Duke Energy Progress 10-Q 2007 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

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	o	No	x

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

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

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

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

As of October 31, 2007, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	259,201,899
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

PART I.  FINANCIAL INFORMATION

Item 1.              Financial Statements

Unaudited Interim Financial Statements:

Progress Energy, Inc. (Progress Energy)

Carolina Power & Light Company

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

Florida Power Corporation

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

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

Item 3.              Quantitative and Qualitative Disclosures about Market Risk

Item 4.              Controls and Procedures

PART II.  OTHER INFORMATION

Item 1.              Legal Proceedings

Item 1A.           Risk Factors

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

Item 6.              Exhibits

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
2006 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2006
401(k)	Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC	Allowance for funds used during construction
AHI	Affordable housing investment
AOCI	Accumulated other comprehensive income, a component of common stock equity
ARO	Asset retirement obligation
Annual Average Price	Average wellhead price per barrel for unregulated domestic crude oil for the year
Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
Audit Committee	Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART	Best Available Retrofit Technology
Bcf	Billion cubic feet
Broad River	Broad River LLC’s Broad River Facility
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CCO	Former Progress Ventures segment’s nonregulated Competitive Commercial Operations
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
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	Coal terminals and marketing operations that blend and transload coal as part of the transportation network for coal delivery
Coal Mining	Five Progress Fuels subsidiaries engaged in the coal mining business
Coal and Synthetic Fuels	Business segment 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	Collectively, the Parent, PESC and consolidation entities
Corporate and Other	Corporate and Other segment includes Corporate as well as other nonregulated businesses
CR3	PEF’s Crystal River Unit No. 3 Nuclear Plant
CR4 and CR5	PEF’s 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

4

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
DSM	Demand-side management
Earthco	Four coal-based solid synthetic fuels limited liability companies of which three are wholly owned
ECCR	Energy Conservation Cost Recovery Clause
ECRC	Environmental Cost Recovery Clause
EIA	Energy Information Agency
EIP	Equity Incentive Plan
Energy Delivery	Distribution operations of the Utilities
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric reliability organization
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FDCA	Florida Department of Community Affairs
FGT	Florida Gas Transmission Company
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”
Fitch	Fitch Ratings
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 FIN 39-1	FASB Staff Position No. 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain Contracts”
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Gas	Former Progress Ventures segment’s natural gas drilling and production business
the Georgia Contracts	Fixed price full-requirement contracts formerly serviced by CCO
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Region	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
Gulfstream	Gulfstream Gas System, L.L.C.
Harris	PEC’s Shearon Harris Nuclear Plant
IBEW	International Brotherhood of Electrical Workers
IRS	Internal Revenue Service
kV	Kilovolt
kVA	Kilovolt-ampere
kWh/s	Kilowatt-hour/s
Level 3	Level 3 Communications, Inc.
LIBOR	London Inter Bank Offering Rate
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in Part I, Item 2 of this Form 10-Q

5

Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
MW	Megawatts
MWh	Megawatt-hours
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCDWQ	North Carolina Division of Water Quality
NCNG	North Carolina Natural Gas Corporation
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NOL	Net operating loss
NOPR	Notice of Proposed Rulemaking
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
PRB	Powder River Basin
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
Progress Ventures	Former business segment that primarily engaged in nonregulated energy generation, energy marketing activities and natural gas drilling and production
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
PTC	Progress Telecommunications Corporation

6

PT LLC	Progress Telecom, LLC
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
REPS	North Carolina Renewable Energy and Efficiency Portfolio Standard
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity
Rowan	Rowan County Power, LLC
RSA	Restricted stock awards program
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 the 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 and Hedging Activities”
SFAS No. 142	Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 143	Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 144	Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS No. 157	Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”
SFAS No. 158	Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”
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”
SNG	Southern Natural Gas Company
SO2	Sulfur dioxide

7

Subordinated Notes	7.10% Junior Subordinated Defferable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
the Threshold Price	Price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits begin to be reduced
the Trust	FPC Capital I
the Utilities	Collectively, PEC and PEF
Winchester Production	Winchester Production Company, Ltd.
Winter Park	City of Winter Park, Fla.

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 facilities, 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; the financial resources and capital needed to comply with environmental laws and our ability to recover eligible costs under cost-recovery clauses or base rates; weather conditions that directly influence the production, delivery and 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; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; economic fluctuations and the corresponding impact on our customers, including downturns in the housing and consumer credit markets; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the impact on our facilities and businesses from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the Progress Registrants’ ability to maintain their current credit ratings and the impact on the Progress Registrants’ financial condition and ability to meet their cash and other financial obligations in the event their credit ratings are downgraded; the impact that increases in leverage may have on each of the Progress Registrants; the impact of derivative contracts used in the normal course of business; the investment performance of our pension and benefit plans; the Progress Registrants’ ability to control costs, including pension and benefit expense, and achieve our cost-management targets for 2007 and 2008; our ability to utilize tax credits from the production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); the impact that future crude oil prices may have on our earnings from our coal-based solid synthetic fuels businesses; the 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, 2006 (2006 Form 10-K), which was filed with the SEC on March 1, 2007, 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 it assess the effect of each such factor on the Progress Registrants.

9

PART I.  FINANCIAL INFORMATION

Item 1.                      Financial Statements

PROGRESS ENERGY, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2007

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per share data)	2007			2006			2007			2006
Operating revenues
Electric	$	2,741		$	2,599		$	6,934		$	6,666
Diversified business		359			177			906			631
Total operating revenues		3,100			2,776			7,840			7,297
Operating expenses
Utility
Fuel used in electric generation		929			860			2,381			2,259
Purchased power		390			391			894			880
Operation and maintenance		456			383			1,337			1,216
Depreciation and amortization		221			243			662			705
Taxes other than on income		135			141			384			380
Other		−			−			14			(2	)
Diversified business
Cost of sales		329			189			926			672
Depreciation and amortization		2			2			6			21
Impairment of long-lived assets		−			−			−			91
Gain on the sales of assets		−			−			(17	)		(4	)
Other		11			10			38			44
Total operating expenses		2,473			2,219			6,625			6,262
Operating income		627			557			1,215			1,035
Other income (expense)
Interest income		7			13			21			37
Other, net		7			(9	)		33			(1	)
Total other income		14			4			54			36
Interest charges
Net interest charges		159			148			444			473
Allowance for borrowed funds used during construction		(5	)		−			(12	)		(4	)
Total interest charges, net		154			148			432			469
Income from continuing operations before income tax and minority interest		487			413			837			602
Income tax expense		154			133			175			205
Income from continuing operations before minority interest		333			280			662			397
Minority interest in subsidiaries’ (income) loss, net of tax		(14	)		3			8			(10	)
Income from continuing operations		319			283			670			387
Discontinued operations, net of tax		−			36			(269	)		(70	)
Net income	$	319		$	319		$	401		$	317
Average common shares outstanding – basic		257			251			256			250
Basic earnings per common share
Income from continuing operations	$	1.24		$	1.13		$	2.62		$	1.55
Discontinued operations, net of tax		−			0.14			(1.05	)		(0.28	)
Net income	$	1.24		$	1.27		$	1.57		$	1.27
Diluted earnings per common share
Income from continuing operations	$	1.24		$	1.13		$	2.61		$	1.54
Discontinued operations, net of tax		−			0.14			(1.05	)		(0.28	)
Net income	$	1.24		$	1.27		$	1.56		$	1.26
Dividends declared per common share	$	0.610		$	0.605		$	1.830		$	1.815

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

10

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2007			December 31, 2006
ASSETS
Utility plant
Utility plant in service	$	24,624		$	23,743
Accumulated depreciation		(10,681	)		(10,064	)
Utility plant in service, net		13,943			13,679
Held for future use		10			10
Construction work in progress		1,880			1,289
Nuclear fuel, net of amortization		355			267
Total utility plant, net		16,188			15,245
Current assets
Cash and cash equivalents		617			265
Short-term investments		178			71
Receivables, net		1,148			930
Inventory		999			969
Deferred fuel cost		177			196
Deferred income taxes		50			159
Assets of discontinued operations		28			887
Derivative assets		185			1
Prepayments and other current assets		162			107
Total current assets		3,544			3,585
Deferred debits and other assets
Regulatory assets		1,113			1,231
Nuclear decommissioning trust funds		1,358			1,287
Diversified business property, net		41			31
Miscellaneous other property and investments		441			456
Goodwill		3,655			3,655
Other assets and deferred debits		233			211
Total deferred debits and other assets		6,841			6,871
Total assets	$	26,573		$	25,701
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 259 and 256 million shares issued and outstanding, respectively	$	5,996		$	5,791
Unearned ESOP shares (2 million shares)		(37	)		(50	)
Accumulated other comprehensive loss		(54	)		(49	)
Retained earnings		2,521			2,594
Total common stock equity		8,426			8,286
Preferred stock of subsidiaries – not subject to mandatory redemption		93			93
Minority interest		64			10
Long-term debt, affiliate		271			271
Long-term debt, net		8,916			8,564
Total capitalization		17,770			17,224
Current liabilities
Current portion of long-term debt		464			324
Short-term debt		550			–
Accounts payable		826			712
Interest accrued		124			171
Dividends declared		159			156
Customer deposits		250			227
Liabilities of discontinued operations		12			189
Income taxes accrued		26			284
Other current liabilities		806			755
Total current liabilities		3,217			2,818
Deferred credits and other liabilities
Noncurrent income tax liabilities		285			306
Accumulated deferred investment tax credits		142			151
Regulatory liabilities		2,385			2,543
Asset retirement obligations		1,359			1,306
Accrued pension and other benefits		896			957
Other liabilities and deferred credits		519			396
Total deferred credits and other liabilities		5,586			5,659
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	26,573		$	25,701

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

11

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine Months Ended September 30	2007			2006
Operating activities
Net income	$	401		$	317
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax		269			70
Impairment of assets		−			91
Depreciation and amortization		754			797
Deferred income taxes		87			(52	)
Investment tax credits		(9	)		(9	)
Deferred fuel cost		28			197
Deferred income		(98	)		(52	)
Other adjustments to net income		104			149
Cash (used) provided by changes in operating assets and liabilities
Receivables		(201	)		(44	)
Inventory		(18	)		(116	)
Prepayments and other current assets		(151	)		(67	)
Accounts payable		112			33
Income taxes, net		(342	)		64
Other current liabilities		89			93
Other assets and deferred debits		(60	)		35
Other liabilities and deferred credits		(8	)		3
Net cash provided by operating activities		957			1,509
Investing activities
Gross utility property additions		(1,404	)		(1,012	)
Diversified business property additions		(5	)		(1	)
Nuclear fuel additions		(198	)		(71	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		659			548
Purchases of available-for-sale securities and other investments		(1,072	)		(1,687	)
Proceeds from sales of available-for-sale securities and other investments		939			1,611
Other investing activities		16			(16	)
Net cash used by investing activities		(1,065	)		(628	)
Financing activities
Issuance of common stock		134			73
Proceeds from issuance of long-term debt, net		742			397
Net increase (decrease) in short-term debt		550			(175	)
Retirement of long-term debt		(287	)		(848	)
Dividends paid on common stock		(469	)		(454	)
Cash distributions to minority interests of consolidated subsidiary		(10	)		(74	)
Other financing activities		22			(42	)
Net cash provided (used) by financing activities		682			(1,123	)
Cash (used) provided by discontinued operations
Operating activities		(220	)		115
Investing activities		(2	)		(143	)
Net increase (decrease) in cash and cash equivalents		352			(270	)
Cash and cash equivalents at beginning of period		265			605
Cash and cash equivalents at end of period	$	617		$	335

12

Supplemental disclosures
Significant non-cash transactions
Capital lease obligation incurred	$	182	$	–
Note receivable for disposal of ownership interest in Ceredo	$	48	$	–
Non-cash property additions accrued for as of September 30	$	192	$	145
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

13

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2007

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Operating revenues
Electric	$	1,286		$	1,200		$	3,339		$	3,113
Diversified business		−			−			1			1
Total operating revenues		1,286			1,200			3,340			3,114
Operating expenses
Fuel used in electric generation		385			322			1,041			880
Purchased power		109			135			243			279
Operation and maintenance		246			218			762			722
Depreciation and amortization		118			128			353			383
Taxes other than on income		52			51			151			141
Other		1			−			−			−
Total operating expenses		911			854			2,550			2,405
Operating income		375			346			790			709
Other income (expense)
Interest income		5			7			16			18
Other, net		(1	)		(10	)		9			(12	)
Total other income (expense)		4			(3	)		25			6
Interest charges
Interest charges		58			44			169			158
Allowance for borrowed funds used during construction		(2	)		−			(4	)		(1	)
Total interest charges, net		56			44			165			157
Income before income tax		323			299			650			558
Income tax expense		119			110			234			207
Net income		204			189			416			351
Preferred stock dividend requirement		1			1			2			2
Earnings for common stock	$	203		$	188		$	414		$	349

See Notes to PEC Consolidated Interim Financial Statements.

14

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2007			December 31, 2006
ASSETS
Utility plant
Utility plant in service	$	14,872		$	14,356
Accumulated depreciation		(6,905	)		(6,408	)
Utility plant in service, net		7,967			7,948
Held for future use		3			3
Construction work in progress		615			617
Nuclear fuel, net of amortization		277			209
Total utility plant, net		8,862			8,777
Current assets
Cash and cash equivalents		89			71
Short-term investments		–			50
Receivables, net		533			473
Receivables from affiliated companies		85			27
Notes receivable from affiliated companies		–			24
Inventory		505			497
Deferred fuel cost		168			196
Prepayments and other current assets		16			45
Total current assets		1,396			1,383
Deferred debits and other assets
Regulatory assets		811			777
Nuclear decommissioning trust funds		782			735
Miscellaneous other property and investments		190			193
Other assets and deferred debits		134			155
Total deferred debits and other assets		1,917			1,860
Total assets	$	12,175		$	12,020
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,048		$	2,010
Unearned ESOP common stock		(37	)		(50	)
Accumulated other comprehensive loss		(6	)		(1	)
Retained earnings		1,726			1,431
Total common stock equity		3,731			3,390
Preferred stock – not subject to mandatory redemption		59			59
Long-term debt, net		3,182			3,470
Total capitalization		6,972			6,919
Current liabilities
Current portion of long-term debt		300			200
Short-term debt		150			–
Notes payable to affiliated companies		1			–
Accounts payable		273			310
Payables to affiliated companies		132			108
Interest accrued		50			69
Customer deposits		68			59
Income taxes accrued		127			68
Current portion of unearned revenue		18			71
Other current liabilities		237			154
Total current liabilities		1,356			1,039
Deferred credits and other liabilities
Noncurrent income tax liabilities		914			909
Accumulated deferred investment tax credits		123			128
Regulatory liabilities		1,098			1,320
Asset retirement obligations		1,048			1,004
Accrued pension and other benefits		555			581
Other liabilities and deferred credits		109			120
Total deferred credits and other liabilities		3,847			4,062
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	12,175		$	12,020

See Notes to PEC Consolidated Interim Financial Statements.

15

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine Months Ended September 30	2007			2006
Operating activities
Net income	$	416		$	351
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		419			446
Deferred income taxes and investment tax credits, net		62			23
Deferred fuel cost (credit)		7			(47	)
Other adjustments to net income		(37	)		32
Cash (used) provided by changes in operating assets and liabilities
Receivables		(62	)		24
Receivables from affiliated companies		(34	)		22
Inventory		(2	)		(23	)
Prepayments and other current assets		(2	)		6
Accounts payable		16			21
Payables to affiliated companies		23			(8	)
Income taxes, net		64			(26	)
Other current liabilities		13			21
Other assets and deferred debits		(19	)		24
Other liabilities and deferred credits		11			2
Net cash provided by operating activities		875			868
Investing activities
Gross utility property additions		(587	)		(493	)
Nuclear fuel additions		(159	)		(65	)
Purchases of available-for-sale securities and other investments		(472	)		(736	)
Proceeds from sales of available-for-sale securities and other investments		498			772
Changes in advances to affiliates		1			–
Other investing activities		2			(3	)
Net cash used by investing activities		(717	)		(525	)
Financing activities
Net increase (decrease) in short-term debt		150			(73	)
Retirement of long-term debt		(200	)		–
Changes in advances from affiliates		–			(9	)
Dividends paid to parent		(108	)		(255	)
Dividends paid on preferred stock		(2	)		(2	)
Other financing activities		20			1
Net cash used by financing activities		(140	)		(338	)
Net increase in cash and cash equivalents		18			5
Cash and cash equivalents at beginning of period		71			125
Cash and cash equivalents at end of period	$	89		$	130
Supplemental disclosures
Significant non-cash transactions
Non-cash property additions accrued for as of September 30	$	67		$	88
See Notes to PEC Consolidated Interim Financial Statements.

16

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

INTERIM FINANCIAL STATEMENTS

September 30, 2007

UNAUDITED STATEMENTS of INCOME
	Three Months Ended September 30,					Nine Months Ended September 30,
(in millions)	2007			2006		2007			2006
Operating revenues	$	1,456		$	1,399	$	3,596		$	3,553
Operating expenses
Fuel used in electric generation		544			538		1,340			1,379
Purchased power		281			256		651			601
Operation and maintenance		213			171		586			515
Depreciation and amortization		100			108		297			301
Taxes other than on income		83			89		233			238
Other		−			−		12			(2	)
Total operating expenses		1,221			1,162		3,119			3,032
Operating income		235			237		477			521
Other income
Interest income		1			4		3			12
Other, net		12			6		27			8
Total other income		13			10		30			20
Interest charges
Interest charges		45			39		126			119
Allowance for borrowed funds used during construction		(3	)		−		(8	)		(3	)
Total interest charges, net		42			39		118			116
Income before income tax		206			208		389			425
Income tax expense		68			83		122			160
Net income		138			125		267			265
Preferred stock dividend requirement		−			−		1			1
Earnings for common stock	$	138		$	125	$	266		$	264

See Notes to PEF Interim Financial Statements.

17

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED BALANCE SHEETS
(in millions)	September 30, 2007			December 31, 2006
ASSETS
Utility plant
Utility plant in service	$	9,567		$	9,202
Accumulated depreciation		(3,719	)		(3,602	)
Utility plant in service, net		5,848			5,600
Held for future use		7			7
Construction work in progress		1,265			672
Nuclear fuel, net of amortization		78			58
Total utility plant, net		7,198			6,337
Current assets
Cash and cash equivalents		325			23
Short-term investments		178			−
Receivables, net		443			340
Receivables from affiliated companies		13			11
Deferred income taxes		73			86
Inventory		466			436
Income taxes receivable		−			47
Prepayments and other current assets		33			62
Total current assets		1,531			1,005
Deferred debits and other assets
Regulatory assets		302			454
Nuclear decommissioning trust funds		576			552
Miscellaneous other property and investments		46			45
Prepaid pension cost		192			174
Other assets and deferred debits		51			26
Total deferred debits and other assets		1,167			1,251
Total assets	$	9,896		$	8,593
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,107		$	1,100
Accumulated other comprehensive loss		(9	)		(1	)
Retained earnings		1,851			1,588
Total common stock equity		2,949			2,687
Preferred stock – not subject to mandatory redemption		34			34
Long-term debt, net		3,137			2,468
Total capitalization		6,120			5,189
Current liabilities
Current portion of long-term debt		84			89
Notes payable to affiliated companies		−			47
Accounts payable		485			292
Payables to affiliated companies		72			116
Interest accrued		28			38
Customer deposits		182			168
Derivative liabilities		31			89
Current regulatory liabilities		123			76
Other current liabilities		210			89
Total current liabilities		1,215			1,004
Deferred credits and other liabilities
Noncurrent income tax liabilities		420			466
Accumulated deferred investment tax credits		19			23
Regulatory liabilities		1,160			1,091
Asset retirement obligations		311			299
Accrued pension and other benefits		319			332
Other liabilities and deferred credits		332			189
Total deferred credits and other liabilities		2,561			2,400
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	9,896		$	8,593

See Notes to PEF Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED STATEMENTS of CASH FLOWS
(in millions)
Nine Months Ended September 30	2007			2006
Operating activities
Net income	$	267		$	265
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		313			323
Deferred income taxes and investment tax credits, net		(50	)		(46	)
Deferred fuel cost		21			244
Other adjustments to net income		27			9
Cash (used) provided by changes in operating assets and liabilities
Receivables		(110	)		(100	)
Receivables from affiliated companies		(2	)		6
Inventory		(22	)		(117	)
Prepayments and other current assets		56			(44	)
Accounts payable		137			43
Payables to affiliated companies		(46	)		(13	)
Income taxes, net		98			14
Other current liabilities		69			94
Other assets and deferred debits		(25	)		4
Other liabilities and deferred credits		(6	)		(28	)
Net cash provided by operating activities		727			654
Investing activities
Gross utility property additions		(819	)		(528	)
Nuclear fuel additions		(39	)		(6	)
Purchases of available-for-sale securities and other investments		(457	)		(547	)
Proceeds from sales of available-for-sale securities and other investments		279			547
Other investing activities		–			4
Net cash used by investing activities		(1,036	)		(530	)
Financing activities
Proceeds from issuance of long-term debt, net		742			–
Net decrease in short-term debt		–			(102	)
Retirement of long-term debt		(87	)		(47	)
Changes in advances from affiliates		(45	)		–
Dividends paid to parent		–			(176	)
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		2			–
Net cash provided (used) by financing activities		611			(326	)
Net increase (decrease) in cash and cash equivalents		302			(202	)
Cash and cash equivalents at beginning of period		23			218
Cash and cash equivalents at end of period	$	325		$	16
Supplemental disclosures
Significant non-cash transactions
Capital lease obligation incurred	$	182		$	–
Non-cash property additions accrued for as of September 30	$	125		$	48
See Notes to PEF Interim Financial Statements.

19

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED INTERIM FINANCIAL STATEMENTS

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

Each of the following combined notes to the unaudited 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 INTERIM FINANCIAL STATEMENTS

In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to the Combined Notes. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.           Organization

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

Our reportable operating segments are: PEC, PEF and Coal and Synthetic Fuels. Our PEC and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity. Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuels as defined under the Internal Revenue Code (the Code), the operation of synthetic fuels facilities for third parties, and coal terminal services. On September 14, 2007, we idled production of synthetic fuels at our majority-owned synthetic fuels facilities due to the current high level of oil prices. On October 12, 2007, based upon the continued high level of oil prices, unfavorable oil price projections through the end of 2007, and the expiration of the current synthetic fuels tax credit program at the end of 2007, we decided to permanently cease production of synthetic fuels at our majority-owned facilities. Our Corporate and Other segment (Corporate and Other) is comprised of the activities of the Parent and Progress Energy Service Company (PESC) as well as nonregulated businesses, which do not separately meet the disclosure requirements as a business segment.

PEC and PEF are regulated public utilities. PEC’s service territory covers portions of North Carolina and South Carolina and PEF’s covers portions of Florida. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory provisions of the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC); PEF is subject to the regulatory provisions of the Florida Public Service Commission (FPSC). Both of the Utilities are also subject to regulation by the United States Nuclear Regulatory Commission (NRC) and the FERC.

B.           Basis of Presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2006 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2006 (2006 Form 10-K).

In accordance with the provisions of Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. The intra-period tax allocation, which will have no impact on total year net income, maintains an effective tax rate consistent with the estimated annual effective tax rate. The fluctuations in the effective tax rate for interim periods are primarily due to the recognition of synthetic fuels tax credits and

21

seasonal fluctuations in energy sales and earnings from the Utilities. Income tax expense was increased (decreased) for the Progress Registrants for the three and nine months ended September 30, 2007 and 2006, as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Progress Energy	$	(26	)	$	(12	)	$	(3	)	$	7
PEC		(1	)		1			(2	)		–
PEF		(4	)		2			(3	)		2

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2007		2006		2007		2006
Progress Energy	$	92	$	89	$	229	$	223
PEC		30		28		78		71
PEF		62		61		151		152

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 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 2006 have been reclassified to conform to the 2007 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 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. At September 30, 2007, the total assets of Ceredo were $69 million and consisted primarily of derivative assets. See Note 3I 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 investments in five limited liability partnerships and limited liability corporations. At September 30, 2007, the aggregate additional maximum loss exposure that we could be required to record in our income statement as a result

22

of these arrangements was $6 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, 2007, 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 investments in 20 limited liability partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. At September 30, 2007, the aggregate maximum loss exposure that PEC could be required to record on its income statement as a result of these arrangements totals approximately $19 million, which primarily represents its net remaining investment in these entities. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure. See Note 1 in the 2006 Form 10-K for additional information.

PEF

PEF has interests in three variable interest entities for which PEF is not the primary beneficiary. These arrangements include investments in one operating lease, one venture capital fund and one building lease with a special-purpose entity. At September 30, 2007, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was $56 million. The majority of this exposure is related to a prepayment clause in the building lease and is not considered equity at risk. The creditors of these variable interest entities do not have recourse to the general credit of PEF in excess of the aggregate maximum loss exposure.

2. NEW ACCOUNTING STANDARD

Refer to Note 7 for information regarding our first quarter 2007 implementation of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48).

SFAS No. 157, “Fair Value Measurements”

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which redefines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” SFAS No. 157 establishes a fair value hierarchy that categorizes and prioritizes the inputs that should be used to estimate fair value. We will implement SFAS No. 157 as of January 1, 2008. We do not expect the adoption of SFAS No. 157 to have a material impact on our or the Utilities' financial position or results of operations.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”

In February 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115"

23

 (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 is effective as of the beginning of an entity's first fiscal year that begins after November 15, 2007, which for us is January 1, 2008. We are currently evaluating the impact of the adoption of SFAS No. 159, but we do not expect it to have a material impact on our or the Utilities' financial position or results of operations.

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

FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN 39), specifies what conditions must be met for an entity to have the right to offset assets and liabilities in the balance sheet and clarifies when it is appropriate to offset amounts recognized for forward, interest rate swap, currency swap, option, and other conditional or exchange contracts. FIN 39 also permits offsetting of fair value amounts recognized for multiple contracts executed with the same counterparty under a master netting arrangement. On April 30, 2007, the FASB issued Staff Position FIN 39-1 (FSP FIN 39-1) which amends portions of FIN 39 to make certain terms consistent with those used in SFAS No. 133. FSP FIN 39-1 also amends FIN 39 to allow for the offsetting of fair value amounts for the right to reclaim collateral assets or liabilities arising from the same master netting arrangement as the derivative instruments. We will implement the FSP as of January 1, 2008, as a retrospective change in accounting principle for all financial statements presented. We and the Utilities currently offset fair value amounts recognized for derivative instruments under master netting arrangements. Upon adoption of FSP FIN 39-1, we and the Utilities expect to change our accounting policy to not offset fair value amounts for such derivatives and related collateral. We expect this change in policy to result in increases to current and non-current assets, total assets, current and non-current liabilities, and total liabilities, but will have no impact on our or the Utilities’ results of operations or equity.

 3. DIVESTITURES

A.           CCO – Georgia Region

On March 9, 2007, our subsidiary, Progress 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 quarter ended March 31, 2007, we reversed $16 million after-tax of the impairment recorded in 2006. During each of the quarters ended June 30, 2007, and September 30, 2007, we reversed an additional $1 million after-tax of the impairment as a result of post-closing adjustments.

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

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of CCO as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the nine months ended September 30, 2007 and 2006, was $11 million and $28 million, respectively. Pre-tax interest expense allocated for the three months ended September 30, 2006, was $9 million. We ceased recording depreciation upon classification of the assets as discontinued operations in December 2006. After-tax depreciation expense during the three and nine months ended September 30, 2006, was $4 million and $11

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million, respectively. 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)	2007			2006			2007			2006
Revenues	$	1		$	141		$	407		$	485
Loss before income taxes		(1	)		(65	)		(444	)		(183	)
Income tax benefit		–			25			164			69
Net loss from discontinued operations		(1	)		(40	)		(280	)		(114	)
Reversal of estimated loss on disposal of discontinued operations, including income tax benefit of $1and $8, respectively		1			–			18			–
Loss from discontinued operations	$	–		$	(40	)	$	(262	)	$	(114	)

B.           Natural Gas Drilling and Production

On October 2, 2006, we sold our natural gas drilling and production business (Gas) to EXCO Resources, Inc. for approximately $1.1 billion in net proceeds. Gas included Winchester Production Company, Ltd. (Winchester Production), Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets Ltd.; all were subsidiaries of Progress Fuels. We used the proceeds from the sale primarily to reduce holding company debt and for other corporate purposes.

Based on the net proceeds associated with the sale, we recorded an after-tax net gain on disposal of $300 million during the year ended December 31, 2006. We recorded an after-tax loss of $1 million during the three months ended March 31, 2007, primarily related to working capital adjustments.

The accompanying consolidated financial statements have been restated for all periods presented to reflect all the operations of Gas as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the three and nine months ended September 30, 2006, was $4 million and $13 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in July 2006. After-tax depreciation expense during the nine months ended September 30, 2006, was $16 million. Results of Gas 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)	2007		2006			2007			2006
Revenues	$	–	$	100		$	–		$	192
Earnings before income taxes		–		88			–			138
Income tax benefit (expense)		1		(31	)		1			(54	)
Net earnings from discontinued operations		1		57			1			84
Loss on disposal of discontinued operations, including income tax benefit of $1		–		–			(1	)		–
Earnings from discontinued operations	$	1	$	57		$	–		$	84

C.           CCO – DeSoto and Rowan Generation Facilities

On May 2, 2006, our board of directors approved a plan to divest of two subsidiaries of PVI, DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (Rowan). DeSoto owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Fla., and Rowan owns a 925 MW dual-fuel combined cycle and combustion turbine electric generation facility in Rowan County, N.C. On May 8, 2006, we entered into definitive agreements to sell DeSoto and Rowan, including certain existing power supply contracts, to Southern Power Company, a subsidiary of Southern Company, for gross sales prices of approximately $80 million

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and $325 million, respectively. We used the proceeds from the sales to reduce debt and for other corporate purposes.

The sale of DeSoto closed in the second quarter of 2006 and the sale of Rowan closed during the third quarter of 2006. Based on the gross proceeds associated with the sales, we recorded an after-tax loss on disposal of $65 million during the nine months ended September 30, 2006.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of DeSoto and Rowan as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the nine months ended September 30, 2006, was $6 million. We ceased recording depreciation upon classification of the assets as discontinued operations in May 2006. After-tax depreciation expense during the nine months ended September 30, 2006, was $3 million. Results of DeSoto and Rowan discontinued operations for the three and nine months ended September 30 were as follows:

(in millions	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
Revenues	$	50		$	64
Earnings before income taxes		30			15
Income tax expense		(12	)		(6	)
Net earnings from discontinued operations		18			9
Loss on disposal of discontinued operations, including income tax benefit of $5 and $40, respectively		(6	)		(65	)
Earnings (loss) from discontinued operations	$	12		$	(56	)

D.           Progress Telecom, LLC

On March 20, 2006, we completed the sale of Progress Telecom, LLC (PT LLC) to Level 3 Communications, Inc. (Level 3). We received gross proceeds comprised of cash of $69 million and approximately 20 million shares of Level 3 common stock valued at an estimated $66 million on the date of the sale. Our net proceeds from the sale of approximately $70 million, after consideration of minority interest, were used to reduce debt. Prior to the sale, we had a 51 percent interest in PT LLC. See Note 11 for a discussion of the subsequent sale of the Level 3 stock.

Based on the net proceeds associated with the sale and after consideration of minority interest, we recorded an after-tax net gain on disposal of $24 million during the three months ended March 31, 2006. During the three months ended June 30, 2006, we recorded an additional after-tax gain of $5 million in connection with certain tax matters. During the three months ended September 30, 2006, we recorded a $1 million adjustment related to additional tax expenses resulting in a total after-tax gain of $28 million for the nine months ended September 30, 2006.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of PT LLC as discontinued operations. We ceased recording depreciation upon classification of the assets as discontinued operations in January 2006. After-tax depreciation expense during the nine months ended September 30, 2006, was $1 million. Results of PT LLC discontinued operations for the three and nine months ended September 30 were as follows:

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

In connection with the sale, PEC and PEF provided indemnification against costs associated with certain asset performances to Level 3. See general discussion of guarantees at Note 13B. The ultimate resolution of these matters could result in adjustments to the gain on sale in future periods.

E.           Dixie Fuels and Other Fuels Business

On March 1, 2006, we sold our 65 percent interest in Dixie Fuels Limited (Dixie Fuels) to Kirby Corporation for $16 million in cash. Dixie Fuels operates a fleet of four ocean-going dry-bulk barge and tugboat units. Dixie Fuels primarily transports coal from the lower Mississippi River to Progress Energy’s Crystal River facility. We recorded an after-tax gain of $2 million on the sale of Dixie Fuels.

The accompanying consolidated financial statements have been restated for all periods presented to reflect Dixie Fuels and the other fuels business as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated was less than $1 million for the three months ended September 30, 2006, and for the nine months ended September 30, 2007 and 2006. We ceased recording depreciation upon classification of the assets as discontinued operations. After-tax depreciation expense during the nine months ended September 30, 2006, was less than $1 million. Results of Dixie Fuels and other fuels business 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)	2007		2006			2007			2006
Revenues	$	–	$	–		$	–		$	5
Earnings before income taxes		–		6			1			10
Income tax expense		–		(3	)		(1	)		(4	)
Net earnings from discontinued operations		–		3			–			6
Gain on disposal of discontinued operations, including income tax expense of $1		–		–			2			2
Earnings from discontinued operations	$	–	$	3		$	2		$	8

F.      Coal Mining Businesses

On November 14, 2005, our board of directors approved a plan to divest of five subsidiaries of Progress Fuels engaged in the coal mining business (Coal Mining). On May 1, 2006, we sold certain net assets of three of our coal mining businesses to Alpha Natural Resources, LLC for gross proceeds of $23 million plus a $4 million working capital adjustment. As a result, during the nine months ended September 30, 2006, we recorded an after-tax loss of $13 million on the sale of these assets. The remaining coal mining operations are expected to be sold by March 31, 2008.

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The accompanying consolidated financial statements have been restated for all periods presented to reflect Coal Mining as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of the coal mines, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest expense allocated for the nine months ended September 30, 2006, was $1 million. There was less than $1 million allocated for the three months ended September 30, 2007 and 2006, and for the nine months ended September 30, 2007. We ceased recording depreciation expense upon classification of Coal Mining as discontinued operations in November 2005. 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)	2007			2006		2007			2006
Revenues	$	8		$	14	$	22		$	73
(Loss) earnings before income taxes		(2	)		1		(13	)		(4	)
Income tax benefit		1			2		4			3
Net (loss) earnings from discontinued operations		(1	)		3		(9	)		(1	)
Loss on disposal of discontinued operations, including income tax benefit of $17		–			–		–			(13	)
(Loss) earnings from discontinued operations	$	(1	)	$	3	$	(9	)	$	(14	)

G. Progress Rail Divestiture

On March 24, 2005, we completed the sale of Progress Rail Services Corporation (Progress Rail) to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds from the sale were approximately $429 million, consisting of $405 million base proceeds plus a working capital adjustment. Proceeds from the sale were used to reduce debt.

During the nine months ended September 30, 2006, we recorded after-tax loss on disposal of $3 million (including income tax benefit of $2 million) in connection with guarantees and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters to One Equity Partners, LLC. The ultimate resolution of these matters could result in adjustments to the loss on disposal in future periods. See general discussion of guarantees at Note 13B.

The accompanying consolidated financial statements reflect the operations of Progress Rail as discontinued operations.

H. Net Assets of Discontinued Operations

At September 30, 2007, the remaining assets and liabilities of Coal Mining were included in net assets of discontinued operations. At December 31, 2006, the assets and liabilities of CCO and the remaining assets and liabilities of Coal Mining and other fuels business were included in net assets of discontinued operations. The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets were as follows:

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(in millions)	September 30, 2007			December 31, 2006
Accounts receivable		$	–	$	45
Inventory			2		24
Other current assets			1		28
Total property, plant and equipment, net			18		573
Total other assets			7		217
Assets of discontinued operations		$	28	$	887
Accounts payable		$	–	$	43
Accrued expenses			1		122
Long-term liabilities			11		24
Liabilities of discontinued operations		$	12	$	189

I. Ceredo Synthetic Fuels Interests

On March 30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership interest in Ceredo, a subsidiary that produces and sells 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 are received as we produce and sell qualifying synthetic fuels on behalf of the buyer during 2007. As of September 30, 2007, we have received payments of $27 million on the note. Actual proceeds could differ based on actual production levels, which shall be determined by the buyer. The estimated production level of Ceredo subsequent to the transaction is 2.8 million tons. As of September 30, 2007, we have produced 2.0 million tons. The note bears interest at a rate equal to the three-month London Inter Bank Offering Rate (LIBOR) rate plus 1%. The estimated fair value of the note at the inception of the transaction was $48 million.

Pursuant to the terms of the disposal agreement, the buyer has the right to unwind the transaction if an Internal Revenue Service (IRS) reconfirmation private letter ruling is not received by November 9, 2007, or if certain adverse changes in tax law, as defined in the agreement, occur before November 19, 2007. Therefore, no gain on the disposal will be recognized prior to the expiration of these rights. Once these rights expire, deferred gains, if any, from the disposal will be recognized over time as we produce and sell qualifying synthetic fuels for the buyer. The IRS reconfirmation private letter ruling was received on October 29, 2007.

On the date of the transaction, the carrying value of the disposed ownership interest totaled $37 million, which consisted primarily of the fair value of crude oil call options purchased in January 2007. Subsequent to the disposal, we remain the primary beneficiary of Ceredo and continue to consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there is no net earnings impact from Ceredo’s operations and our net investment in Ceredo is zero. In connection with the disposal, Progress Fuels and Progress Energy provided guarantees and indemnifications for certain legal and tax matters to the buyer which reduces any potential deferred gain. The ultimate resolution of these matters could result in adjustments to the gain, if any, on disposal in future periods. See general discussion of guarantees at Note 13B.

4. REGULATORY MATTERS

A.           PEC Retail Rate Matters

BASE RATES

PEC’s base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC. In June 2002, the North Carolina Clean Smokestacks Act (Clean Smokestacks Act) was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxides (NOx) and sulfur dioxide (SO₂) from their North Carolina coal-fired power plants in phases by 2013. The Clean Smokestacks Act freezes North Carolina electric utility base rates for a five-year period ending in December 2007, unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return

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established and found reasonable by the NCUC in the respective utility’s last general rate case. Subsequent to 2007, PEC’s current North Carolina base rates will continue subject to traditional cost-based rate regulation.

During the rate freeze period, the legislation provides 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. For the three and nine months ended September 30, 2007, PEC recognized amortization of $8 million and $25 million, respectively. For the three and nine months ended September 30, 2006, PEC recognized amortization of $21 million and $65 million, respectively. PEC has recognized $560 million in cumulative amortization through September 30, 2007. We will record at least the remaining amortization requirement of $9 million during the three-month period ending December 31, 2007.

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 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 Associations (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. We cannot predict the outcome of this matter.

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

FUEL COST RECOVERY

On May 2, 2007, 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 $12 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements and to meet future expected fuel costs. On June 27, 2007, the SCPSC approved a settlement agreement filed jointly by PEC and all other parties to the proceedings. The settlement agreement resolved all issues and provided for a $12 million increase in fuel rates. Effective July 1, 2007, residential electric bills increased by $1.83 per 1,000 kWhs, or 1.9 percent, for fuel cost recovery.

On June 8, 2007, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. PEC asked the NCUC to approve a $48 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements, as discussed below. On September 25, 2007, the NCUC approved PEC’s petition. The increase took effect October 1, 2007, and increased residential electric bills by $1.30 per 1,000 kWhs, or 1.3 percent, for fuel cost recovery.

On June 2, 2006, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. On September 25, 2006, the NCUC approved a settlement agreement filed jointly by PEC, the NCUC Public Staff and CIGFUR. The settlement agreement provided for a $177 million, or 6.7 percent increase in rates effective October 1, 2006. The settlement agreement further provided for rate increases of approximately $50 million in 2007 and $30 million in 2008 and for PEC to collect its existing deferred fuel balance by September 30, 2009. PEC initially sought an increase of $292 million, or 11.0 percent, but agreed to a three-year phase-in of the increase in order to address concerns regarding the magnitude of the proposed increase. PEC will be allowed to calculate and collect interest at 6.0% on an amount equal to the under-recovery resulting from the difference between PEC’s fuel factor proposed in its original request to the NCUC and the settlement agreement’s fuel factor.

On November 21, 2006, CUCA filed an appeal with the North Carolina Tenth District Court of Appeals of the NCUC’s September 25, 2006, order on the grounds that the NCUC does not have the statutory authority to establish fuel rates for more than one year. PEC filed a motion to dismiss with the Court of Appeals on March 22, 2007. On October 24, 2007, CUCA filed a motion to withdraw their appeal.

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OTHER MATTERS

PEC filed petitions on September 14, 2006, and September 22, 2006, with the SCPSC and NCUC, respectively, seeking authorization to defer and amortize the respective jurisdictional portion of $18 million of previously recorded operation and maintenance (O&M) expense relating to certain environmental remediation sites (See Note 12A). On October 11, 2006, the SCPSC granted PEC’s petition to defer its jurisdictional amount, totaling $3 million, and amortize it over a five-year period beginning January 1, 2007. On October 19, 2006, the NCUC granted PEC’s petition to defer its jurisdictional amount, totaling $15 million, and amortize it over a five-year period. However, the NCUC order directed that amortization begin in 2006, with an amortization expense of $3 million. As a result, during the fourth quarter of 2006, PEC reversed $18 million of O&M expense, established a regulatory asset and recorded $3 million of amortization expense. During the three and nine months ended September 30, 2007, PEC recorded $1 million and $2 million, respectively, of amortization expense. Additionally, PEC reduced the regulatory asset by $5 million during the nine months ended September 30, 2007, based on newly available data regarding certain remediation sites and insurance proceeds (See Note 12A).

B.           PEF Retail Rate Matters

PASS-THROUGH CLAUSE COST RECOVERY

On September 4, 2007, PEF filed a request with the FPSC seeking approval of a cost adjustment to reflect a projected over-collection of fuel costs in 2007, declining projected fuel costs for 2008, and other recovery clause factors. PEF asked the FPSC to approve a $163 million, or 4.53 percent, decrease in rates effective January 1, 2008. This cost adjustment would decrease residential bills by $5.00 for the first 1,000 kWhs. As discussed in “Other Matters” below, residential base rates will increase effective January 1, 2008, by $2.73 for the first 1,000 kWhs. After considering the net effect of the base rate increase and the proposed fuel cost adjustment, 2008 residential bills would decrease by a net amount of $2.27 for the first 1,000 kWhs. The FPSC is scheduled to hold hearings on the cost adjustment proposal on November 6, 2007. We cannot predict the outcome of this matter.

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus interest, of alleged excessive past fuel recovery charges and SO₂ allowance costs 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, inclusive of interest, over a 12-month period beginning January 1, 2008. For the nine months ended September 30, 2007, PEF recorded a pre-tax other operating expense of $12 million, interest expense of $2 million and an associated regulatory liability for the disallowed fuel costs and interest. 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. PEF is also evaluating its options, including an appeal to the Florida Supreme Court of the FPSC’s October 10, 2007 order. We cannot predict the outcome of this matter. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish a separate docket on the prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. The OPC filed testimony in support of its position to require PEF to refund at least $14 million for alleged excessive fuel recovery charges for 2006 coal purchases. PEF believes its coal procurement practices have been prudent. We cannot predict the outcome of this matter.

On September 22, 2006, PEF filed a petition with the FPSC for Determination of Need to uprate Crystal River Unit No. 3 Nuclear Plant (CR3), bid rule exemption and 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 multi-stage uprate will increase CR3’s gross output by approximately 180 MW by 2012. Several design modifications will require a license amendment approved by the NRC. The petition filed with the FPSC included estimated project

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costs of approximately $382 million. These cost estimates may continue to change depending upon the results of more detailed engineering and development work and increased material, labor and equipment costs. On February 8, 2007, the FPSC issued an order approving the need certification petition and bid rule exemption. The request for recovery through PEF’s fuel recovery clause was transferred to a separate docket filed on January 16, 2007. On February 2, 2007, intervenors filed a motion to abate the cost-recovery portion of PEF’s request. On February 9, 2007, PEF requested that the FPSC deny the intervenors’ motion as legally deficient and without merit. On March 27, 2007, the FPSC denied the motion to abate and directed the staff of the FPSC to conduct a hearing to determine whether the revenue requirements of the uprate should be recovered through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony clarifying the scope of the project. The FPSC held a hearing on this matter on August 7 and 8, 2007. The staff of the FPSC recommended that PEF be allowed to recover prudent and reasonable costs of Phase 1, instrumentation modifications for improved accuracy, estimated at $6 million through the fuel clause. The staff of the FPSC recommended that the costs of all other phases, estimated at $376 million, be considered in a base rate proceeding. On October 19, 2007, PEF filed a notice of withdrawal of its cost recovery petition with the FPSC. PEF intends to re-file a petition in the fourth quarter of this year seeking cost recovery under Florida’s comprehensive energy bill enacted in 2006, and the FPSC's new nuclear cost recovery rule. We cannot predict the outcome of this matter.

OTHER MATTERS

On November 3, 2004, the FPSC approved PEF’s petition for Determination of Need for the construction of a fourth unit at PEF’s Hines Energy Complex. Hines Unit 4 is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to its ratepayers at a reasonable cost. Hines Unit 4 will be a combined cycle unit with a generating capacity of approximately 461 MW (summer rating). The estimated total in-service cost of Hines Unit 4 approved as part of the Determination of Need was $286 million. If the actual cost is less than the original estimate, ratepayers will receive the benefit of such cost under-runs. Any costs that exceed this estimate will not be recoverable absent, among other things, extraordinary circumstances as found by the FPSC in subsequent proceedings. The current estimate of in-service cost exceeds the initial project estimate due to what we believe to be extraordinary circumstances, including higher than anticipated land acquisition costs and unforeseen increases in commodity and labor costs. PEF filed a cost-recovery petition with the FPSC on April 30, 2007, to recover the full revenue requirements of Hines Unit 4, which has a current estimated in-service cost of $327 million, by increasing base rates $52 million, as provided for in PEF’s 2005 base rate agreement. Under this rate agreement, the base rate increase would become effective upon Hines Unit 4 being placed in service, which PEF anticipates will be on December 1, 2007. The 2005 base rate agreement also provides that concurrent with the in-service date of Hines Unit 4, PEF will transfer the cost of Hines Unit 2 to base rates from the fuel clause. On September 27, 2007, the staff of the FPSC recommended that PEF be allowed to recover the full in-service costs, including the $41 million cost in excess of the Determination of Need and increase base rates $52 million effective December 1, 2007, for Hines Unit 4 and the related transmission facilities. The staff also recommended that the base rate changes associated with both Hines Unit 4 and Hines Unit 2 be achieved by applying the new rates to energy sales after December 1, 2007, thus requiring PEF to pro-rate the changes on customer bills rendered in December for customers that had consumption of electricity in both November and December. On October 12, 2007, PEF entered into a stipulation and settlement agreement that was filed with the FPSC. The agreement was reached with intervenors in settlement of all issues related to recovery of the revenue requirements of Hines Unit 4 and Hines Unit 2 and provides that PEF shall 1) increase its base rates for revenue requirements of Hines Unit 2 and Hines Unit 4 as approved in the staff recommendation and 2) simplify the implementation of the base rate increase by making it effective with the first billing cycle in January 2008. On October 23, 2007, the FPSC voted to approve the stipulation and settlement agreement.

On October 29, 2007, PEF 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 PEF OATT in order to more accurately reflect the costs that PEF incurs in providing transmission service. In the filing, PEF proposed to move from a fixed rate 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. PEF is awaiting FERC approval of the settlement agreement. If approved, the new rates will be effective January 1, 2008, and PEF estimates the impact of the new rates will increase 2008 expected revenues by $1 million to $2 million.

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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)	2007	2006	2007	2006
Weighted-average common shares – basic	257	251	256	250
Net effect of dilutive stock-based compensation plans	−	−	−	1
Weighted-average shares – fully dilutive	257	251	256	251

B.           Comprehensive Income

Progress Energy
	Three Months Ended September 30,
(in millions)	2007			2006
Net income	$	319		$	319
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $- and $20, respectively)		1			32
Net unrealized losses on cash flow hedges (net of tax benefit of $7 and $33, respectively)		(11	)		(41	)
Other comprehensive loss		(10	)		(9	)
Comprehensive income	$	309		$	310

	Nine Months Ended September 30,
(in millions)	2007			2006
Net income	$	401		$	317
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $2 and $19, respectively)		4			31
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $-)		2			−
Net unrealized losses on cash flow hedges (net of tax benefit of $5 and $17, respectively)		(9	)		(23	)
Other (net of tax benefit of $3)		(2	)		−
Other comprehensive (loss) income		(5	)		8
Comprehensive income	$	396		$	325

33

PEC
	Three Months Ended September 30,
(in millions)	2007			2006
Net income	$	204		$	189
Other comprehensive (loss) income
Net unrealized (losses) gains on cash flow hedges (net of tax benefit of $1 and $-, respectively)		(2	)		1
Other comprehensive (loss) income		(2	)		1
Comprehensive income	$	202		$	190
	Nine Months Ended September 30,
(in millions)	2007			2006
Net income	$	416		$	351
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $1 and $1, respectively)		(1	)		(1	)
Other (net of tax benefit of $1)		(4	)		−
Other comprehensive loss		(5	)		(1	)
Comprehensive income	$	411		$	350

PEF
	Three Months Ended September 30,
(in millions)	2007			2006
Net income	$	138		$	125
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $6 and $1, respectively)		(10	)		(2	)
Other comprehensive loss		(10	)		(2	)
Comprehensive income	$	128		$	123
	Nine Months Ended September 30,
(in millions)	2007			2006
Net income	$	267		$	265
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $5 and $1, respectively)		(8	)		(2	)
Other comprehensive loss		(8	)		(2	)
Comprehensive income	$	259		$	263

C.           Common Stock

At December 31, 2006, we had 500 million shares of common stock authorized under our charter, of which approximately 256 million were outstanding. At December 31, 2006, we had approximately 54 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, 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 Investor Plus Stock Purchase Plan. For the three months ended September 30, 2006, we issued approximately 0.3 million shares of common stock resulting in approximately $13 million in proceeds, primarily to meet the requirements of the Investor Plus Stock Purchase Plan. For the nine months ended September 30, 2006, we issued approximately 1.7 million shares of common stock resulting in

34

approximately $73 million in proceeds. Included in these amounts were approximately 1.4 million shares for proceeds of approximately $58 million 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, 2006, are described below.

On July 2, 2007, PEF paid at maturity $85 million of its 6.81% Medium-Term Notes with available cash on hand and commercial paper borrowings.

On August 15, 2007, due to extreme volatility in the commercial paper market, Progress Energy borrowed $400 million under its $1.13 billion revolving credit agreement (RCA) to repay outstanding commercial paper. At September 30, 2007, $400 million of Progress Energy’s RCA loan was still outstanding. On October 17, 2007, Progress Energy used $200 million of commercial paper proceeds to repay a portion of the amount borrowed under the RCA. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining balance of the RCA loan, while maintaining an appropriate level of liquidity.

On August 15, 2007, due to extreme volatility in the commercial paper market, PEC borrowed $300 million under its $450 million RCA and paid at maturity $200 million of its 6.80% First Mortgage Bonds. At September 30, 2007, $150 million of PEC’s RCA loan was still outstanding. On October 17, 2007, PEC repaid the remaining $150 million of its RCA loan using available cash on hand.

On September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017. The proceeds were used to repay PEF’s utility money pool borrowings and the remainder was placed in temporary investments for general corporate use as needed.

7. UNCERTAIN TAX POSITIONS

Progress Energy

In July 2006, the FASB issued FIN 48, which clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. A two-step process is required for the application of FIN 48; recognition of the tax benefit based on a “more-likely-than-not” threshold and measurement of the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with the taxing authority. We adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a $2 million reduction of the January 1, 2007, balance of retained earnings and a $4 million increase in regulatory assets. Including the cumulative effect impact, our liability for unrecognized tax benefits at January 1, 2007, was $126 million. Of the total amount of unrecognized tax benefits at January 1, 2007, $24 million would have affected the effective tax rate for income from continuing operations, if recognized. Primarily due to the closure of certain tax years in the second quarter, at June 30, 2007, our liability for unrecognized tax benefits decreased to $84 million and the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations decreased to $6 million. We did not record any material changes for the three months ended September 30, 2007.

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state jurisdictions. Our open federal tax years are from 2004 forward and our open state tax years in our major jurisdictions are generally from 1992 forward. The IRS is currently examining our federal tax returns for years 2004 and 2005. We cannot predict when those examinations will be completed. We are not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the twelve-month period ending September 30, 2008.

We include interest expense related to unrecognized tax benefits in interest charges and we include penalties in other, net on the Consolidated Statements of Income. As of January 1, 2007, we had accrued $24 million for interest and penalties. As of September 30, 2007, we have accrued $20 million for interest and penalties.

35

PEC

PEC adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a $6 million reduction of the January 1, 2007, balance of retained earnings. Including the cumulative effect impact, PEC’s liability for unrecognized tax benefits at January 1, 2007, was $43 million. Of the total amount of unrecognized tax benefits at January 1, 2007, $9 million would have affected the effective tax rate, if recognized. Primarily due to the closure of certain tax years in the second quarter, at June 30, 2007, PEC’s liability for unrecognized tax benefits decreased to $29 million. At June 30, 2007, the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate decreased to $7 million. PEC did not record any material changes for the three months ended September 30, 2007.

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. PEC’s open federal tax years are from 2004 forward and PEC’s open state tax years in our major jurisdictions are generally from 1992 forward. The IRS is currently examining our federal tax returns for years 2004 and 2005. PEC cannot predict when those examinations will be completed. PEC is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the twelve-month period ending September 30, 2008.

PEC includes interest expense related to unrecognized tax benefits in interest charges and includes penalties in other, net on the Consolidated Statements of Income. As of January 1, 2007, PEC had accrued $4 million for interest and penalties. PEC did not record any material changes at September 30, 2007.

PEF

PEF adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a $1 million reduction of the January 1, 2007, balance of retained earnings and a $4 million increase in regulatory assets. Including the cumulative effect impact, PEF’s liability for unrecognized tax benefits at January 1, 2007, was $72 million. Of the total amount of unrecognized tax benefits at January 1, 2007, $4 million would have affected the effective tax rate, if recognized. Primarily due to the closure of certain tax years in the second quarter, at June 30, 2007, the PEF liability for unrecognized tax benefits decreased to $56 million and the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate decreased to $1 million. PEF did not record any material changes for the three months ended September 30, 2007.

We file consolidated federal and state income tax returns that include PEF. PEF’s open federal tax years are from 2004 forward and PEF’s open state tax years are generally from 1992 forward. The IRS is currently examining our federal tax returns for years 2004 and 2005. PEF cannot predict when those examinations will be completed. PEF is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the twelve-month period ending September 30, 2008.

Pursuant to a regulatory order, PEF records interest expense related to unrecognized tax benefits as a regulatory asset, which is amortized over a three-year period, with the amortization included in interest charges on the Statements of Income. Penalties are included in other, net on the Statements of Income. At January 1, 2007, PEF had accrued $7 million for interest and penalties. At September 30, 2007, PEF had accrued $17 million for interest and penalties.

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:

36

Progress Energy
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2007			2006			2007			2006
Service cost	$	13		$	10		$	2		$	2
Interest cost		31			30			6			8
Expected return on plan assets		(38	)		(39	)		(1	)		(2	)
Amortization of actuarial loss (gain) (a)		4			1			(2	)		(1	)
Other amortization, net (a)		–			–			1			1
Net periodic cost	$	10		$	2		$	6		$	8
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Service cost	$	35		$	34		$	5		$	6
Interest cost		92			88			24			25
Expected return on plan assets		(116	)		(111	)		(4	)		(4	)
Amortization of actuarial loss (a)		11			13			1			3
Other amortization, net (a)		1			–			4			4
Net periodic cost	$	23		$	24		$	30		$	34

^(a)      Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2006 Form 10-K.

PEC
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2007			2006			2007			2006
Service cost	$	7		$	5		$	2		$	1
Interest cost		14			14			2			4
Expected return on plan assets		(14	)		(16	)		(1	)		(1	)
Amortization of actuarial loss (gain)		4			2			(2	)		(1	)
Net periodic cost	$	11		$	5		$	1		$	3
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Service cost	$	17		$	16		$	4		$	3
Interest cost		42			39			11			12
Expected return on plan assets		(45	)		(44	)		(3	)		(3	)
Amortization of actuarial loss		9			8			–			2
Other amortization, net		2			1			1			1
Net periodic cost	$	25		$	20		$	13		$	15

37

PEF
	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
(in millions)	2007			2006			2007			2006
Service cost	$	5		$	4		$	–		$	1
Interest cost		13			12			4			3
Expected return on plan assets		(21	)		(21	)		–			–
Amortization of actuarial gain		–			(1	)		–			–
Other amortization, net		–			–			1			1
Net periodic (benefit) cost	$	(3	)	$	(6	)	$	5		$	5
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Service cost	$	12		$	12		$	1		$	2
Interest cost		39			37			11			10
Expected return on plan assets		(63	)		(58	)		(1	)		(1	)
Amortization of actuarial loss		–			2			1			1
Other amortization, net		–			(1	)		3			3
Net periodic (benefit) cost	$	(12	)	$	(8	)	$	15		$	15

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 3A, our subsidiary, PVI, entered into a series of transactions to sell or assign substantially all of its CCO physical and commercial assets and liabilities. On June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of 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. The sale of the generation assets closed on June 11, 2007. Additionally, we sold Gas on October 2, 2006 (See Note 3B). Due to these divestitures, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts would be fulfilled and cash flow hedge accounting for the contracts was discontinued beginning in the second quarter of 2006 for Gas and in the fourth quarter of 2006 for CCO.

At September 30, 2007, due to the closing of the transactions discussed above, our discontinued operations did not have outstanding positions in derivative instruments. At December 31, 2006, derivative assets of $107 million were included in assets of discontinued operations and derivative liabilities of $31 million were included in liabilities of discontinued operations on the Consolidated Balance Sheet. For the three months ended September 30, 2007, there were no material net gains and losses from derivative instruments included in discontinued operations on the Consolidated Statements of Income. For the nine months ended September 30, 2007, after-tax gains from derivative instruments of $88 million were included in discontinued operations on the Consolidated Statements of Income. For the three and nine months ended September 30, 2006, after-tax losses from derivative instruments of $30 million and $39 million, respectively, were included in discontinued operations on the Consolidated Statements of Income. For the three and nine months ended September 30, 2007, there were no reclassifications to earnings due to the

38

discontinuance of the related cash flow hedges. For the three months ended September 30, 2006, there were no reclassifications to earnings due to the discontinuance of the related cash flow hedges. For the nine months ended September 30, 2006, $7 million in after-tax losses were reclassified to earnings due to the discontinuance of the related cash flow hedges in anticipation of the sale of Gas.

A.           Commodity Derivatives

GENERAL

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

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” (DIG Issue C20). The related liability is being amortized to earnings over the term of the related contract (See Note 11). At September 30, 2007, and December 31, 2006, the remaining liability was $11 million and $14 million, respectively.

ECONOMIC DERIVATIVES

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

On January 8, 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge instruments is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts are marked-to-market with changes in fair value recorded through earnings from synthetic fuels production. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed in Notes 1C and 3I, we disposed of our 100 percent ownership interest in Ceredo on March 30, 2007. Progress Energy is the primary beneficiary of, and continues to consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there is no net earnings impact for the contracts entered into by Ceredo. At September 30, 2007, the fair value of these contracts was recorded as a $170 million short-term derivative asset position, including $58 million at Ceredo. The fair value of these contracts was included in derivative assets on the Consolidated Balance Sheet. During the three and nine months ended September 30, 2007, we recorded net pre-tax gains of $74 million and $105 million, respectively, in diversified business revenues related to these contracts, including net pre-tax gains of $26 million and $21 million, respectively, at Ceredo subsequent to disposal of our 100 percent ownership interest.

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets on the Balance Sheets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause.

At September 30, 2007, the fair value of PEC’s commodity derivative instruments was recorded as a $3 million long-term derivative asset position included in other assets and deferred debits and a $5 million short-term derivative liability position included in other current liabilities on the Consolidated Balance Sheet. At December 31, 2006, PEC did not have material outstanding positions in such contracts.

At September 30, 2007, the fair value of PEF’s commodity derivative instruments was recorded as a $14 million short-term derivative asset position included in prepayments and other current assets, a $12 million long-term derivative asset position included in other assets and deferred debits, a $31 million short-term derivative liability position included in derivative liabilities, and a $5 million long-term derivative liability position included in other

39

liabilities and deferred credits on the PEF Balance Sheet. At December 31, 2006, the fair value of such instruments was recorded as a $2 million long-term derivative asset position included in other assets and deferred debits, an $87 million short-term derivative liability position included in derivative liabilities and a $36 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet.

CASH FLOW HEDGES

Our subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of natural gas and power for our forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate. At September 30, 2007, and December 31, 2006, we and the Utilities did not have material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges for the three and nine months ended September 30, 2007 and 2006, was not material to our or the Utilities’ results of operations.

At September 30, 2007, and December 31, 2006, the amount recorded in our or PEC’s accumulated other comprehensive income (AOCI) related to commodity cash flow hedges was not material and PEF had no amount recorded in AOCI related to commodity cash flow hedges.

Our discontinued operations did not have material outstanding positions in commodity cash flow hedges at September 30, 2007, or December 31, 2006.

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.

The fair values of interest rate hedges at September 30, 2007, and December 31, 2006, were as follows:

September 30, 2007

December 31, 2006

(in millions)

Progress Energy

PEC

PEF

Progress Energy

PEC

PEF

Interest rate cash flow hedges

Fair value of assets

$

–

$

–

$

–

$

–

$

–

$

–

Fair value of liabilities

(4

)

(4

)

–

(2

)

(1

)

(1

)

Interest rate fair value hedges

Fair value of assets

–

–

–

–

–

–

Fair value of liabilities

–

–

–

(1

)

–

–

CASH FLOW HEDGES

Gains and losses from cash flow hedges are recorded in AOCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in AOCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The ineffective portion of interest rate cash flow hedges for the three and nine months ended September 30, 2007 and 2006, was not material to our or the Utilities’ results of operations.

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The following table presents selected information related to our interest rate cash flow hedges at September 30, 2007:

(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)	$	(20	)	$	(7	)	$	(9	)
Portion expected to be reclassified to earnings during the next 12 months(b)		(2	)		(1	)		–

^(a)      Includes amounts related to terminated hedges.

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

At September 30, 2007, we had $100 million notional of interest rate cash flow hedges at PEC. Subsequently, on October 24, 2007, PEC entered into $100 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. At December 31, 2006, we had $100 million notional of interest rate cash flow hedges, including $50 million notional at PEC and $50 million notional at PEF.

PEF entered into a $25 million notional forward starting swap in July 2007, $150 million notional in forward starting swaps in June 2007, and a $50 million forward starting swap in February 2007 to mitigate exposure to interest rate risk in anticipation of future debt issuances. All of PEF’s forward starting swaps were terminated on September 13, 2007, in conjunction with PEF’s issuance of $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017. On July 30, 2007, PEC entered into a $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances. On September 25, 2007, PEC amended its 10-year forward starting swap in order to move the maturity date from October 1, 2017 to April 1, 2018.

At December 31, 2006, including amounts related to terminated hedges, we had $14 million of after-tax deferred losses, including $5 million of after-tax deferred losses at PEC and $1 million of after-tax deferred losses at PEF, recorded in AOCI related to interest rate cash flow hedges.

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, 2007, we had no open interest rate fair value hedges. At December 31, 2006, we had a $50 million notional interest rate fair value hedge, which was terminated on September 26, 2007. At September 30, 2007, and December 31, 2006, the Utilities had no open interest rate fair value hedges.

10. FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are: PEC, PEF, and Coal and Synthetic Fuels.

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

Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuels (as defined under the Code), the operation of synthetic fuels facilities for third parties, and coal terminal services. On September 14, 2007, we idled production of synthetic fuels at our majority-owned synthetic fuels facilities due to the current high level of oil prices. On October 12, 2007, based upon the continued high level of oil prices, unfavorable oil price projections through the end of 2007, and the expiration of the current synthetic fuels tax credit program at the end of 2007, we decided to permanently cease production of synthetic fuels at our majority-owned facilities. The operation of synthetic fuels facilities on the behalf of third parties is expected to continue through the end of the current synthetic fuels tax credit program.

41

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

Income and assets of discontinued operations are not included in the table presented below. For comparative purposes, the prior year results have been restated to conform to the current segment presentation. The following information is for the three and nine months ended September 30:

									Income
	Revenues								(Loss) from
(in millions)	Unaffiliated		Intersegment			Total			Continuing Operations			Assets
Three Months Ended September 30, 2007
PEC	$	1,286	$	–		$	1,286		$	203		$	12,175
PEF		1,456		–			1,456			138			9,896
Coal and Synthetic Fuels (a)		356		–			356			(16	)		672
Corporate and Other		2		99			101			(6	)		16,170
Eliminations		–		(99	)		(99	)		–			(12,368	)
Totals	$	3,100	$	–		$	3,100		$	319		$	26,545
Three Months Ended September 30, 2006
PEC	$	1,200	$	–		$	1,200		$	188
PEF		1,399		–			1,399			125
Coal and Synthetic Fuels (a)		177		88			265			7
Corporate and Other		–		97			97			(37	)
Eliminations		–		(185	)		(185	)		–
Totals	$	2,776	$	–		$	2,776		$	283

									Income
	Revenues								(Loss) from
(in millions)	Unaffiliated		Intersegment			Total			Continuing Operations			Assets
Nine Months Ended September 30, 2007
PEC	$	3,340	$	–		$	3,340		$	414		$	12,175
PEF		3,596		–			3,596			266			9,896
Coal and Synthetic Fuels (a)		897		2			899			56			672
Corporate and Other		7		286			293			(66	)		16,170
Eliminations		–		(288	)		(288	)		–			(12,368	)
Totals	$	7,840	$	–		$	7,840		$	670		$	26,545
Nine Months Ended September 30, 2006
PEC	$	3,114	$	–		$	3,114		$	349
PEF		3,553		–			3,553			264
Coal and Synthetic Fuels (a)		630		251			881			(83	)
Corporate and Other		–		289			289			(143	)
Eliminations		–		(540	)		(540	)		–
Totals	$	7,297	$	–		$	7,297		$	387

^(a) Coal and Synthetic Fuels includes revenues of synthetic fuels facilities that are operated on behalf of third parties.

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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. AFUDC equity represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets. Contingent value obligations (CVOs) unrealized gain or loss is due to changes in the fair market value of the liability. See Note 15 in the 2006 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)	2007		2006			2007		2006
Other income
Nonregulated energy and delivery services income	$	2	$	4		$	25	$	27
DIG Issue C20 amortization (see Note 9)		1		2			3		4
CVOs unrealized gain		1		−			2		−
Gain on sale of property, net		3		−			1		−
Gain on sale of Level 3 stock(a)		−		−			−		32
Investment gains		2		1			5		3
Income from equity investments		1		−			7		−
AFUDC equity		14		6			34		13
Other		2		5			10		16
Total other income		26		18			87		95
Other expense
Nonregulated energy and delivery services expenses		7		7			19		22
Donations		6		3			16		15
Investment losses		4		−			4		−
Loss from equity investments		1		3			2		6
CVOs unrealized loss		−		3			4		25
Indemnification liability (See Note 12)		−		8			−		13
Other		1		3			9		15
Total other expense		19		27			54		96
Other, net	$	7	$	(9	)	$	33	$	(1	)

^(a) Other income includes pre-tax gains of $32 million for the nine months ended September 30, 2006, from the sale of approximately 20 million shares of Level 3 stock received as part of the sale of our interest in PT LLC (See Note 3D). These gains are prior to the consideration of minority interest.

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PEC
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007		2006
Other income
Nonregulated energy and delivery services income	$	(3	)	$	(2	)	$	6	$	8
DIG Issue C20 amortization (see Note 9)		1			2			3		4
Income from equity investments		1			−			3		−
Investment gains		2			2			3		2
AFUDC equity		2			−			7		2
Other		2			−			7		7
Total other income		5			2			29		23
Other expense
Nonregulated energy and delivery services expenses		3			2			6		6
Donations		1			1			6		8
Loss from equity investments		−			−			1		1
Investment losses		2			−			3		3
Indemnification liability		−			8			−		13
Other		−			1			4		4
Total other expense		6			12			20		35
Other, net	$	(1	)	$	(10	)	$	9	$	(12	)

PEF
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2007		2006		2007		2006
Other income
Nonregulated energy and delivery services income	$	5	$	6	$	19	$	19
Investment gains		−		−		2		1
AFUDC equity		12		6		27		11
Other		1		−		1		1
Total other income		18		12		49		32
Other expense
Nonregulated energy and delivery services expenses		4		5		13		15
Donations		1		1		4		7
Investment losses		1		−		1		−
Loss from equity investments		−		−		1		1
Other		−		−		3		1
Total other expense		6		6		22		24
Other, net	$	12	$	6	$	27	$	8

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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 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 potential PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of these potential claims cannot be predicted. No material claims are currently pending. A discussion of sites by legal entity follows.

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

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

(in millions)	September 30, 2007		December 31, 2006
PEC
MGP and other sites(a)	$	16	$	22
PEF
Remediation of distribution and substation transformers		36		43
MGP and other sites		18		18
Total PEF environmental remediation accruals(b)		54		61
Progress Energy nonregulated operations		1		3
Total Progress Energy environmental remediation accruals	$	71	$	86

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

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

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Progress Energy

In addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, our environmental sites include the following related to our nonregulated operations.

In 2001, we, through our Progress Fuels subsidiary, established an accrual to address indemnities and retained an environmental liability associated with the sale of our Inland Marine Transportation business. For the nine months ended September 30, 2007, the accrual was reduced by $2 million due to a reduction in the anticipated scope of work based on responses from regulatory agencies. Expenditures related to this liability were not material for the three and nine months ended September 30, 2007 and 2006.

On March 24, 2005, we completed the sale of our Progress Rail subsidiary. In connection with the sale, we incurred indemnity obligations related to certain pre-closing liabilities, including certain environmental matters (See discussion under Guarantees in Note 13B).

PEC

For the three months ended September 30, 2007, including the Carolina Transformer site, the Ward Transformer site and MGP sites discussed below, PEC made no material accruals or expenditures. For the nine months ended September 30, 2007, including the Carolina Transformer site, the Ward Transformer site and MGP sites discussed below, PEC reduced its accrual by approximately $4 million, primarily related to the Ward Transformer site, and spent approximately $2 million. For the three months ended September 30, 2006, PEC made no additional accruals and spent approximately $1 million. For the nine months ended September 30, 2006, PEC accrued approximately $21 million, of which approximately $9 million related to the Ward Transformer site and approximately $12 million related to MGP sites, and spent approximately $5 million. For the nine months ended September 30, 2007, PEC received $2 million in insurance proceeds. In October 2006, PEC received orders from the NCUC and SCPSC to defer and amortize certain environmental remediation expenses, net of insurance proceeds (See Note 4A).

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

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC and a number of other PRPs the opportunity to negotiate cleanup of the site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the site. At December 31, 2006, PEC’s accrual for its portion of the estimated remediation costs was approximately $9 million. In March 2007, the PRP agreement was amended to include an additional participating PRP, which reduced PEC’s allocable share. Accordingly, PEC refined and reduced its estimated liability for this site, as discussed above. At September 30, 2007, PEC’s recorded liability for the site was approximately $5 million. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. The outcome of this matter cannot be predicted.

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

In September 2005, the EPA advised PEC that it had been identified as a PRP at the Carolina Transformer site located in Fayetteville, N.C. The EPA offered PEC and a number of other PRPs the opportunity to share in the reimbursement to the EPA of past expenditures in addressing conditions at the site, which are currently approximately $33 million. Negotiations are continuing between the PRPs and the EPA in an effort to settle this matter. For the three and nine months ended September 30, 2007, PEC recorded an immaterial accrual based on its estimated share of the settlement offers made to date. An agreement with the EPA has not been finalized. The outcome of this matter cannot be predicted.

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PEF

PEF has received approval from the FPSC for recovery of the majority of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection, PEF is in the process of examining distribution transformer sites and substation sites for mineral oil-impacted soil remediation caused by equipment integrity issues. PEF has reviewed a number of distribution transformer sites and all substation sites. Based on changes to the estimated time frame for inspections of distribution transformer sites, PEF currently expects to have completed this review by the end of 2008. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC. For the 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 approximately $5 million and $16 million, respectively, related to the remediation of transformers. For the three and nine months ended September 30, 2006, PEF accrued approximately $1 million and $40 million, respectively, due to additional sites expected to require remediation and spent approximately $6 million and $12 million, respectively, related to the remediation of transformers. At September 30, 2007, PEF has recorded a regulatory asset for the probable recovery of these costs through the ECRC.

The amounts for MGP and other sites, in the table above, relate to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation. The amounts include approximately $12 million in insurance claim settlement proceeds received in 2004, which are restricted for use in addressing costs associated with environmental liabilities. For the three and nine months ended September 30, 2007 and 2006, PEF made no additional accruals or material expenditures.

B. Air and Water Quality

We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations include the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule (CAMR), the Clean Air Visibility Rule (CAVR), the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) and the Clean Smokestacks Act. At September 30, 2007, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.360 billion, including $1.174 billion at PEC and $186 million at PEF.

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, 2007, and December 31, 2006, the amount of the liability was $30 million and $29 million, respectively, based upon the respective current estimates for Clean Smokestacks Act compliance. 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. In 2006, PEC notified the NCUC of its intent to record these estimated excess costs as part of the $569 million amortization required to be recorded by December 31, 2007, and accordingly, recorded the indemnification expense to Clean Smokestacks Act amortization. If the settlement agreement filed on October 22, 2007 (See Note 4A) is approved by the NCUC, under its provisions any costs in excess of the joint owner’s share will be treated in the same manner as PEC’s Clean Smokestacks costs in excess of the original estimated compliance costs.

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13. COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2006 Form 10-K are described below.

A. Purchase Obligations

Progress Energy

As part of our ordinary course of business, we enter into various long- and short-term contracts for fuel requirements at our generating plants. Through September 30, 2007, contracts procured through our subsidiaries have increased our aggregate purchase obligations for fuel and purchased power by $ 4.274 billion from $13.133 billion, as stated in Note 22A in the 2006 Form 10-K. Future obligations under operating leases also increased by approximately $413 million from $428 million at December 31, 2006. These increases are discussed under “PEC” and “PEF” below.

PEC

Through September 30, 2007, PEC’s fuel and purchase power commitments increased by $1.015 billion from $4.358 billion, as stated in Note 22A in the 2006 Form 10-K. This increase is primarily related to nuclear fuel commitments, of which approximately $412 million will be incurred through 2011, with the remainder incurred through 2018.

PEF

Through September 30, 2007, PEF’s fuel and purchase power commitments increased by $3.494 billion from $8.513 billion as stated in Note 22A in the 2006 Form 10-K. The increase is primarily due to precedent and related agreements PEF entered into on December 2, 2004, for the supply of natural gas and associated firm pipeline transportation to augment PEF’s gas supply needs for the period from May 1, 2007, to April 30, 2027, as discussed in Note 22A in the 2006 Form 10-K. At September 30, 2007, the total cost associated with these agreements is approximately $4.4 billion, an increase of $500 million from December 31, 2006, as payments under the gas supply agreement are based on a market index, which has increased since year-end. Based upon current market prices, we anticipate incurring these costs ratably over the contract period. The transactions were subject to several conditions precedent, some of which were satisfied at December 31, 2006. Due to the conditions in the agreements, the estimated costs associated with these agreements were not included in our or PEF’s contractual cash obligations table at December 31, 2006. During 2007, the remaining conditions precedent were satisfied and the long-term contracts were contractual obligations of PEF at September 30, 2007.

In August 2007, PEF entered into a purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $28 million from 2012 through 2027 for a total of approximately $420 million.

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, 2007, 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, 2007, 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, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations, which are within the scope of FIN 45. Related to the sales of businesses, the latest notice period extends until 2012 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations

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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, 2007, the estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $427 million, including $32 million at PEF. At September 30, 2007, and December 31, 2006, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $80 million and $60 million, respectively. These amounts include $30 million and $29 million, respectively, for PEC and $8 million for PEF at September 30, 2007, and December 31, 2006. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million of guarantees 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. Our damages due to the DOE’s breach will be significant, but have yet to be determined. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

The DOE and the Utilities agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called “rate issues,” or the minimum mandatory schedule for the acceptance of spent nuclear fuel and high-level radioactive waste by which the government was contractually obligated to accept contract holders’ spent nuclear fuel and/or high-level waste, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been or are expected to be presented in the trials or appeals that occurred in 2006 or are currently scheduled to occur during 2007. Resolution of these issues in other cases could facilitate agreements by the parties in the Utilities’ lawsuit, or at a minimum, inform the court of decisions reached by other courts if they remain contested and require resolution in this case. In July 2005, the parties jointly requested a continuance of the stay through December 15, 2005, which the trial court granted. Subsequently, the trial court continued the stay until March 17, 2006. The trial court lifted the stay on March 22, 2006, and discovery has commenced. The trial court issued a scheduling order on March 23, 2006, and the case is scheduled to go to trial on November 5, 2007.

In July 2002, Congress passed an override resolution to Nevada’s veto of the DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.; and the city of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit (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 D.C. Court of Appeals rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. In August 2005, the EPA issued new proposed standards. The proposed standards include a 1,000,000-year compliance period in the radiation protection standard. Comments were due November 21, 2005, and are being reviewed by the EPA. The EPA is expected to issue a new safety standard for the repository later this year. The DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004. However, in November 2004, the DOE announced it would not submit the license application until mid-2005 or later. The DOE did not submit the license application in 2005 and has since reported that the license application will be submitted by June 2008 if full funding is obtained for fiscal year 2008. The DOE requested $545 million for fiscal year 2007 and received $445 million.

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The DOE has requested $495 million for fiscal year 2008. The budget for fiscal year 2008 has not been finalized but the Senate Appropriations Committee has recommended funding of $446 million. 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. Based upon this certification, the DOE is expected to submit its license application in spring 2008. 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 stated that if legislative changes requested by the Bush administration are enacted, the repository may be able to accept spent nuclear fuel starting in 2017, but 2020 is more probable due to anticipated litigation by the state of Nevada. The Utilities cannot predict the outcome of this matter.

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

SYNTHETIC FUELS MATTERS

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

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

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

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

In December 2006, we reached agreement with Global to settle an additional claim in the suit related to amounts due to Global that were placed in escrow 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. The remainder of the suit continues. We cannot predict the outcome of this matter.

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OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, we have made accruals and disclosures in accordance with SFAS No. 5, “Accounting for Contingencies,” to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on our consolidated results of operations or financial position.

14. CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2006 Form 10-K, we have guaranteed certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.) since September 2005. Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress Corporation (Florida Progress). Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 12B in the 2006 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. The Other column includes the consolidated financial results of all other non-guarantor subsidiaries and elimination entries for all intercompany transactions. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities. The accompanying condensed consolidating financial statements have been restated for all periods presented to reflect the operations of CCO as discontinued operations as described in Note 3.

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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
Electric	$	−		$	1,455	$	1,286		$	2,741
Diversified business		−			310		49			359
Total operating revenues		−			1,765		1,335			3,100
Operating expenses
Utility
Fuel used in electric generation		−			544		385			929
Purchased power		−			281		109			390
Operation and maintenance		2			213		241			456
Depreciation and amortization		−			100		121			221
Taxes other than on income		−			83		52			135
Diversified business
Cost of sales		−			284		45			329
Depreciation and amortization		−			2		−			2
Other		−			8		3			11
Total operating expenses		2			1,515		956			2,473
Operating (loss) income		(2	)		250		379			627
Other income (expense), net		10			13		(9	)		14
Interest charges, net		51			53		50			154
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(43	)		210		320			487
Income tax (benefit) expense		(20	)		58		116			154
Equity in earnings of consolidated subsidiaries		340			−		(340	)		−
Minority interest in subsidiaries’ income, net of tax		−			(14)		−			(14)
Income (loss) from continuing operations		317			138		(136	)		319
Discontinued operations, net of tax		2			1		(3	)		−
Net income (loss)	$	319		$	139	$	(139	)	$	319

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Condensed Consolidating Statement of Income Three Months Ended September 30, 2006
(in millions)	Parent			Subsidiary Guarantor		Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,399	$	1,200		$	2,599
Diversified business		−			175		2			177
Total operating revenues		−			1,574		1,202			2,776
Operating expenses
Utility
Fuel used in electric generation		−			538		322			860
Purchased power		−			256		135			391
Operation and maintenance		3			171		209			383
Depreciation and amortization		−			108		135			243
Taxes other than on income		−			89		52			141
Diversified business
Cost of sales		−			187		2			189
Depreciation and amortization		−			2		−			2
Other		−			7		3			10
Total operating expenses		3			1,358		858			2,219
Operating (loss) income		(3	)		216		344			557
Other income (expense), net		7			9		(12	)		4
Interest charges, net		70			47		31			148
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(66	)		178		301			413
Income tax (benefit) expense		(14	)		60		87			133
Equity in earnings of consolidated subsidiaries		371			−		(371	)		−
Minority interest in subsidiaries’ loss, net of tax		−			3		−			3
Income (loss) from continuing operations		319			121		(157	)		283
Discontinued operations, net of tax		−			59		(23	)		36
Net income (loss)	$	319		$	180	$	(180	)	$	319

53

Condensed Consolidating Statement of Income Nine Months Ended September 30, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	3,595		$	3,339		$	6,934
Diversified business		−			812			94			906
Total operating revenues		−			4,407			3,433			7,840
Operating expenses
Utility
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		−			297			365			662
Taxes other than on income		−			233			151			384
Other		−			12			2			14
Diversified business
Cost of sales		−			812			114			926
Depreciation and amortization		−			6			−			6
Gain on the sale of assets		−			(17	)		−			(17	)
Other		−			30			8			38
Total operating expenses		9			3,950			2,666			6,625
Operating (loss) income		(9	)		457			767			1,215
Other income, net		19			34			1			54
Interest charges, net		150			137			145			432
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(140	)		354			623			837
Income tax (benefit) expense		(63	)		51			187			175
Equity in earnings of consolidated subsidiaries		472			−			(472	)		−
Minority interest in subsidiaries’ loss, net of tax		−			8			−			8
Income (loss) from continuing operations		395			311			(36	)		670
Discontinued operations, net of tax		6			(7	)		(268	)		(269	)
Net income (loss)	$	401		$	304		$	(304	)	$	401

54

Condensed Consolidating Statement of Income Nine Months Ended September 30, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	3,553		$	3,113		$	6,666
Diversified business		−			628			3			631
Total operating revenues		−			4,181			3,116			7,297
Operating expenses
Utility
Fuel used in electric generation		−			1,379			880			2,259
Purchased power		−			601			279			880
Operation and maintenance		10			515			691			1,216
Depreciation and amortization		−			301			404			705
Taxes other than on income		−			238			142			380
Other		−			(2	)		−			(2	)
Diversified business
Cost of sales		−			645			27			672
Depreciation and amortization		−			11			10			21
Impairment of assets		−			44			47			91
Other		−			27			13			40
Total operating expenses		10			3,759			2,493			6,262
Operating (loss) income		(10	)		422			623			1,035
Other income (expense), net		9			47			(20	)		36
Interest charges, net		216			142			111			469
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(217	)		327			492			602
Income tax (benefit) expense		(73	)		107			171			205
Equity in earnings of consolidated subsidiaries		461			−			(461	)		−
Minority interest in subsidiaries’ income, net of tax		−			(10)			−			(10)
Income (loss) from continuing operations		317			210			(140	)		387
Discontinued operations, net of tax		−			86			(156	)		(70	)
Net income (loss)	$	317		$	296		$	(296	)	$	317

55

Condensed Consolidating Balance Sheet September 30, 2007
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−	$	7,198	$	8,990		$	16,188
Current assets
Cash and cash equivalents		180		341		96			617
Short-term investments		−		178		−			178
Notes receivable from affiliated companies		321		−		(321	)		−
Deferred fuel cost		−		9		168			177
Assets of discontinued operations		−		27		1			28
Other current assets		95		1,323		1,126			2,544
Total current assets		596		1,878		1,070			3,544
Deferred debits and other assets
Investment in consolidated subsidiaries		10,977		−		(10,977	)		−
Goodwill		−		1		3,654			3,655
Other assets and deferred debits		142		1,483		1,561			3,186
Total deferred debits and other assets		11,119		1,484		(5,762	)		6,841
Total assets	$	11,715	$	10,560	$	4,298		$	26,573
Capitalization
Common stock equity	$	8,426	$	3,007	$	(3,007	)	$	8,426
Preferred stock of subsidiaries – not subject to mandatory redemption		−		34		59			93
Minority interest		−		61		3			64
Long-term debt, affiliate		−		309		(38	)		271
Long-term debt, net		2,597		3,137		3,182			8,916
Total capitalization		11,023		6,548		199			17,770
Current liabilities
Current portion of long-term debt		−		164		300			464
Short-term debt		400		−		150			550
Notes payable to affiliated companies		−		313		(313	)		−
Liabilities of discontinued operations		−		12		−			12
Other current liabilities		246		1,233		712			2,191
Total current liabilities		646		1,722		849			3,217
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		56		229			285
Regulatory liabilities		−		1,160		1,225			2,385
Accrued pension and other benefits		12		365		519			896
Other liabilities and deferred credits		34		709		1,277			2,020
Total deferred credits and other liabilities		46		2,290		3,250			5,586
Total capitalization and liabilities	$	11,715	$	10,560	$	4,298		$	26,573

56

Condensed Consolidating Balance Sheet December 31, 2006
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−	$	6,337	$	8,908		$	15,245
Current assets
Cash and cash equivalents		153		40		72			265
Short-term investments		21		−		50			71
Notes receivable from affiliated companies		58		37		(95	)		−
Deferred fuel cost		−		−		196			196
Assets of discontinued operations		−		45		842			887
Other current assets		27		1,109		1,030			2,166
Total current assets		259		1,231		2,095			3,585
Deferred debits and other assets
Investment in consolidated subsidiaries		10,740		−		(10,740	)		−
Goodwill		−		1		3,654			3,655
Other assets and deferred debits		126		1,583		1,507			3,216
Total deferred debits and other assets		10,866		1,584		(5,579	)		6,871
Total assets	$	11,125	$	9,152	$	5,424		$	25,701
Capitalization
Common stock equity	$	8,286	$	2,708	$	(2,708	)	$	8,286
Preferred stock of subsidiaries – not subject to mandatory redemption		−		34		59			93
Minority interest		−		6		4			10
Long-term debt, affiliate		−		309		(38	)		271
Long-term debt, net		2,582		2,512		3,470			8,564
Total capitalization		10,868		5,569		787			17,224
Current liabilities
Current portion of long-term debt		−		124		200			324
Notes payable to affiliated companies		−		77		(77	)		−
Liabilities of discontinued operations		−		13		176			189
Other current liabilities		210		1,281		814			2,305
Total current liabilities		210		1,495		1,113			2,818
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		61		245			306
Regulatory liabilities		−		1,091		1,452			2,543
Accrued pension and other benefits		14		377		566			957
Other liabilities and deferred credits		33		559		1,261			1,853
Total deferred credits and other liabilities		47		2,088		3,524			5,659
Total capitalization and liabilities	$	11,125	$	9,152	$	5,424		$	25,701

57

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		$	595		$	957
Investing activities
Gross utility property additions		−			(819	)		(585	)		(1,404	)
Nuclear fuel additions		−			(39	)		(159	)		(198	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			38			621			659
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 affiliates		(250	)		37			213			−
Return of investment in consolidated subsidiary		190			−			(190	)		−
Other investing activities		(5	)		10			6			11
Net cash used by investing activities		(44	)		(951	)		(70	)		(1,065	)
Financing activities
Issuance of common stock		134			−			−			134
Proceeds from issuance of long-term debt, net		−			742			−			742
Net increase in short-term debt		400			−			150			550
Retirement of long-term debt		−			(87	)		(200	)		(287	)
Dividends paid on common stock		(469	)		−			−			(469	)
Dividends paid to parent		−			(10	)		10			−
Changes in advances from affiliates		−			214			(214	)		−
Cash distributions to minority interests of consolidated subsidiary		−			(10	)		−			(10	)
Other financing activities		−			49			(27	)		22
Net cash provided (used) by financing activities		65			898			(281	)		682
Cash used by discontinued operations
Operating activities		−			(1	)		(219	)		(220	)
Investing activities		−			(1	)		(1	)		(2	)
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

58

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	376		$	728		$	405		$	1,509
Investing activities
Gross utility property additions		−			(519	)		(493	)		(1,012	)
Diversified business property additions		−			(1	)		−			(1	)
Nuclear fuel additions		−			(6	)		(65	)		(71	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			134			414			548
Purchases of available-for-sale securities and other investments		(392	)		(547	)		(748	)		(1,687	)
Proceeds from sales of available-for-sale securities and other investments		191			646			774			1,611
Changes in advances to affiliates		248			(7	)		(241	)		−
Return of investment in consolidated subsidiary		287			−			(287	)		−
Other investing activities		(5	)		(3	)		(8	)		(16	)
Net cash provided (used) by investing activities		329			(303	)		(654	)		(628	)
Financing activities
Issuance of common stock		73			−			−			73
Proceeds from issuance of long-term debt, net		397			−			−			397
Net decrease in short-term debt		−			(102	)		(73	)		(175	)
Retirement of long-term debt		(801	)		(47	)		−			(848	)
Dividends paid on common stock		(454	)		−			−			(454	)
Dividends paid to parent		−			(222	)		222			−
Changes in advances from affiliates		−			(132	)		132			−
Cash distributions to minority interests of consolidated subsidiary		−			(74	)		−			(74	)
Other financing activities		(7	)		9			(44	)		(42	)
Net cash (used) provided by financing activities		(792	)		(568	)		237			(1,123	)
Cash provided (used) by discontinued operations
Operating activities		−			94			21			115
Investing activities		−			(143	)		−			(143	)
Net (decrease) increase in cash and cash equivalents		(87	)		(192	)		9			(270	)
Cash and cash equivalents at beginning of period		239			239			127			605
Cash and cash equivalents at end of period	$	152		$	47		$	136		$	335

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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 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, 2006 (2006 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 2006 Form 10-K.

PROGRESS ENERGY

RESULTS OF OPERATIONS

Our reportable operating business segments and their primary operations include:

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

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

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

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

As discussed in “Other Matters – Synthetic Fuels Tax Credits,” on September 14, 2007, we idled production of synthetic fuels at our majority-owned synthetic fuels facilities. The decision to idle production was based on the current high level of oil prices and the resumption of synthetic fuels production was dependent upon a number of factors, including a reduction in oil prices. On October 12, 2007, based upon the continued high level of oil prices, unfavorable oil price projections through the end of 2007, and the expiration of the current synthetic fuels tax credit program at the end of 2007, we decided to permanently cease production of synthetic fuels at our majority-owned facilities. The operation of synthetic fuels facilities on behalf of third parties is expected to continue through December 31, 2007. Because we have abandoned our majority-owned facilities and our other synthetic fuels operations will cease as of December 31, 2007, we expect to report all of our synthetic fuels operations as discontinued operations in the fourth quarter of 2007.

60

As discussed more fully in Note 3 and “Results of Operations – Discontinued Operations,” many of our nonregulated business operations have recently been divested or are in the process of being divested. These operations have been classified as discontinued operations in the accompanying financial statements. The composition of our reportable operating business 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, 2007, are compared to the same periods in 2006. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

Overview

For the quarter ended September 30, 2007, our net income was $319 million, or $1.24 per share, compared to net income of $319 million, or $1.27 per share, for the same period in 2006. For the quarter ended September 30, 2007, our income from continuing operations was $319 million compared to $283 million for the same period in 2006. The increase in income from continuing operations as compared to prior year was primarily due to:

· higher tax credits due to higher synthetic fuels production;

· unrealized mark-to-market gains on Coal and Synthetic Fuels derivative contracts;

· favorable weather at the Utilities;

· 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;

· lower Clean Smokestacks Act amortization expense at PEC;

· lower interest expense due to reducing holding company debt in late 2006;

· lower income tax expense related to the deduction for domestic production activities; and

· higher wholesale sales at the Utilities.

Partially offsetting these items were:

· higher operating and maintenance expenses (O&M) at the Utilities;

· higher phase-out of year-to-date tax credits related to synthetic fuels production; and

· lower margins at Coal and Synthetic Fuels due to higher synthetic fuels production.

For the nine months ended September 30, 2007, our net income was $401 million, or $1.57 per share, compared to net income of $317 million, or $1.27 per share, for the same period in 2006. For the nine months ended September 30, 2007, our income from continuing operations was $670 million compared to $387 million for the same period in 2006. The increase in income from continuing operations as compared to prior year was primarily due to:

· higher tax credits due to higher synthetic fuels production;

· impairment of our synthetic fuels assets and a portion of our coal terminal assets in 2006;

· unrealized mark-to-market gains on Coal and Synthetic Fuels derivative contracts;

· lower interest expense due to reducing holding company debt in late 2006;

· favorable weather at PEC;

· the impact of unrealized losses recorded on contingent value obligations (CVOs) during 2006;

· lower Clean Smokestacks Act amortization expense at PEC;

· lower income tax expense due to the closure of certain federal tax years and positions;

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

· higher wholesale sales at PEF; and

· favorable growth and usage at the Utilities.

61

Partially offsetting these items were:

· higher phase-out of tax credits related to synthetic fuels production;

· higher O&M expenses at the Utilities;

· the impact of the 2006 gain on sale of Level 3 Communications, Inc. (Level 3) stock acquired as part of the divestiture of Progress Telecom, LLC (PT LLC); and

· higher other operating expenses due to disallowed fuel costs at PEF.

Our segments contributed the following profits or losses for the three and nine months ended September 30, 2007 and 2006:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Business Segment
PEC	$	203		$	188		$	414		$	349
PEF		138			125			266			264
Coal and Synthetic Fuels		(16	)		7			56			(83	)
Total segment profit		325			320			736			530
Corporate and Other		(6	)		(37	)		(66	)		(143	)
Income from continuing operations		319			283			670			387
Discontinued operations, net of tax		−			36			(269	)		(70	)
Net income	$	319		$	319		$	401		$	317

Progress Energy Carolinas

PEC contributed segment profits of $203 million and $188 million for the three months ended September 30, 2007 and 2006, respectively. The increase in profits for the three months ended September 30, 2007, compared to the same period in 2006, was primarily due to favorable weather, lower North Carolina Clean Smokestacks Act (Clean Smokestacks Act) amortization and higher wholesale sales, partially offset by higher O&M expenses related to plant outage and maintenance costs and employee benefit costs.

PEC contributed segment profits of $414 million and $349 million for the nine months ended September 30, 2007 and 2006, respectively. The increase in profits for the nine months ended September 30, 2007, compared to the same period in 2006, was primarily due to favorable weather, lower Clean Smokestacks Act amortization and favorable retail growth and usage, partially offset by higher O&M expenses related to plant outage and maintenance costs and employee benefit costs.

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 a presentation defined under GAAP, and it may not be comparable to other companies’ presentation nor more useful than the GAAP information provided elsewhere in this report.

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Three Months ended September 30, 2007, Compared to Three Months ended September 30, 2006

REVENUES

PEC’s revenues for the three months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended September 30,
Customer Class	2007			Change			% Change			2006
Residential	$	503		$	45			9.8		$	458
Commercial		325			28			9.4			297
Industrial		196			(2	)		(1.0	)		198
Governmental		29			1			3.6			28
Total retail revenues		1,053			72			7.3			981
Wholesale		208			3			1.5			205
Unbilled		−			9			−			(9	)
Miscellaneous		25			2			8.7			23
Total electric revenues		1,286			86			7.2			1,200
Less: Fuel revenues		(441	)		(49	)		−			(392	)
Revenues excluding fuel	$	845		$	37			4.6		$	808

PEC’s energy sales for the three months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2007	Change	% Change	2006
Residential	5,118	232	4.7	4,886
Commercial	4,091	116	2.9	3,975
Industrial	3,110	(207)	(6.2)	3,317
Governmental	421	(6)	(1.4)	427
Total retail energy sales	12,740	135	1.1	12,605
Wholesale	4,184	210	5.3	3,974
Unbilled	(138)	110	−	(248)
Total kWh sales	16,786	455	2.8	16,331

PEC’s revenues, excluding fuel revenues of $441 million and $392 million for the three months ended September 30, 2007 and 2006, respectively, increased $37 million. The increase in revenues is primarily due to the $24 million favorable impact of weather with cooling degree days 15 percent higher than 2006. Additionally, wholesale revenues, excluding fuel revenues, increased $5 million due to higher wholesale sales and capacity revenues due to contract changes primarily with two major customers and the favorable impact of weather. Overall growth and usage did not have a material impact on revenues because favorable growth driven by an approximate increase in the average number of customers of 28,000 for the three months ended September 30, 2007, compared to the same period in 2006, was offset by lower average usage per customer.

Industrial electric energy revenues and sales decreased in 2007 compared to 2006 primarily due to continued reduction in textile manufacturing in North and South Carolina as a result of global competition and domestic consolidation as well as a downturn in the lumber and building materials segment as a result of declines in residential construction.

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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 $494 million for the three months ended September 30, 2007, which represents a $37 million increase compared to the same period in 2006. Fuel used in electric generation increased $63 million to $385 million compared to the prior year. This increase is due to a $39 million increase in fuel used in generation primarily due to higher system requirements and a change in generation mix as the percentage of generation supplied by natural gas increased in response to plant outages. A $24 million increase in deferred fuel expense primarily due to the collection of fuel costs from customers that had been previously under-recovered also contributed to the increase in fuel expense. Current year purchased power costs were $26 million lower than the three months ended September 30, 2006, due to lower cogeneration as a result of contract changes with one of PEC’s co-generators and decreased availability from a plant with which PEC has a tolling agreement.

Operation and Maintenance

O&M expenses were $246 million for the three months ended September 30, 2007, which represents a $28 million increase compared to the same period in 2006. O&M expenses increased $16 million primarily due to higher plant outage and maintenance costs and $11 million due to higher employee benefit costs.

Depreciation and Amortization

Depreciation and amortization expense was $118 million for the three months ended September 30, 2007, which represents a $10 million decrease compared to the same period in 2006. Depreciation and amortization expense decreased $14 million due to lower Clean Smokestacks Act amortization, partially offset by the impact of depreciable asset base increases.

Total Other Income

Total other income was $4 million for the three months ended September 30, 2007, compared to total other expense of $3 million for the same period in 2006. This change is primarily due to an $8 million increase in an indemnification liability recorded in the prior year for estimated capital costs associated with Clean Smokestacks Act compliance expected to be incurred in excess of the maximum billable costs to the joint owner (See Note 12B).

Total Interest Charges, net

Total interest charges, net of $56 million increased $12 million for the three months ended September 30, 2007, compared to the same period in 2006, primarily due to the prior year reversal of $14 million of interest related to the favorable resolution of certain tax matters.

Income Tax Expense

Income tax expense increased $9 million for the three months ended September 30, 2007, as compared to the same period in 2006, primarily due to the $10 million tax impact of higher pre-tax earnings, partially offset by the $2 million impact related to the deduction for domestic production activities.

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Nine Months ended September 30, 2007, Compared to Nine Months ended September 30, 2006

REVENUES

PEC’s revenues for the nine months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions)	Nine Months Ended September 30,
Customer Class	2007			Change			% Change			2006
Residential	$	1,254		$	121			10.7		$	1,133
Commercial		840			81			10.7			759
Industrial		535			1			0.2			534
Governmental		73			4			5.8			69
Total retail revenues		2,702			207			8.3			2,495
Wholesale		560			(4	)		(0.7	)		564
Unbilled		3			24			−			(21	)
Miscellaneous		74			(1	)		(1.3	)		75
Total electric revenues		3,339			226			7.3			3,113
Less: Fuel revenues		(1,157	)		(153	)		−			(1,004	)
Revenues excluding fuel	$	2,182		$	73			3.5		$	2,109

PEC’s energy sales for the nine months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2007	Change	% Change	2006
Residential	13,434	693	5.4	12,741
Commercial	10,682	437	4.3	10,245
Industrial	8,917	(472)	(5.0)	9,389
Governmental	1,080	−	−	1,080
Total retail energy sales	34,113	658	2.0	33,455
Wholesale	11,306	46	0.4	11,260
Unbilled	(78)	317	−	(395)
Total kWh sales	45,341	1,021	2.3	44,320

PEC’s revenues, excluding fuel revenues of $1.157 billion and $1.004 billion for the nine months ended September 30, 2007 and 2006, respectively, increased $73 million. The increase in revenues is primarily due to favorable weather and favorable retail growth and usage. The impact of weather was $50 million favorable with heating degree days five percent higher than 2006 and cooling degree days 14 percent higher than 2006. Favorable retail growth and usage of $13 million was driven by an approximate increase in the average number of customers of 28,000 for the nine months ended September 30, 2007, compared to the same period in 2006, partially offset by a decrease in the average usage per retail customer.

Industrial electric energy sales decreased in 2007 compared to 2006 primarily due to continued reduction in textile manufacturing in the Carolinas as a result of global competition and domestic consolidation as well as a downturn in the lumber and building materials segment as a result of declines in residential construction. The increase in industrial revenues for 2007 compared to 2006 is due to an increase in 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 expenses were $1.284 billion for the nine months ended September 30, 2007, which represents a $125 million increase compared to the same period in 2006. Fuel used in electric generation increased $161 million to $1.041 billion compared to the prior year. This increase is due to a $112 million increase in fuel used in generation primarily due to higher system requirements and a change in generation mix as the percentage of generation supplied by natural gas increased in response to plant outages. A $49 million increase in deferred fuel expense primarily due to the collection of fuel costs from customers that had been previously under-recovered also contributed to the increase in fuel expense. Current year purchased power costs were $36 million lower than the nine months ended September 30, 2006, due to lower cogeneration as a result of contract changes with one of PEC’s co-generators.

Operation and Maintenance

O&M expenses were $762 million for the nine months ended September 30, 2007, which represents a $40 million increase compared to the same period in 2006. O&M expenses increased $35 million primarily due to higher plant outage and maintenance costs, $19 million due to higher employee benefit costs and $4 million of higher costs related to the operation of emission control equipment installed at our coal-fired plants. This was partially offset by a decrease of $23 million primarily due to recording additional estimated environmental remediation expenses in 2006 (See Note 12A).

Depreciation and Amortization

Depreciation and amortization expense was $353 million for the nine months ended September 30, 2007, which represents a $30 million decrease compared to the same period in 2006. Depreciation and amortization expense decreased $40 million due to lower Clean Smokestacks Act amortization, partially offset by the impact of depreciable asset base increases.

Taxes other than on Income

Taxes other than on income were $151 million for the nine months ended September 30, 2007, which represents a $10 million increase compared to the same period in 2006. The increase is primarily due to an $8 million increase in gross receipts taxes due to higher retail revenues. Gross receipts taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Total Other Income

Total other income of $25 million increased $19 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to a $13 million increase in an indemnification liability recorded in the prior year for estimated capital costs associated with Clean Smokestacks Act compliance expected to be incurred in excess of the maximum billable costs to the joint owner (See Note 12B). Additionally, AFUDC equity increased $5 million related to costs associated with certain large construction projects.

Total Interest Charges, net

Total interest charges, net of $165 million increased $8 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to the prior year reversal of $14 million of interest related to the favorable resolution of certain tax matters, partially offset by the current year reversal of $4 million of interest related to the closure of certain federal tax years and positions (See Note 7).

Income Tax Expense

Income tax expense increased $27 million for the nine months ended September 30, 2007, as compared to the same period in 2006, primarily due to the $37 million tax impact of higher pre-tax earnings. This was partially offset by

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$5 million of favorable current year changes related to prior year federal and state income tax returns and the $4 million impact related to the deduction for domestic production activities.

Progress Energy Florida

PEF contributed segment profits of $138 million and $125 million for the three months ended September 30, 2007 and 2006, respectively. The increase in profits for the three months ended September 30, 2007, compared to the same period in 2006, was primarily due to lower income tax expense, favorable weather, lower property taxes and higher wholesale sales, partially offset by higher O&M expenses related to employee benefit costs and plant outage and maintenance costs and higher non-recovery clause depreciation and amortization expense.

PEF contributed segment profits of $266 million and $264 million for the nine months ended September 30, 2007 and 2006, respectively. The increase in profits for the nine months ended September 30, 2007, compared to the same period in 2006, was primarily due to lower income tax expense, higher wholesale sales and favorable AFUDC equity, partially offset by higher O&M expenses related to plant outage and maintenance costs and employee benefit costs, higher non-recovery clause depreciation and amortization expense and higher other operating expenses.

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 a presentation defined under GAAP, and it may not be comparable to other companies’ presentation nor more useful than the GAAP information provided elsewhere in this report.

Three Months ended September 30, 2007, Compared to Three Months ended September 30, 2006

REVENUES

PEF’s revenues for the three months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended September 30,
Customer Class	2007			Change			% Change			2006
Residential	$	774		$	20			2.7		$	754
Commercial		336			2			0.6			334
Industrial		84			(6	)		(6.7	)		90
Governmental		84			1			1.2			83
Total retail revenues		1,278			17			1.3			1,261
Wholesale		133			35			35.7			98
Unbilled		2			5			−			(3	)
Miscellaneous		43			−			−			43
Total electric revenues		1,456			57			4.1			1,399
Less: Fuel and other pass-through revenues		(966	)		(41	)		−			(925	)
Revenues excluding fuel and other pass-through revenues	$	490		$	16			3.4		$	474

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PEF’s electric energy sales for the three months ended September 30, 2007 and 2006, and the amount and percentage change by customer class are as follows:

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2007	Change	% Change	2006
Residential	6,490	121	1.9	6,369
Commercial	3,555	74	2.1	3,481
Industrial	1,008	(59)	(5.5)	1,067
Governmental	927	22	2.4	905
Total retail energy sales	11,980	158	1.3	11,822
Wholesale	1,753	381	27.8	1,372
Unbilled	(22)	75	−	(97)
Total kWh sales	13,711	614	4.7	13,097

PEF’s revenues, excluding fuel and other pass-through revenues of $966 million and $925 million for the three months ended September 30, 2007 and 2006, respectively, increased $16 million. The increase in revenues is primarily due to the $11 million favorable impact of weather with cooling degree days six percent higher than 2006. Additionally, wholesale revenues, excluding fuel and other pass-through revenues, increased $7 million primarily due to higher sales and capacity revenues associated with contract changes with several major customers and the favorable impact of weather. Overall growth and usage did not have a material impact on revenues because favorable growth driven by an approximate average net increase in the number of customers of 22,000 for the three months ended September 30, 2007, compared to the same period in 2006 was offset by lower average usage per customer.

Industrial electric energy revenues and sales decreased in 2007 compared to 2006 primarily due to a change in the terms of an agreement with a major customer.

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 $825 million for the three months ended September 30, 2007, which represents a $31 million increase compared to the same period in 2006. Fuel used in electric generation increased $6 million to $544 million compared to the prior year. This increase is due to increased current year fuel costs of $109 million, partially offset by lower deferred fuel expense of $103 million. The increase in current year fuel costs is primarily due to an increase in oil prices. Deferred fuel expenses were higher in 2006 primarily due to the collection of fuel costs from customers that had been previously under-recovered. Current year purchased power costs were $25 million higher than the three months ended September 30, 2006, due to increased current year purchases of $29 million as a result of higher capacity costs, primarily due to new contracts, and higher prices, partially offset by lower recovery of deferred capacity costs of $4 million.

Operation and Maintenance

O&M expenses were $213 million for the three months ended September 30, 2007, which represents a $42 million increase when compared to the same period in 2006. O&M expenses increased $17 million related to an increase in storm damage reserves from the one-year extension of the storm surcharge, which began August 2007; $12 million related to higher environmental cost recovery (ECRC) and energy conservation cost recovery (ECCR) costs; $8 million due to higher employee benefit costs and $5 million due to higher plant outage and maintenance costs. The storm damage reserve, ECRC and ECCR expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings.

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Depreciation and Amortization

Depreciation and amortization expense was $100 million for the three months ended September 30, 2007, which represents an $8 million decrease compared to the same period in 2006. Depreciation and amortization expense decreased $16 million due to lower amortization of unrecovered storm restoration costs, partially offset by a $7 million write-off of leasehold improvements, primarily related to vacated office space. Storm restoration costs, which were fully amortized in August 2007, were recovered through a cost-recovery clause and, therefore, have no material impact on earnings.

Taxes other than on Income

Taxes other than on income were $83 million for the three months ended September 30, 2007, which represents a $6 million decrease compared to the same period in 2006. The decrease is primarily due to lower property taxes of $7 million as a result of lower property tax rates and decreased property value assessments in accordance with a state mandate.

Total Other Income

Total other income of $13 million increased $3 million for the three months ended September 30, 2007, compared to the same period in 2006, primarily due to a $6 million increase in AFUDC equity related to costs associated with large construction projects, partially offset by lower interest income. Interest income decreased $3 million due primarily to lower interest on unrecovered storm restoration costs and lower short-term investment balances. We expect AFUDC equity to continue to increase for the remainder of 2007.

Income Tax Expense

Income tax expense decreased $15 million for the three months ended September 30, 2007, compared to the same period in 2006, primarily due to the $6 million impact of tax levelization, discussed below, the $4 million impact of prior year unfavorable tax adjustments and the $3 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 tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was decreased by $4 million for the three months ended September 30, 2007 compared to an increase of $2 million for the three months ended September 30, 2006, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

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Nine Months ended September 30, 2007, Compared to Nine Months ended September 30, 2006

REVENUES

PEF’s revenues for the nine months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions)	Nine Months Ended September 30,
Customer Class	2007			Change			% Change			2006
Residential	$	1,798		$	(22	)		(1.2	)	$	1,820
Commercial		864			(5	)		(0.6	)		869
Industrial		236			(28	)		(10.6	)		264
Governmental		225			2			0.9			223
Retail revenue sharing		−			(1	)		(100.0	)		1
Total retail revenues		3,123			(54	)		(1.7	)		3,177
Wholesale		314			78			33.1			236
Unbilled		29			8			−			21
Miscellaneous		130			11			9.2			119
Total electric revenues		3,596			43			1.2			3,553
Less: Fuel and other pass-through revenues		(2,336	)		(21	)		−			(2,315	)
Revenues excluding fuel and other pass-through revenues	$	1,260		$	22			1.8		$	1,238

PEF’s electric energy sales for the nine months ended September 30, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2007	Change	% Change	2006
Residential	15,147	(278)	(1.8)	15,425
Commercial	9,125	85	0.9	9,040
Industrial	2,842	(331)	(10.4)	3,173
Governmental	2,486	54	2.2	2,432
Total retail energy sales	29,600	(470)	(1.6)	30,070
Wholesale	4,370	1,028	30.8	3,342
Unbilled	919	387	−	532
Total kWh sales	34,889	945	2.8	33,944

PEF’s revenues, excluding fuel and other pass-through revenues of $2.336 billion and $2.315 billion for the nine months ended September 30, 2007 and 2006, respectively, increased $22 million. The increase in revenues is primarily due to increased wholesale revenues, other miscellaneous service revenues and favorable growth and usage, partially offset by unfavorable weather. Wholesale revenues, excluding fuel and other pass-through revenues, increased $20 million primarily due to the $18 million impact of increased capacity under contract with a major customer. Other miscellaneous service revenues increased primarily due to increased electric property rental revenues of $8 million. Favorable retail growth and usage of $6 million was driven by an approximate average net increase in the number of customers of 27,000 for the nine months ended September 30, 2007, compared to the same period in 2006, partially offset by lower average usage per customer. The impact of weather was $8 million unfavorable with cooling degree days two percent lower than 2006.

Industrial electric energy revenues and sales decreased in 2007 compared to 2006 primarily due to a change in the terms of an agreement with a major customer.

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EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.991 billion for the nine months ended September 30, 2007, which represents an $11 million increase compared to the same period in 2006. Fuel used in electric generation decreased $39 million to $1.340 billion compared to the prior year. This decrease is due to lower deferred fuel expense of $206 million partially offset by increased current year fuel costs of $167 million. Deferred fuel expenses were higher in 2006 primarily due to the collection of fuel costs from customers that had been previously under-recovered. The increase in current year fuel costs is primarily due to an increase in oil and natural gas prices. Current year purchased power costs were $50 million higher than the nine months ended September 30, 2006, due to increased current year purchases of $64 million as a result of higher capacity costs, primarily due to new contracts, and higher prices, partially offset by lower recovery of deferred capacity costs of $14 million.

Operation and Maintenance

O&M expenses were $586 million for the nine months ended September 30, 2007, which represents a $71 million increase when compared to the same period in 2006. O&M expenses increased $27 million related to higher ECRC and ECCR costs, $17 million related to an increase in storm damage reserves from the one-year extension of the storm surcharge, which began August 2007; $14 million due to higher plant outage and maintenance costs; $9 million due to higher employee benefit costs and $4 million due to the estimated impact of additional Florida sales and use tax related to an ongoing audit in the current year. The ECRC, ECCR and storm damage reserve expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings.

Depreciation and Amortization

Depreciation and amortization expense was $297 million for the nine months ended September 31, 2007, which represents a $4 million decrease compared to the same period in 2006. Depreciation and amortization expense decreased $18 million due to lower amortization of unrecovered storm restoration costs, partially offset by the impact of depreciable asset base increases and a $7 million write-off of leasehold improvements, primarily related to vacated office space. Storm restoration costs, which were fully amortized in August 2007, were recovered through a cost-recovery clause and, therefore, have no material impact on earnings.

Other

Other operating expenses of $12 million increased $14 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to the $12 million impact of a FPSC order requiring PEF to refund disallowed fuel costs to its ratepayers (See Note 4B).

Total Other Income

Total other income of $30 million increased $10 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to a $16 million increase in AFUDC equity related to costs associated with large construction projects, partially offset by lower interest income. Interest income decreased $9 million due primarily to lower short-term investment balances and lower interest on unrecovered storm restoration costs. We expect AFUDC equity to continue to increase for the remainder of 2007.

Income Tax Expense

Income tax expense decreased $38 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to the $14 million tax impact of lower pre-tax earnings compared to the prior year, the $6 million impact of the increase in AFUDC equity discussed above, the $4 million impact related to the closure of certain federal tax years and positions (See Note 7), $5 million impact of tax levelization, discussed below, and the $4 million impact of prior year unfavorable tax adjustments. AFUDC equity is excluded from the calculation of income tax expense. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was decreased by $3 million for the nine months ended September 30, 2007 compared to an increase of $2 million for the nine months ended September 30, 2006, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations

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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.

Coal and Synthetic Fuels

The operations of the Coal and Synthetic Fuels segment include the production and sale of coal-based solid synthetic fuels, the operation of synthetic fuels facilities for third parties, and coal terminal services. The following summarizes the Coal and Synthetic Fuels segment profits, which are reported within Diversified Business on the Consolidated Statements of Income:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Synthetic fuels operations	$	(15	)	$	20		$	73		$	(59	)
Coal terminals and marketing		8			(6	)		8			6
Corporate overhead and other operations		(9	)		(7	)		(25	)		(30	)
Segment (losses) profits	$	(16	)	$	7		$	56		$	(83	)

SYNTHETIC FUELS OPERATIONS

The production and sale of coal-based solid synthetic fuels generate operating losses, but qualify for tax credits under Section 29/45K of the Internal Revenue Code (the Code), which generally more than offset the effect of such losses (See “Other Matters – Synthetic Fuels Tax Credits” below). Our synthetic fuels operations were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2007			2006			2007			2006
Tons sold		2.3			0.2			6.8			1.9
After-tax losses (excluding impairment charge, valuation allowance and tax credits)	$	(4	)	$	(2	)	$	(19	)	$	(52	)
After-tax impairment charge		−			−			−			(45	)
Net operating loss (NOL) valuation allowance		−			−			−			(7	)
Tax credits generated		67			6			200			54
Tax credit inflation adjustment		−			−			2			10
Tax credits reserve (increase) decrease due to estimated phase-out		(78	)		16			(110	)		(19	)
Net (loss) profit	$	(15	)	$	20		$	73		$	(59	)

Synthetic fuels operations had a net loss of $15 million for the three months ended September 30, 2007, compared to a net profit of $20 million for the same period in 2006. After-tax losses (excluding impairment charges, valuation allowance and tax credits) for synthetic fuels operations increased $2 million for the three months ended September 30, 2007, compared to the same period in 2006, primarily due to the impact of $32 million of lower after-tax margins as a result of higher coal-based solid synthetic fuels production, partially offset by the $31 million unrealized after-tax mark-to-market gain recorded on derivative contracts entered into in January 2007 (See Note 9A). Tax credits recorded during the three months ended September 30, 2007, compared to the same period in 2006, increased due to higher production. We increased production in 2007 as a result of shorter idling of synthetic fuels production in the current year compared to the prior year and the protection against oil price increases provided by the derivative contracts in the current year. The change in the tax credit reserve is primarily due to the increase in production and the change in the relative level of oil prices, which indicated an increase in estimated phase-out from 24 percent at June 30, 2007, to 55 percent at September 30, 2007, compared to a decrease in estimated phase-out from 72 percent at June 30, 2006 to 35 percent at September 30, 2006. Of the $78 million tax credit reserve increase during the three months ended September 30, 2007, $41 million relates to tax credits generated during the first six months of 2007. Similarly, of the $16 million tax credit reserve decrease during the three months ended September

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30, 2006, $18 million relates to tax credits generated during the first six months of 2006. The 2007 tax credit reserve increase is due to the potential phase-out of the tax credits generated in 2007.

Synthetic fuels operations had a net profit of $73 million for the nine months ended September 30, 2007, compared to a net loss of $59 million for the same period in 2006. After-tax losses (excluding impairment charges, valuation allowance and tax credits) for synthetic fuels operations decreased $33 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to the $45 million unrealized after-tax mark-to-market gain recorded on derivative contracts entered into in January 2007 (See Note 9A). After-tax losses (excluding impairment charges, valuation allowance and tax credits) were also positively impacted by lower depreciation expense due to the second quarter 2006 impairment of our synthetic fuels assets and the $6 million after-tax impact of the recovery of losses from an equity investment. These were partially offset by $46 million of lower after-tax margins due to the increase in coal-based solid synthetic fuels production. Net profit for synthetic fuels operations increased in 2007 due to the $45 million after-tax impairment of synthetic fuels assets and the $7 million recognition of a valuation allowance recorded against the deferred tax assets for state NOL carry forwards, both of which were recorded in 2006. Tax credits recorded during the nine months ended September 30, 2007, compared to the same period in 2006, increased due to higher production. We increased production in 2007 as a result of shorter idling of synthetic fuels production in the current year compared to the prior year and the protection against oil price increases provided by the derivative contracts in the current year. The change in the tax credit reserve is primarily due to the increase in production and the change in the relative level of oil prices, which indicated a higher estimated phase-out in 2007 compared to 2006. The 2007 tax credit reserve increase includes $110 million due to the potential phase-out of the 2007 tax credits. The Department of the Treasury released the final 2006 inflation adjustment factor and the average wellhead price per barrel for unregulated domestic crude oil, which indicated a phase-out and devaluation of 33 percent of the 2006 tax credits. This was 2 percent, or $2 million, lower than our December 31, 2006 phase-out estimate of 35 percent.

On September 14, 2007, we idled production of synthetic fuels at our majority-owned synthetic fuels facilities. The decision to idle production was based on the current high level of oil prices and the resumption of synthetic fuels production was dependent upon a number of factors, including a reduction in oil prices. On October 12, 2007, based upon the continued high level of oil prices, unfavorable oil price projections through the end of 2007, and the expiration of the current synthetic fuels tax credit program at the end of 2007, we decided to permanently cease production of synthetic fuels at our majority-owned facilities. The operation of synthetic fuels facilities on behalf of third parties is expected to continue through December 31, 2007. Because we have abandoned our majority-owned facilities and our other synthetic fuels operations will cease as of December 31, 2007, we expect to report all of our synthetic fuels operations as discontinued operations in the fourth quarter of 2007. See “Other Matters – Synthetic Fuels Tax Credits” below for additional information on the impact of oil prices on Section 29/45K tax credits.

In March 2007, we disposed of our 100 percent ownership interest in Ceredo Synfuel LLC (Ceredo) and entered into an agreement to operate Ceredo on behalf of the third-party buyer (see Note 3I and “Other Matters – Synthetic Fuels Tax Credits”). We have continued to consolidate Ceredo in accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51” (FIN 46R), but we have recorded a 100 percent minority interest and there is no net earnings impact from Ceredo’s operations subsequent to the disposal. Consequently, tons sold, net operating results and tax credits recorded by Ceredo subsequent to March 31, 2007, are excluded from our Coal and Synthetic Fuels segment.

COAL TERMINALS AND MARKETING

Coal terminals and marketing (Coal) operations blend and transload coal as part of the trucking, rail and barge network for coal delivery. This business also has an operating fee agreement with our synthetic fuels operations for the procuring and processing of coal and the transloading and marketing of synthetic fuels. Coal operations had earnings of $8 million for the three months ended September 30, 2007, compared to losses of $6 million for the same period in 2006. Coal’s 2007 results increased due to the $24 million pre-tax increase in sales. As a result of the relationship with the synthetic fuels operations, fluctuations in Coal’s annual earnings are primarily related to production volumes at our synthetic fuels facilities. Because of the relationship with our synthetic fuels operations, which will cease in 2007, we expect to incur immaterial losses in the fourth quarter and we are currently evaluating alternative business strategies with respect to our Coal operations.

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Coal operations had earnings of $8 million for the nine months ended September 30, 2007, compared to earnings of $6 million for the same period in 2006. Coal’s 2007 results increased primarily due to a $17 million pre-tax increase in sales and the $17 million pre-tax impairment of a portion of Coal’s terminal assets recorded in 2006, partially offset by the prior year impact of the $11 million pre-tax expense reduction due to restructuring a coal supply contract in 2006 and the $10 million pre-tax expense due to a contract buyout for future coal purchases.

CORPORATE OVERHEAD AND OTHER OPERATIONS

Corporate overhead and other operations incurred losses of $9 million and $7 million for the three months ended September 30, 2007 and 2006, respectively, and $25 million and $30 million for the nine months ended September 30, 2007 and 2006, respectively. The increase in losses for the three months ended September 30, 2007, compared to the same period in 2006, is primarily due to higher interest expense driven by increased money pool borrowings to finance increased coal-based solid synthetic fuels production. The decrease in losses for the nine months ended September 30, 2007, compared to the same period in 2006, is primarily due to a decrease in the allocation of corporate overhead and lower interest expense resulting from the divestitures completed during 2006.

Corporate and Other

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

	Three Months Ended September 30,						Nine Months Ended  September 30,
(in millions)	2007			2006			2007			2006
Other interest expense	$	(50	)	$	(64	)	$	(136	)	$	(187	)
Contingent value obligations		1			(3	)		(2	)		(25	)
Tax levelization		21			15			(2	)		(5	)
Other income tax benefit		24			16			78			58
Other		(2	)		(1	)		(4	)		16
Corporate and Other after-tax expense	$	(6	)	$	(37	)	$	(66	)	$	(143	)

Other interest expense decreased $14 million for the three months ended September 30, 2007, and decreased $51 million for the nine months ended September 30, 2007, compared to the same periods in 2006. The decrease for the three months ended September 30, 2007, is primarily due to the $1.7 billion reduction in holding company debt during 2006, partially offset by a $14 million decrease in the interest allocated to discontinued operations. The decrease for the nine months ended September 30, 2007, is primarily due to the $1.7 billion reduction in holding company debt during 2006 and the impact of the closure of certain federal tax years and positions (See Note 7), partially offset by a $36 million 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 2006 for operations that were sold later in 2006. Interest expense allocated to discontinued operations was less than $1 million and $14 million for the three months ended September 30, 2007 and 2006, respectively. Interest expense allocated to discontinued operations was $12 million and $48 million for the nine months ended September 30, 2007 and 2006.

Progress Energy issued 98.6 million CVOs in connection with the acquisition of Florida Progress in 2000. Each CVO represents the right of the holder to receive contingent payments based on the performance of four synthetic fuels facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At September 30, 2007 and 2006, the CVOs had fair market values of approximately $34 million and $33 million, respectively. We recorded an unrealized gain of $1 million for the three months ended September 30, 2007, and unrealized losses of $3 million for the three months ended September 30, 2006, to record the changes in fair value of the CVOs, which had average unit prices of $0.35 and $0.33 at September 30, 2007 and 2006, respectively. We recorded unrealized losses of $2 million for the nine months ended September 30, 2007, and unrealized losses of $25 million for the nine months ended September 30, 2006.

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GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $21 million for the three months ended September 30, 2007, compared to a decrease of $15 million for the three months ended September 30, 2006, and increased by $2 million for the nine months ended September 30, 2007, compared to an increase of $5 million for the nine months ended September 30, 2006, in order to maintain an effective rate consistent with the estimated annual rate. The tax credits associated with our synthetic fuels operations and seasonal fluctuations in our annual earnings primarily drive the fluctuations in the effective tax rate for interim periods. The tax levelization adjustment will vary each quarter, but it will have no effect on net income for the year.

Other income tax benefit increased for the three months ended September 30, 2007, compared to the same period in 2006, primarily due to the $5 million tax impact related to the deduction for domestic production activities. Other income tax benefit increased for the nine months ended September 30, 2007, compared to the same periods in 2006, primarily due to the $14 million impact related to the closure of certain federal tax years and positions (See Note 7) and other tax adjustments.

Other decreased $20 million for the nine months ended September 30, 2007, compared to the same period in 2006, primarily due to the $17 million gain, net of minority interest, on the sale of Level 3 stock subsequent to the sale of PT LLC in 2006 (See Note 3D).

Discontinued Operations

Over the last several years, we have reduced our business risk by exiting the majority of our nonregulated businesses. We divested, or announced divestitures, of multiple nonregulated businesses during 2007 and 2006 in accordance with our business strategy to reduce our business risk and to focus on the core operations of the Utilities. Consequently, we no longer report a Progress Ventures segment, and the composition of other continuing segments has been impacted by these divestitures.

CCO OPERATIONS

CCO – Georgia Region

On March 9, 2007, our subsidiary, Progress 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 quarter ended March 31, 2007, we reversed $16 million after-tax of the impairment recorded in 2006. During each of the quarters ended June 30, 2007, and September 30, 2007, we reversed an additional $1 million after-tax of the impairment as a result of closing adjustments.

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

CCO’s operations generated net losses from discontinued operations of $1 million and $40 million for the three months ended September 30, 2007 and 2006, respectively.

CCO’s operations generated net losses from discontinued operations of $280 million and $114 million for the nine months ended September 30, 2007 and 2006, respectively. Net losses from discontinued operations for the nine months ended September 30, 2007, primarily represent the $349 million after-tax charge associated with exit costs, partially offset by unrealized mark-to-market gains related to the increase in natural gas prices.

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CCO – DeSoto and Rowan Generation Facilities

On May 2, 2006, our board of directors approved a plan to divest of two subsidiaries of PVI, DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (Rowan). DeSoto owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Fla., and Rowan owns a 925 MW dual-fuel combined cycle and combustion turbine electric generation facility in Rowan County, N.C. On May 8, 2006, we entered into definitive agreements to sell DeSoto and Rowan, including certain existing power supply contracts, to Southern Power Company, a subsidiary of Southern Company, for gross sales prices of approximately $80 million and $325 million, respectively. We used the proceeds from the sales to reduce debt and for other corporate purposes.

The sale of DeSoto closed in the second quarter of 2006 and the sale of Rowan closed during the third quarter of 2006. We recorded an after-tax loss during the nine months ended September 30, 2006, on the sale of DeSoto and Rowan of $65 million.

DeSoto and Rowan operations generated combined net earnings from discontinued operations of $18 million and $9 million for the three and nine months ended September 30, 2006, respectively.

NATURAL GAS DRILLING AND PRODUCTION

On October 2, 2006, we sold our natural gas drilling and production business (Gas) to EXCO Resources, Inc. for approximately $1.1 billion in net proceeds. Gas included Winchester Production Company, Ltd. (Winchester Production), Westchester Gas Company, Texas Gas Gathering and Talco Midstream Assets Ltd.; all were subsidiaries of Progress Fuels. We used the proceeds from the sale primarily to reduce holding company debt and for other corporate purposes.

Based on the net proceeds associated with the sale, we recorded an after-tax net gain on disposal of $300 million during the year ended December 31, 2006. We recorded an after-tax loss of $1 million during the three months ended March 31, 2007, primarily related to working capital adjustments.

Gas operations generated net earnings from discontinued operations of $1 million for the three and nine months ended September 30, 2007. Net earnings from discontinued operations were $57 million and $84 million for the three and nine months ended September 30, 2006, respectively.

PROGRESS TELECOM, LLC

On March 20, 2006, we completed the sale of PT LLC to Level 3. We received gross proceeds comprised of cash of $69 million and approximately 20 million shares of Level 3 common stock valued at an estimated $66 million on the date of the sale. Our net proceeds from the sale of approximately $70 million, after consideration of minority interest, were used to reduce debt. Prior to the sale, we had a 51 percent interest in PT LLC. See Note 11 for a discussion of the subsequent sale of the Level 3 stock.

Based on the net proceeds associated with the sale and after consideration of minority interest, we recorded an after-tax net gain on disposal of $24 million during the three months ended March 31, 2006. During the three months ended June 30, 2006, we recorded an additional after-tax gain of $5 million in connection with certain tax matters. During the three months ended September 30, 2006, we recorded a $1 million adjustment related to additional tax expenses resulting in a total after-tax gain of $28 million for the nine months ended September 30, 2006.

Net earnings from discontinued operations for PT LLC were $2 million for the three months ended September 30, 2006. Net losses from discontinued operations were $3 million for the nine months ended September 30, 2006.

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DIXIE FUELS AND OTHER FUELS BUSINESS

On March 1, 2006, we sold our 65 percent interest in Dixie Fuels Limited (Dixie Fuels) to Kirby Corporation for $16 million in cash. Dixie Fuels operates a fleet of four ocean-going dry-bulk barge and tugboat units. Dixie Fuels primarily transports coal from the lower Mississippi River to Progress Energy’s Crystal River facility. We recorded an after-tax gain of $2 million on the sale of Dixie Fuels.

Net earnings from discontinued operations were $3 million and $6 million for the three and nine months ended September 30, 2006, respectively.

COAL MINING BUSINESSES

On November 14, 2005, our board of directors approved a plan to divest of five subsidiaries of Progress Fuels engaged in the coal mining business (Coal Mining). On May 1, 2006, we sold certain net assets of three of our coal mining businesses to Alpha Natural Resources, LLC for gross proceeds of $23 million plus a $4 million working capital adjustment. As a result, during the nine months ended September 30, 2006, we recorded an after-tax loss of $13 million on the sale of these assets. The remaining coal mining operations are expected to be sold by March 31, 2008.

Net losses from discontinued operations for Coal Mining were $1 million and net earnings from discontinued operations were $3 million for the three months ended September 30, 2007 and 2006, respectively. Net losses from Coal Mining discontinued operations were $9 million and $1 million for the nine months ended September 30, 2007 and 2006, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

The majority of our operating costs are related to the Utilities. Most of these costs are recovered from ratepayers in accordance with various rate plans. We are allowed to recover certain fuel, purchased power, environmental 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 do not materially affect net income.

As a registered holding company, we are subject to regulation by the 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.

Cash from operations, asset sales, short-term and long-term debt, and limited ongoing equity sales from our Investor Plus Stock Purchase Plan, employee benefit plan and existing stock options are expected to fund capital expenditures, common stock dividends, and debt service for the remainder of 2007. For fiscal year 2007, we expect to realize an aggregate amount of approximately $150 million from the sale of stock through these plans.

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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 2006 Form 10-K.

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

Historical for 2007 Compared to 2006

CASH FLOWS FROM OPERATIONS

Cash from operations is the primary source used to meet operating requirements and capital expenditures. Net cash provided by operating activities from continuing operations decreased by $552 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year. The decrease in operating cash flow was primarily due to a $169 million decrease in the recovery of fuel costs and changes in working capital related to a $157 million decrease from the change in accounts receivable, primarily at PEC, $65 million in premiums paid for derivative contracts (see Note 9A), and approximately $406 million due to income tax impacts. The tax impacts were largely driven by the costs to exit the Georgia Contracts and income tax payments related to the sale of Gas, partially offset by lower income tax payments at the Utilities. The decrease from the change in accounts receivable at PEC was primarily due to higher collections in the prior year of wholesale billings and the impact of weather. These impacts were partially offset by a $98 million increase from the change in inventory, primarily related to prior year coal inventory purchases at PEF, and $45 million in net refunds in 2007 of cash collateral previously paid to counterparties on derivative contracts compared to $52 million in net cash payments in 2006 at PEF.

INVESTING ACTIVITIES

Net cash used by investing activities increased by $437 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year. This is due primarily to a $392 million increase in capital expenditures for utility property additions, a $127 million increase in nuclear fuel additions, and a $57 million increase in net purchases of short-term investments included in available-for-sale securities and other investments. These impacts were partially offset by a $111 million increase in proceeds from sales of discontinued operations and other assets, net of cash divested. At PEC, the increase in utility property additions was primarily due to environmental compliance expenditures. At PEF, the increase in utility property additions was primarily due to repowering the Bartow plant to more efficient natural gas-burning technology and environmental compliance projects. The increase in nuclear fuel additions was largely driven by an additional refueling outage at PEC in 2007. 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, 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 3A), working capital adjustments for Gas, and the sale of poles at Progress Telecommunications Corporation (PTC).

During the nine months ended September 30, 2006, proceeds from sales of discontinued operations and other assets, net of cash divested primarily included approximately $80 million and $325 million, respectively, from the sale of DeSoto and Rowan (See Note 3C), approximately $70 million from the sale of PT LLC (See Note 3D), approximately $27 million from the sale of certain net assets of the coal mining business (See Note 3F), and approximately $16 million from the sale of Dixie Fuels (See Note 3E).

FINANCING ACTIVITIES

Net cash provided by financing activities was $682 million for the nine months ended September 30, 2007, compared to net cash used by financing activities of $1.123 billion for the nine months ended September 30, 2006, for a net increase in cash provided by financing activities of $1.805 billion. The change in cash provided (used) by financing activities was due primarily to the 2007 financing activities described below and the March 1, 2006 maturity of $800 million 6.75% senior unsecured notes. These notes were paid with net proceeds from the sale of $400 million in senior notes and a combination of available cash and commercial paper proceeds. On January 13,

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2006, Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100 million of Series A Floating Rate Senior Notes due 2010.

On July 2, 2007, PEF paid at maturity $85 million of its 6.81% Medium-Term Notes with available cash on hand and commercial paper borrowings.

On August 15, 2007, due to extreme volatility in the commercial paper market, Progress Energy borrowed $400 million under its $1.13 billion revolving credit agreement (RCA) to repay outstanding commercial paper. At September 30, 2007, $400 million of Progress Energy’s RCA loan was still outstanding. On October 17, 2007, Progress Energy used $200 million of commercial paper proceeds to repay a portion of the amount borrowed under the RCA. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining balance of the RCA loan, while maintaining an appropriate level of liquidity.

On August 15, 2007, due to extreme volatility in the commercial paper market, PEC borrowed $300 million under its $450 million RCA and paid at maturity $200 million of its 6.80% First Mortgage Bonds. At September 30, 2007, $150 million of PEC’s RCA loan was still outstanding. On October 17, 2007, PEC repaid the remaining $150 million of its RCA loan using available cash on hand.

On September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017. The proceeds were used to repay PEF’s utility money pool borrowings and the remainder was placed in temporary investments for general corporate use as needed.

At December 31, 2006, we had 500 million shares of common stock authorized under our charter, of which approximately 256 million were outstanding. At December 31, 2006, we had approximately 54 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, 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 Investor Plus Stock Purchase Plan. For the three months ended September 30, 2006, we issued approximately 0.3 million shares of common stock resulting in approximately $13 million in proceeds, primarily to meet the requirements of the Investor Plus Stock Purchase Plan. For the nine months ended September 30, 2006, we issued approximately 1.7 million shares of common stock resulting in approximately $73 million in proceeds. Included in these amounts were approximately 1.4 million shares for proceeds of approximately $58 million to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan.

DISCONTINUED OPERATIONS

Net cash used by discontinued operations increased by $194 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year. This increase was primarily due to a $335 million increase in cash used by operating activities, driven by a net cash payment of $347 million, representing the net cost to assign the Georgia Contracts and other related contracts (See Note 3A). This increase was partially offset by a $141 million decrease in cash used by investing activities, largely driven by the impact of 2006 property additions at Gas prior to its divestiture.

Future Liquidity and Capital Resources

At September 30, 2007, 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 2006 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 operations are expected to produce positive operating cash flow in the future when tax credits are realized for tax purposes (See “Other Matters – Synthetic Fuels Tax Credits”).

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We expect cash from operations plus availability under our credit facilities and shelf registration statements to be sufficient to meet our requirements in the near term. To the extent necessary, we may also use limited ongoing equity sales from our Investor Plus Stock Purchase Plan, employee benefit plan and existing stock options to meet our liquidity requirements.

As discussed in “Capital Expenditures,” under LIQUIDITY AND CAPITAL RESOURCES and “Strategy” under INTRODUCTION in Item 7 to the 2006 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 will require the Utilities to make significant capital investments. We expect these anticipated capital investments to be funded through a combination of long-term debt, preferred stock and common equity, which is dependent on our ability to successfully access capital markets. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing, construction and operational risks associated with new baseload generation.

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

At September 30, 2007, the current portion of our long-term debt was $464 million, which we expect to fund with cash from operations, commercial paper borrowings and/or long-term debt issuances.

CREDIT RATING MATTERS

On September 6, 2007, Standard & Poor’s Rating Services (S&P) upgraded the first mortgage bonds of both PEC and PEF to A- from BBB+ as a result of a methodology change for collateral coverage requirements. Because both PEC and PEF had asset to potential secured debt ratios of less than 1.5, they were assigned a recovery rating of 1, which qualified for a one notch increase over their corporate credit ratings.

On July 13, 2007, Fitch Ratings (Fitch) upgraded the long-term ratings of both PEC and PEF to A- from BBB+ and revised their rating outlooks to stable from positive. Fitch cited cash flow coverage and leverage credit ratios more consistent with the ‘A’ rating category at the individual utilities, sound utility operations, and operations in historically favorable regulatory environments as the primary factors for the upgrades. Fitch also noted lowered group linkage risks for PEC and PEF resulting from improved business risk at the Parent due to the sale or wind-down of non-utility operations and reduced debt.

On June 15, 2007, Moody’s Investors Service, Inc. (Moody’s) upgraded the corporate credit rating for PEC to A3 from Baa1 and revised its outlook to stable from positive. Moody’s cited strong cash flow coverage measures and financial metrics, operations in constructive regulatory environments with growing service territories, and lower debt and business risk at the Parent as the primary factors in the upgrade.

On March 15, 2007, S&P upgraded corporate credit ratings to BBB+ from BBB at Progress Energy, Inc., PEC and PEF and revised each company’s outlook to stable from positive. S&P cited the significant reduction in our holding company debt and the moderation of business risk achieved by our renewed focus on our regulated utilities as the primary factors in the upgrade.

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, as discussed in “Other Matters – Regulatory Environment” and Note 4, and filings for recovery of environmental costs, as discussed in Note 12 and in “Other Matters – Environmental Matters” of this filing and in Note 22 and in “Other Matters – Environmental Matters” of the 2006 Form 10-K may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Developments since our 2006 Form 10-K are discussed below.

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PEC Base Rates

On March 23, 2007, PEC filed a petition with the North Carolina Utility Commission (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 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 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 Associations (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. We cannot predict the outcome of this matter.

PEC Fuel Cost Recovery

On May 2, 2007, PEC filed with the Public Service Commission of South Carolina (SCPSC) for an increase in the fuel rate charged to its South Carolina ratepayers. On June 27, 2007, the SCPSC approved a settlement agreement filed jointly by PEC and all other parties to the proceedings. The settlement agreement resolved all issues and provided for a $12 million increase in fuel rates. Effective July 1, 2007, residential electric bills increased by $1.83 per 1,000 kWhs, or 1.9 percent, for fuel cost recovery.

On June 8, 2007, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. PEC asked the NCUC to approve a $48 million increase in fuel rates for under-recovered fuel costs associated with prior year settlements, as discussed below. On September 25, 2007, the NCUC approved PEC’s petition. The increase took effect October 1, 2007, and increased residential electric bills by $1.30 per 1,000 kWhs, or 1.3 percent, for fuel cost recovery.

On June 2, 2006, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina ratepayers. On September 25, 2006, the NCUC approved a settlement agreement filed jointly by PEC, the NCUC Public Staff and CIGFUR, which included a three-year phase-in of the increase in rates.

On November 21, 2006, CUCA filed an appeal with the North Carolina Tenth District Court of Appeals of the NCUC’s September 25, 2006, order on the grounds that the NCUC does not have the statutory authority to establish fuel rates for more than one year. PEC filed a motion to dismiss with the Court of Appeals on March 22, 2007. On October 24, 2007, CUCA filed a motion to withdraw their appeal.

PEF Pass-through Clause Cost Recovery

On September 4, 2007, PEF filed a request with the FPSC seeking approval of a cost adjustment to reflect a projected over-collection of fuel costs in 2007, declining projected charges for fuel for 2008, and other recovery clause factors. PEF asked the FPSC to approve a $163 million, or 4.53 percent, decrease in rates effective January 1, 2008. This cost adjustment would decrease residential bills by $5.00 for the first 1,000 kWhs. As discussed in “Other Regulatory Matters” below, residential base rates will increase effective January 1, 2008, by $2.73 for the first 1,000 kWhs. After considering the net effect of the base rate increase and the proposed fuel cost adjustment, 2008 residential bills would decrease by a net amount of $2.27 for the first 1,000 kWhs. The FPSC is scheduled to hold hearings on the cost adjustment proposal on November 6, 2007. We cannot predict the outcome of this matter.

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus interest, of alleged excessive past fuel recovery charges and sulfur dioxide (SO₂) allowance costs associated with PEF’s purported failure to utilize the most economical sources of coal at Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) during the period 1996 to 2005. The OPC subsequently revised its claim to $135 million, plus interest. 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, inclusive of interest, over a 12-month period beginning January 1, 2008. On October 25, 2007, the OPC requested the FPSC to

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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. PEF is also evaluating its options, including a request an appeal to the Florida Supreme Court of the FPSC’s October 10, 2007 order. We cannot predict the outcome of this matter. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish a separate docket on the prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. The OPC filed testimony in support of its position to require PEF to refund at least $14 million for alleged excessive fuel recovery charges for 2006 coal purchases. PEF believes its coal procurement practices were prudent. We cannot predict the outcome of this matter.

On September 22, 2006, PEF filed a petition with the FPSC for Determination of Need to uprate Crystal River Unit No. 3 Nuclear Plant (CR3), bid rule exemption and 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. On February 8, 2007, the FPSC issued an order approving PEF’s request for a need determination to uprate through a multi-stage uprate to be completed by 2012. PEF’s need determination filing included estimated project costs of approximately $382 million. On February 2, 2007, intervenors filed a motion to abate the cost-recovery portion of PEF’s request. On February 9, 2007, PEF requested that the FPSC deny the intervenors’ motion as legally deficient and without merit. On March 27, 2007, the FPSC denied the motion to abate and directed the staff of the FPSC to conduct a hearing on the matter to determine whether the revenue requirements of the uprate should be recovered through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony clarifying the scope of the project. The FPSC held a hearing on this matter on August 7 and 8, 2007. The staff of the FPSC recommended that PEF be allowed to recover prudent and reasonable costs of Phase 1, instrumentation modifications for improved accuracy, estimated at $6 million through the fuel clause. The staff of the FPSC recommended that the costs of all other phases, estimated at $376 million, be considered in a base rate proceeding. On October 19, 2007, PEF filed a notice of withdrawal of its cost recovery petition with the FPSC. PEF intends to re-file a petition in the fourth quarter of this year seeking cost recovery under Florida’s comprehensive energy bill enacted in 2006, and the FPSC's new nuclear cost recovery rule. We cannot predict the outcome of this matter.

Other Regulatory Matters

PEF filed a cost-recovery petition with the FPSC on April 30, 2007, to recover the full revenue requirements of Hines Unit 4, which has a current estimated in-service cost of $327 million, by increasing base rates $52 million, as provided for in PEF’s 2005 base rate agreement. The base rate increase would be effective upon placing Hines Unit 4 in service. The current estimate of in-service cost exceeds the initial project estimate of $286 million due to what we believe to be extraordinary circumstances. On September 27, 2007, the staff of the FPSC recommended that PEF be allowed to recover the full in-service costs, including the $41 million cost in excess of the Determination of Need and increase base rates $52 million effective December 1, 2007, for Hines Unit 4 and the related transmission facilities. The staff also recommended that the base rate changes associated with both Hines Unit 4 and Hines Unit 2 be achieved by applying the new rates to energy sales after December 1, 2007, thus requiring PEF to pro-rate the changes on customer bills rendered in December for customers that had consumption of electricity in both November and December. On October 12, 2007, PEF entered into a stipulation and settlement agreement that was filed with the FPSC. The agreement was reached with intervenors in settlement of all issues related to recovery of the revenue requirements of Hines Unit 4 and Hines Unit 2 and provides that PEF shall 1) increase its base rates for revenue requirements of Hines Unit 2 and Hines Unit 4 as approved in the staff recommendation and 2) simplify the implementation of the base rate increase by making it effective with the first billing cycle in January 2008. On October 23, 2007, the FPSC voted to approve the stipulation and settlement agreement.

As discussed further in “Other Matters – Regulatory Environment”, South Carolina and North Carolina state energy legislation that became law in 2007 may impact our liquidity over the long term. Among other provisions, these 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. We anticipate that PEC’s reagent and purchased power costs eligible for jurisdictional recovery under the North Carolina and South Carolina energy laws will total approximately $50 million 2008.

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Additionally, on July 13, 2007, the governor of Florida issued executive orders to address reduction of greenhouse gas emissions. The FPSC has held meetings regarding the renewable portfolio standard but no actions have been taken or rules issued. The Energy and Climate Action Team appointed by the governor submitted its initial recommendations for implementation of the governor’s executive orders on November 1, 2007. The recommendations encourage the development and implementation of energy efficiency and conservation measures, implementation of a climate registry, and consideration of a cap-and-trade approach to reducing the state's greenhouse gas emissions. Additional development and discussion of the recommendations will occur through a stakeholder process in 2008. The Florida Department of Environmental Protection held its first workshop on the greenhouse gas emissions cap on August 22, 2007, but we do not anticipate drafts of the rule to be issued until 2008. We cannot currently predict the impacts to our liquidity of complying with these executive orders.

The Energy Policy Act of 2005 (EPACT), among other provisions, gave the FERC accountability for system reliability and the authority to impose civil penalties. On June 18, 2007, compliance with 83 FERC-approved reliability standards became mandatory for all registered users, owners and operators of the bulk-power system, including PEC and PEF.

Based on FERC’s directive to revise 56 of the adopted standards, we expect standards to migrate to more definitive and enforceable requirements over time. We are committed to meeting those standards. The financial impact of mandatory compliance cannot currently be determined. Failure to comply with the reliability standards could result in the imposition of fines and civil penalties. If we are unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on our cash flows.

Prior to the effective date of mandatory compliance with the reliability standards, PEC self-reported two noncompliances and PEF self-reported three noncompliances. Entities responsible for enforcement of mandatory reliability standards have proposed that entities that self-reported noncompliance prior to the effective date and pursue aggressive mitigation plans will not be assessed fines. PEC and PEF have submitted mitigation plans to address the self-reported noncompliance. The costs of executing the mitigation plans are not expected to have a significant effect on our results of operations or liquidity.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

Guarantees

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. Our guarantees also include standby letters of credit and surety bonds. At September 30, 2007, we have issued $879 million of guarantees for future financial or performance assurance, including $29 million at PEC, $1 million at PEF and approximately $380 million related to PVI. Also included in the total amount is $300 million of guarantees for certain payments of two wholly owned indirect subsidiaries issued by the Parent (See Note 14). Subsequent to September 30, 2007, approximately $120 million of guarantees related to PVI were terminated. We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below Baa3 or BBB-) by Moody’s or S&P for the Parent’s senior unsecured debt rating, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. At September 30, 2007, the Parent’s senior unsecured debt rating was Baa2 by Moody’s and BBB by S&P and no guarantee obligations had been triggered. If the guarantee obligations were triggered, the liquidity requirements to support ongoing operations within a 60-day period, associated with guarantees for

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Progress Energy’s nonregulated portfolio and power supply agreements, would not have had a material impact on our financial condition or liquidity at September 30, 2007.

At September 30, 2007, 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, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations as discussed in 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 enter into various long- and short-term contracts for fuel requirements at our generating plants. Through September 30, 2007, contracts procured though our subsidiaries have increased our aggregate purchase obligations for fuel and purchased power by $4.274 billion from $13.133 billion, as stated in Note 22A in the 2006 Form 10-K. Future obligations under operating leases also increased by approximately $413 million from $428 million at December 31, 2006. In September 2007, PEF issued long-term debt totaling $750 million. These increases are discussed under “PEC” and “PEF” below.

PEC

Through September 30, 2007, PEC’s fuel and purchase power commitments increased by $1.015 billion from $4.358 billion, as stated in Note 22A in the 2006 Form 10-K. This increase is primarily related to nuclear fuel commitments, of which approximately $412 million will be incurred through 2011, with the remainder incurred through 2018.

PEF

Through September 30, 2007, PEF’s fuel and purchase power commitments increased by $3.494 billion from $8.513 billion, as stated in Note 22A in the 2006 Form 10-K. The increase is primarily due to precedent and related agreements PEF entered into on December 2, 2004, for the supply of natural gas and associated firm pipeline transportation to augment PEF’s gas supply needs for the period from May 1, 2007, to April 30, 2027, as discussed in Note 22A in the 2006 Form 10-K. At September 30, 2007, the total cost associated with these agreements is approximately $4.4 billion, an increase of $500 million from December 31, 2006, as payments under the gas supply agreement are based on a market index, which has increased since year-end. Based upon current market prices, we anticipate incurring these costs ratably over the contract period. The transactions were subject to several conditions precedent, some of which were satisfied at December 31, 2006. Due to the conditions in the agreements, the estimated costs associated with these agreements were not included in our or PEF’s contractual cash obligations table at December 31, 2006. During 2007, the remaining conditions precedent were satisfied and the long-term contracts were contractual obligations of PEF at September 30, 2007.

In August 2007, PEF entered into a purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $28 million from 2012 though 2027 for a total of approximately $420 million.

On September 18, 2007, PEF issued $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017 (See Note 6).

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OTHER MATTERS

Synthetic Fuels Tax Credits

Historically, we have had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Code (Section 29). The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied, including a requirement that the synthetic fuels differ significantly in chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced from a facility that was placed in service before July 1, 1998. Qualifying synthetic fuels facilities entitle their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The tax credits associated with synthetic fuels in a particular year may be phased out if annual average market prices for crude oil exceed certain prices, as discussed below. Synthetic fuels are generally not economical to produce and sell absent the credits. The current synthetic fuels tax credit program expires at the end of 2007.

On September 14, 2007, we idled production of synthetic fuels at our majority-owned synthetic fuels facilities. As discussed below in “Impact Of Crude Oil Prices”, the decision to idle production was based on the current high level of oil prices and the resumption of synthetic fuels production was dependent upon a number of factors, including a reduction in oil prices. On October 12, 2007, based upon the continued high level of oil prices, unfavorable oil price projections through the end of 2007, and the expiration of the current synthetic fuels tax credit program at the end of 2007, we decided to permanently cease production of synthetic fuels at our majority-owned facilities. The operation of synthetic fuels facilities on behalf of third parties is expected to continue through December 31, 2007. Because we have abandoned our majority-owned facilities and our other synthetic fuels operations will cease as of December 31, 2007, we expect to report all of our synthetic fuels operations as discontinued operations in the fourth quarter of 2007.

TAX CREDITS

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

Total Section 29/45K credits generated through September 30, 2007 (including those generated by Florida Progress Corporation (Florida Progress) prior to our acquisition), were approximately $2.024 billion, of which $1.069 billion has been used to offset regular federal income tax liability, $845 million is being carried forward as deferred tax credits and was recorded as a reduction of noncurrent income tax liabilities on the Consolidated Balance Sheet, and $110 million has been reserved due to the estimated phase-out of tax credits due to high oil prices in 2007, as described below.

IMPACT OF CRUDE OIL PRICES

Although the Section 29/45K tax credit program is expected to continue through 2007, recent market conditions, world events and catastrophic weather events have increased the volatility and level of oil prices, which reduced the value of the credits for 2006 and could limit or entirely eliminate the amount of credits for 2007. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the Annual Average Price) exceeds a certain threshold price (the Threshold Price), the value of Section 29/45K tax credits is reduced for that year. Also, if the Annual Average Price increases high enough (the Phase-out Price), the value of Section 29/45K tax credits are eliminated for that year. The Threshold Price and the Phase-out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase-out Price for a year, the amount by which Section 29/45K tax credits are reduced will depend on where the Annual Average Price falls in that

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continuum. The Department of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three-month lag, the secretary of the Treasury finalizes the calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2006 was published on April 4, 2007. Based on the Annual Average Price of $59.68, our synthetic fuels tax credits generated during 2006 were reduced by 33 percent, or approximately $35 million.

We estimate that the 2007 Threshold Price will be approximately $57 per barrel and the Phase-out Price will be approximately $71 per barrel, based on an estimated inflation adjustment for 2007. The monthly Domestic Crude Oil First Purchases Price published by the EIA has recently averaged approximately $5 lower than the corresponding daily New York Mercantile Exchange (NYMEX) prompt month settlement price for light sweet crude oil. Through September 30, 2007, the average NYMEX settlement price for light sweet crude oil was $66.18 per barrel, and as of September 30, 2007, the average NYMEX futures price for light sweet crude oil for the remainder of calendar year 2007 was $80.27 per barrel. This results in a weighted-average annual price for light sweet crude oil of approximately $69.80 per barrel for calendar year 2007. Based upon the estimated 2007 Threshold Price and Phase-out Price, if oil prices for 2007 averaged this weighted price of approximately $69.80 per barrel for the entire year in 2007, we estimate that the synthetic fuels tax credit amount for 2007 would be reduced by approximately 55 percent. Therefore, we reserved 55 percent or approximately $110 million of the $200 million of tax credits generated during the first nine months of 2007. As of September 30, 2007, the NYMEX price of oil for the remainder of 2007 would have to be $49.89 to have no reduction in value of tax credits generated during 2007 and would have to be $104.04 to have a full reduction in value. The final calculations of any reductions in the value of the tax credits will not be determined until April 2008 when final 2007 oil prices are published. Additional fluctuations in oil prices through the end of 2007, which impact the estimated weighted-average annual price of oil for 2007, may cause quarterly adjustments, either positive or negative, to our results of operations and the amount of tax credits we reserve.

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 NYMEX basis. The notional quantity of these oil price hedge instruments is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production and will be 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 3I, we disposed of our 100 percent ownership interest in Ceredo in March 2007. Through September 30, 2007, we have fully utilized the production levels necessary to maximize the potential benefits of the economic hedge. See Note 9 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

As discussed above, on October 12, 2007, we permanently abandoned operations at our majority-owned synthetic fuels facilities. If the 2007 tax credits earned to date were completely phased out due to high oil prices, we would reverse an additional $90 million of income related to tax credits recorded during the first nine months of 2007. We would expect that additional favorable mark-to-market adjustments on the derivative contracts would partially mitigate such a reversal.

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 produces and sells 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 are received as we produce and sell qualifying coal-based solid synthetic fuels on behalf of the buyer during 2007. As of September 30, 2007, we have received payments of $27 million on the note. Actual proceeds could differ based on actual production levels, which shall be determined by the buyer. The estimated production level of Ceredo subsequent to the transaction is 2.8 million tons. As of September 30, 2007, we have produced 2.0 million tons. Pursuant to the terms of the disposal agreement, the buyer has the right to unwind the transaction if an Internal Revenue Service (IRS) reconfirmation private letter ruling is not received by November 9, 2007, or if certain adverse changes in tax law, as defined in the agreement, occur before November 19, 2007. Therefore, no gain on the disposal will be recognized prior to the expiration of these rights. Once these rights expire, deferred gains, if any,

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from the disposal will be recognized over time as we produce and sell qualifying coal-based solid synthetic fuels for the buyer and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. The IRS reconfirmation private letter ruling was received on October 29, 2007. Subsequent to the disposal, we remain the primary beneficiary of Ceredo and continue to consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there is no net earnings impact from Ceredo’s operations and our net investment in Ceredo is zero. In connection with the disposal, Progress Fuels and Progress Energy provided guarantees and indemnifications for certain legal and tax matters to the buyer, which reduces any potential deferred gain. The ultimate resolution of these matters could result in adjustments to the gain, if any, on disposal in future periods. See Note 3I for additional discussion of this transaction and Note 13B for a general discussion of guarantees.

In June 2004, through our subsidiary Progress Fuels, we sold in two transactions a combined 49.8 percent partnership interest in Colona, one of our coal-based solid synthetic fuels facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gains from the sales will be recognized on a cost-recovery basis as the facility produces and sells synthetic fuels and when there is persuasive evidence that the sales proceeds have become fixed or determinable, collectability is reasonably assured and payments are non-refundable. Gain recognition is dependent on the synthetic fuels production qualifying for Section 29/45K tax credits and the value of such tax credits as discussed above. Until there is persuasive evidence that the gain recognition criteria are met, proceeds from selling interests in Colona will be deferred to subsequent quarters, or to a subsequent calendar year. This could result in shifting earnings from earlier quarters to later quarters in a calendar year or to a subsequent calendar year. In the event that the synthetic fuels tax credits from the Colona facility are reduced, including from an extended idling of our production due to an increase in the price of oil that could limit or eliminate synthetic fuels tax credits, the amount of proceeds realized from the sale could be significantly impacted. At September 30, 2007, proceeds from monetization of $14 million have been deferred. Based on the current level of oil prices, it is unlikely that these proceeds will be recognized.

See Note 13B for additional discussion related to our synthetic fuels operations.

Regulatory Environment

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

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.

In 2007, the U.S. House of Representatives passed energy bill H.R. 3221 and the U.S. Senate passed energy bill H.R. 6. Provisions in these bills include: a proposal for a 15% Federal Renewable Portfolio Standard (only included in the House bill), provisions for a Corporate Average Fuel Economy standard for automobiles, provisions for funding of research on clean coal technologies, incentives for plug-in hybrid vehicles and incentives for increased energy efficiency. Discussions are continuing between the two chambers in an effort to convene a conference committee to work through differences in the bills in an attempt to produce a conference report. We are continuing to monitor these discussions and are unable to predict if these congressional efforts will result in an energy bill that would ultimately be sent to the President to be signed into law. The specific requirements of the proposed legislation and associated costs, if any, cannot be predicted.

During 2007, the North Carolina legislature passed comprehensive energy legislation, which became law on August 20, 2007. The law establishes a minimum Renewable Energy and Energy Efficiency Portfolio Standard (REPS) for

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the use of energy from specified renewable energy resources or implementation of energy efficiency measures by the state’s electric utilities beginning with a 3 percent requirement in 2012 and increasing to 12.5 percent in 2021 for regulated public utilities, including PEC. The premium to be paid by electric utilities to comply with the requirements above the cost they would have otherwise incurred to meet consumer demand, is to be recovered through an annual rider. The annual amount that can be recovered through the REPS rider is capped and once a utility has expended monies equal to the cap, the utility is deemed to have met its obligations under the REPS, regardless of the actual renewables generated or purchased. The law grants the NCUC authority to modify or alter the REPS requirements if the NCUC determines it is in the public interest to do so.

The law allows the utility to meet a portion of the REPS with energy reductions achieved through energy efficiency programs. Energy efficiency programs include any program or activity implemented after January 1, 2007, that results in less energy being used to perform the same function. Through the year 2020, a utility can use energy efficiency programs to satisfy up to 25 percent of their REPS; beginning in 2021, these programs may constitute up to 40 percent of the requirements.

The law allows the utility to recover the costs of new demand-side management (DSM)/energy efficiency programs through an annual DSM rider. The law allows the utility 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 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 and interruptible load. PEC has begun implementing a series of energy efficiency/DSM programs and deferred an immaterial amount of implementation and program costs for future recovery through the nine months ended September 30, 2007.

The law also expands the definition of the traditional fuel clause so that additional costs may be recovered annually. These additional costs include costs of reagents (commodities such as ammonia and limestone used in emissions control technologies), renewable energy and certain components of purchased power not previously recoverable through the fuel clause (see additional discussion below). The North Carolina law also authorizes the NCUC to allow annual prudence reviews of the construction costs of a baseload generating plant if requested by the public utility that is constructing the plant 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.

On October 26, 2007, the NCUC issued its proposed rules for implementation of the law and reconfirmed its intention to complete the rulemaking process by January 1, 2008. Until the rulemaking process is completed, we cannot predict the costs of complying with the law. PEC would be able to annually recover its reasonable prudent compliance costs.

During 2007, the South Carolina legislature ratified new energy legislation, which became law on May 3, 2007. Key elements of the law include expansion of the annual fuel clause mechanism to include recovery of the costs of reagents used in the operation of PEC’s emissions control technologies (see additional discussion below). The law also includes provisions to provide base rate cost recovery for upfront development costs associated with nuclear baseload generation and construction costs associated with nuclear or coal baseload generation without a base rate proceeding and the ability to recover financing costs for new nuclear baseload generation through annual riders.

We anticipate PEC’s reagent and purchased power costs eligible for jurisdictional recovery under the North Carolina and South Carolina energy laws will total approximately $50 million in 2008.

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)

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

On April 10, 2007, the FPSC adopted a rule that specifies what storm costs will be recoverable and whether such recoverable costs would be offset against a utility’s storm reserve fund or recoverable through its base rates. PEF does not believe that compliance with this rule will materially increase its costs.

The Energy Policy Act of 2005 (EPACT), among other provisions, gave the FERC accountability for system reliability and the authority to impose civil penalties. EPACT provides procedures and rules for the establishment of an electric reliability organization (ERO) that will propose and enforce mandatory reliability standards. On July 20, 2006, the FERC certified the North American Electric Reliability Corporation (NERC) as the ERO. Included in this certification was a provision for the ERO to delegate authority for the purpose of proposing and enforcing reliability standards in particular regions of the country by entering into delegation agreements with regional entities. The SERC Reliability Corporation (SERC) and the Florida Reliability Coordinating Council (FRCC) are the regional entities for PEC and PEF, respectively.

In Order 693, the FERC completed part of its EPACT implementation plan by approving 83 reliability standards developed by the NERC and set aside 24 standards pending further development. On June 18, 2007, compliance with the 83 FERC-approved reliability standards became mandatory for all registered users, owners and operators of the bulk-power system, including PEC and PEF. Prior to the FERC action, electric utility industry compliance with the NERC standards had been voluntary.

Based on FERC’s directive to revise 56 of the adopted standards, we expect standards to migrate to more definitive and enforceable requirements over time. We are committed to meeting those standards. The financial impact of mandatory compliance cannot currently be determined. Failure to comply with the reliability standards could result in the imposition of fines and civil penalties. If we are unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Prior to the effective date of mandatory compliance with the reliability standards, PEC self-reported noncompliance in two areas to SERC and PEF self-reported noncompliance in three areas to FRCC. The FRCC, SERC and NERC have proposed that entities that self-reported noncompliance prior to the effective date and pursue aggressive mitigation plans will not be assessed fines. PEC and PEF have submitted mitigation plans to SERC and FRCC, respectively, to address the self-reported noncompliance. The costs of executing the mitigation plans are not expected to have a significant impact on our results of operations or liquidity.

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.

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Increasing Energy Demand

Meeting the anticipated growth and resulting demand for electricity within the Utilities’ service territories will require a balanced approach, which includes a strong commitment to energy efficiency, investments in emerging alternative and renewable energy technologies and investments in state-of-the-art power plants.

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 ways for residential customers to reduce energy use, promotes home energy checks, provides tools and programs for large and small businesses to minimize their energy use and provides an interactive internet Web site with online calculators, programs and efficiency tips.

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

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

As authorized under EPACT, on October 4, 2007, the 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. Congress has approved $4 billion in loan guarantees, with the DOE seeking an additional $9 billion in loan guarantees in its fiscal 2008 budget request. Initial applications for loan guarantees were for non-nuclear projects but it is expected that approval of additional funding could result in guarantees being available for nuclear generation projects. We cannot predict the outcome of this matter.

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 December 2008.

On January 16, 2007, the U.S. Supreme Court declined to hear an appeal of a Ninth Circuit U.S. Court of Appeals’ decision in which the Ninth Circuit held that the NRC is required to consider the environmental impacts of terrorist attacks under the National Environmental Policy Act in authorizing an independent spent fuel storage installation. Similar cases, including cases involving operating license renewals, are pending in seven other jurisdictions. The NRC is considering the scope and import of the Ninth Circuit’s decision in reviewing its operating license renewal program. In response to the Ninth Circuit’s decision, on February 26, 2007, the NRC reconfirmed that the National Environmental Policy Act does not require the NRC to consider the environmental consequences of hypothetical terrorist attacks on NRC-licensed facilities.

Our nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications (See Note 13C).

We have announced that we are pursuing development of combined license (COL) applications to potentially construct new nuclear plants. Our announcement is not a commitment to build a nuclear plant but is a necessary step

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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 have selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. PEC expects to file the application for the COL in 2008. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, a new plant would not be online until at least 2018 (See “Increasing Energy Demand” above).

On December 12, 2006, we announced that PEF selected a site in Levy County, Fla., to evaluate for possible future nuclear expansion. We have selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application submission. PEF expects to file the application for the COL in 2008. If we receive approval from the NRC and applicable state agencies, and if the decision to build is 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 September 2007, PEF completed the purchase of the 3,100 acre Levy County site. PEF anticipates filing a need case with the FPSC in early 2008.

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

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

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

In 2007, the South Carolina legislature ratified new energy legislation, which includes provisions for cost-recovery mechanisms associated with nuclear baseload generation. The North Carolina legislature ratified 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. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the 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 parties (PRP) groups. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 4 and 12). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of these potential claims cannot be predicted. No material claims are currently pending. Hazardous and solid waste management matters are discussed in detail in Note 12A.

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

AIR QUALITY AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which would likely 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), SO₂, carbon dioxide (CO₂) and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs that could be material to our financial position or results of operations. Control equipment that will be installed pursuant to the provisions of the Clean Smokestacks Act, Clean Air Interstate Rule (CAIR,) Clean Air Mercury Rule (CAMR) and Clean Air Visibility Rule (CAVR), which are discussed below, may address some of the issues outlined above. CAVR requires the installation of best available retrofit technology (BART) on certain units. However, the outcome of these matters cannot be predicted.

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

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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, 2007
NOx SIP Call	2002–2007	$342	$342
Clean Smokestacks Act	2002–2013	1,100 – 1,400	826
CAIR/CAMR/CAVR	2005–2018	1,500 – 2,600	192
Total air quality		2,942 – 4,342	1,360
Clean Water Act Section 316(b) (a)		–	–
North Carolina Groundwater Standard (b)		–	–
Total water quality		–	–
Total air and water quality		$2,942 – $4,342	$1,360

PEC
Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through September 30, 2007
NOx SIP Call	2002–2007	$342	$342
Clean Smokestacks Act	2002–2013	1,100 – 1,400	826
CAIR/CAMR/CAVR	2005–2018	200 – 300	6
Total air quality		1,642 – 2,042	1,174
Clean Water Act Section 316(b) (a)		–	–
North Carolina Groundwater Standard (b)		–	–
Total water quality		–	–
Total air and water quality		$1,642 – $2,042	$1,174

PEF
Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through September 30, 2007
CAIR/CAMR/CAVR	2005–2018	$1,300 – $2,300	$186
Clean Water Act Section 316(b) (a)		–	–
Total air and water quality		$1,300 – $2,300	$186

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

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

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 in excess of $1.0 billion. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related costs through rate adjustments or similar mechanisms. On April 2, 2007, the U.S. Supreme Court issued a ruling on an appeal of a decision of the U.S. Court of Appeals for the Fourth Circuit, in a case involving an unaffiliated utility. The Fourth Circuit held that NSR applies to projects that result in an increase in maximum hourly emissions. The U.S. Supreme Court rejected the lower court decision and held that the EPA is not required to adopt the maximum hourly emissions test but may use an actual annual emissions test to determine whether NSR applies.

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On March 17, 2006, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Court of Appeals) set aside the EPA’s 2003 NSR equipment replacement rule. The rule would have provided a more uniform definition of routine equipment replacement, which is excluded from NSR applicability. The D.C. Court of Appeals denied a request by the EPA for a re-hearing regarding this matter on June 30, 2006. On November 27, 2006, the EPA filed a petition for a writ of certiorari requesting that the U.S. Supreme Court review the D.C. Court of Appeals’ decision. On April 30, 2007, the U.S. Supreme Court denied the EPA’s petition. In a previous case decided in late 2005, the D.C. Court of Appeals had also set aside a provision in the NSR rule that had exempted the installation of pollution control projects from review. These projects are now subject to NSR requirements, adding time and cost to the installation process.

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

The NOx SIP Call is an EPA rule that requires 22 states, including North Carolina and South Carolina, to further reduce NOx emissions. The NOx SIP Call is not applicable to Florida. PEC has completed installation of controls to meet the NOx SIP Call requirements. Increased O&M expenses relating to the NOx SIP Call are not expected to be material to our or PEC’s results of operations.

Clean Smokestacks Act

In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO₂ from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by the Clean Smokestacks Act. In March 2007, PEC filed its annual estimate with the NCUC of the total capital expenditures to meet emission targets under the Clean Smokestacks Act by the end of 2013, which were approximately $1.1 billion to $1.4 billion at the time of the filing. The increase in estimated total capital expenditures from the original 2002 estimate of $813 million is primarily due to the higher cost and revised quantities of construction materials, such as concrete and steel, refinement of cost and scope estimates for the current projects, and increases in the estimated inflation factor applied to future project costs. We are continuing to evaluate various design, technology, and new generation options that could further change expenditures required by the Clean Smokestacks Act. O&M expenses will significantly increase due to the cost of reagents, additional personnel and general maintenance associated with the 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. On March 23, 2007, PEC filed a petition with the NCUC regarding future recovery of costs to comply with the Clean Smokestacks Act and on October 22, 2007, PEC filed with the NCUC a settlement agreement with the NCUC Public Staff, CUCA and CIGFUR supporting PEC’s proposal. The NCUC held a hearing on this matter on October 30, 2007. See further discussion about the Clean Smokestacks Act in Note 4A.

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.

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

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

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

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

States were required to adopt mercury rules implementing the CAMR that are subject to review and approval by the EPA. The three states in which the Utilities operate have adopted mercury regulations and have submitted their state implementation rules to the EPA. North Carolina's rule, which was adopted on November 9, 2006, utilizes the EPA’s cap-and-trade approach and requires the addition of mercury controls by 2018 on certain of PEC's North Carolina units that do not have SO₂ controls installed under the Clean Smokestacks Act. PEC has until 2013 to provide the North Carolina Department of Environment and Natural Resources detailed plans for the installation of controls at existing plants. South Carolina’s rule, which was adopted on January 11, 2007, utilizes the EPA’s cap-and-trade approach and requires that 25 percent of the mercury allowances allocated to each unit be held in a compliance supplement set-aside pool. Allowances in the set-aside pool may be used by a unit to meet compliance requirements but cannot be traded. The Florida rule, which was adopted on June 29, 2006, utilizes the EPA’s cap-and-trade approach with changes to the EPA’s mercury allowance allocations in the rule’s first phase. The EPA is currently reviewing the states’ rules. The outcome of this matter cannot be predicted.

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

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

On October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs associated with the development and implementation of an integrated strategy to comply with the CAIR, CAMR and CAVR through the ECRC. On March 31, 2006, PEF filed a series of compliance alternatives with the FPSC to meet these federal environmental rules. At the time, PEF’s recommended proposed compliance plan included approximately $740 million of estimated capital costs expected to be spent through 2016, to plan, design, build and install pollution control equipment at our Anclote and Crystal River plants. On November 6, 2006, the FPSC approved PEF’s petition for its integrated strategy to address compliance with CAIR, CAMR and CAVR. They also approved cost recovery of prudently incurred costs necessary to achieve this strategy. On June 1, 2007, PEF filed a supplemental petition for approval of its compliance plan and associated contracts and recovery of costs for air pollution control projects, which included approximately $1.0 billion to $2.3 billion of estimated capital costs for the range of alternative plans. The estimated capital cost for the recommended plan, which was $1.26 billion in the June 1, 2007 filing, represents the low end of the range in the table of estimated required environmental expenditures shown above. The difference in costs between the recommended plan and the high end of the range represents the additional costs that may be incurred if pollution controls are required on Crystal River Units No. 1 and No. 2 in order to comply with the requirements of CAVR beyond BART, should reasonable progress in improving visibility not be achieved, as discussed above. 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. These costs will continue to change depending upon the results of the engineering and strategy development work and/or increases in the underlying material, labor and equipment costs. Subsequent rule interpretations, equipment availability, or the unexpected acceleration of the initial NOx or other compliance dates, among other things, could require acceleration of some projects. The outcome of this matter cannot be predicted.

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

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

National Ambient Air Quality Standards

On December 21, 2005, the EPA announced proposed changes to the National Ambient Air Quality Standards (NAAQS) for particulate matter. The EPA proposed to lower the 24-hour standard for particulate matter less than 2.5 microns in diameter (PM 2.5) from 65 micrograms per cubic meter to 35 micrograms per cubic meter. In addition, the EPA proposed to establish a new 24-hour standard of 70 micrograms per cubic meter for particulate matter that is between 2.5 and 10 microns in diameter (PM 2.5-10). The EPA also proposed to eliminate the current standards for particulate matter less than 10 microns in diameter (PM 10). On September 20, 2006, the EPA 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.

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On June 20, 2007, the EPA announced proposed changes to the NAAQS for ground-level ozone. The EPA proposed to lower the 8-hour primary standard from 0.08 parts per million to a range of 0.070 to 0.075 parts per million. The two alternatives proposed for the secondary standard are to either establish a new cumulative, seasonal standard or set the secondary standard as identical to the proposed primary standard. 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. The final rule is expected in March 2008. The outcome of this matter cannot be predicted.

Water Quality

1. General

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

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

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

Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued an opinion and order remanding many 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 permitting authorities establish best available technology controls for minimizing adverse environmental impact at existing cooling water intake structures on a case-by-case, best professional judgment basis. As a result of these recent 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.

3. North Carolina Groundwater Standard

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

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OTHER ENVIRONMENTAL MATTERS

Global Climate Change

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO₂ and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration favors voluntary programs. There are proposals and ongoing studies at the state and federal levels, 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. 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 2007, we issued a corporate responsibility summary report, which discusses our actions and in 2006, we issued our report to shareholders for an assessment of global climate change and air quality risks and actions. While we participate in the development of a national climate change policy framework, we will continue to actively engage others in our region to develop consensus-based solutions, as we did with the Clean Smokestacks Act.

In a decision issued July 15, 2005, the D.C. Court of Appeals denied petitions for review filed by several states, cities and organizations seeking the regulation by the EPA of CO₂ emissions from new automobiles under the Clean Air Act, holding that the EPA administrator properly exercised his discretion in denying the request for regulation. The U.S. Supreme Court agreed to hear the case and on April 2, 2007, it ruled that the EPA has the authority under the Clean Air Act to regulate CO₂ emissions from new automobiles. The impact of this decision cannot be predicted.

New Accounting Standards

See Note 2 for a discussion of the impact of 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 2006 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 $7 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to a $54 million increase in the recovery of fuel costs driven by the 2007 recovery of previously under-recovered fuel costs, a $31 million increase from payables to affiliates, and $59 million related to lower income tax extension payments. These impacts were partially offset by a $142 million decrease from the change in accounts receivable and receivables from affiliated companies. The increase from payables to affiliates was largely related to the timing of settlements with affiliates. The decrease from the change in accounts receivable was primarily due to higher collections in the prior year of wholesale billings and the impact of weather.

Cash used by investing activities increased $192 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year, primarily due to a $94 million increase in capital expenditures for utility property additions, primarily related to an increase in spending for compliance with the Clean Smokestacks Act, and a $94 million increase in nuclear fuel additions, largely driven by an additional refueling outage in 2007.

Net cash used by financing activities decreased $198 million for the nine months ended September 30, 2007, when compared to the nine months ended September 30, 2006. The decrease in cash used by financing activities was due primarily to PEC’s 2007 financing activities described under Progress Energy’s MD&A, “Liquidity and Capital Resources” and a $147 million decrease in dividends paid to the Parent.

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 2006 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

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

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Cash provided by operating activities increased $73 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year. The increase was primarily due to $95 million from the change in inventory, $45 million in net refunds of cash collateral previously paid to counterparties on derivative contracts in the current year compared to $52 million in net cash payments in the prior year, a $94 million increase from accounts payable, and $84 million related to lower income tax payments. The increase from inventory was principally driven by higher coal inventory purchases in the prior year. The increase from accounts payable was largely due to the timing of purchases and payments to vendors. These impacts were largely offset by a $223 million decrease in the recovery of fuel costs driven by the recovery of previously under-recovered fuel costs in the prior year and a $33 million decrease in payables to affiliated companies, driven by timing of settlements.

Cash used by investing activities increased $506 million for the nine months ended September 30, 2007, when compared to the corresponding period in the prior year. The increase in cash used by investing activities was primarily due to a $291 million increase in capital expenditures for utility property additions, a $178 million increase in net purchases of short-term investments included in available-for-sale securities and other investments, and a $33 million increase in nuclear fuel additions. The increase in utility property additions is primarily due to repowering the Bartow plant to more efficient natural gas-burning technology and environmental compliance and nuclear projects, partially offset by lower spending on energy system distribution projects and at the Hines Unit 4 facility. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

Net cash provided by financing activities was $611 million for the nine months ended September 30, 2007, compared to net cash used by financing activities of $326 million for the nine months ended September 30, 2006, for a net increase of $937 million. The increase in cash provided by financing activities was due primarily to PEF’s 2007 financing activities described under Progress Energy’s MD&A, “Liquidity and Capital Resources” and a $176 million decrease in dividends paid to the Parent.

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.

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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 credit reviews using, among other things, publicly available credit ratings of such counterparties (See Note 9).

The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review Item 1A, “Risk Factors” to the 2006 Form 10-K and “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q 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, 2006.

INTEREST RATE RISK

Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at September 30, 2007, has changed from December 31, 2006. The total notional amount of fixed rate long-term debt at September 30, 2007, was $8.3 billion, with an average interest rate of 6.23% and fair market value of $8.5 billion. The total notional amount of fixed rate long-term debt at December 31, 2006, was $7.8 billion, with an average interest rate of 6.26% and fair market value of $8.1 billion. The total notional amount of variable rate long-term debt at September 30, 2007, was $1.4 billion, with an average interest rate of 4.68% and fair market value of $1.4 billion. The total notional amount of variable rate long-term debt at December 31, 2006, was $1.4 billion, with an average interest rate of 4.47% 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 revolving credit agreement (RCA) facilities, which are also exposed to floating interest rates. At September 30, 2007, approximately 19.1 percent of consolidated debt was in floating rate mode compared to 15.8 percent at the end of 2006, including interest rate swaps.

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

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

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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 Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative 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, 2007, and December 31, 2006, the Utilities had a combined $100 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions. Under terms of these swap agreements, we will pay a fixed rate and receive a floating rate based on the 3-month London Inter Bank Offering Rate (LIBOR). The Parent had no open interest rate cash flow hedges at September 30, 2007, and December 31, 2006.

Cash Flow Hedges (dollars in millions)	Notional Amount	Pay	Receive (a)	Fair Value	Exposure (b)
PEC
Risk hedged at September 30, 2007:
Anticipated 10-year debt issue (c)	$50	5.66%	3-month LIBOR	$(2)	$(1)
Anticipated 30-year debt issue (d)	50	5.77%	3-month LIBOR	(2)	(2)
Total	$100	5.72%		$(4)	$(3)
Risk hedged at December 31, 2006:
Anticipated 10-year debt issue (e)	$50	5.61%	3-month LIBOR	$(1)	$(1)
PEF
Risk hedged at September 30, 2007:	None
Risk hedged at December 31, 2006:
Anticipated 10-year debt issue (e)	$50	5.61%	3-month LIBOR	$(1)	$(1)

^(a) 3-month LIBOR rate was 5.23% at September 30, 2007, and 5.36% at December 31, 2006.

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

^(c) Anticipated 10-year debt issue hedge mature on April 1, 2018, and require mandatory cash settlement on April 1, 2008.

^(d) Anticipated 30-year debt issue hedge matures on April 1, 2038, and requires mandatory cash settlement on April 1, 2008.

^(e) Anticipated 10-year debt issue hedges matured on October 1, 2017, and required mandatory cash settlement on October 1, 2007.

Subsequent to December 31, 2006, PEF had entered into a combined $225 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances, which were terminated on September 13, 2007, in conjunction with PEF’s issuance of $500 million of First Mortgage Bonds, 6.35% Series due 2037 and $250 million of First Mortgage Bonds, 5.80% Series due 2017. On July 30, 2007, PEC entered into a $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances. On September 25, 2007, PEC amended its 10-year forward starting swap in order to move the maturity date from October 1, 2017 to April 1, 2018.

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On October 24, 2007, PEC entered into $100 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

Fair Value Hedges

At December 31, 2006, the Parent had $50 million notional of fixed rate debt swapped to floating rate debt, which was terminated on September 26, 2007. Under terms of these swap agreements, we received a fixed rate and paid a floating rate based on 3-month LIBOR. At September 30, 2007, and December 31, 2006, the Utilities had no open interest rate fair value hedges.

Fair Value Hedges (dollars in millions)	Notional Amount	Receive	Pay (a)	Fair Value	Exposure (b)
Progress Energy
Risk hedged at September 30, 2007	None
Risk hedged at December 31, 2006
7.10% Notes due 3/1/2011	$50	4.65%	3-month LIBOR	$(1)	$–

^(a)      3-month LIBOR rate was 5.36% at December 31, 2006.

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

MARKETABLE SECURITIES PRICE RISK

At September 30, 2007, and December 31, 2006, the fair value of our nuclear decommissioning trust funds was $1.358 billion and $1.287 billion, respectively, including $782 million and $735 million, respectively, for PEC and $576 million and $552 million, respectively, for PEF. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At September 30, 2007, and December 31, 2006, the fair value of CVOs was $34 million and $32 million, respectively. A hypothetical 10 percent decrease in the September 30, 2007, market price would result in a $3 million decrease 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. We also have oil price risk exposure related to synthetic fuels tax credits as discussed in “Other Matters – Synthetic Fuels Tax Credits” of Item 2.

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

As discussed in Note 3A, our subsidiary, PVI, entered into a series of transactions to sell substantially all of its CCO physical and commercial assets and liabilities. On June 1, 2007, PVI closed the transaction involving the assignment of a contract portfolio consisting of 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. The sale of the generation assets closed on June 11, 2007. Additionally, we sold

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Gas on October 2, 2006 (See Note 3B). Due to these divestitures, management determined that it was no longer probable that the forecasted transactions underlying certain derivative contracts would be fulfilled and cash flow hedge accounting for the contracts was discontinued beginning in the second quarter of 2006 for Gas and fourth quarter of 2006 for CCO.

At September 30, 2007, due to the closing of the transactions discussed above, our discontinued operations did not have outstanding positions in derivative instruments. At December 31, 2006, derivative assets of $107 million were included in assets of discontinued operations and derivative liabilities of $31 million were included in liabilities of discontinued operations on the Consolidated Balance Sheet. For the three months ended September 30, 2007, there were no material net gains and losses from derivative instruments included in discontinued operations on the Consolidated Statements of Income. For the nine months ended September 30, 2007, after-tax gains from derivative instruments of $88 million were included in discontinued operations on the Consolidated Statements of Income. For the three and nine months ended September 30, 2006, after-tax losses from derivative instruments of $30 million and $39 million, respectively, were included in discontinued operations on the Consolidated Statements of Income. For the three and nine months ended September 30, 2007, there were no reclassifications to earnings due to the discontinuance of the related cash flow hedges. For the three months ended September 30, 2006, there were no reclassifications to earnings due to the discontinuance of the related cash flow hedges. For the nine months ended September 30, 2006, $7 million in after-tax losses were reclassified to earnings due to the discontinuance of the related cash flow hedges in anticipation of the sale of Gas.

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments that are not eligible for recovery from ratepayers. The following discussion addresses the stand-alone commodity risk created by these derivative commodity instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge. The sensitivity analysis performed on these derivative commodity instruments uses quoted prices obtained from brokers to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. At September 30, 2007, derivative commodity instruments not eligible for recovery from ratepayers related to derivative contracts entered into on January 8, 2007, to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices as discussed under “Economic Derivatives” below. A decrease of 10 percent in the market prices of energy commodities from their September 30, 2007, levels would decrease after-tax earnings by approximately $18 million. At December 31, 2006, derivative commodity instruments not eligible for recovery from ratepayers are included in discontinued operations.

The above analysis of our derivative commodity instruments used for hedging purposes does not include the potential favorable impact of the same hypothetical price movement on the value of synthetic fuels tax credits to which the hedges relate. Additionally, our derivative commodity portfolio is managed to complement the physical transaction portfolio, reducing overall risk within set limits. Therefore, the potential impact to earnings from a hypothetical 10 percent adverse change in commodity market prices would be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity positions are not closed out in advance of their expected term, continue to function effectively as hedges of the underlying risk, and the anticipated underlying transactions settle, as applicable. If any of these assumptions ceases to be true, a loss on the derivative instruments may occur.

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

Economic Derivatives

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

On January 8, 2007, we entered into derivative contracts to hedge economically a portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil prices over an average annual oil price range of $63 to $77 per barrel on a New York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price hedge

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instruments is 25 million barrels and will provide protection for the equivalent of approximately eight million tons of 2007 synthetic fuels production. The cost of the hedges was approximately $65 million. The contracts are marked-to-market with changes in fair value recorded through earnings from synthetic fuels production. Approximately 34 percent of the notional quantity of these contracts was entered into by Ceredo. As discussed in Notes 1C and 3I, we disposed of our 100 percent ownership interest in Ceredo on March 30, 2007. Progress Energy is the primary beneficiary of, and continues to consolidate Ceredo in accordance with FIN 46R, but we have recorded a 100 percent minority interest. Consequently, subsequent to the disposal there is no net earnings impact for the contracts entered into by Ceredo. At September 30, 2007, the fair value of these contracts was recorded as a $170 million short-term derivative asset position, including $58 million at Ceredo. The fair value of these contracts was included in derivative assets on the Consolidated Balance Sheet. During the three and nine months ended September 30, 2007, we recorded net pre-tax gains of $74 million and $105 million, respectively, in diversified business revenues related to these contracts, including net pre-tax gains of $26 million and $21 million, respectively, at Ceredo subsequent to disposal of our 100 percent ownership interest.

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets on the Balance Sheets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause.

At September 30, 2007, the fair value of PEC’s commodity derivative instruments was recorded as a $3 million long-term derivative asset position included in other assets and deferred debits and a $5 million short-term derivative liability position included in other current liabilities on the Consolidated Balance Sheet. At December 31, 2006, PEC did not have material outstanding positions in such contracts.

At September 30, 2007, the fair value of PEF’s commodity derivative instruments was recorded as a $14 million short-term derivative asset position included in prepayments and other current assets, a $12 million long-term derivative asset position included in other assets and deferred debits, a $31 million short-term derivative liability position included in derivative liabilities, and a $5 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet. At December 31, 2006, the fair value of such instruments was recorded as a $2 million long-term derivative asset position included in other assets and deferred debits, an $87 million short-term derivative liability position included in derivative liabilities and a $36 million long-term derivative liability position included in other liabilities and deferred credits on the PEF Balance Sheet.

Cash Flow Hedges

Our subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of natural gas and power for our forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate. At September 30, 2007, and December 31, 2006, we and the Utilities did not have material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges for the three and nine months ended September 30, 2007 and 2006, was not material to our or the Utilities’ results of operations.

Our discontinued operations did not have material outstanding positions in commodity cash flow hedges at September 30, 2007, or December 31, 2006.

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, 2006.

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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.

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2007, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PEC

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

There has been no change in PEC’s internal control over financial reporting during the quarter ended September 30, 2007, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

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

There has been no change in PEF’s internal control over financial reporting during the quarter ended September 30, 2007, 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 13B).

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 2006 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in the 2006 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 2007 divestiture of the physical and commercial assets of CCO, we are no longer subject to risks from operating nonregulated plants or engaging in nonregulated energy marketing and trading activities as disclosed in the 2006 Form 10-K.

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

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a) Securities Delivered. On July 2, 2007, July 5, 2007, July 19, 2007 and September 26, 2007, 4,584 shares, 1,944 shares, 87 shares and 3,433 shares, respectively, of our common stock were delivered to certain former employees pursuant to the terms of the Progress Energy 2002 Equity Incentive Plan (EIP), which was approved by the Progress Energy’s shareholders on May 8, 2002. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

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

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

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Issuer Purchases of Equity Securities for Third Quarter of 2007

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	229,612	$45.1534	N/A	N/A
August 1 - August 31	58,500	44.7313	N/A	N/A
September 1 - September 30	–	–	N/A	N/A
Total	288,112	$44.9424	N/A	N/A

(1) As of September 30, 2007, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) The plan administrator purchased 288,112 shares of our common stock in open-market transactions to meet share delivery obligations under our 401(k).

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, 2007	(Registrants)
	By: /s/ Peter M. Scott III
	Peter M. Scott III
	Executive Vice President and Chief Financial Officer
	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer and Controller
	Progress Energy, Inc.
	Chief Accounting Officer
	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
	Florida Power Corporation d/b/a Progress Energy Florida, Inc.

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