHENSIVE INCOME

Progress Energy
	Three Months Ended September 30,
(in millions)	2008		2007
Net income	$	309	$	319
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $- and $-, respectively)		1		1
Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of ($1) and $7, respectively)		1		(11	)
Other comprehensive income (loss)		2		(10	)
Comprehensive income	$	311	$	309

	Nine Months Ended September 30,
(in millions)	2008		2007
Net income	$	723	$	401
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $2, respectively)		2		4
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $1 and $-, respectively)		1		2
Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of ($3) and $5, respectively)		5		(9	)
Other (net of tax benefit of $3)		–		(2	)
Other comprehensive income (loss)		8		(5	)
Comprehensive income	$	731	$	396

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PEC
	Three Months Ended September 30,
(in millions)	2008		2007
Net income	$	201	$	204
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $-)		1		–
Net unrealized gains (losses) on cash flow hedges (net of tax benefit of $- and $1, respectively)		1		(2	)
Other comprehensive income (loss)		2		(2	)
Comprehensive income	$	203	$	202

	Nine Months Ended September 30,
(in millions)	2008			2007
Net income	$	428		$	416
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $-)		1			–
Net unrealized losses on cash flow hedges (net of tax benefit of $2 and $1, respectively)		(4	)		(1	)
Other (net of tax benefit of $1)		–			(4	)
Other comprehensive loss		(3	)		(5	)
Comprehensive income	$	425		$	411

PEF
	Three Months Ended September 30,
(in millions)	2008		2007
Net income	$	143	$	138
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $6)		–		(10	)
Other comprehensive loss		–		(10	)
Comprehensive income	$	143	$	128

	Nine Months Ended September 30,
(in millions)	2008		2007
Net income	$	335	$	267
Other comprehensive income (loss)
Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of ($5) and $5, respectively)		8		(8	)
Other comprehensive income (loss)		8		(8	)
Comprehensive income	$	343	$	259

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 nine months ended September 30, 2008, respectively, we issued approximately 1.5 million shares and 2.5 million shares of common

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stock resulting in approximately $64 million and $106 million in proceeds. Included in these amounts were approximately 1.5 million shares and 2.4 million shares for proceeds of approximately $63 million and $104 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. For the three and nine months ended September 30, 2007, respectively, we issued approximately 0.3 million shares and 3.0 million shares of common stock resulting in approximately $12 million and $134 million in proceeds. Included in these amounts were approximately 0.2 million shares and 0.7 million shares for proceeds of approximately $12 million and $35 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, the Parent amended its RCA with a syndication of financial institutions to extend the termination date by one year. The extension was effective on May 2, 2008. The 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 August 14, 2008, PEF redeemed the entire outstanding $450 million principal amount of its Series A Floating Rate Notes due November 14, 2008, at 100 percent of par plus accrued interest. The redemption was funded with a portion of the proceeds from the June 18, 2008 debt issuance.

On November 3, 2008, the Parent borrowed $600 million under its RCA to reduce rollover risk in the commercial paper markets. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity.

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).

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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 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.

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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 September 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	$	–	$	130		$	39		$	169
Interest rate derivatives		–		4			–			4
Nuclear decommissioning trust funds		713		497			–			1,210
Other marketable securities		20		41			–			61
Total assets	$	733	$	672		$	39		$	1,444
Liabilities:
Commodity derivatives	$	–	$	(228	)	$	(20	)	$	(248	)
Interest rate derivatives		–		(2	)		–			(2	)
CVO derivatives		–		(36	)		–			(36	)
Total liabilities	$	–	$	(266	)	$	(20	)	$	(286	)

PEC
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivatives	$	–	$	14	$	6	$	20
Interest rate derivatives		–		2		–		2
Nuclear decommissioning trust funds		423		300		–		723
Other marketable securities		4		–		–		4
Total assets	$	427	$	316	$	6	$	749

Liabilities:
Commodity derivatives	$	–	$	(32	)	$	(10	)	$	(42	)
Interest rate derivatives		–		(1	)		–			(1	)
Total liabilities	$	–	$	(33	)	$	(10	)	$	(43	)

PEF
(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivatives	$	–	$	116	$	33	$	149
Nuclear decommissioning trust funds		290		197		–		487
Other marketable securities		1		–		–		1
Total assets	$	291	$	313	$	33	$	637

Liabilities:
Commodity derivatives	$	–	$	(196	)	$	(10	)	$	(206	)

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

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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.

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 primarily 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 nine months ended September 30, 2008.

Progress Energy
	Three Months Ended			Nine Months Ended
(in millions)	September 30, 2008			September 30, 2008
Derivatives, net at beginning of period	$	163		$	26
Total gains (losses), realized and unrealized:
Included in earnings		–			–
Included in other comprehensive income		–			–
Deferred as regulatory assets and liabilities, net		(145	)		(8	)
Purchases, issuances and settlements, net		–			–
Transfers out of Level 3, net		1			1
Derivatives, net at end of period	$	19		$	19

PEC
	Three Months Ended			Nine Months Ended
(in millions)	September 30, 2008			September 30, 2008
Derivatives, net at beginning of period	$	36		$	6
Total gains (losses), realized and unrealized:
Included in earnings		–			–
Included in other comprehensive income		–			–
Deferred as regulatory assets and liabilities, net		(42	)		(12	)
Purchases, issuances and settlements, net		–			–
Transfers out of Level 3, net		2			2
Derivatives, net at end of period	$	(4	)	$	(4	)

PEF
	Three Months Ended			Nine Months Ended
(in millions)	September 30, 2008			September 30, 2008
Derivatives, net at beginning of period	$	127		$	20
Total gains (losses), realized and unrealized:
Included in earnings		–			–
Included in other comprehensive income		–			–
Deferred as regulatory assets and liabilities, net		(103	)		4
Purchases, issuances and settlements, net		–			–
Transfers out of Level 3, net		(1	)		(1	)
Derivatives, net at end of period	$	23		$	23

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

Transfers out of Level 3 represent existing assets or liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

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 nine months ended September 30 were:

Progress Energy
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2008			2007			2008			2007
Service cost	$	11		$	13		$	2		$	2
Interest cost		33			31			9			6
Expected return on plan assets		(45	)		(38	)		(1	)		(1	)
Amortization of actuarial loss (gain) (a)		–			4			–			(2	)
Other amortization, net (a)		1			–			1			1
Net periodic cost	$	–		$	10		$	11		$	6

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Service cost	$	35		$	35		$	6		$	5
Interest cost		95			92			25			24
Expected return on plan assets		(127	)		(116	)		(4	)		(4	)
Amortization of actuarial loss (a)		5			11			1			1
Other amortization, net (a)		2			1			3			4
Net periodic cost	$	10		$	23		$	31		$	30

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

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PEC
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2008			2007			2008			2007
Service cost	$	5		$	7		$	1		$	2
Interest cost		15			14			5			2
Expected return on plan assets		(17	)		(14	)		(1	)		(1	)
Amortization of actuarial loss (gain)		–			4			–			(2	)
Other amortization, net		1			–			–			–
Net periodic cost	$	4		$	11		$	5		$	1

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Service cost	$	17		$	17		$	3		$	4
Interest cost		43			42			13			11
Expected return on plan assets		(49	)		(45	)		(3	)		(3	)
Amortization of actuarial loss		4			9			–			–
Other amortization, net		2			2			1			1
Net periodic cost	$	17		$	25		$	14		$	13

PEF
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2008			2007			2008		2007
Service cost	$	4		$	5		$	1	$	–
Interest cost		14			13			4		4
Expected return on plan assets		(24	)		(21	)		–		–
Other amortization, net		–			–			–		1
Net periodic (benefit) cost	$	(6	)	$	(3	)	$	5	$	5

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Service cost	$	13		$	12		$	2		$	1
Interest cost		40			39			11			11
Expected return on plan assets		(68	)		(63	)		(1	)		(1	)
Amortization of actuarial loss		–			–			1			1
Other amortization, net		–			–			2			3
Net periodic (benefit) cost	$	(15	)	$	(12	)	$	15		$	15

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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 September 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 September 30, 2008, and December 31, 2007, the remaining liability was $8 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. We had a $108 million cash collateral liability related to these contracts at December 31, 2007, included in other current liabilities on the Consolidated Balance Sheet. 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 September 30, 2007, we recorded net pre-tax gains of $74 million related to these contracts, including $26 million attributable to Ceredo, which was attributed to minority interest for the portion of the gain subsequent to disposal. For the nine months ended September 30, 2007, we recorded net pre-tax gains of $105 million related to these contracts, including $36 million attributable to Ceredo, of which $21 million were attributed to minority interest for the portion of the gain 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

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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 nine months ended September 30, 2008, PEC recorded a net realized gain of $6 million and $12 million, respectively. During each of the three and nine months ended September 30, 2007, PEC recorded a net realized loss of $6 million. During the three and nine months ended September 30, 2008, PEF recorded a net realized gain of $118 million and $237 million, respectively. During the three and nine months ended September 30, 2007, PEF recorded a net realized loss of $23 million and $45 million, respectively.

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

At September 30, 2008, the fair value of PEC’s commodity derivative instruments was recorded as a $1 million short-term derivative asset position included in prepayments and other current assets, a $19 million long-term derivative asset position included in other assets and deferred debits, a $24 million short-term liability position included in other current liabilities, and a $18 million long-term derivative liability position included in other liabilities and deferred credits on the PEC Consolidated Balance Sheet. At December 31, 2007, the fair value of such instruments was recorded as a $19 million long-term derivative asset position included in other assets and deferred debits and a $4 million short-term derivative liability position included in other current liabilities on the PEC Consolidated Balance Sheet. PEC had no cash collateral position at September 30, 2008 or December 31, 2007.

At September 30, 2008, the fair value of PEF’s commodity derivative instruments was recorded as a $59 million short-term derivative asset position included in current derivative assets, a $90 million long-term derivative asset position included in derivative assets, a $133 million short-term liability position included in derivative liabilities, and a $73 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 $14 million cash collateral receivable included in prepayments and other current assets and a $14 million cash collateral liability included in other current liabilities at September 30, 2008, 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 September 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 nine months ended September 30, 2008 and 2007.

At September 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.

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CASH FLOW HEDGES

The fair values of open interest rate hedges at September 30, 2008, and December 31, 2007, were as follows:

	September 30, 2008								December 31, 2007
(in millions)	Progress Energy			PEC			PEF		Progress Energy			PEC			PEF
Fair value of assets	$	4		$	2		$	–	$	–		$	–		$	–
Fair value of liabilities		(2	)		(1	)		–		(12	)		(12	)		–
Fair value, net	$	2		$	1		$	–	$	(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 effective portion of the hedges is included in accumulated other comprehensive income and will be amortized to interest expense over the term of the related debt. The ineffective portion of interest rate cash flow hedges for the three and nine months ended September 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 September 30, 2008:

(term in years/millions of dollars)	Progress Energy			PEC			PEF
Maximum term	Less than 1			Less than 1				–
Accumulated other comprehensive loss, net of tax(a)	$	(16	)	$	(14	)	$	–
Portion expected to be reclassified to earnings during the next 12 months(b)	$	–		$	1		$	–

(a)  Includes amounts related to terminated hedges.

(b)  Actual amounts that will be reclassified to earnings may vary from the expected amounts presented abouve 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.

In August 2008, the Parent entered into a $50 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. In September 2008, the Parent entered into a combined $100 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. In October 2008, the Parent entered into a $50 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance.

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. In August 2008, PEC entered into a $50 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. In September 2008, PEC entered into a combined $100 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance. In October 2008, PEC entered into a $50 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuance.

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

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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 September 30, 2008, and December 31, 2007, neither we nor the Utilities had any outstanding positions in such contracts.

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.

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 nine months ended September 30:

									Income (Loss)
	Revenues								From Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
Three Months Ended September 30, 2008
PEC	$	1,266	$	–		$	1,266		$	200		$	12,492
PEF		1,428		–			1,428			143			11,658
Corporate and Other		2		92			94			(35	)		17,426
Eliminations		–		(92	)		(92	)		–			(13,339	)
Totals	$	2,696	$	–		$	2,696			308		$	28,237
Three Months Ended September 30, 2007
PEC	$	1,286	$	–		$	1,286		$	203
PEF		1,456		–			1,456			138
Corporate and Other		8		99			107			(30	)
Eliminations		–		(99	)		(99	)		–
Totals	$	2,750	$	–		$	2,750		$	311

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									Income (Loss)
	Revenues								From Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
Nine Months Ended September 30, 2008
PEC	$	3,382	$	–		$	3,382		$	426		$	12,492
PEF		3,618		–			3,618			334			11,658
Corporate and Other		6		268			274			(103	)		17,426
Eliminations		–		(268	)		(268	)		–			(13,339	)
Totals	$	7,006	$	–		$	7,006		$	657		$	28,237
Nine Months Ended September 30, 2007
PEC	$	3,340	$	–		$	3,340		$	414
PEF		3,596		–			3,596			266
Corporate and Other		15		288			303			(82	)
Eliminations		–		(288	)		(288	)		–
Totals	$	6,951	$	–		$	6,951		$	598

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.

The components of other, net as shown on the accompanying Statements of Income were as follows:

Progress Energy
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Other income
Nonregulated energy and delivery services income	$	3		$	2		$	25		$	25
DIG Issue C20 amortization (see Note 9A)		1			1			2			3
CVOs unrealized gain		–			1			–			2
Gain on sale of property, net		–			3			–			1
Investment gains		2			2			6			5
Income from equity investments		1			1			1			2
Derivative mark-to-market gain		–			–			4			–
Other		3			3			9			10
Total other income		10			13			47			48
Other expense
Nonregulated energy and delivery services expenses		6			7			15			19
Donations		3			6			14			16
Investment losses		1			4			8			4
Loss from equity investments		–			–			3			1
Derivative mark-to-market loss		5			–			5			–
CVOs unrealized loss		–			–			2			4
Other		2			1			9			10
Total other expense		17			18			56			54
Other, net	$	(7	)	$	(5	)	$	(9	)	$	(6	)

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PEC
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008		2007
Other income
Nonregulated energy and delivery services income	$	(1	)	$	(3	)	$	11	$	6
DIG Issue C20 amortization (see Note 9A)		1			1			2		3
Investment gains		2			2			3		3
Income from equity investments		1			1			1		3
Derivative mark-to-market gain		–			–			4		–
Other		3			2			8		7
Total other income		6			3			29		22
Other expense
Nonregulated energy and delivery services expenses		3			3			6		6
Donations		2			1			8		6
Investment losses		–			2			3		3
Loss from equity investments		–			–			2		1
Derivative mark-to-market loss		5			–			5		–
Other		1			–			5		4
Total other expense		11			6			29		20
Other, net	$	(5	)	$	(3	)	$	–	$	2

PEF
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2008		2007		2008			2007
Other income
Nonregulated energy and delivery services income	$	5	$	5	$	15		$	19
Investment gains		–		–		1			2
Other		–		1		2			1
Total other income		5		6		18			22
Other expense
Nonregulated energy and delivery services expenses		3		4		9			13
Donations		1		1		6			4
Investment losses		–		1		2			1
Loss from equity investments		–		–		1			1
Other		1		–		1			3
Total other expense		5		6		19			22
Other, net	$	–	$	–	$	(1	)	$	–

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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 potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.

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

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

(in millions)	September 30, 2008		December 31, 2007
PEC
MGP and other sites(a)	$	18	$	16
PEF
Remediation of distribution and substation transformers		26		31
MGP and other sites		15		17
Total PEF environmental remediation accruals(b)		41		48
Total Progress Energy environmental remediation accruals	$	59	$	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).

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PEC

In 2006, the NCUC and the SCPSC authorized PEC to defer and amortize certain environmental remediation expenses. Remediation expenses not authorized to be deferred are included in operation and maintenance expense. Including the Ward Transformer site located in Raleigh, N.C. (Ward) and MGP sites discussed below, for the three months ended September 30, 2008, PEC accrued approximately $2 million and spent approximately $2 million. For the nine months ended September 30, 2008, PEC accrued approximately $8 million, of which $2 million was deferred, and spent approximately $6 million. For the three months ended September 30, 2007, PEC accrued and deferred approximately $1 million and spent approximately $1 million. For the nine months ended September 30, 2007, PEC reduced its accrual by approximately $4 million and spent approximately $2 million. These amounts primarily relate to the Ward site.

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 site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. During 2007, the PRP agreement was amended to include an additional participating PRP, which reduced on an interim basis, 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 September 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. On September 12, 2008, PEC filed a complaint seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. The complaint names 28 parties that did not sign a tolling agreement with PEC, which was entered into by over 200 PRPs.  The tolling agreement suspends the running of the statute of limitations for determination of cost recovery from PRPs at the Ward site. The litigation has been stayed to allow the parties to explore private settlements. The outcome of these matters cannot be predicted.

On September 30, 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation for Ward OU1 and Ward OU2.

PEF

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. 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 nine months ended September 30, 2008, PEF accrued approximately $3 million and $15 million, respectively, due to the identification of additional transformer sites and an increase in estimated remediation costs, and spent approximately $6 million and $20 million, respectively, related to the remediation of transformers. For the three and nine months ended September 30, 2007, PEF accrued approximately $4 million and $9 million, respectively, due to an increase in estimated remediation costs and spent

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approximately $5 million and $16 million, respectively, related to the remediation of transformers. At September 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 months ended September 30, 2008, PEF made no additional accruals or material expenditures. For the nine months ended September 30, 2008, PEF made no additional accruals and spent approximately $2 million. For the three and nine months ended September 30, 2007, PEF made no additional accruals or material expenditures.

B.   AIR AND WATER QUALITY

At September 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 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 September 30, 2008, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.754 billion, including $1.009 billion at PEC of which $15 million related to in-process CAIR projects, and $745 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 $1.225 billion, including $902 million at PEC and $323 million at PEF. PEC completed installation of controls to meet the requirements of the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) in 2007.

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. On September 24, 2008, petitions for rehearing were filed by the EPA, the Utility Air Regulatory Group, the National Mining Association and several environmental groups. PEC and PEF are members of the Utility Air Regulatory Group. On October 21, 2008, the Court issued an order directing petitionersto address (1) whether any party is seeking to vacate the CAIR, and (2) whether the court should stay its mandate until EPA promulgates a revised rule. The Court will not issue its mandate until after it evaluates the responses to this order and renders a decision on the petitions for rehearing. If it stands, 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 Clean Air Mercury Rule (CAMR). On September 17, 2008, the Utility Air Regulatory Group filed a petition for writ of certiorari with the U.S. Supreme Court seeking a review of the decision that vacated the CAMR. On October 17, 2008, the EPA filed a similar petition. 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 any review granted by the Supreme Court 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. We are currently evaluating the impact of these decisions. The outcome of these matters cannot be predicted.

The Utilities are 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 complete 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 and the market prices for emission allowances have declined. At September 30, 2008, PEC had approximately $25 million in SO2 emission allowances, which will

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be utilized to comply with existing Clean Air Act requirements and an immaterial amount of NOx emission allowances. 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. During the three months ended September 30, 2008, PEF reduced the value of its annual NOx allowance inventory by $59 million due to the uncertainty of whether the allowances will ultimately be used, and reduced the value of its seasonal NOx allowance inventory by approximately $1 million based on current market prices. 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 retail portion of the costs of these allowances through its ECRC. Accordingly, PEF recorded a $57 million regulatory asset for the retail portion of its annual and seasonal NOx allowances. Therefore, there was no material impact to PEF’s results of operations for the reduction in value of its NOx allowance inventory. On August 29, 2008, PEF filed for recovery of its CAIR expenses, including NOx allowance inventory expense, through the ECRC. A hearing on the matter is scheduled for November 4-6, 2008. At September 30, 2008, PEF had approximately $6 million in seasonal NOx emission allowance inventory and approximately $14 million in SO2 emission allowance inventory. 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 September 30, 2008 and December 31, 2007, the amount of the liability was $15 million and $30 million, respectively, based upon the respective estimates for the remaining Clean Smokestacks Act compliance costs. During the three months ended September 30, 2008, PEC made no additional accruals and spent approximately $5 million that exceeded the joint owner limit. During the nine months ended September 30, 2008, PEC made no additional accruals and spent approximately $15 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 September 5, 2008, the NCUC ordered that PEC shall be allowed to include in rate base all reasonable and prudently incurred environmental compliance costs in excess of $584 million, including eligible compliance costs in excess of the joint owner’s share, as the projects are closed to plant in service (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.

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PROGRESS ENERGY

Through September 30, 2008, contracts procured through our subsidiaries have increased our aggregate purchase obligations for fuel and purchased power by $7.417 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 September 30, 2008, PEC’s fuel and purchased power commitments increased by $3.495 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 $2.156 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 $487 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.

In July 2008, PEC entered into an amendment to an existing transportation service agreement with an intrastate pipeline for firm pipeline transportation capacity to support PEC’s gas supply needs for the period from April 2011 through May 2030. The total additional cost to PEC associated with this amendment is estimated to be approximately $54 million. The amendment is subject to several conditions precedent, including state regulatory approval, the completion and commencement of operation of necessary related intrastate natural 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 September 30, 2008, PEF’s fuel and purchased power commitments increased by $3.922 billion from $12.566 billion as stated in Note 22A in the 2007 Form 10-K.  As discussed in Note 22A in the 2007 Form 10-K, PEF entered into certain conditional contracts for gas supply and transportation. Due to the conditions of these contracts, the associated estimated costs were not included in our or PEF’s contractual cash obligations table at December 31, 2007. Additional conditional gas supply and transportation contracts were entered into during the second quarter of 2008. During 2008, the conditions were satisfied and several gas supply and transportation contracts totaling $3.255 billion became effective.  These agreements for the supply of natural gas and associated firm pipeline transportation augment PEF’s gas supply needs for various periods from September 2008 through January 2032.  The estimated costs associated with these agreements are approximately $81 million in 2008, $436 million in 2009, $570 million in 2010, $602 million in 2011, $548 million in 2012, and $1.018 billion thereafter.  Also, the increase in gas supply and transportation purchase commitments includes new contracts along with the impact of price increases on certain existing contracts that are market price indexed. Coal purchase commitments increased by approximately $804 million; of this increase, approximately $230 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.

In April 2008, PEF entered into conditional contracts 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 these agreements is estimated to be approximately $2.176 billion. The contracts are 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 contracts, 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

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$987 million. 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 September 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 September 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 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 September 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 September 30, 2008 and December 31, 2007, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $66 million and $80 million, respectively. These amounts include $15 million and $30 million, respectively, for PEC and $8 million for PEF at September 30, 2008 and December 31, 2007. During the three months ended September 30, 2008, PEC made no additional accruals and spent approximately $5 million that exceeded the joint owner limit. During the nine months ended September 30, 2008, PEC made no additional accruals and spent approximately $15 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. On August 15, 2008, the Department of Justice appealed the United States Court of Federal Claims ruling to the D.C. Court of Appeals. In the event that the Utilities recover

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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. On September 30, 2008, the EPA issued final rules for limiting radiation exposure at Yucca Mountain, Nev. The EPA retained the dose limit of 15 millirem per year for the first 10,000 years and established a dose limit of 100 millirem for annual exposure per year between 10,000 years and 1 million years. On October 10, 2008, the state of Nevada again filed suit with the D.C. Court of Appeals challenging the EPA standard.

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.

The DOE submitted the license application for the proposed high-level nuclear waste repository at Yucca Mountain in June 2008. The NRC formally docketed the license application in September 2008, which begins the formal licensing phase that is anticipated to take three to four years. The state of Nevada and other interested parties are expected to intervene in the licensing proceedings.

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.

On October 9, 2008, the NRC proposed revisions to its waste confidence findings that would remove the provisions stating that the NRC’s confidence in waste management, underlying the licensing of reactors, is based in part on a repository being in operation by 2025. Instead, the NRC states that repository capacity will be available within 50 to 60 years beyond the licensed operation of all reactors, and that used fuel generated in any reactor can be safely stored without significant environmental impact for at least 60 years beyond the licensed operation of the reactor.

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 previously 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.

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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.

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.

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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.

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Condensed Consolidating Statement of Income Three Months Ended September 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	1,430		$	1,266		$	2,696
Operating expenses
Fuel used in electric generation		–			521			348			869
Purchased power		–			305			145			450
Operation and maintenance		1			201			237			439
Depreciation and amortization		–			77			128			205
Taxes other than on income		–			88			53			141
Other		–			2			(1	)		1
Total operating expenses		1			1,194			910			2,105
Operating (loss) income		(1	)		236			356			591
Other income, net		3			29			3			35
Interest charges, net		49			68			50			167
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(47	)		197			309			459
Income tax (benefit) expense		(20	)		59			111			150
Equity in earnings of consolidated subsidiaries		336			–			(336	)		–
Minority interest in subsidiaries’ income, net of tax		–			(1	)		–			(1	)
Income (loss) from continuing operations		309			137			(138	)		308
Discontinued operations, net of tax		–			(1	)		2			1
Net income (loss)	$	309		$	136		$	(136	)	$	309

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Condensed Consolidating Statement of Income Three Months Ended September 30, 2007
(in millions)	Parent			Subsidiary Guarantor		Other			Progress Energy, Inc.
Operating revenues	$	–		$	1,465	$	1,285		$	2,750
Operating expenses
Fuel used in electric generation		–			544		385			929
Purchased power		–			281		109			390
Operation and maintenance		2			213		241			456
Depreciation and amortization		–			102		121			223
Taxes other than on income		–			83		52			135
Other		–			4		3			7
Total operating expenses		2			1,227		911			2,140
Operating (loss) income		(2	)		238		374			610
Other income (expense), net		10			13		(8	)		15
Interest charges, net		52			53		49			154
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(44	)		198		317			471
Income tax (benefit) expense		(21	)		65		116			160
Equity in earnings of consolidated subsidiaries		340			–		(340	)		–
Income (loss) from continuing operations		317			133		(139	)		311
Discontinued operations, net of tax		2			6		–			8
Net income (loss)	$	319		$	139	$	(139	)	$	319

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Condensed Consolidating Statement of Income Nine Months Ended September 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	3,624		$	3,382		$	7,006
Operating expenses
Fuel used in electric generation		–			1,235			1,027			2,262
Purchased power		–			746			266			1,012
Operation and maintenance		3			621			746			1,370
Depreciation and amortization		–			229			390			619
Taxes other than on income		–			235			152			387
Other		–			–			(6	)		(6	)
Total operating expenses		3			3,066			2,575			5,644
Operating (loss) income		(3	)		558			807			1,362
Other income, net		7			68			20			95
Interest charges, net		147			165			154			466
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(143	)		461			673			991
Income tax (benefit) expense		(60	)		139			250			329
Equity in earnings of consolidated subsidiaries		806			–			(806	)		–
Minority interest in subsidiaries’ income, net of tax		–			(5	)		–			(5	)
Income (loss) from continuing operations		723			317			(383	)		657
Discontinued operations, net of tax		–			62			4			66
Net income (loss)	$	723		$	379		$	(379	)	$	723

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Condensed Consolidating Statement of Income Nine Months Ended September 30, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues	$	–		$	3,611		$	3,340		$	6,951
Operating expenses
Fuel used in electric generation		–			1,340			1,041			2,381
Purchased power		–			651			243			894
Operation and maintenance		9			586			742			1,337
Depreciation and amortization		–			300			365			665
Taxes other than on income		–			233			151			384
Other		–			18			10			28
Total operating expenses		9			3,128			2,552			5,689
Operating (loss) income		(9	)		483			788			1,262
Other income, net		19			27			2			48
Interest charges, net		151			135			145			431
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(141	)		375			645			879
Income tax (benefit) expense		(64	)		101			236			273
Equity in earnings of consolidated subsidiaries		472			–			(472	)		–
Minority interest in subsidiaries’ income, net of tax		–			(8	)		–			(8	)
Income (loss) from continuing operations		395			266			(63	)		598
Discontinued operations, net of tax		6			38			(241	)		(197	)
Net income (loss)	$	401		$	304		$	(304	)	$	401

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Condensed Consolidating Balance Sheet September 30, 2008
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	8,619	$	9,296		$	17,915
Current assets
Cash and cash equivalents		–		257		146			403
Notes receivable from affiliated companies		17		66		(83	)		–
Prepayments and other current assets		69		1,353		1,324			2,746
Total current assets		86		1,676		1,387			3,149
Deferred debits and other assets
Investment in consolidated subsidiaries		11,927		–		(11,927	)		–
Goodwill		–		–		3,655			3,655
Regulatory assets		–		578		769			1,347
Other assets and deferred debits		155		1,025		991			2,171
Total deferred debits and other assets		12,082		1,603		(6,512	)		7,173
Total assets	$	12,168	$	11,898	$	4,171		$	28,237
CAPITALIZATION AND LIABILITIES
Common stock equity	$	8,827	$	3,527	$	(3,527	)	$	8,827
Preferred stock of subsidiaries – not subject to mandatory redemption		–		34		59			93
Minority interest		–		3		3			6
Long-term debt, affiliate		–		309		(37	)		272
Long-term debt, net		2,595		4,182		3,109			9,886
Total capitalization		11,422		8,055		(393	)		19,084
Current liabilities
Current portion of long-term debt		–		–		400			400
Short-term debt		495		–		–			495
Notes payable to affiliated companies		–		131		(131	)		–
Other current liabilities		203		1,226		743			2,172
Total current liabilities		698		1,357		1,012			3,067
Deferred credits and other liabilities
Noncurrent income tax liabilities		1		80		645			726
Regulatory liabilities		–		1,282		1,175			2,457
Other liabilities and deferred credits		47		1,124		1,732			2,903
Total deferred credits and other liabilities		48		2,486		3,552			6,086
Total capitalization and liabilities	$	12,168	$	11,898	$	4,171		$	28,237

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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
Notes receivable from affiliated companies		157		149		(306	)		–
Assets to be divested		–		48		4			52
Prepayments and other current assets		21		1,252		1,249			2,522
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
Regulatory assets		–		266		680			946
Other assets and deferred debits		149		1,309		872			2,330
Total deferred debits and other assets		11,118		1,576		(5,763	)		6,931
Total assets	$	11,481	$	10,668	$	4,216		$	26,365
CAPITALIZATION AND LIABILITIES
Common stock equity	$	8,422	$	3,052	$	(3,052	)	$	8,422
Preferred stock of subsidiaries – not subject to mandatory redemption		–		34		59			93
Minority interest		–		81		3			84
Long-term debt, affiliate		–		309		(38	)		271
Long-term debt, net		2,597		2,686		3,183			8,466
Total capitalization		11,019		6,162		155			17,336
Current liabilities
Current portion of long-term debt		–		577		300			877
Short-term debt		201		–		–			201
Notes payable to affiliated companies		–		227		(227	)		–
Liabilities to be divested		–		8		–			8
Other current liabilities		215		1,237		764			2,216
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

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Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(138	)	$	502		$	995		$	1,359
Investing activities
Gross property additions		–			(1,230	)		(530	)		(1,760	)
Nuclear fuel additions		–			(27	)		(131	)		(158	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			60			3			63
Proceeds from sales of assets to affiliated companies		–			12			(12	)		–
Purchases of available-for-sale securities and other investments		(6	)		(618	)		(566	)		(1,190	)
Proceeds from sales of available-for-sale securities and other investments		–			622			532			1,154
Contributions to consolidated subsidiaries		(99	)		–			99			–
Changes in advances to affiliated companies		140			83			(223	)		–
Other investing activities		(1	)		9			(11	)		(3	)
Net cash provided (used) by investing activities		34			(1,089	)		(839	)		(1,894	)
Financing activities
Issuance of common stock		106			–			–			106
Dividends paid on common stock		(481	)		–			–			(481	)
Dividends paid to parent		–			(3	)		3			–
Payments of short-term debt with original maturities greater than 90 days		(176	)		–			–			(176	)
Net increase in short-term debt		470			–			–			470
Proceeds from issuance of long-term debt, net		–			1,475			322			1,797
Retirement of long-term debt		–			(577	)		(300	)		(877	)
Cash distributions to minority interests of consolidated subsidiaries		–			(85	)		–			(85	)
Contributions from parent		–			85			(85	)		–
Changes in advances from affiliated companies		–			(96	)		96			–
Other financing activities		–			2			(73	)		(71	)
Net cash (used) provided by financing activities		(81	)		801			(37	)		683
Net (decrease) increase in cash and cash equivalents		(185	)		214			119			148
Cash and cash equivalents at beginning of period		185			43			27			255
Cash and cash equivalents at end of period	$	–		$	257		$	146		$	403

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Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	6		$	356		$	376		$	738
Investing activities
Gross property additions		–			(822	)		(589	)		(1,411	)
Nuclear fuel additions		–			(39	)		(159	)		(198	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			37			621			658
Purchases of available-for-sale securities and other investments		–			(457	)		(615	)		(1,072	)
Proceeds from sales of available-for-sale securities and other investments		21			279			639			939
Changes in advances to affiliated companies		(250	)		37			213			–
Return of investment in consolidated subsidiary		190			–			(190	)		–
Other investing activities		(5	)		12			9			16
Net cash used by investing activities		(44	)		(953	)		(71	)		(1,068	)
Financing activities
Issuance of common stock		134			–			–			134
Dividends paid on common stock		(469	)		–			–			(469	)
Dividends paid to parent		–			(10	)		10			–
Net increase in short-term debt		400			–			150			550
Proceeds from issuance of long-term debt, net		–			742			–			742
Retirement of long-term debt		–			(87	)		(200	)		(287	)
Cash distributions to minority interests of consolidated subsidiaries		–			(10	)		–			(10	)
Changes in advances from affiliated companies		–			214			(214	)		–
Other financing activities		–			49			(27	)		22
Net cash provided (used) by financing activities		65			898			(281	)		682
Net increase in cash and cash equivalents		27			301			24			352
Cash and cash equivalents at beginning of period		153			40			72			265
Cash and cash equivalents at end of period	$	180		$	341		$	96		$	617

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ITEM 2.                      MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS 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 nine months ended September 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.

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OVERVIEW

For the quarter ended September 30, 2008, our net income was $309 million, or $1.19 per share, compared to net income of $319 million, or $1.24 per share, for the same period in 2007. For the quarter ended September 30, 2008, our income from continuing operations was $308 million compared to $311 million for the same period in 2007. The decrease in income from continuing operations as compared to prior year was primarily due to:

·   unfavorable weather at the Utilities;

·   higher interest expense at PEF;

·   the impact of tax levelization recorded because accounting principles generally accepted in the United States (GAAP) require companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate; and

·   unfavorable retail customer growth and usage at PEF.

Partially offsetting these items were:

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

·   increased retail base rates at PEF;

·   higher wholesale revenues at PEF; and

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

For the nine months ended September 30, 2008, our net income was $723 million, or $2.78 per share, compared to net income of $401 million, or $1.57 per share, for the same period in 2007. For the nine months ended September 30, 2008, our income from continuing operations was $657 million compared to $598 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;

·   increased retail base rates at PEF;

·   higher wholesale revenues at PEF;

·   favorable retail customer growth and usage at PEC; and

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

Partially offsetting these items were:

·   higher interest expense at PEF;

·   unfavorable weather at PEC;

·   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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2008			2007			2008			2007
Business Segment
PEC	$	200		$	203		$	426		$	414
PEF		143			138			334			266
Total segment profit		343			341			760			680
Corporate and Other		(35	)		(30	)		(103	)		(82	)
Income from continuing operations		308			311			657			598
Discontinued operations, net of tax		1			8			66			(197	)
Net income	$	309		$	319		$	723		$	401

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $200 million and $203 million for the three months ended September 30, 2008 and 2007, respectively. The decrease in profits for the three months ended September 30, 2008, compared to the same period in 2007, was primarily due to the unfavorable impact of weather, partially offset by favorable AFUDC and lower purchased power capacity costs due to the expiration of a power buyback agreement.

PEC contributed segment profits of $426 million and $414 million for the nine months ended September 30, 2008 and 2007, respectively. The increase in profits for the nine months ended September 30, 2008, compared to the same period in 2007, was primarily due to the favorable impact of retail customer growth and usage, lower purchased power capacity costs due to the expiration of a power buyback agreement and favorable AFUDC, partially offset by the unfavorable impact of weather, higher depreciation and amortization and lower excess generation revenues.

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 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.

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

REVENUES

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

(in millions)	Three Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential	$	495		$	(8	)		(1.6	)	$	503
Commercial		331			6			1.8			325
Industrial		200			4			2.0			196
Governmental		32			3			10.3			29
Total retail revenues		1,058			5			0.5			1,053
Wholesale		196			(12	)		(5.8	)		208
Unbilled		(16	)		(16	)		–			–
Miscellaneous		28			3			12.0			25
Total electric revenues		1,266			(20	)		(1.6	)		1,286
Less: Fuel revenues		(455	)		(12	)		–			(443	)
Revenues excluding fuel	$	811		$	(32	)		(3.8	)	$	843

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

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential		4,929			(189	)		(3.7	)		5,118
Commercial		4,079			(12	)		(0.3	)		4,091
Industrial		2,879			(231	)		(7.4	)		3,110
Governmental		437			16			3.8			421
Total retail energy sales		12,324			(416	)		(3.3	)		12,740
Wholesale		3,746			(438	)		(10.5	)		4,184
Unbilled		(250	)		(112	)		–			(138	)
Total kWh sales		15,820			(966	)		(5.8	)		16,786

PEC’s revenues, excluding fuel revenues of $455 million and $443 million for the three months ended September 30, 2008 and 2007, respectively, decreased $32 million. The decrease in revenues excluding fuel is primarily due to the $28 million unfavorable impact of weather and $5 million lower excess generation revenues, partially offset by the $7 million favorable impact of retail customer growth and usage. The unfavorable impact of weather was driven by cooling degree days 12 percent lower than 2007. The lower excess generation revenues were primarily due to unfavorable market dynamics due to higher relative fuel costs. The favorable impact of retail customer growth and usage was driven by a net 23,000 customer increase in PEC’s average number of customers for the three months ended September 30, 2008, compared to the same period in 2007, partially offset by a decrease in the average usage per retail customer.

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 impacted by the decline in general economic conditions as significantly as PEF. However, through September 30, 2008, PEC has experienced some decline in the rate of residential and commercial sales growth. In the future, PEC’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates resulting from higher fuel and other recoverable costs.

Retail revenues increased for the three months ended September 30, 2008, despite a decrease in retail 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.

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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 $493 million for the three months ended September 30, 2008, which represents a $1 million decrease compared to the same period in 2007. Fuel used in electric generation decreased $37 million compared to the same period in 2007. The decrease was primarily due to a decrease in deferred fuel expense driven by a $24 million impact from the implementation of the North Carolina comprehensive energy legislation (See “Other Matters – Regulatory Environment”) and a $12 million impact related to a decrease in the collection of prior period costs. Current year purchased power costs were $36 million higher than the three months ended September 30, 2007, due to increased economical purchases in 2008. Higher purchased power expenses were partially offset by the $9 million impact from the expiration of a power buyback agreement with North Carolina Eastern Municipal Power Agency (Power Agency).

Depreciation and Amortization

Depreciation and amortization expense was $124 million for the three months ended September 30, 2008, which represents a $6 million increase compared to the same period in 2007. Depreciation and amortization expense increased primarily due to $10 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 (See Note 4A).

Total Other Income, net

Total other income, net of $6 million increased $2 million for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to $7 million favorable AFUDC equity related to increased Clean Smokestacks Act compliance and other eligible construction project costs, partially offset by $5 million derivative mark-to-market losses. The derivative mark-to-market losses 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.

Total Interest Charges, net

Total interest charges, net of $50 million decreased $6 million for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to $2 million lower interest as a result of lower average debt outstanding and $2 million favorable AFUDC debt related to increased Clean Smokestacks Act compliance and other eligible construction project costs.

Income Tax Expense

Income tax expense decreased $11 million for the three months ended September 30, 2008, as compared to the same period in 2007, primarily due to the $6 million tax impact of lower pre-tax earnings, the $4 million tax impact of employee stock-based benefits and the $3 million impact of the increase in AFUDC equity discussed above, partially offset by the $4 million impact of tax levelization. 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. PEC’s income tax expense was increased by $3 million for the three months ended September 30, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate, compared to a decrease of $1 million for the three months ended September 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.

68

Nine Months Ended September 30, 2008, Compared to Nine Months Ended September 30, 2007

REVENUES

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

(in millions)	Nine Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential	$	1,256		$	2			0.2		$	1,254
Commercial		862			22			2.6			840
Industrial		555			20			3.7			535
Governmental		78			5			6.8			73
Total retail revenues		2,751			49			1.8			2,702
Wholesale		566			6			1.1			560
Unbilled		(10	)		(13	)		–			3
Miscellaneous		74			–			–			74
Total electric revenues		3,381			42			1.3			3,339
Less: Fuel revenues		(1,227	)		(61	)		–			(1,166	)
Revenues excluding fuel	$	2,154		$	(19	)		(0.9	)	$	2,173

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

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential		13,192			(242	)		(1.8	)		13,434
Commercial		10,741			59			0.6			10,682
Industrial		8,773			(144	)		(1.6	)		8,917
Governmental		1,105			25			2.3			1,080
Total retail energy sales		33,811			(302	)		(0.9	)		34,113
Wholesale		10,959			(347	)		(3.1	)		11,306
Unbilled		(246	)		(168	)		–			(78	)
Total kWh sales		44,524			(817	)		(1.8	)		45,341

PEC’s revenues, excluding fuel revenues of $1.227 billion and $1.166 billion for the nine months ended September 30, 2008 and 2007, respectively, decreased $19 million. The decrease in revenues excluding fuel is primarily due to the $36 million unfavorable impact of weather and $13 million lower excess generation revenues, partially offset by the $33 million favorable impact of retail customer growth and usage. The unfavorable impact of weather was driven by cooling degree days 7 percent lower than 2007. Lower excess generation revenues were primarily due to unfavorable market dynamics due to higher relative fuel costs. The favorable impact of retail customer growth and usage was driven by a net 25,000 customer increase in PEC’s average number of customers for the nine months ended September 30, 2008, compared to the same period in 2007, and by an increase in the average usage per retail customer.

As discussed previously in “Revenues” for the three months ended September 30, 2008 and 2007, PEC has not been impacted by the decline in general economic conditions as significantly as PEF. However, through September 30, 2008, PEC has experienced some decline in the rate of residential and commercial sales growth. In the future, PEC’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates resulting from higher fuel and other recoverable costs.

Retail and wholesale revenues increased for the nine months ended September 30, 2008, despite a decrease in retail and wholesale energy sales for the same period primarily due to the impact of increased fuel revenues as a result of higher energy costs. Additionally, retail revenues increased for the nine months ended September 30, 2008, due to the recovery of prior year fuel costs.

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EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.293 billion for the nine months ended September 30, 2008, which represents a $9 million increase compared to the same period in 2007. Current year purchased power costs were $23 million higher than the nine months ended September 30, 2007 due to increased economical purchases in 2008 of $46 million, partially offset by the $29 million impact from the expiration of a power buyback agreement with Power Agency. Fuel used in electric generation decreased $14 million compared to the same period in 2007 primarily due to a decrease in deferred fuel expense of $31 million, partially offset by an increase in current year fuel costs of $17 million. Deferred fuel expense decreased primarily due to a $48 million impact of the implementation of the North Carolina comprehensive energy legislation (See “Other Matters – Regulatory Environment”), partially offset by a $10 million increase driven by higher fuel costs. Current year fuel costs increased primarily due to an increase in fuel prices, partially offset by a change in the generation mix and lower system requirements.

Operation and Maintenance

O&M expenses were $766 million for the nine months ended September 30, 2008, which represents a $4 million increase compared to the same period in 2007. O&M expenses increased primarily due to a $24 million increase in nuclear expenses, of which $11 million relates to refurbishments, preventative maintenance and incremental outage expenses at Brunswick Nuclear Plant (Brunswick), and a $7 million increase in estimated environmental remediation expenses (See Note 12A), partially offset by lower plant outage and maintenance costs of $25 million (primarily due to one nuclear outage in the current year compared to two in the prior year).

Depreciation and Amortization

Depreciation and amortization expense was $379 million for the nine months ended September 30, 2008, which represents a $26 million increase compared to the same period in 2007. Depreciation and amortization expense increased primarily due to $25 million additional depreciation associated with the accelerated cost-recovery program for nuclear generating assets (See Note 4A) and the $9 million impact of depreciable asset base increases, partially offset by $10 million lower Clean Smokestacks Act amortization (See Note 4A).

Other

Other operating expenses consisted of gains of $6 million for the nine months ended September 30, 2008, primarily due to land sales. There were no net gains from land sales for the same period in 2007.

Total Other Income, net

Total other income, net of $28 million increased $3 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to $12 million favorable AFUDC equity related to increased Clean Smokestacks Act compliance and other eligible construction project costs, partially offset by $7 million lower interest income resulting from lower temporary investment balances. We expect AFUDC equity to continue to increase for the remainder of 2008, primarily due to increased spending on eligible construction projects.

Total Interest Charges, net

Total interest charges, net of $156 million decreased $9 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to $5 million lower interest as a result of lower average debt outstanding and $4 million favorable AFUDC debt related to increased Clean Smokestacks Act compliance and other eligible construction project costs.

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Income Tax Expense

Income tax expense increased $8 million for the nine months ended September 30, 2008, as compared to the same period in 2007, primarily due to the $8 million tax impact of higher pre-tax earnings, $4 million prior year changes in tax estimates and the $4 million impact of tax levelization, partially offset by the $6 million tax impact of employee stock-based benefits and the $5 million impact of the increase in AFUDC equity discussed above. 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. PEC’s income tax expense was increased by $2 million for the nine months ended September 30, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate, compared to a decrease of $2 million for the nine months ended September 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.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $143 million and $138 million for the three months ended September 30, 2008 and 2007, respectively. The increase in profits for the three months ended September 30, 2008, compared to the same period in 2007, was primarily due to increased retail base rates, favorable AFUDC and higher wholesale revenues, partially offset by higher interest expense, the unfavorable impact of weather, the unfavorable impact of retail customer growth and usage and severance expenses in 2008.

PEF contributed segment profits of $334 million and $266 million for the nine months ended September 30, 2008 and 2007, respectively. The increase in profits for the nine months ended September 30, 2008, compared to the same period in 2007, was primarily due to favorable AFUDC, increased retail base rates and higher wholesale revenues, partially offset by higher interest expense and 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 September 30, 2008, Compared to Three Months Ended September 30, 2007

REVENUES

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

(in millions)	Three Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential	$	722		$	(52	)		(6.7	)	$	774
Commercial		328			(8	)		(2.4	)		336
Industrial		81			(3	)		(3.6	)		84
Governmental		81			(3	)		(3.6	)		84
Total retail revenues		1,212			(66	)		(5.2	)		1,278
Wholesale		175			42			31.6			133
Unbilled		(5	)		(7	)		–			2
Miscellaneous		46			3			7.0			43
Total electric revenues		1,428			(28	)		(1.9	)		1,456
Less: Fuel and other pass-through revenues		(920	)		46			–			(966	)
Revenues excluding fuel and other pass-through revenues	$	508		$	18			3.7		$	490

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

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential		6,093			(397	)		(6.1	)		6,490
Commercial		3,523			(32	)		(0.9	)		3,555
Industrial		981			(27	)		(2.7	)		1,008
Governmental		901			(26	)		(2.8	)		927
Total retail energy sales		11,498			(482	)		(4.0	)		11,980
Wholesale		1,924			171			9.8			1,753
Unbilled		(184	)		(162	)		–			(22	)
Total kWh sales		13,238			(473	)		(3.4	)		13,711

PEF’s revenues, excluding fuel and other pass-through revenues of $920 million and $966 million for the three months ended September 30, 2008 and 2007, respectively, increased $18 million. The increase in revenues was primarily due to base rate increases and increased wholesale revenues, partially offset by the unfavorable impacts of weather and retail customer growth and usage. The increase in base rates was $28 million; Hines 4 being placed in service contributed $16 million in additional revenues and the transfer of Hines 2 cost recovery from the fuel clause to base rates contributed $12 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 $13 million primarily due to several new and amended contracts. Offsetting these favorable items were the $16 million unfavorable impact of weather driven by cooling degree days 8 percent lower than 2007 and the unfavorable retail customer growth and usage impact of $9 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’s average number of customers for the three months ended September 30, 2008, compared to the same period in 2007, decreased a net 2,000 customers. In comparison, PEF’s average number of customers for the three months ended September 30, 2007, compared to the same period in 2006, increased a net 22,000 customers. In the future, PEF’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates resulting from higher fuel and other recoverable costs.

PEF has secured 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 $826 million for the three months ended September 30, 2008, which represents a $1 million increase compared to the same period in 2007. Purchased power costs were $24 million higher for the three months ended September 30, 2008, primarily due to increased costs of $14 million in the current year driven by higher fuel costs and an increase in the recovery of deferred capacity costs of $9 million. Fuel used in electric generation decreased $23 million primarily due to a decrease in deferred fuel expense of $86 million, partially offset by an increase in current year fuel costs of $62 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 fuel prices.

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With the higher fuel costs experienced in 2008 and the anticipated high fuel costs for the remainder of 2008, the Florida Public Service Commission (FPSC) approved PEF’s petition requesting a mid-course correction to its fuel cost-recovery factors which was effective August 1, 2008 (See Note 4B).

Operation and Maintenance

O&M expenses were $201 million for the three months ended September 30, 2008, which represents a $12 million decrease when compared to the same period in 2007. O&M expenses decreased $8 million due to lower employee benefits, $6 million related to the expiration of a regulatory order spanning August 2007 to August 2008 to replenish storm damage reserves and $4 million lower environmental cost-recovery clause (ECRC) costs due to a decrease in the current year rates resulting from prior year over-recovery, partially offset by $6 million severance expenses in 2008. The severance expenses in 2008 resulted from the elimination of approximately 300 positions as part of a restructuring of our distribution operations in response to the ongoing economic downturn in Florida. The replenishment of storm damage reserves and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. In the aggregate, O&M expenses recoverable through base rates decreased approximately $3 million compared to the same period in 2007.

Depreciation and Amortization

Depreciation and amortization expense was $77 million for the three months ended September 30, 2008, which represents a $23 million decrease compared to the same period in 2007. Depreciation and amortization expense decreased $21 million due to lower amortization of unrecovered storm restoration costs and $7 million due to a write-off in 2007 of leasehold improvements primarily related to vacated office space, 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.

Total Other Income, net

Total other income, net of $30 million increased $17 million for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to $13 million favorable AFUDC equity related to eligible construction project costs and $4 million higher interest income driven by higher temporary investment balances resulting from a debt issuance. We expect AFUDC equity to continue to increase primarily due to increased spending on environmental initiatives and other eligible construction projects.

Total Interest Charges, net

Total interest charges, net were $61 million for the three months ended September 30, 2008, which represents a $19 million increase compared to the same period in 2007. Interest charges, net increased $27 million as a result of higher average debt outstanding, partially offset by $4 million favorable AFUDC debt related to increased eligible construction project costs.

Income Tax Expense

Income tax expense decreased $6 million for the three months ended September 30, 2008, compared to the same period in 2007, primarily due to the $5 million impact of the increase in AFUDC equity discussed above. AFUDC equity is excluded from the calculation of income tax expense.

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Nine Months Ended September 30, 2008, Compared to Nine Months Ended September 30, 2007

REVENUES

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

(in millions)	Nine Months Ended September 30,
Customer Class	2008			Change			% Change			2007
Residential	$	1,739			(59	)		(3.3	)	$	1,798
Commercial		852			(12	)		(1.4	)		864
Industrial		230			(6	)		(2.5	)		236
Governmental		217			(8	)		(3.6	)		225
Total retail revenues		3,038			(85	)		(2.7	)		3,123
Wholesale		420			106			33.8			314
Unbilled		27			(2	)		–			29
Miscellaneous		133			3			2.3			130
Total electric revenues		3,618			22			0.6			3,596
Less: Fuel and other pass-through revenues		(2,260	)		76			–			(2,336	)
Revenues excluding fuel and other pass-through revenues	$	1,358		$	98			7.8		$	1,260

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

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2008		Change			% Change			2007
Residential		14,854		(293	)		(1.9	)		15,147
Commercial		9,252		127			1.4			9,125
Industrial		2,855		13			0.5			2,842
Governmental		2,468		(18	)		(0.7	)		2,486
Total retail energy sales		29,429		(171	)		(0.6	)		29,600
Wholesale		5,225		855			19.6			4,370
Unbilled		751		(168	)		–			919
Total kWh sales		35,405		516			1.5			34,889

PEF’s revenues, excluding fuel and other pass-through revenues of $2.260 billion and $2.336 billion for the nine months ended September 30, 2008 and 2007, respectively, increased $98 million. The increase in revenues was primarily due to base rate increases and increased wholesale revenues, partially offset by unfavorable retail customer growth and usage. The increase in base rates was $72 million; Hines 4 being placed in service contributed $42 million in additional revenues and the transfer of Hines 2 cost recovery from the fuel clause to base rates contributed $30 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 $41 million primarily due to several new and amended contracts. PEF’s base rate and wholesale revenue favorability was partially offset by the unfavorable retail customer growth and usage impact of $22 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 nine months of 2008 than had been experienced in recent periods. PEF’s average number of customers for the nine months ended September 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 nine months ended September 30, 2007, compared to the same period in 2006, increased a net 27,000 customers. In the future, PEF’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates resulting from higher fuel and other recoverable costs.

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EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.981 billion for the nine months ended September 30, 2008, which represents a $10 million decrease compared to the same period in 2007. Fuel used in electric generation decreased $105 million compared to the same period in 2007 due to lower deferred fuel expense of $353 million, partially offset by increased current year fuel costs of $248 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 increased fuel prices. Purchased power costs were $95 million higher for the nine months ended September 30, 2008, primarily due to increased current year purchases of $73 million as a result of higher fuel costs and an increase in the recovery of deferred capacity costs of $22 million.

As previously discussed, the FPSC approved PEF’s petition requesting a mid-course correction to its fuel cost-recovery factors, which was effective August 1, 2008 (See Note 4B).

Operation and Maintenance

O&M expenses were $621 million for the nine months ended September 30, 2008, which represents a $35 million increase when compared to the same period in 2007. O&M expenses increased $49 million related to replenishment of storm damage reserves, which began in August 2007 and continued through August 2008 in accordance with a regulatory order, and $6 million severance expenses in 2008, partially offset by $11 million lower ECRC costs due to a decrease in the current year rates resulting from prior year over-recovery and a $9 million sales and use tax audit adjustment. The severance expenses in 2008 resulted from the elimination of approximately 300 positions as part of a restructuring of our distribution operations in response to the ongoing economic downturn in Florida. The replenishment of storm damage reserves and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. In the aggregate, O&M expenses recoverable through base rates decreased $5 million compared to the same period in 2007.

Depreciation and Amortization

Depreciation and amortization expense was $229 million for the nine months ended September 30, 2008, which represents a $68 million decrease compared to the same period in 2007. Depreciation and amortization expense decreased $75 million due to lower amortization of unrecovered storm restoration costs and $7 million due to a write-off in 2007 of leasehold improvements primarily related to vacated office space, partially offset by the $15 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 nine months ended September 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 nine months ended September 30, 2008, consists of a gain on a land sale. The other operating expenses of $12 million for the nine months ended September 30, 2007, resulted from 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 $71 million increased $41 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to $38 million favorable AFUDC equity related to costs associated with eligible construction projects. We expect AFUDC equity to continue to increase primarily due to increased spending on environmental initiatives and other eligible construction projects.

Total Interest Charges, net

Total interest charges, net were $144 million for the nine months ended September 30, 2008, which represents a $26 million increase compared to the same period in 2007. The increase was primarily due to $45 million higher interest as a result of higher average debt outstanding. Partially offsetting this increase was $11 million favorable AFUDC

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debt related to costs associated with eligible construction projects and an $8 million interest benefit resulting from the resolution of tax matters in 2008.

Income Tax Expense

Income tax expense increased $26 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to the $36 million tax impact of higher pre-tax income compared to the prior year and the $4 million prior year benefit related to the closure of certain federal tax years and positions, partially offset by the $15 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 $7 million for the nine months ended September 30, 2008, compared to a decrease of $3 million for the nine months ended September 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  September 30,						Nine Months Ended  September 30,
(in millions)	2008			2007			2008			2007
Other interest expense	$	(54	)	$	(57	)	$	(165	)	$	(149	)
Contingent value obligations		–			1			(2	)		(2	)
Tax levelization		1			5			1			4
Other income tax benefit		18			23			59			81
Other		–			(2	)		4			(16	)
Corporate and Other after-tax expense	$	(35	)	$	(30	)	$	(103	)	$	(82	)

Other interest expense increased $16 million for the nine months ended September 30, 2008, compared to the same period in 2007, 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 to operations that were sold later in 2007. No interest expense was allocated to discontinued operations for the three months ended September 30, 2008, and an immaterial amount of interest expense was allocated to discontinued operations for the nine months ended September 30, 2008. An immaterial amount and $12 million of interest expense was allocated to discontinued operations for the three and nine months ended September 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 September 30, 2008 and 2007, the CVOs had fair values of approximately $36 million and $34 million, respectively, and average unit prices of $0.37 and $0.35, respectively. We recorded an unrealized gain of $1 million for the three months ended September 30, 2007, and no adjustment for the three months ended September 30, 2008, to record the changes in fair value of the CVOs. We recorded net unrealized losses of $2 million for the nine months ended September 30, 2008 and 2007.

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 and $5 million for the three months ended September 30, 2008 and 2007, respectively, and $1 million and $4 million for the nine months ended September 30, 2008 and 2007, respectively, in order to maintain an effective rate consistent with the estimated

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

Other income tax benefit decreased $22 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to the $14 million prior year benefit related to the closure of certain federal tax years and positions.

Other decreased $20 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily due to $12 million decreased indirect corporate overhead due to divestitures completed in 2007 and $11 million decreased legal expenses.

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 nine months ended September 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 for the three months ended September 30, 2007, compared to no earnings for the same period in 2008, and net earnings from discontinued operations of $21 million and $72 million for the nine months ended September 30, 2008 and 2007, respectively. The decrease in net earnings from discontinued operations for the three and nine months ended September 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 nine months ended September 30, 2007, we reversed $1 million and $18 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 loss 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.

CCO’s operations generated net earnings from discontinued operations of $2 million and net losses from discontinued operations of $1 million for the three months ended September 30, 2008 and 2007, respectively, and net losses from discontinued operations of $1 million and $280 million for the nine months ended September 30, 2008 and 2007, respectively. The decrease in net losses from discontinued operations for the nine months ended

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September 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 nine months ended September 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 were $1 million for each of the three months ended September 30, 2008 and 2007, and $5 million and $9 million for the nine months ended September 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 nine months ended September 30, 2008, we recorded additional gains of $3 million, net of tax. For the three and nine months ended September 30, 2007, we recorded additional gains of $1 million and $2 million, net of tax.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Our 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. As discussed under “Future Liquidity and Capital Resources” below, synthetic fuels tax credits provide an additional source of liquidity as those credits are realized.

Progress Energy, Inc. is a holding company and, as such, has no revenue-generating operations of its own. The Parent’s primary cash needs are its common stock dividend and interest and principal payments on its $2.6 billion of senior unsecured debt. The Parent’s ability to meet these needs is dependent on the earnings and cash flows of the Utilities, the ability of the Utilities and other subsidiaries to pay dividends or repay funds to the Parent, the Parent’s commercial paper and bank facilities, and the Parent’s ability to access the long-term debt and equity capital markets. The Utilities have not paid, and do not currently expect to pay, dividends to the Parent in 2008. There are a number of factors that impact the Utilities’ ability to pay dividends to the Parent, including capital expenditure decisions and the timing of recovery of fuel and other pass-through costs. Although we cannot predict the level of dividends that the Utilities may pay to the Parent in the near term, we do not currently expect changes to the Parent's common stock dividend policy.

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.

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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 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.

We expect to fund our 2008 capital expenditures and common stock dividend with cash from operations, issuance of short-term and long-term debt, proceeds from the first quarter sale of the remainder of our nonregulated businesses, and periodic common stock sales from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans. For the fiscal year 2008, we anticipate realizing approximately $130 million from the sale of common stock through these plans. At September 30, 2008, we had $403 million in cash and cash equivalents.

The financial market distress of September and October 2008 has made it more difficult and expensive for companies to raise both short-term and long-term capital. As shown in the table below, we have a number of financial institutions that support our combined $2.030 billion revolving credit facilities for the Parent, PEC and PEF, thereby limiting our dependence on any one individual institution. The credit facilities serve as back-ups to our commercial paper programs. At September 30, 2008, we had no outstanding borrowings under our credit facilities. In November 2008, the Parent borrowed $600 million under its revolving credit agreement (RCA) as discussed below.

(in millions)	Total Commitment
Credit Provider	Progress Energy		Parent(a)		PEC		PEF
JPMorgan Chase Bank, N.A.	$	225.0	$	141.0	$	44.0	$	40.0
Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch		200.0		95.0		45.0		60.0
Barclays Bank PLC		190.5		100.0		20.5		70.0
Bank of America, N.A.		190.0		98.0		22.0		70.0
Citibank, N.A.		180.0		111.0		34.0		35.0
Wachovia Bank, N.A.		175.5		53.0		82.5		40.0

Royal Bank of Scotland plc		169.0		92.0		77.0		–
The Bank of New York Mellon		120.0		35.0		40.0		45.0
SunTrust Bank		115.0		50.0		20.0		45.0
Morgan Stanley Bank		100.0		50.0		50.0	–
William Street Commitment Corporation		100.0		100.0	–		–
Deutsche Bank AG,  New York Branch		95.0		50.0	–			45.0
UBS Loan Finance LLC		80.0		80.0	–		–
BNP Paribas		50.0		50.0	–		–
Branch Banking & Trust Co.		25.0		25.0	–		–
First Tennessee Bank N.A.		15.0	–			15.0	–
Total commitment	$	2,030.0	$	1,130.0	$	450.0	$	450.0

(a)   To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At September 30, 2008, the Parent had $495 million in commercial paper outstanding and $29 million of letters of credit issued, which were supported by the RCA.

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At September 30, 2008, we had limited mark-to-market exposure to certain financial institutions under pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions for both the Parent and PEC as disclosed in the table below. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates.

(dollars in millions)	Number of Counterparties		Net Mark-to-Market Asset Position		Net Mark-to-Market Liability Position
Parent		3	$	2	$	1
PEC		3		2		1
Progress Energy total		6	$	4	$	2

At September 30, 2008, PEC and PEF had limited counterparty mark-to-market exposure for financial commodity hedges (primarily gas and oil hedges) due to spreading our concentration risk over a number of partners, as disclosed in the table below. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. The mark-to-market exposure in the table takes into account collateral held for or paid to counterparties.

(dollars in millions) Financial Counterparty Type	Number of Counterparties(a)		Net Mark-to-Market Asset Position		Net Mark-to-Market Liability Position
PEC
Financial institutions		9	$	4	$	26
PEF
Financial institutions		16		49		78
Energy companies		3		1		32
PEF total		19		50		110
Progress Energy total		28	$	54	$	136

(a)   PEC also had positions with two energy companies, which were not material.

Our pension trust funds, nuclear decommissioning trust funds and short-term investments do not include material investments in the securities of institutions that have recently been sold, taken over or filed for bankruptcy.

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 $621 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to the $347 payment made in 2007 to exit the Georgia contracts (See Note 3B); a $306 million increase from the change in accounts receivable related to our divested CCO operations and former synthetic fuels businesses; a $251 million increase from income taxes, net; a $118 million increase from the change in accounts payable; an $87 million increase related to derivative assets in 2007 at our divested CCO operations; and $65 million in premiums paid in 2007 for derivative contracts in our synthetic fuels businesses (See Note 9A). These impacts were partially offset by a $358 million decrease in the recovery of fuel costs, primarily 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; a $110 million decrease from inventory, primarily coal, driven by higher prices; and a $108 million decrease in

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collateral held associated with derivative contracts for our synthetic fuels businesses. The primary driver of the change in accounts receivable was the settlement of $234 million of derivative receivables related to derivative contracts for our former synthetic fuels businesses (see Note 9A). The increase from income taxes, net was primarily due to $252 million in income tax payments made in 2007 related to the sale of natural gas drilling and production business (see Note 3D). The primary drivers of the change in accounts payable were the impact of rising fuel prices at the Utilities and the change in accounts payable related to our divested CCO operations.

INVESTING ACTIVITIES

Net cash used by investing activities increased by $826 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. This is due primarily to a $595 million decrease in proceeds from sales of discontinued operations and other assets, net of cash divested; a $410 million increase in capital expenditures for utility property additions at PEF, partially offset by a $69 million decrease in utility property additions at PEC. These impacts were partially offset by a $97 million decrease in net purchases of short-term investments included in available-for-sale securities and other investments and a $40 million decrease in nuclear fuel additions. At PEF, the increase in utility property additions was primarily due to a $343 million increase in environmental compliance expenditures and a $109 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 nine months ended September 30, 2008, proceeds from sales of discontinued operations and other assets of $63 million primarily included proceeds from the sale of Terminals and Coal Mining (see Notes 3A and 3C). During the nine months ended September 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 increased $1 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The increase in net cash provided by financing activities was primarily due to PEF’s $1.475 billion net proceeds and PEC’s $322 million net proceeds from the issuance of long-term debt in 2008 discussed below, compared to $742 million in net proceeds in 2007. The increase in proceeds from long-term debt issuances was offset by a $590 million increase in long-term debt retirements; $176 million in payments on short-term debt; an $80 million decrease in short-term indebtedness, and $85 million in cash distributions to owners of minority interests of consolidated subsidiaries primarily related to the settlement of Ceredo Synfuel LLC’s (Ceredo) synthetic fuels derivatives contracts (See Note 9A).

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 RCAs 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, the Parent amended its RCA with a syndication of financial institutions to extend the termination date by one year. The extension was effective on May 2, 2008. The RCA is now scheduled to expire on May 3, 2012.

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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 August 14, 2008, PEF redeemed the entire outstanding $450 million principal amount of its Series A Floating Rate Notes due November 14, 2008, at 100 percent of par plus accrued interest. The redemption was funded with a portion of the proceeds from the June 18, 2008 debt issuance.

On November 3, 2008, the Parent borrowed $600 million under its RCA to reduce rollover risk in the commercial paper markets. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity.

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 nine months ended September 30, 2008, respectively, we issued approximately 1.5 million shares and 2.5 million shares of common stock resulting in approximately $64 million and $106 million in proceeds. Included in these amounts were approximately 1.5 million shares and 2.4 million shares for proceeds of approximately $63 million and $104 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. For the three and nine months ended September 30, 2007, respectively, we issued approximately 0.3 million shares and 3.0 million shares of common stock resulting in approximately $12 million and $134 million in proceeds. Included in these amounts were approximately 0.2 million shares and 0.7 million shares for proceeds of approximately $12 million and $35 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At September 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”). A portion of 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 September 30, 2008, we have carried forward $803 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.

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.

We expect to be able to meet our future liquidity needs through cash from operations, commercial paper issuance, availability under our credit facilities and long-term financings. To the extent necessary, we may also use periodic 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 rates and shorter available durations. In the latter half of the first quarter of 2008 and continuing into the second quarter of 2008, the market improved; however, there was volatility in commercial interest rates. In September 2008, the financial markets significantly deteriorated and the short-term credit markets tightened again, resulting in a further increase in interest rates and shorter available durations. Prior to the end of the third quarter of 2008, we were able to issue commercial paper to meet our short-term financing needs

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with maturities past the quarter-end, albeit at higher interest rates. In September 2008, the weighted average interest rate for the Parent’s outstanding commercial paper balance increased 56 basis points to 3.47% compared to August 2008. The interest rate increase resulted in an immaterial increase in interest expense for September 2008 compared to August 2008. PEC and PEF did not have any outstanding commercial paper balances during September 2008. In November 2008, the Parent borrowed $600 million under its RCA. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity. If liquidity conditions deteriorate further 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 extending the term of our borrowings under the Parent’s RCA, issuing short-term floating rate notes, and/or issuing long-term debt.

Progress Energy and its subsidiaries have approximately $11.053 billion in outstanding debt. Currently, $860 million of our Utility debt obligations, which consists of approximately $620 million at PEC and approximately $240 million at PEF, 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 PEC’s bonds and Syncora Guarantee Inc., formerly XL Capital Assurance, Inc., (Syncora) insures PEF’s bonds.

In 2008, 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 (SIFMA) Index or the London Interbank Offered Rate (LIBOR). The interest rates for PEC’s portfolio of tax-exempt securities reset based on the SIFMA index. The interest rates for PEF’s portfolio of tax-exempt securities reset based on one-month 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 Syncora in February 2008 by Moody’s and S&P caused an initial increase in market volatility and an increase in interest rates. The June 2008 downgrades of Syncora by Moody’s and S&P to B2 and BBB-, respectively, and Ambac by Moody’s and S&P to Aa3 and AA, respectively, did not materially impact the reset rates of the Utilities’ tax-exempt bonds. In October 2008, Syncora was downgraded again by Moody’s to Caa1. We do not expect this to materially impact the reset rates of the Utilities’ tax-exempt securities.

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 decreased as the underlying indices trended down through the middle of September 2008. However, during the second half of September 2008, the financial markets deteriorated further and the SIFMA index dramatically increased, thereby causing a significant increase in the interest rate for many of PEC’s tax-exempt auction rate securities. One-month LIBOR also increased. The increase in interest rates will increase the Utilities’ interest expense for 2008. However, since the interest rates for these bonds reset on either a weekly or monthly basis, while the SIFMA index resets weekly and LIBOR resets daily, the total impact to 2008 interest expense cannot be determined at this time. In September 2008, the Utilities’ interest expense related to tax-exempt bonds increased by an immaterial amount compared to August 2008 and the September 2008 weighted average interest rate related to tax-exempt bonds increased 43 basis points to 4.29% compared to August 2008. The September 2008 weighted average interest rate increase compared to August 2008 for PEC was 50 basis points to 3.93% and 27 basis points to 5.20% for PEF. Continued volatility in the indices that dictate our interest rate resets and rating agency downgrades that move our tax-exempt bonds below A2/A- could result in the continuation of higher interest rate resets. We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our defined benefit pension plans. Although there are a number of factors that impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the obligations under our defined benefit pension plans.

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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.

At September 30, 2008, the current portion of our long-term debt was $400 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. Regulatory developments since our 2007 Form 10-K that are expected to have a material impact on our liquidity 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. Subsequently, PEC jointly filed a settlement agreement with CIGFUR, CUCA and the NCUC Public Staff. Under the terms of the settlement agreement, PEC would collect $203 million of deferred fuel costs ratably over a three-year period beginning December 1, 2008, compared with a one-year recovery period proposed in PEC’s original request. Amounts to be collected in years beginning December 1, 2009 and 2010, will bear interest at a rate equal to the five-year United States Treasury Note plus 150 basis points. If the settlement agreement is approved, the increase would take effect on or about December 1, 2008, and would increase residential electric bills by $8.79 per

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1,000 kWh, or 9.1 percent. A hearing on the settlement agreement was held on September 16, 2008. The NCUC is expected to make a decision on this settlement agreement in November 2008. We cannot predict the outcome of this matter.

PEC has begun implementing a series of DSM and energy-efficiency programs and has deferred $6 million of implementation and program costs for future recovery. On October 14, 2008, the NCUC approved PEC’s request for approval of four DSM and energy-efficiency programs. On April 29, 2008, PEC filed for NCUC approval of a distribution system demand response (DSDR) program. PEC anticipates that the DSDR program will require an investment of approximately $260 million over five years. We cannot predict the outcome of the DSDR program filing or whether any of the programs will produce the expected operational and economic results.

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.  A hearing has been scheduled on the 2006 and 2007 coal purchases for April 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 percent 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 increased by $2.48 per 1,000 kWh, or 2.29 percent. On October 15, 2008, PEF filed a request with the FPSC to seek approval of a cost adjustment for the under-recovery of fuel costs in 2008 and other recovery-clause factors. PEF asked the FPSC to approve an increase in residential electric bills of $27.28 per 1,000 kWh, or 24.7 percent, effective January 1, 2009. The FPSC is scheduled to hold hearings on the cost adjustment proposal November 4-6, 2008. We cannot predict the outcome of this matter.

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 $26 million at September 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 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.

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As discussed further in Note 4 and “Other Matters – Nuclear”, on August 12, 2008, the FPSC issued the final order granting 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 October 14, 2008, the FPSC voted to approve the inclusion of preconstruction and carrying charges of $357 million as well as site selection costs of $38 million in establishing PEF's 2009 capacity cost-recovery clause factor.

During 2008, PEF filed for recovery of costs incurred to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) under Florida’s comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule. The current project estimate of fully loaded costs is $364 million. On August 19, 2008, the FPSC granted PEF’s petition to amend its request to recover costs for the nuclear uprate project under the nuclear cost-recovery rule.

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 September 30, 2008, we have issued $402 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 September 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.

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 September 30, 2008, contracts procured though our subsidiaries have increased our aggregate purchase obligations for fuel and purchased power by $7.417 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.

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We have noncontributory defined benefit retirement plans for substantially all full-time employees that provide pension benefits. The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our defined benefit pension plans. Although there are a number of factors that impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the obligations under our defined benefit pension plans.

PEC

Through September 30, 2008, PEC’s fuel and purchased power commitments increased by $3.495 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 $2.156 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 $487 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.

In July 2008, PEC entered into an amendment to an existing transportation service agreement with an intrastate pipeline for firm pipeline transportation capacity to support PEC’s gas supply needs for the period from April 2011 through May 2030. The total additional cost to PEC associated with this amendment is estimated to be approximately $54 million. The amendment is subject to several conditions precedent, including state regulatory approval, the completion and commencement of operation of necessary related intrastate natural 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 September 30, 2008, PEF’s fuel and purchased power commitments increased by $3.922 billion from $12.566 billion, as stated in Note 22A in the 2007 Form 10-K. As discussed in Note 22A in the 2007 Form 10-K, PEF entered into certain conditional contracts for gas supply and transportation. Due to the conditions of these contracts, the associated estimated costs were not included in our or PEF’s contractual cash obligations table at December 31, 2007. Additional conditional gas supply and transportation contracts were entered into during the second quarter of 2008. During 2008, the conditions were satisfied and several gas supply and transportation contracts totaling $3.255 billion became effective. These contracts for the supply of natural gas and associated firm pipeline transportation augment PEF’s gas supply needs for various periods from September 2008 through January 2032.  The estimated costs associated with these agreements are approximately $81 million in 2008, $436 million in 2009, $570 million in 2010, $602 million in 2011, $548 million in 2012, and $1.018 billion thereafter. Also, the increase in gas supply and transportation purchase commitments includes new contracts along with the impact of price increases on certain existing contracts that are market price indexed. Coal purchase commitments increased by approximately $804 million; of this increase, approximately $230 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.

In April 2008, PEF entered into conditional contracts 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 these agreements is estimated to be approximately $2.176 billion. The contracts are 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 contracts, 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 $987 million. Due to the conditions of these agreements, the estimated costs associated with these agreements are

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not included in the increase in PEF’s fuel and purchased power commitments discussed above.

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 September 30, 2008, $1.088 billion of tax credits had been used to offset regular federal income tax liability and $803 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 March 2007. For the three months ended September 30, 2007, we recorded net pre-tax gains of $74 million related to these contracts, including $26 million attributable to Ceredo which was attributed to minority interest for the

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portion of the gain subsequent to disposal. For the nine months ended September 30, 2007, we recorded net pre-tax gains of $105 million related to these contracts, including $36 million attributable to Ceredo, of which $21 million were attributed to minority interest for the portion of the gain 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 nine months ended September 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 potentially 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, the 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 the Governor and legislature by January 1, 2009. In complying with the provisions of the law, PEF would be able to recover its reasonable prudent compliance costs. However, until the rulemaking processes are completed, we cannot predict the costs of complying with the law.

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During 2007, the North Carolina legislature passed comprehensive energy legislation, which became law on August 20, 2007. The law includes provisions for REPS, 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 required PEC to submit its first annual REPS compliance plan as part of its integrated resource plan, which was filed on September 2, 2008. 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 DSDR 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. On October 14, 2008, the NCUC approved PEC’s request for its EnergyWise™ program as well as three other DSM and energy-efficiency programs.

Also on April 29, 2008, PEC filed for NCUC approval of its DSDR 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 DSDR program has been scheduled by the NCUC for December 17, 2008.

We cannot predict the outcome of the DSDR program filing or whether any of the DSM and energy-efficiency 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 standard, and the FPSC staff has drafted a renewable portfolio standard (RPS) that would require that 20 percent of electricity produced in the state come from renewable resources by 2041. The FPSC has not formally proposed a RPS rule. 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. Additional development and

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discussion of the recommendations has occurred through a stakeholder process in 2008.The Energy and Climate Action Team submitted its final report to the governor on October 15, 2008. The report’s recommendations encourage the development and implementation of energy-efficiency and conservation measures, implementation of a climate registry, consideration of a cap-and-trade approach to reducing the state’s greenhouse gas emissions and a recommendation to implement a RPS of 20 percent by 2020. The FDEP’s first workshop on the greenhouse gas cap-and-trade rulemaking is scheduled for December 11, 2008. The rulemaking is expected to continue through 2009. 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 producing electricity from swine waste and other plant or animal sources, solar, hydrogen, biomass and landfill-gas technologies. We are evaluating the feasibility of producing electricity from these and other 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. In 2007, PEC announced a two-year moratorium on constructing new coal-fired plants while pursuing expansion of energy-efficiency and conservation programs. If PEC proceeds with construction of a new nuclear plant, the new plant would not be online until at least 2019 (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.PEF submitted Part I of the Application for Federal Loan Guarantees for Nuclear Power Facilities on September 29, 2008, for the proposed Levy nuclear project. PEF was one of 19 applicants that submitted Part I of the application. Part II of the application is due on December 19, 2008. We cannot predict if PEF’s application will be approved.

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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 2019 (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. On October 6, 2008, the NRC docketed, or accepted for review, the Levy nuclear project 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. 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 issued the final order granting the petition for the Determination of Need for the proposed nuclear power plants on August 12, 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. On May 29, 2008, the Florida Department of Community Affairs (FDCA) issued its final determination that the amendments to the Levy County Comprehensive Plan are in compliance with land use regulations.

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.

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

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adequate review of the projects costs recoverable under the FPSC nuclear cost-recovery rule (see discussion of nuclear cost-recovery rule below).  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. On October 2, 2008, the FPSC staff recommended that PEF recover all prudently incurred costs under the nuclear cost-recovery rule. On October 14, 2008, the FPSC voted to approve the inclusion of preconstruction and carrying charges as well as site selection costs in establishing PEF's 2009 capacity cost-recovery clause factor.

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”).

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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.

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 potential and pending claims cannot be predicted. 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

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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 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. On September 24, 2008, petitions for rehearing were filed by the EPA, the Utility Air Regulatory Group, the National Mining Association and several environmental groups. PEC and PEF are members of the Utility Air Regulatory Group. On October 21, 2008, the Court issued an order directing petitionersto address (1) whether any party is seeking to vacate the CAIR, and (2) whether the court should stay its mandate until EPA promulgates a revised rule. The Court will not issue its mandate until after it evaluates the responses to this order and renders a decision on the petitions for rehearing. The outcome of this matter cannot be predicted.

The Utilities are 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 complete 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 and the market prices for emission allowances have declined. At September 30, 2008, PEC had approximately $25 million in SO2 emission allowances, which will be utilized to comply with existing Clean Air Act requirements, and an immaterial amount of NOx emission allowances. In order to achieve compliance with the requirements of the CAIR pursuant to its Integrated Clean Air Compliance Plan (discussed further in “Compliance Strategy”), PEF needed to purchase CAIR seasonal and annual NOx allowances. During the three months ended September 30, 2008, PEF reduced the value of its annual NOx allowance inventory by $59 million due to the uncertainty of whether the allowances will ultimately be used, and

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reduced the value of its seasonal NOx allowance inventory by approximately $1 million based on current market prices. 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 retail portion of the costs of these allowances through its ECRC. Accordingly, PEF recorded a $57 million regulatory asset for the retail portion of its annual and seasonal NOx allowances. Therefore, there was no material impact to PEF’s results of operations for the reduction in value of its NOx allowance inventory. On August 29, 2008, PEF filed for recovery of its CAIR expenses, including NOx allowance inventory expense, through the ECRC. A hearing on the matter is scheduled for November 4-6, 2008. At September 30, 2008, PEF had approximately $6 million in seasonal NOx emission allowance inventory and approximately $14 million in SO2 emission allowance inventory. SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements.

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 filed petitions for rehearing by the full court of appeals, which were denied on May 20, 2008. On September 17, 2008, the Utility Air Regulatory Group filed a petition for writ of certiorari with the U.S. Supreme Court with regard to the decision that vacated the CAMR. On October 17, 2008, the EPA filed a similar petition. 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 any review granted by the Supreme Court 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. If it stands, 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. Consequently, 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, the CAVR and mercury regulation. The air quality controls installed to comply with the requirements of the NOx SIP Call Rule under Section 110 of the Clean Air Act (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.

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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 programs by North Carolina and South Carolina 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 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. Amounts presented in the tables exclude AFUDC. 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 estimated costs to comply with the CAVR prior to the July 11, 2008 D.C. Court of Appeals’ decision regarding CAIR 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.

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Progress Energy
Air and Water Quality Estimated Required Environmental Expenditures  (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2008
Clean Smokestacks Act		2002–2013	$	1,500 – 1,600	$	986
In-process CAIR projects(a)		2005–2010		1,200		760
CAVR(b)		–2017		–		–
Mercury regulation(c)		2006–2017		–		8
Total air quality				2,700 – 2,800		1,754
Clean Water Act Section 316(b) (d)				–		–
Total air and water quality			$	2,700 – 2,800	$	1,754

PEC
Air and Water Quality Estimated Required Environmental Expenditures  (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2008
Clean Smokestacks Act		2002–2013	$	1,500 – 1,600	$	986
In-process CAIR projects(a)		2005–2008		–		15
CAVR(b)		–2017		–		–
Mercury regulation(c)		2006–2017		–		8
Total air quality				1,500 – 1,600		1,009
Clean Water Act Section 316(b) (d)				–		–
Total air and water quality			$	1,500 – 1,600	$	1,009

PEF
Air and Water Quality Estimated Required Environmental Expenditures  (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2008
In-process CAIR projects(a)		2005–2010	$	1,200	$	745
CAVR(b)		–2017		–		–
Mercury regulation(c)				–		–
Total air quality				1,200		745
Clean Water Act Section 316(b) (d)				–		–
Total air and water quality			$	1,200	$	745

(a) The Utilities are continuing construction of 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 first phase 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.

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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 had been held in abeyance but was resumed following the D.C. Court of Appeal’s decision that vacated the CAIR. The outcome of this matter cannot be predicted.

National Ambient Air Quality Standards

On December 21, 2005, the EPA announced proposed changes to the National Ambient Air Quality Standards (NAAQS) for particulate matter. The EPA proposed to lower the 24-hour standard for particulate matter less than 2.5 microns in diameter (PM 2.5) from 65 micrograms per cubic meter to 35 micrograms per cubic meter. In addition, the EPA proposed to establish a new 24-hour standard of 70 micrograms per cubic meter for particulate matter that is between 2.5 and 10 microns in diameter (PM 2.5-10). The EPA also proposed to eliminate the current standards for particulate matter less than 10 microns in diameter (PM 10). On September 20, 2006, the EPA 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 October 16, 2008, the EPA published a revision to the NAAQS for lead to 0.15 micrograms per cubic meter rolling three-month average. The former standard was 1.5 micrograms per cubic meter, calendar quarter average. The 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

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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 will be generated at certain affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes is currently ongoing and will result in permitting, construction and treatment requirements imposed on the Utilities now and into the 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.

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

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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

As discussed in Note 2, on January 1, 2008, we adopted SFAS No. 157, "Fair Value Measurements" (SFAS No. 157), for all recurring financial assets and liabilities. 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). SFAS No. 157 also requires disclosure of the impact on earnings of fair value measurements based on significant unobservable inputs. Our financial assets and liabilities are primarily comprised of derivative financial instruments and marketable debt and equity securities held in our nuclear decommissioning trusts, substantially all of which are valued using directly or indirectly observable inputs. In addition, substantially all unrealized gains and losses on derivatives and all unrealized gains and losses on nuclear decommissioning trust investments are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Therefore, the impact of fair value measurements from recurring financial assets and liabilities on our or the Utilities’ earnings is not significant.

We will adopt SFAS No. 157 for all nonrecurring nonfinancial assets and liabilities, such as reporting units and long-lived asset groups measured at fair value for impairment purpose, on January 1, 2009. We do not expect the adoption 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.

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

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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 $57 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to the $74 million increase from the change in receivables largely driven by the timing of settlements with affiliated companies; a $50 million increase in cash receipts from a wholesale customer due to the expiration of a prepayment agreement; and lower interest payments of $18 million. These impacts were partially offset by a $53 million decrease from inventory, primarily coal, driven by higher prices and $39 million in higher income tax payments.

Cash used by investing activities decreased $40 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The decrease in cash used in investing activities was primarily due to a $69 million decrease in utility property additions, primarily related to lower environmental compliance expenditures, and a $28 million decrease in nuclear fuel additions. These impacts were partially offset by a $57 million decrease in net proceeds from short-term investments included in available-for-sale securities and other investments. Available-for-sale securities and other investments include marketable debt and equity securities and investments held in nuclear decommissioning and benefit investment trusts.

Net cash used by financing activities decreased by $5 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The decrease in net cash used by financing activities was primarily due to $322 million in net proceeds from the issuance of long-term debt in 2008 and $108 million in dividends paid to the Parent in 2007, offset by a $100 million increase in the retirement of long-term debt and decreases in short-term debt and advances from affiliated companies in 2008. PEC’s 2008 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources”.

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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.

 OTHER MATTERS

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

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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 decreased $372 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The decrease in operating cash flow was primarily due to a $321 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 $51 million increase in inventory primarily driven by coal price increases, and net refunds of $45 million received during the prior year for cash collateral previously paid to counterparties on derivative contracts. These impacts were partially offset by $42 million related to the extension of PEF’s storm recovery surcharge, which began in August 2007 and expired in August 2008.

Cash used by investing activities increased $63 million for the nine months ended September 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 $410 million increase in capital expenditures for utility property additions, including a $343 million increase in environmental compliance expenditures and a $109 million increase in nuclear project expenditures, partially offset by a $180 million increase in net proceeds from short-term investments included in available-for-sale securities and other investments and a $149 million decrease from changes in advances to affiliated companies. 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 provided by financing activities increased $333 million for the nine months ended September 30, 2008, when compared to the corresponding period in the prior year. The increase in cash provided by financing activities was primarily due to PEF’s $1.475 billion in net proceeds from issuance of long-term debt in 2008, partially offset by $742 million in net proceeds from the issuance of long-term debt in 2007 and a $445 million increase in long-term debt retirements. PEF’s 2008 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources”.

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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.

OTHER MATTERS

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

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ITEM 3.                      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various risks related to changes in market conditions. 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 annual and interim credit reviews using, among other things, publicly available credit ratings of such counterparties (See Note 9). Both PEC and PEF also have limited counterparty exposure for commodity hedges (primarily gas and oil hedges) due to spreading our concentration risk over a number of partners.

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 September 30, 2008, has changed from December 31, 2007. The total notional amount of fixed rate long-term debt at September 30, 2008, was $9.345 billion, with an average interest rate of 6.17% and fair market value of $8.8 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 September 30, 2008, was $961 million, with an average interest rate of 5.45% and fair market value of $961 million. 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 September 30, 2008 and December 31, 2007, approximately 13 percent of consolidated debt was in floating rate mode.

Based on our variable rate long-term debt balances at September 30, 2008, a 100 basis point change in interest rates would result in an annual interest expense change of approximately $10 million. Based on our commercial paper balances at September 30, 2008, a 100 basis point change in interest rates would result in an annual interest expense change of approximately $5 million.

The financial market distress of September 2008 resulted in higher interest expense for floating rate debt, including tax-exempt auction rate securities and commercial paper. See “Future Liquidity and Capital Resources” in Item 2 for additional information.

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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.

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

At September 30, 2008, the Parent had $150 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions. The Parent had no open interest rate cash flow hedges at December 31, 2007. At September 30, 2008, PEC had $150 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions. 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 had no open interest rate cash flow hedges at September 30, 2008, and December 31, 2007. See "Future Liquidity and Capital Resources" in Item 2 above for additional information.

(dollars in millions)	Notional Amount		Pay			Receive (a)	Fair Value			Exposure (b)
Parent
Risk hedged at September 30, 2008
Anticipated 10-year debt issue	$	150		4.44	%	3-month LIBOR	$	1		$	(3	)
PEC
Risk hedged at September 30, 2008
Anticipated 10-year debt issue	$	150		4.46	%	3-month LIBOR	$	1		$	(3	)
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% and 4.05% at December 31, 2007 and September 30, 2008, respectively.

(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. In January 2008, PEF entered into a $100 million notional 10-year forward starting swap and a $100 million notional 30-year forward starting swap. In May 2008, PEF entered into combined

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$100 million notional 10-year forward starting swaps and $150 million notional 30-year forward starting swaps.  In June 2008, PEF entered into combined $100 million notional 30-year forward starting swaps. In June 2008, PEF terminated 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.

In October 2008, the Parent and PEC each entered into $50 million notional 10-year forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

MARKETABLE SECURITIES PRICE RISK

At September 30, 2008 and December 31, 2007, the fair value of our nuclear decommissioning trust funds was $1.210 billion and $1.384 billion, respectively, including $723 million and $804 million, respectively, for PEC and $487 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. The trust funds have no material investments in the securities of financial institutions that were recently sold, taken over or filed for bankruptcy.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At September 30, 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 September 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 September 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

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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. We had a $108 million cash collateral liability related to these contracts at December 31, 2007, included in other current liabilities on the Consolidated Balance Sheet. 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 September 30, 2007, we recorded net pre-tax gains of $74 million related to these contracts, including $26 million attributable to Ceredo, which was attributed to minority interest for the portion of the gain subsequent to disposal. For the nine months ended September 30, 2007, we recorded net pre-tax gains of $105 million related to these contracts, including $36 million attributable to Ceredo, of which $21 million were attributed to minority interest for the portion of the gain 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.

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 nine months ended September 30, 2008, PEC recorded a net realized gain of $6 million and $12 million, respectively. During each of the three and nine months ended September 30, 2007, PEC recorded a net realized loss of $6 million. During the three and nine months ended September 30, 2008, PEF recorded a net realized gain of $118 million and $237 million, respectively. During the three and nine months ended September 30, 2007, PEF recorded a net realized loss of $23 million and $45 million, respectively.

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

At September 30, 2008, the fair value of PEC’s commodity derivative instruments was recorded as a $1 million short-term derivative asset position included in prepayments and other current assets, a $19 million long-term derivative asset position included in other assets and deferred debits, a $24 million short-term liability position included in other current liabilities, and a $18 million long-term derivative liability position included in other liabilities and deferred credits on the PEC Consolidated Balance Sheet. At December 31, 2007, the fair value of such instruments was recorded as a $19 million long-term derivative asset position included in other assets and deferred debits and a $4 million short-term derivative liability position included in other current liabilities on the PEC Consolidated Balance Sheet. PEC had no cash collateral position at September 30, 2008 or December 31, 2007.

At September 30, 2008, the fair value of PEF’s commodity derivative instruments was recorded as a $59 million short-term derivative asset position included in current derivative assets, a $90 million long-term derivative asset position included in derivative assets, a $133 million short-term liability position included in derivative liabilities, and a $73 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 $14 million cash collateral receivable included in prepayments and other current assets and a $14 million cash collateral liability included in other current liabilities at September 30, 2008, on the PEF Balance Sheet, and no cash collateral position at December 31, 2007.

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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 September 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 nine months ended September 30, 2008 and 2007.

At September 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.

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).

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.

During the third quarter of 2008, Progress Energy announced that Peter M Scott, III, Executive Vice President and Chief Financial Officer of Progress Energy would retire effective September 1, 2008. Mark F. Mulhern, Senior Vice President - Finance, was appointed as Chief Financial Officer of Progress Energy and its subsidiaries upon Mr. Scott’s retirement.

Other than the above-referenced item, there has been no change in our internal control over financial reporting during the quarter ended September 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

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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.

During the third quarter of 2008, Progress Energy announced that Peter M Scott, III, Executive Vice President and Chief Financial Officer of Progress Energy and PEC would retire effective September 1, 2008.Mark F. Mulhern, Senior Vice President - Finance of Progress Energy was appointed as Chief Financial Officer of Progress Energy and PEC upon Mr. Scott’s retirement.

Other than the above-referenced item, there has been no change in PEC’s internal control over financial reporting during the quarter ended September 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.

During the third quarter of 2008, Progress Energy announced that Peter M Scott, III, Executive Vice President and Chief Financial Officer of Progress Energy and PEF would retire effective September 1, 2008.Mark F. Mulhern, Senior Vice President - Finance of Progress Energy, was appointed as Chief Financial Officer of Progress Energy and PEF upon Mr. Scott’s retirement.

Other than the above-referenced item, there has been no change in PEF’s internal control over financial reporting during the quarter ended September 30, 2008, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1.                      LEGAL PROCEEDINGS

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

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors 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

ISSUER PURCHASES OF EQUITY SECURITIES FOR THIRD QUARTER OF 2008

Period	(a) Total Number of Shares (or Units) Purchased(1)(2)		(b) Average Price Paid Per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs(1)		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs(1)
July 1 – July 31		20,763	$	41.19		N/A		N/A
August 1 – August 31		29,500	$	41.94		N/A		N/A
September 1 – September 30		101,400	$	43.41		N/A		N/A
Total		151,663	$	42.18		N/A		N/A

(1)   As of September 30, 2008, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2)   151,663 shares of our common stock were purchased in open-market transactions by the plan administrator to meet share delivery obligations under the Savings Plan for Employees of Florida Progress Corporation.

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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

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SIGNATURES

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

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
	FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
Date: November 5, 2008	(Registrants)
	By: /s/ Mark F. Mulhern
	Mark F. Mulhern
	Senior 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.

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