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 March 31, 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

1

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 April 30, 2007, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	257,861,484
PEC	Common Stock (Without Par Value)	159,608,055 (all of which were held directly by Progress Energy, Inc.)
PEF	Common Stock (Without par value)	100 (all of which were held indirectly by Progress Energy, Inc.)

This combined Form 10-Q is filed separately by three registrants: Progress Energy, PEC and PEF (collectively, the Progress Registrants). Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants.

PEF meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

2

TABLE OF CONTENTS

GLOSSARY OF TERMS

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Interim Financial Statements:

Progress Energy, Inc. (Progress Energy)

Unaudited Consolidated Statements of Income

Unaudited Consolidated Balance Sheets

Unaudited Consolidated Statements of Cash Flows

Carolina Power & Light Company

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

Unaudited Consolidated Statements of Income

Unaudited Consolidated Balance Sheets

Unaudited Consolidated Statements of Cash Flows

Florida Power Corporation

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

Unaudited Statements of Income

Unaudited Balance Sheets

Unaudited Statements of Cash Flows

Combined Notes to Unaudited Interim Financial Statements for Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a Progress Energy Florida, Inc.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

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

Item 5. Other Information

Item 6. Exhibits

SIGNATURES

3

GLOSSARY OF TERMS

We use the words “Progress Energy,” “we,” “us” or “our” with respect to certain information to indicate that such information relates to Progress Energy, Inc. and its subsidiaries on a consolidated basis. When appropriate, the parent holding company or the subsidiaries of Progress Energy are specifically identified on an unconsolidated basis as we discuss their various business activities.

The following abbreviations or acronyms are used by the Progress Registrants:

TERM	DEFINITION
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
Clean Smokestacks Act	North Carolina Clean Smokestacks Act, enacted in June 2002
Coal	Coal terminals and marketing operations that blend and transload coal as part of the transportation network for coal delivery
Coal and Synthetic Fuels	Business segment primarily engaged in synthetic fuels production and sales operations, 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 coal-fired steam turbines Crystal River Units No. 4 and 5
CUCA	Carolina Utility Customers Association
CVO	Contingent value obligation
D.C. Circuit Court	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
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
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
FGT	Florida Gas Transmission Company
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
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 serviced by CCO
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Region	Reporting unit consisting of our Effingham, Monroe, Walton and Washington nonregulated generation plants in service
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
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

5

NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Council

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 Oxide
NOx SIP Call	EPA rule which requires 22 states including North Carolina, South Carolina and Georgia (but excluding Florida) to further reduce nitrogen oxide emissions
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
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	Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company
PEF	Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation
PESC	Progress Energy Service Company, LLC
the Phase-out Price	Price per barrel of unregulated domestic crude oil at which the value of Section 29/45K tax credits are fully eliminated
PM 2.5	EPA standard for particulate matter less than 2.5 microns in diameter
PM 2.5-10	EPA standard for particulate matter between 2.5 and 10 microns in diameter
PM 10	EPA standard for particulate matter less than 10 microns in diameter
Power Agency	North Carolina Eastern Municipal Power Agency
Preferred Securities	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Affiliates	Five affiliated 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
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
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity

6

Rowan	Rowan County Power, LLC
RSA	Restricted stock awards program
RTO	Regional transmission organization
SCPSC	Public Service Commission of South Carolina

Scrubber	A device that neutralizes sulfur compounds formed during coal combustion
SEC	United States Securities and Exchange Commission
Section 29	Section 29 of the 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
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”
SNG	Southern Natural Gas Company
SO2	Sulfur dioxide
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
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.

7

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

In this combined report, each of the Progress Registrants makes forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-Q that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. 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, baseload expansion and the effects of new 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; 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 commercial and industrial customers; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the impact on our facilities and businesses from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the anticipated future need for additional baseload generation 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 2008; our ability to generate and 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 execution of our announced transactions to dispose of our Competitive Commercial Operations (CCO) business and additional resulting charges to income, which could exceed $320 million after-tax; our ability to manage the risks involved with the CCO business, including dependence on third parties and related counterparty risks, until completion of our divestiture transactions; 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.

8

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

PROGRESS ENERGY, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

March 31, 2007

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
(in millions, except per share data)
Three Months Ended March 31	2007			2006
Operating revenues
Electric	$	2,068		$	1,985
Diversified business		266			238
Total operating revenues		2,334			2,223
Operating expenses
Utility
Fuel used in electric generation		736			690
Purchased power		221			229
Operation and maintenance		420			416
Depreciation and amortization		219			228
Taxes other than on income		124			119
Other		(1	)		(2	)
Diversified business
Cost of sales		244			256
Depreciation and amortization		2			9
Gain on the sales of assets		(16	)		(4	)
Other		18			14
Total operating expenses		1,967			1,955
Operating income		367			268
Other income (expense)
Interest income		8			17
Other, net		9			(2	)
Total other income		17			15
Interest charges
Net interest charges		144			165
Allowance for borrowed funds used during construction		(3	)		(2	)
Total interest charges, net		141			163
Income from continuing operations before income tax and minority interest		243			120
Income tax expense		19			29
Income from continuing operations before minority interest		224			91
Minority interest in subsidiaries’ income, net of tax		4			6
Income from continuing operations		220			85
Discontinued operations, net of tax		55			(40	)
Net income	$	275		$	45
Average common shares outstanding - basic		254			249
Basic earnings per common share
Income from continuing operations	$	0.87		$	0.34
Discontinued operations, net of tax		0.21			(0.16	)
Net income	$	1.08		$	0.18
Diluted earnings per common share
Income from continuing operations	$	0.87		$	0.34
Discontinued operations, net of tax		0.21			(0.16	)
Net income	$	1.08		$	0.18
Dividends declared per common share	$	0.610		$	0.605

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

9

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	March 31, 2007			December 31, 2006
ASSETS
Utility plant
Utility plant in service	$	23,865		$	23,743
Accumulated depreciation		(10,152	)		(10,064	)
Utility plant in service, net		13,713			13,679
Held for future use		10			10
Construction work in progress		1,526			1,289
Nuclear fuel, net of amortization		300			267
Total utility plant, net		15,549			15,245
Current assets
Cash and cash equivalents		133			265
Short-term investments		1			71
Receivables, net		960			930
Inventory		1,013			969
Deferred fuel cost		189			196
Deferred income taxes		17			159
Assets of discontinued operations		895			887
Derivative assets		112			1
Prepayments and other current assets		68			107
Total current assets		3,388			3,585
Deferred debits and other assets
Regulatory assets		1,104			1,231
Nuclear decommissioning trust funds		1,307			1,287
Diversified business property, net		30			31
Miscellaneous other property and investments		456			456
Goodwill		3,655			3,655
Other assets and deferred debits		230			211
Total deferred debits and other assets		6,782			6,871
Total assets	$	25,719		$	25,701
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 258 and 256 million shares issued and outstanding, respectively	$	5,882		$	5,791
Unearned ESOP shares (2 million shares)		(42	)		(50	)
Accumulated other comprehensive loss		(50	)		(49	)
Retained earnings		2,711			2,594
Total common stock equity		8,501			8,286
Preferred stock of subsidiaries - not subject to mandatory redemption		93			93
Minority interest		54			10
Long-term debt, affiliate		271			271
Long-term debt, net		8,512			8,564
Total capitalization		17,431			17,224
Current liabilities
Current portion of long-term debt		404			324
Short-term debt		117			-
Accounts payable		652			712
Interest accrued		139			171
Dividends declared		157			156
Customer deposits		236			227
Liabilities of discontinued operations		179			189
Income taxes accrued		44			284
Other current liabilities		692			755
Total current liabilities		2,620			2,818
Deferred credits and other liabilities
Noncurrent income tax liabilities		270			306
Accumulated deferred investment tax credits		148			151
Regulatory liabilities		2,584			2,543
Asset retirement obligations		1,321			1,306
Accrued pension and other benefits		964			957
Other liabilities and deferred credits		381			396
Total deferred credits and other liabilities		5,668			5,659
Commitments and contingencies (Notes 11 and 12)
Total capitalization and liabilities	$	25,719		$	25,701

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

10

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Three Months Ended March 31	2007			2006
Operating activities
Net income	$	275		$	45
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax		(55	)		40
Depreciation and amortization		250			267
Deferred income taxes		106			34
Investment tax credits		(3	)		(3	)
Tax levelization		(8	)		16
Deferred fuel cost		108			134
Other adjustments to net income		12			75
Cash provided (used) by changes in operating assets and liabilities
Receivables		59			123
Inventory		(36	)		(60	)
Prepayments and other current assets		(74	)		(15	)
Accounts payable		(51	)		(78	)
Other current liabilities		(290	)		(172	)
Regulatory assets and liabilities		8			(2	)
Other liabilities and deferred credits		(11	)		22
Other assets and deferred debits		(21	)		16
Net cash provided by operating activities		269			442
Investing activities
Gross utility property additions		(469	)		(304	)
Nuclear fuel additions		(61	)		(52	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		30			103
Purchases of available-for-sale securities and other investments		(192	)		(538	)
Proceeds from sales of available-for-sale securities and other investments		252			522
Other investing activities		(1	)		(11	)
Net cash used by investing activities		(441	)		(280	)
Financing activities
Issuance of common stock		65			28
Proceeds from issuance of long-term debt, net		-			397
Net increase in short-term debt		117			79
Retirement of long-term debt		-			(801	)
Dividends paid on common stock		(155	)		(151	)
Other financing activities		(33	)		(60	)
Net cash used by financing activities		(6	)		(508	)
Cash provided (used) by discontinued operations
Operating activities		47			54
Investing activities		(1	)		(50	)
Financing activities		-			-
Net decrease in cash and cash equivalents		(132	)		(342	)
Cash and cash equivalents at beginning of period		265			605
Cash and cash equivalents at end of period	$	133		$	263

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

11

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS

March 31, 2007

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
(in millions)
Three Months Ended March 31	2007			2006
Operating revenues
Electric	$	1,057		$	978
Diversified business		1			-
Total operating revenues		1,058			978
Operating expenses
Fuel used in electric generation		351			296
Purchased power		58			64
Operation and maintenance		248			256
Depreciation and amortization		117			126
Taxes other than on income		50			46
Other		(1	)		1
Total operating expenses		823			789
Operating income		235			189
Other income (expense)
Interest income		6			7
Other, net		3			(1	)
Total other income		9			6
Interest charges
Interest charges		57			57
Allowance for borrowed funds used during construction		(1	)		(1	)
Total interest charges, net		56			56
Income before income tax		188			139
Income tax expense		64			53
Net income		124			86
Preferred stock dividend requirement		1			1
Earnings for common stock	$	123		$	85

See Notes to PEC Consolidated Interim Financial Statements.

12

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	March 31, 2007			December 31, 2006
ASSETS
Utility plant
Utility plant in service	$	14,423		$	14,356
Accumulated depreciation		(6,459	)		(6,408	)
Utility plant in service, net		7,964			7,948
Held for future use		3			3
Construction work in progress		711			617
Nuclear fuel, net of amortization		225			209
Total utility plant, net		8,903			8,777
Current assets
Cash and cash equivalents		81			71
Short-term investments		1			50
Receivables, net		448			473
Receivables from affiliated companies		20			27
Note receivable from affiliated company		-			24
Inventory		513			497
Deferred fuel cost		185			196
Prepayments and other current assets		9			45
Total current assets		1,257			1,383
Deferred debits and other assets
Regulatory assets		755			777
Nuclear decommissioning trust funds		749			735
Miscellaneous other property and investments		187			193
Other assets and deferred debits		142			155
Total deferred debits and other assets		1,833			1,860
Total assets	$	11,993		$	12,020
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, authorized 200 million shares, 160 million shares issued and outstanding	$	2,024		$	2,010
Unearned ESOP common stock		(42	)		(50	)
Accumulated other comprehensive loss		(6	)		(1	)
Retained earnings		1,511			1,431
Total common stock equity		3,487			3,390
Preferred stock - not subject to mandatory redemption		59			59
Long-term debt, net		3,482			3,470
Total capitalization		7,028			6,919
Current liabilities
Current portion of long-term debt		200			200
Accounts payable		277			310
Payables to affiliated companies		42			108
Interest accrued		62			69
Customer deposits		62			59
Income taxes accrued		66			68
Current portion of unearned revenue		56			71
Other current liabilities		166			154
Total current liabilities		931			1,039
Deferred credits and other liabilities
Noncurrent income tax liabilities		854			909
Accumulated deferred investment tax credits		126			128
Regulatory liabilities		1,337			1,320
Asset retirement obligations		1,019			1,004
Accrued pension and other benefits		587			581
Other liabilities and deferred credits		111			120
Total deferred credits and other liabilities		4,034			4,062
Commitments and contingencies (Notes 11 and 12)
Total capitalization and liabilities	$	11,993		$	12,020

See Notes to PEC Consolidated Interim Financial Statements.

13

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Three Months Ended March 31	2007			2006
Operating activities
Net income	$	124		$	86
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		138			147
Deferred income taxes and investment tax credits, net		7			24
Deferred fuel cost		44			24
Other adjustments to net income		(11	)		44
Cash provided (used) by changes in operating assets and liabilities
Receivables		25			79
Receivables from affiliated companies		7			12
Inventory		(8	)		(15	)
Prepayments and other current assets		3			2
Accounts payable		(17	)		(6	)
Payables to affiliated companies		(66	)		(13	)
Other current liabilities		(28	)		(136	)
Other liabilities and deferred credits		-			(22	)
Other assets and deferred debits		(8	)		11
Net cash provided by operating activities		210			237
Investing activities
Gross utility property additions		(208	)		(151	)
Nuclear fuel additions		(38	)		(46	)
Purchases of available-for-sale securities and other investments		(120	)		(238	)
Proceeds from sales of available-for-sale securities and other investments		162			285
Changes in advances to affiliates		24			-
Other investing activities		6			-
Net cash used by investing activities		(174	)		(150	)
Financing activities
Net decrease in short-term debt		-			(21	)
Changes in advances from affiliates		-			(1	)
Dividends paid to parent		(36	)		(85	)
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		11			1
Net cash used by financing activities		(26	)		(107	)
Net increase (decrease) in cash and cash equivalents		10			(20	)
Cash and cash equivalents at beginning of period		71			125
Cash and cash equivalents at end of period	$	81		$	105

See Notes to PEC Consolidated Interim Financial Statements.

14

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

INTERIM FINANCIAL STATEMENTS

March 31, 2007

UNAUDITED STATEMENTS of INCOME
(in millions)
Three Months Ended March 31	2007			2006
Operating revenues	$	1,011		$	1,007
Operating expenses
Fuel used in electric generation		385			394
Purchased power		163			165
Operation and maintenance		175			166
Depreciation and amortization		97			95
Taxes other than on income		74			73
Other		-			(3	)
Total operating expenses		894			890
Operating income		117			117
Other income (expense)
Interest income		1			5
Other, net		7			(1	)
Total other income		8			4
Interest charges
Interest charges		39			40
Allowance for borrowed funds used during construction		(2	)		(1	)
Total interest charges, net		37			39
Income before income tax		88			82
Income tax expense		27			29
Net income		61			53
Preferred stock dividend requirement		1			1
Earnings for common stock	$	60		$	52

See Notes to PEF Interim Financial Statements.

15

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED BALANCE SHEETS
(in millions)	March 31, 2007			December 31, 2006
ASSETS
Utility plant
Utility plant in service	$	9,258		$	9,202
Accumulated depreciation		(3,639	)		(3,602	)
Utility plant in service, net		5,619			5,600
Held for future use		7			7
Construction work in progress		815			672
Nuclear fuel, net of amortization		75			58
Total utility plant, net		6,516			6,337
Current assets
Cash and cash equivalents		12			23
Receivables, net		297			340
Receivables from affiliated companies		9			11
Deferred income taxes		27			86
Inventory		460			436
Deferred fuel cost		4			-
Income taxes receivable		14			47
Prepayments and other current assets		7			62
Total current assets		830			1,005
Deferred debits and other assets
Regulatory assets		349			454
Nuclear decommissioning trust funds		558			552
Miscellaneous other property and investments		45			45
Prepaid pension cost		180			174
Derivative assets		17			2
Other assets and deferred debits		28			24
Total deferred debits and other assets		1,177			1,251
Total assets	$	8,523		$	8,593
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,101		$	1,100
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		1,648			1,588
Total common stock equity		2,748			2,687
Preferred stock - not subject to mandatory redemption		34			34
Long-term debt, net		2,389			2,468
Total capitalization		5,171			5,189
Current liabilities
Current portion of long-term debt		169			89
Notes payable to affiliated companies		11			47
Accounts payable		274			292
Payables to affiliated companies		45			116
Customer deposits		174			168
Interest accrued		32			38
Derivative liabilities		33			89
Current regulatory liabilities		143			76
Other current liabilities		102			89
Total current liabilities		983			1,004
Deferred credits and other liabilities
Noncurrent income tax liabilities		430			466
Accumulated deferred investment tax credits		22			23
Regulatory liabilities		1,117			1,091
Asset retirement obligations		302			299
Accrued pension and other benefits		332			332
Other liabilities and deferred credits		166			189
Total deferred credits and other liabilities		2,369			2,400
Commitments and contingencies (Notes 11 and 12)
Total capitalization and liabilities	$	8,523		$	8,593

See Notes to PEF Interim Financial Statements.

16

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED STATEMENTS of CASH FLOWS
(in millions)
Three Months Ended March 31	2007			2006
Operating activities
Net income	$	61		$	53
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		103			101
Deferred income taxes and investment tax credits, net		14			19
Deferred fuel cost		64			110
Other adjustments to net income		-			10
Cash provided (used) by changes in operating assets and liabilities
Receivables		41			40
Receivables from affiliated companies		2			4
Inventory		(23	)		(66	)
Prepayments and other current assets		56			4
Accounts payable		18			(29	)
Payables to affiliated companies		(71	)		(28	)
Other current liabilities		48			(19	)
Regulatory assets and liabilities		8			(2	)
Other liabilities and deferred credits		(9	)		10
Other assets and deferred debits		(3	)		6
Net cash provided by operating activities		309			213
Investing activities
Gross utility property additions		(261	)		(162	)
Nuclear fuel additions		(23	)		(6	)
Purchases of available-for-sale securities and other investments		(44	)		(126	)
Proceeds from sales of available-for-sale securities and other investments		44			71
Other investing activities		-			(3	)
Net cash used by investing activities		(284	)		(226	)
Financing activities
Changes in advances from affiliates		(36	)		(13	)
Dividends paid to parent		-			(58	)
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		1			-
Net cash used by financing activities		(36	)		(72	)
Net decrease in cash and cash equivalents		(11	)		(85	)
Cash and cash equivalents at beginning of period		23			218
Cash and cash equivalents at end of period	$	12		$	133

See Notes to PEF Interim Financial Statements.

17

PROGRESS ENERGY, INC.

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

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

COMBINEDNOTES TO 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 8, and 10 through 12
PEF	1, 2, 4 through 8, and 10 through 12

18

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED 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 provisions 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. 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 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 seasonal fluctuations in energy sales and earnings from the Utilities. Income tax expense was increased (decreased) for the Progress Registrants for the three months ended March 31, 2007 and 2006, as follows:

19

	Three Months Ended March 31,
(in millions)	2007			2006
Progress Energy	$	(8	)	$	16
PEC		(1	)		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 March 31,
(in millions)	2007		2006
Progress Energy	$	66	$	65
PEC		24		22
PEF		42		43

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all normal recurring adjustments necessary to fairly present the Progress Registrants’ financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or 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 synthetic fuels production facility that qualifies for federal tax credits under Section 45K of the Code. Progress Energy, through its subsidiary Progress Fuels Corporation (Progress Fuels), is the primary beneficiary of, and continues to consolidate Ceredo. At March 31, 2007, the total assets of Ceredo were $37 million and were included in other current assets in the Consolidated Balance Sheets. See Note 3H 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 March 31, 2007, the aggregate additional maximum loss exposure that we could be required to record in our income statement as a result of these arrangements was $7 million, which represents our net remaining investment in the entities. The creditors of these variable interest entities do not have recourse to our general credit in excess of the aggregate maximum loss exposure.

20

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 March 31, 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 a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. PEC also has an interest in one power plant resulting from long-term power purchase contracts. PEC has requested the necessary information to determine if the 17 partnerships and the power plant owner are variable interest entities or to identify the primary beneficiaries; all entities from which the necessary financial information 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 March 31, 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 $20 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 March 31, 2007, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was $57 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 STANDARDS

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). Enterprises must adopt FIN 48 through a cumulative effect adjustment to retained earnings at the beginning of their first fiscal year that begins after December 15, 2006, which for us was January 1, 2007. FIN 48 applies to all tax positions within the scope of Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” and includes tax positions taken and tax positions expected to be taken. A two-step process is required for the application of FIN 48: recognition of the tax benefit based on a “more likely than not” threshold and measurement of the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with the taxing authority. FIN 48 also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. See Note 6 for additional information regarding the adoption of FIN 48.

3. DIVESTITURES

A. CCO - Georgia Operations

On March 9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series of transactions to sell substantially all of its Competitive Commercial Operations (CCO) physical and commercial assets and liabilities. Assets to be divested include approximately 1,900 megawatts (MW) of gas-fired generation assets in Georgia. The sale of the generation assets is expected to close in the summer of 2007 for a net sales price of $603 million and is subject to federal regulatory approvals and customary closing conditions. We recorded an estimated loss of $226

21

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 noncash impairment recorded in 2006.

Additionally, PVI has agreed, subject to obtaining federal regulatory approvals, customer consents and customary closing conditions, to assign the CCO 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. As a result of the assignment, PVI will make a net cash payment of $347 million, which will represent the net cost to assign the Georgia Contracts and other related contracts. As of March 31, 2007, we estimated, as a result of the assignments, the charge associated with exit costs will be in excess of $320 million after-tax. The actual amount of the exit costs to be recorded may vary based on changes in commodity prices. However, any variation in the estimated exit costs will have an offsetting impact in net earnings from discontinued operations. The contract assignment agreement is expected to close in the summer of 2007.

We estimate pre-tax net proceeds on these transactions to be $256 million. Proceeds will be used 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 three months ended March 31, 2007 and 2006 was $8 million and $10 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in December 2006. After-tax depreciation expense during the three months ended March 31, 2006 was $4 million. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2007			2006
Revenues	$	252		$	188
Earnings (loss) before income taxes		70			(95	)
Income tax (expense) benefit		(27	)		35
Net earnings (loss) from discontinued operations		43			(60	)
Reversal of estimated loss on disposal of discontinued operations, including income tax benefit of $2		16			-
Earnings (loss) from discontinued operations	$	59		$	(60	)

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. Proceeds from the sale have been used 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 months ended March 31, 2006, was $4 million. We ceased recording depreciation upon classification of the assets as discontinued operations in July 2006. After-tax depreciation expense during the three months ended March 31, 2006, was $8 million. Results of discontinued operations for the three months ended March 31 were as follows:

22

(in millions)	2007			2006
Revenues	$	-		$	31
Earnings before income taxes		-			39
Income tax expense		-			(18	)
Net earnings from discontinued operations		-			21
Loss on disposal of discontinued operations, including income tax benefit of $1		(1	)		-
(Loss) earnings from discontinued operations	$	(1	)	$	21

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 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 $67 million during the year ended December 31, 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 three months ended March 31, 2006 was $4 million. We ceased recording depreciation upon classification of the assets as discontinued operations in May 2006. After-tax depreciation expense during the three months ended March 31, 2006 was $2 million. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2006
Revenues	$	6
Loss before income taxes		(5	)
Income tax benefit		2
Loss from discontinued operations	$	(3	)

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 10 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 remainder of 2006, we recorded an additional after-tax gain of $4 million after finalizing the working capital adjustment and other operating estimates.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of PT LLC as discontinued operations. Interest expense has been allocated to discontinued operations based on their respective net assets, assuming a uniform debt-to-equity ratio across our operations. Pre-tax interest

23

expense allocated was less than $1 million for the three months ended March 31, 2006. We ceased recording depreciation upon classification of the assets as discontinued operations in January 2006. After-tax depreciation expense during the three months ended March 31, 2006, was $1 million. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2006
Revenues	$	18
Earnings before income taxes and minority interest		1
Income tax expense		(4	)
Minority interest		(3	)
Net loss from discontinued operations		(6	)
Gain on disposal of discontinued operations, including income tax expense of $13 and minority interest of $36		24
Earnings from discontinued operations	$	18

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 12A. 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 operating under long-term contracts with PEF. Dixie Fuels primarily transports coal from the lower Mississippi River to Progress Energy’s Crystal River facility. We recorded an after-tax gain of $2 million on the sale of Dixie Fuels. The other fuels business is Progress Materials, Inc. and is expected to be sold in 2007.

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 each of the three months ended March 31, 2007 and 2006. We ceased recording depreciation upon classification of the assets as discontinued operations. After-tax depreciation expense during the three months ended March 31, 2006 was less than $1 million. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2007		2006
Revenues	$	2	$	8
Earnings before income taxes		1		3
Income tax expense		-		(1	)
Net earnings from discontinued operations		1		2
Gain on disposal of discontinued operations, including income tax expense of $1		-		2
Earnings from discontinued operations	$	1	$	4

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. 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 three months ended March 31, 2006, we recorded an after-tax loss of $15 million on the sale of these assets. During the remainder of 2006, we recorded an after-tax gain of $5 million after finalizing the working capital adjustment and other operating estimates. The remaining coal mining operations are expected to be sold in 2007.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the coal mining operations as discontinued operations. Interest expense has been allocated to discontinued operations based

24

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 three months ended March 31, 2006, was $1 million. There was less than $1 million allocated for the three months ended March 31, 2007. We ceased recording depreciation expense upon classification of the coal mining operations as discontinued operations in November 2005. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2007			2006
Revenues	$	7		$	35
Loss before income taxes		(6	)		(7	)
Income tax benefit		2			2
Net loss from discontinued operations		(4	)		(5	)
Loss on disposal of discontinued operations, including income tax benefit of $9		-			(15	)
Loss from discontinued operations	$	(4	)	$	(20	)

G. Net Assets of Discontinued Operations

At March 31, 2007, and December 31, 2006, the assets and liabilities of CCO, the remaining coal mining operations 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:

(in millions)	March 31, 2007		December 31, 2006
Accounts receivable	$	1	$	45
Inventory		22		24
Other current assets		13		28
Total property, plant and equipment, net		586		573
Total other assets		273		217
Assets of discontinued operations	$	895	$	887
Accounts payable	$	1	$	43
Accrued expenses		166		122
Long-term liabilities		12		24
Liabilities of discontinued operations	$	179	$	189

H. 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 qualifying synthetic fuels, to an unrelated 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 will be received as we produce and sell qualified synthetic fuels on behalf of the buyer during 2007. Actual proceeds could differ based on actual production levels, which shall be determined by the buyer. The estimated production level of Ceredo is 2.8 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 March 31, 2007 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 from the disposal will be recognized over time as we produce and sell qualified synthetic fuels for the buyer. The reconfirmation private letter ruling request has been submitted to the IRS.

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. Ceredo’s long-lived assets were fully impaired during the second quarter of 2006. Subsequent to the disposal, we remain the primary beneficiary of Ceredo and will continue to consolidate Ceredo in accordance with FIN 46R, but we anticipate

25

recording a 100 percent minority interest. Consequently, we anticipate that there will be no net earnings impact. 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 the deferred gain. The ultimate resolution of these matters could result in adjustments to the gain on disposal in future periods. See general discussion of guarantees at Note 12A.

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 oxide (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 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 months ended March 31, 2007, and 2006, PEC recognized amortization of $8 million and $22 million, respectively, and has recognized $543 million in cumulative amortization through March 31, 2007. We will record at least the remaining amortization requirement of $26 million during the nine-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. We cannot predict the outcome of this matter.

See Note 11B 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 customers. PEC is asking the SCPSC to approve a $12 million increase in rates. PEC requested the increase for underrecovered fuel costs associated with prior year settlements and to meet future expected fuel costs. If approved, the increase would take effect July 1, 2007 and would increase residential electric bills by $1.76 per 1,000 kWhs, or 1.9 percent, for fuel cost recovery. A hearing on the matter has been scheduled by the SCPSC for June 13, 2007. We cannot predict the outcome of this matter.

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 the Carolinas Industrial Group for Fair Utility Rates II. The settlement agreement provided for a $177 million, or 6.7 percent increase in rates effective October 1, 2006. The settlement agreement further provides for rate increases of $50 million in 2007 and $30 million in 2008 and for PEC to collect its existing deferred fuel balance by September 30, 2009. PEC initially sought an increase of $292 million, or 11.0 percent, but agreed to a three-year phase-in of the increase in order to address concerns regarding the magnitude of the proposed increase. PEC will be allowed to calculate and collect interest at 6% on the difference between its fuel factor proposed in its original request to the NCUC and the settlement agreement’s factor. Effective October 1, 2006, residential electric bills

26

increased by $4.87 per 1,000 kWhs for fuel cost recovery.

On November 21, 2006, the Carolina Utility Customers Association (CUCA) filed an appeal with the North Carolina Tenth District Court of Appeals of the NCUC’s 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. We cannot predict the outcome of this matter.

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 11A). 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 first quarter of 2007, PEC recorded $1 million of amortization expense. Additionally, PEC reduced the regulatory asset and corresponding liability by $4 million during the first quarter of 2007 based on newly available data regarding certain remediation sites (See Note 11A).

B. PEF Retail Rate Matters

PASS-THROUGH CLAUSE COST RECOVERY

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus interest, of alleged excessive past fuel recovery charges and SO₂ allowance costs 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. The OPC claims that although CR4 and CR5 were designed to burn a blend of coals, PEF failed to act to lower ratepayers’ costs by purchasing the most economical blends of coal. During the period specified in the petition, PEF’s costs recovered through fuel recovery clauses were annually reviewed for prudence and approval by the FPSC. On August 30, 2006, PEF filed a motion with the FPSC to dismiss the petition on the grounds that the OPC petition would require the FPSC to engage in retroactive ratemaking for rates previously approved under the fuel recovery clause. On September 13, 2006, the OPC filed a memorandum in opposition to PEF’s motion to dismiss the petition. PEF’s motion to dismiss was denied by the FPSC on December 19, 2006. The FPSC held a hearing on the matter from April 2 through April 5, 2007. We anticipate that the FPSC will reach a decision on this matter later in 2007. PEF believes that its coal procurement practices were prudent and that it has sound legal and factual arguments to successfully defend its position. 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 costs through PEF’s fuel recovery clause. 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 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 of uprate costs 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 uprate costs should be recovered through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony clarifying the scope of the project. The FPSC has scheduled an August 7, 2007, hearing on this matter. If PEF does not receive approval to recover the uprate costs through the fuel recovery clause, these costs will be recoverable through base rates, similar to other utility plant

27

additions. 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 current estimate of in-service cost of $327 million, which will result in a base rate increase of $52 million, as provided for by PEF’s base rate agreement. The rate base increase would become effective upon Hines Unit 4 being placed in service, which PEF anticipates will be on December 1, 2007. We cannot predict the outcome of this matter.

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 March 31,
(in millions)	2007	2006
Weighted-average common shares - basic	254	249
Net effect of dilutive stock-based compensation plans	1	-
Weighted-average shares - fully dilutive	255	249

B. Comprehensive Income

Progress Energy

	Three Months Ended March 31,
(in millions)	2007			2006
Net income	$	275		$	45
Other comprehensive (loss) income
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax benefit of $2)		-			(4	)
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $-)		1			-
Changes in net unrealized gains on cash flow hedges (net of tax expense of $7)		-			13
Other (net of tax (benefit) expense of $(3) and $2, respectively)		(2	)		5
Other comprehensive (loss) income		(1	)		14
Comprehensive income	$	274		$	59

28

PEC

	Three Months Ended March 31,
(in millions)	2007			2006
Net income	$	124		$	86
Other comprehensive (loss) income
Changes in net unrealized losses on cash flow hedges (net of tax benefit of $1)		(1	)		-
Other (net of tax benefit of $1 and $-, respectively)		(4	)		1
Other comprehensive (loss) income		(5	)		1
Comprehensive income	$	119		$	87

PEF

Comprehensive income and net income for PEF for the three months ended March 31, 2007 and 2006 were $61 million and $53 million, respectively.

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. For the three months ended March 31, 2007 and 2006, respectively, we issued approximately 1.5 million shares and 0.7 million shares of common stock resulting in approximately $65 million and $28 million in proceeds. Included in these amounts were approximately 0.2 million shares and 0.3 million shares for proceeds of approximately $11 million and $14 million, respectively, to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan. 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 401(k) and the Investor Plus Stock Purchase Plan with original issue shares.

6.  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 reduction of the January 1, 2007, balance of retained earnings of $2 million and an increase in regulatory assets of $4 million. 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 affect the effective tax rate for income from continuing operations, if recognized.

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 1998 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 through 2005. We cannot predict when those examinations will be completed. Due to the expected closure of certain tax years and positions, we believe it is reasonably possible that we would recognize a decrease in the total amounts of unrecognized tax benefits ranging from $35 million to $45 million during the twelve-month period ending March 31, 2008.

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

PEC

PEC adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a reduction of the January 1,

29

2007, balance of retained earnings of $6 million. 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 affect the effective tax rate, if recognized.

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 1998 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 through 2005. PEC cannot predict when those examinations will be completed. Due to the expected closure of certain tax years and positions, PEC believes it is reasonably possible that it would recognize a decrease in the total amounts of unrecognized tax benefits ranging from $10 million to $15 million during the twelve-month period ending March 31, 2008.

PEC recognizes accrued interest related to unrecognized tax benefits in interest charges and penalties in other, net on the Consolidated Statements of Income. As of January 1, 2007, PEC had accrued $4 million for interest and penalties.

PEF

PEF adopted the provisions of FIN 48 on January 1, 2007, which was accounted for as a reduction of the January 1, 2007, balance of retained earnings of $1 million and an increase in regulatory assets of $4 million. 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 affect the effective tax rate, if recognized.

We file consolidated federal and state income tax returns that include PEF. PEF’s open federal tax years are from 1999 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 through 2005. PEF cannot predict when those examinations will be completed. Due to the expected closure of certain tax years and positions, PEF believes it is reasonably possible that it would recognize a decrease in the total amounts of unrecognized tax benefits ranging from $10 million to $15 million during the twelve-month period ending March 31, 2008.

PEF recognizes accrued interest related to unrecognized tax benefits in interest charges and penalties in other, net on the Statements of Income. As of January 1, 2007, PEF had accrued $7 million for interest and penalties.

7.  BENEFIT PLANS

We have noncontributory defined benefit retirement plans for substantially all full-time employees that provide pension benefits. We also have supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, we provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the respective Progress Registrants for the three months ended March 31 were:

Progress Energy

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Service cost	$	11		$	12		$	2		$	2
Interest cost		30			29			9			9
Expected return on plan assets		(39	)		(36	)		(1	)		(1	)
Amortization of actuarial loss (a)		4			6			1			2
Other amortization, net (a)		-			-			1			1
Net periodic cost	$	6		$	11		$	12		$	13

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

30

PEC

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007			2006
Service cost	$	5		$	6		$	1		$	1
Interest cost		14			13			5			5
Expected return on plan assets		(15	)		(15	)		(1	)		(1	)
Amortization of actuarial loss		3			3			1			1
Net periodic cost	$	7		$	7		$	6		$	6

PEF

	Pension Benefits						Other Postretirement Benefits
(in millions)	2007			2006			2007		2006
Service cost	$	4		$	4		$	1	$	1
Interest cost		13			12			3		3
Expected return on plan assets		(21	)		(19	)		-		-
Amortization of actuarial loss		-			2			-		-
Other amortization, net		-			-			1		1
Net periodic (benefit) cost	$	(4	)	$	(1	)	$	5	$	5

8.  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 3, on March 9, 2007, we entered into two separate agreements to dispose of substantially all of PVI’s remaining CCO physical and commercial assets, and on October 2, 2006, we sold Gas. Due to these divestiture plans, 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 March 31, 2007 and December 31, 2006, derivative assets of $178 million and $107 million, respectively, were included in assets of discontinued operations and derivative liabilities of $10 million and $31 million, respectively, were included in liabilities of discontinued operations on the Consolidated Balance Sheets. For the three months ending March 31, 2007, gains from derivative instruments of $59 million were included in discontinued operations, net of tax on the Consolidated Statement of Income. For the three months ending March 31, 2006, net gains and losses from derivative instruments of discontinued operations were not material. For the three months ending March 31, 2007 and 2006, there were no reclassifications to earnings due to discontinuance of the related cash flow hedges.

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

31

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 10). At March 31, 2007 and December 31, 2006, the remaining liability was $13 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.

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. PEC and PEF did not have material outstanding positions in such contracts at March 31, 2007 and December 31, 2006, other than those receiving regulatory accounting treatment, as discussed below.

At March 31, 2007, the fair value of PEC’s derivative instruments was recorded as a $4 million long-term derivative asset position included in other assets and deferred debits on the Consolidated Balance Sheet. At December 31, 2006, PEC did not have material outstanding positions in such contracts.

At March 31, 2007, the fair value of PEF’s derivative instruments was recorded as a $2 million short-term derivative asset position included in other assets and deferred debits, a $17 million long-term derivative asset position included in derivative assets, a $31 million short-term derivative liability position included in derivative liabilities, and an $11 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 derivative assets, 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.

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 3H, 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. At March 31, 2007, the fair value of these contracts was recorded as a $110 million short-term derivative asset position, including $37 million at Ceredo. The fair value of these contracts was included in derivative assets on the Consolidated Balance Sheet. During the three months ended March 31, 2007, we recorded net pre-tax gains of $45 million in diversified business revenues related to these contracts. We anticipate that future mark-to-market changes on the Ceredo portion of the derivatives contracts will have no net earnings impact.

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 March 31, 2007, we and the Utilities did not have

32

material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges for the three months ended March 31, 2007 and 2006, was not material to our or the Utilities’ results of operations.

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

	December 31, 2006
(in millions)	Progress Energy		PEC		PEF
Fair value of assets	$	2	$	2	$	-
Fair value of liabilities		-		-		-
Fair value, net	$	2	$	2	$	-

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

At March 31, 2007 and December 31, 2006, the amount recorded in our, PEC’s or PEF’s accumulated other comprehensive income (AOCI) related to commodity cash flow hedges was not material.

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

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

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

	March 31, 2007									December 31, 2006
(in millions)	Progress Energy			PEC			PEF			Progress Energy			PEC			PEF
Interest rate cash flow hedges	$	(4	)	$	(2	)	$	(2	)	$	(2	)	$	(1	)	$	(1	)
Interest rate fair value hedges		(1	)		-			-			(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 months ended March 31, 2007 and 2006, was not material to our or the Utilities’ results of operations.

The following table presents selected information related to our interest rate cash flow hedges at March 31, 2007:

(term in years/millions of dollars)	Progress Energy			PEC			PEF
Maximum term	Less than 1			Less than 1			Less than 1
Accumulated other comprehensive loss, net of tax(a)	$	(13	)	$	(6	)	$	(1	)
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.

PEF entered into a $50 million forward starting swap on February 16, 2007, to mitigate exposure to interest rate risk

33

in anticipation of future debt issuances.

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.

At March 31, 2007, we had $150 million notional of interest rate cash flow hedges, including $50 million notional at PEC and $100 million notional at PEF. 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.

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 March 31, 2007 and December 31, 2006, we had $50 million notional of interest rate fair value hedges. At March 31, 2007 and December 31, 2006, the Utilities had no open interest rate fair value hedges.

9.  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.

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.

34

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 months ended March 31:

									Income
	Revenues								(Loss) from
(in millions)	Unaffiliated		Intersegment			Total			Continuing Operations			Assets
2007
PEC	$	1,058	$	-		$	1,058		$	123		$	11,993
PEF		1,011		-			1,011			60			8,523
Coal and Synthetic Fuels		263		2			265			57			372
Corporate and Other		2		85			87			(20	)		15,658
Eliminations		-		(87	)		(87	)		-			(11,722	)
Totals	$	2,334	$	-		$	2,334		$	220		$	24,824
2006
PEC	$	978	$	-		$	978		$	85
PEF		1,007		-			1,007			52
Coal and Synthetic Fuels		238		78			316			9
Corporate and Other		-		89			89			(61	)
Eliminations		-		(167	)		(167	)		-
Totals	$	2,223	$	-		$	2,223		$	85

35

10.  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 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 March 31,
(in millions)	2007		2006
Other income
Nonregulated energy and delivery services income	$	9	$	8
DIG Issue C20 amortization (see Note 8)		−		1
CVOs unrealized gain		1		−
Gain on sale of Level 3 stock (a)		−		25
Investment gains		1		2
Income from equity investments		2		−
AFUDC equity		9		3
Other		4		5
Total other income		26		44
Other expense
Nonregulated energy and delivery services expenses		7		6
Donations		4		7
Loss from equity investments		4		1
CVOs unrealized loss		−		25
Other		2		7
Total other expense		17		46
Other, net - Progress Energy	$	9	$	(2	)

^(a)   Other income includes a $25 million gain from the sale of approximately 15 million shares of Level 3 stock received as part of the sale of our interest in PT LLC (See Note 3D). This gain is prior to the consideration of minority interest.

36

PEC

	Three Months Ended March 31,
(in millions)	2007		2006
Other income
Nonregulated energy and delivery services income	$	2	$	2
DIG Issue C20 amortization (see Note 8)		−		1
Income from equity investments		2		−
AFUDC equity		2		1
Other		4		3
Total other income		10		7
Other expense
Nonregulated energy and delivery services expenses		2		1
Donations		2		3
Loss from equity investments		1		−
Other		2		4
Total other expense		7		8
Other, net - PEC	$	3	$	(1	)

PEF

	Three Months Ended March 31,
(in millions)	2007		2006
Other income
Nonregulated energy and delivery services income	$	7		6
Investment gains		−		1
AFUDC equity		7		2
Total other income		14		9
Other expense
Nonregulated energy and delivery services expenses		5		5
Donations		2		3
Other		−		2
Total other expense		7		10
Other, net - PEF	$	7	$	(1	)

11.  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

37

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)	March 31, 2007		December 31, 2006
PEC
MGP and other sites(a)	$	16	$	22
PEF
Remediation of distribution and substation transformers		40		43
MGP and other sites		18		18
Total PEF environmental remediation accruals(b)		58		61
Progress Energy nonregulated operations		3		3
Total Progress Energy environmental remediation accruals	$	77	$	86

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

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

Progress Energy

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

In 2001, we, through our Progress Fuels subsidiary, established an accrual to address indemnities and retained an environmental liability associated with the sale of our Inland Marine Transportation business. At March 31, 2007 and December 31, 2006, the remaining accrual balance was approximately $3 million. Expenditures related to this liability were not material for the three months ended March 31, 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 12A).

PEC

For the three months ended March 31, 2007, including the Ward Transformer site and MGP sites discussed below, PEC reduced its accrual by approximately $5 million, primarily related to the Ward Transformer site, and spent approximately $1 million. For the three months ended March 31, 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 $3 million. In October 2006, PEC received orders from the NCUC and SCPSC to defer and amortize certain environmental remediation expenses (See Note 4A).

PEC has recorded a minimum estimated total remediation cost for all of its remaining MGP sites based upon its

38

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.

In September 2005, the EPA advised PEC that it had been identified as a PRP at the Carolina Transformer site located in Fayetteville, N.C. The EPA offered PEC and a number of other PRPs the opportunity to share in the reimbursement to the EPA of past expenditures in addressing conditions at the site, which are currently approximately $32 million. In May 2006, a meeting was called by the EPA to discuss a settlement proposal among the PRPs. An agreement among PRPs has not been reached; consequently, it is not possible at this time to reasonably estimate the amount of PEC’s share of the reimbursement for remediation of the Carolina Transformer site. The outcome of this matter cannot be predicted.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC and a number of other PRPs the opportunity to negotiate cleanup of the site and reimbursement to the EPA for EPA’s past expenditures in addressing conditions at the site. 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 March 31, 2007, PEC’s recorded liability for the site was approximately $4 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.

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 months ended March 31, 2007 and 2006, PEF accrued approximately $2 million and $38 million, respectively, due to additional sites expected to require remediation and spent approximately $5 million and $1 million, respectively, related to the remediation of transformers. At March 31, 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 months ended March 31, 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 March 31, 2007, cumulative capital expenditures to date to comply with these environmental laws and regulations were $1.067 billion, including $1.009 billion at PEC and $58 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 generation plants (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements, the joint owners are required

39

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 on 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 March 31, 2007 and December 31, 2006, the amount of the liability was $31 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 customers have significantly benefited from the strategy of focusing emission reduction efforts on the jointly owned units, and, therefore, PEC believes that any costs in excess of the joint owner’s share should be recovered from North Carolina retail customers, consistent with other capital expenditures associated with PEC’s compliance with the Clean Smokestacks Act. 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 has, accordingly, recorded the indemnification expense to Clean Smokestacks Act amortization.

12.  COMMITMENTS AND CONTINGENCIES

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

A.  Guarantees

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 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 March 31, 2007, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations. Related to the sales of businesses, the latest notice period extends until 2012 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. In 2005, PEC entered into an agreement with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 11B). PEC’s maximum exposure cannot be determined. At March 31, 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 March 31, 2007 and December 31, 2006, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $82 million and $60 million, respectively. These amounts include $31 million and $29 million, respectively, for PEC and $8 million for PEF at March 31, 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 of certain payments of two wholly owned indirect subsidiaries. See Note 13 for additional information.

40

B. 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’s scheduling order, issued on March 23, 2006, included an anticipated trial date in late 2007.

In July 2002, Congress passed an override resolution to Nevada’s veto of the DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.; and the city of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) 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. Circuit Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. In August 2005, the EPA issued new proposed standards. The proposed standards include a 1,000,000-year compliance period in the radiation protection standard. Comments were due November 21, 2005, and are being reviewed by the EPA. The EPA 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. The DOE has requested $495 million for fiscal year 2008. 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.

41

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.

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.

13.  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 11B in the 2006 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

42

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, Gas, DeSoto, Rowan, Dixie Fuels and other fuels business as discontinued operations as described in Note 3.

43

Condensed Consolidating Statement of Income Three Months Ended March 31, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,011		$	1,057		$	2,068
Diversified business		−			236			30			266
Total operating revenues		−			1,247			1,087			2,334
Operating expenses
Utility
Fuel used in electric generation		−			385			351			736
Purchased power		−			163			58			221
Operation and maintenance		5			175			240			420
Depreciation and amortization		−			97			122			219
Taxes other than on income		−			74			50			124
Other		−			−			(1	)		(1	)
Diversified business
Cost of sales		−			224			20			244
Depreciation and amortization		−			2			−			2
Gain on the sale of assets		−			(16	)		−			(16	)
Other		−			15			3			18
Total operating expenses		5			1,119			843			1,967
Operating (loss) income		(5	)		128			244			367
Other income, net		6			6			5			17
Interest charges, net		47			45			49			141
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(46	)		89			200			243
Income tax (benefit) expense		(19	)		(1	)		39			19
Equity in earnings of consolidated subsidiaries		302			−			(302	)		−
Minority interest in subsidiaries’ income, net of tax		−			4			−			4
Income (loss) from continuing operations		275			86			(141	)		220
Discontinued operations, net of tax		−			(4	)		59			55
Net income (loss)	$	275		$	82		$	(82	)	$	275

44

Condensed Consolidating Statement of Income Three Months Ended March 31, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	1,007		$	978		$	1,985
Diversified business		−			243			(5	)		238
Total operating revenues		−			1,250			973			2,223
Operating expenses
Utility
Fuel used in electric generation		−			394			296			690
Purchased power		−			165			64			229
Operation and maintenance		4			166			246			416
Depreciation and amortization		−			95			133			228
Taxes other than on income		−			73			46			119
Other		−			(3	)		1			(2	)
Diversified business
Cost of sales		−			244			12			256
Depreciation and amortization		−			4			5			9
Other		−			6			4			10
Total operating expenses		4			1,144			807			1,955
Operating (loss) income		(4	)		106			166			268
Other (expense) income, net		(10	)		28			(3	)		15
Interest charges, net		77			48			38			163
(Loss) income from continuing operations before income tax, equity in earnings of consolidated subsidiaries and minority interest		(91	)		86			125			120
Income tax (benefit) expense		(33	)		19			43			29
Equity in earnings of consolidated subsidiaries		103			−			(103	)		−
Minority interest in subsidiaries’ income, net of tax		−			6			−			6
Income (loss) from continuing operations		45			61			(21	)		85
Discontinued operations, net of tax		−			(1	)		(39	)		(40	)
Net income (loss)	$	45		$	60		$	(60	)	$	45

45

Condensed Consolidating Balance Sheet March 31, 2007
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−	$	6,516	$	9,033		$	15,549
Current assets
Cash and cash equivalents		10		40		83			133
Short-term investments		−		−		1			1
Notes receivables from affiliated companies		238		−		(238	)		−
Deferred fuel cost		−		4		185			189
Assets of discontinued operations		−		42		853			895
Other current assets		31		1,095		1,044			2,170
Total current assets		279		1,181		1,928			3,388
Deferred debits and other assets
Investment in consolidated subsidiaries		11,035		−		(11,035	)		−
Goodwill		−		1		3,654			3,655
Other assets and deferred debits		137		1,503		1,487			3,127
Total deferred debits and other assets		11,172		1,504		(5,894	)		6,782
Total assets	$	11,451	$	9,201	$	5,067		$	25,719
Capitalization
Common stock equity	$	8,501	$	2,798	$	(2,798	)	$	8,501
Preferred stock of subsidiaries - not subject to mandatory redemption		−		34		59			93
Minority interest		−		50		4			54
Long-term debt, affiliate		−		309		(38	)		271
Long-term debt, net		2,595		2,435		3,482			8,512
Total capitalization		11,096		5,626		709			17,431
Current liabilities
Current portion of long-term debt		−		204		200			404
Notes payable to affiliated companies		−		263		(263	)		−
Liabilities of discontinued operations		−		8		171			179
Other current liabilities		311		993		733			2,037
Total current liabilities		311		1,468		841			2,620
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		57		213			270
Regulatory liabilities		−		1,117		1,467			2,584
Accrued pension and other benefits		13		377		574			964
Other liabilities and deferred credits		31		556		1,263			1,850
Total deferred credits and other liabilities		44		2,107		3,517			5,668
Total capitalization and liabilities	$	11,451	$	9,201	$	5,067		$	25,719

46

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 receivables 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

47

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2007
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(8	)	$	33		$	244		$	269
Investing activities
Gross utility property additions		−			(261	)		(208	)		(469	)
Nuclear fuel additions		−			(23	)		(38	)		(61	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			25			5			30
Purchases of available-for-sale securities and other investments		−			(44	)		(148	)		(192	)
Proceeds from sales of available-for-sale securities and other investments		21			44			187			252
Changes in advances to affiliates		(180	)		37			143			−
Other investing activities		(2	)		(6	)		7			(1	)
Net cash used by investing activities		(161	)		(228	)		(52	)		(441	)
Financing activities
Issuance of common stock		65			−			−			65
Net increase in short-term debt		117			−			−			117
Dividends paid on common stock		(155	)		−			−			(155	)
Changes in advances from affiliates		−			187			(187	)		−
Other financing activities		(1	)		11			(43	)		(33	)
Net cash provided (used) by financing activities		26			198			(230	)		(6	)
Cash (used) provided by discontinued operations
Operating activities		−			(2	)		49			47
Investing activities		−			(1	)		−			(1	)
Financing activities		−			−			−			−
Net (decrease) increase in cash and cash equivalents		(143	)		−			11			(132	)
Cash and cash equivalents at beginning of period		153			40			72			265
Cash and cash equivalents at end of period	$	10		$	40		$	83		$	133

48

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2006
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	64		$	341		$	37		$	442
Investing activities
Gross utility property additions		−			(153	)		(151	)		(304	)
Nuclear fuel additions		−			(6	)		(46	)		(52	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			98			5			103
Purchases of available-for-sale securities and other investments		(163	)		(126	)		(249	)		(538	)
Proceeds from sales of available-for-sale securities and other investments		163			71			288			522
Changes in advances to affiliates		135			(66	)		(69	)		−
Other investing activities		(3	)		(3	)		(5	)		(11	)
Net cash provided (used) by investing activities		132			(185	)		(227	)		(280	)
Financing activities
Issuance of common stock		28			−			−			28
Proceeds from issuance of long-term debt, net		397			−			−			397
Net increase (decrease) in short-term debt		100			−			(21	)		79
Retirement of long-term debt		(800	)		(1	)		−			(801	)
Dividends paid on common stock		(151	)		−			−			(151	)
Dividends paid to parent		−			(59	)		59			−
Changes in advances from affiliates		−			(127	)		127			−
Other financing activities		(5	)		(24	)		(31	)		(60	)
Net cash (used) provided by financing activities		(431	)		(211	)		134			(508	)
Cash provided (used) by discontinued operations
Operating activities		−			16			38			54
Investing activities		−			(49	)		(1	)		(50	)
Financing activities		−			−			−			−
Net decrease in cash and cash equivalents		(235	)		(88	)		(19	)		(342	)
Cash and cash equivalents at beginning of period		239			239			127			605
Cash and cash equivalents at end of period	$	4		$	151		$	108		$	263

49

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). 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 term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF.

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” 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 seasonal temperature variations on energy consumption and the timing of maintenance on electric generating units, among other factors.

This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 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;

·   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 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 months ended March 31, 2007 are compared to the same period 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.

50

Overview

For the quarter ended March 31, 2007, our net income was $275 million, or $1.08 per share, compared to net income of $45 million, or $0.18 per share, for the same period in 2006. For the quarter ended March 31, 2007, our income from continuing operations was $220 million compared to $85 million for the same period in 2006. The increase in income from continuing operations as compared to prior year was primarily due to:

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

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

·   higher tax credits due to higher synthetic fuels production;

·   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 operating and maintenance (O&M) expenses due to the impact of recording additional estimated environmental remediation expenses at PEC in 2006;

·   lower interest expense due to reducing holding company debt during 2006; and

·   higher retail base revenue at PEC primarily due to the impact of favorable growth and usage and weather.

Partially offsetting these items was:

·   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).

Our segments contributed the following profits or losses for the three months ended March 31, 2007 and 2006:

	Three Months Ended March 31,
(in millions)	2007			2006
Business Segment
PEC	$	123		$	85
PEF		60			52
Coal and Synthetic Fuels		57			9
Total segment profit		240			146
Corporate and Other		(20	)		(61	)
Income from continuing operations		220			85
Discontinued operations, net of tax		55			(40	)
Net income	$	275		$	45

Progress Energy Carolinas

PEC contributed segment profits of $123 million and $85 million for the three months ended March 31, 2007 and 2006, respectively. The increase in profits for the three months ended March 31, 2007, when compared to 2006, was primarily due to lower O&M expenses related to the impact of recording additional environmental remediation expenses in 2006, favorable retail customer growth and usage and favorable weather partially offset by higher income tax expense.

51

REVENUES

PEC’s revenues for the three months ended March 31, 2007 and 2006, and the percentage change by customer class were as follows:

(in millions)	Three Months Ended March 31,
Customer Class	2007			Change			% Change			2006
Residential	$	424		$	48			12.8		$	376
Commercial		254			28			12.4			226
Industrial		165			2			1.2			163
Governmental		22			2			10.0			20
Total retail revenues		865			80			10.2			785
Wholesale		194			2			1.0			192
Unbilled		(25	)		2			-			(27	)
Miscellaneous		23			(5	)		(17.9	)		28
Total electric revenues		1,057			79			8.1			978
Less: Fuel revenues		(375	)		(58	)		-			(317	)
Revenues excluding fuel	$	682		$	21			3.2		$	661

PEC’s energy sales for the three months ended March 31, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended March 31,
Customer Class	2007			Change			% Change			2006
Residential		4,740			323			7.3			4,417
Commercial		3,245			193			6.3			3,052
Industrial		2,821			(112	)		(3.8	)		2,933
Governmental		327			7			2.2			320
Total retail energy sales		11,133			411			3.8			10,722
Wholesale		3,956			(2	)		(0.1	)		3,958
Unbilled		(343	)		35			-			(378	)
Total kWh sales		14,746			444			3.1			14,302

PEC’s revenues, excluding fuel revenues of $375 million and $317 million for the three months ended March 31, 2007 and 2006, respectively, increased $21 million. The increase in revenues is primarily due to favorable retail growth and usage and favorable weather partially offset by a decrease in miscellaneous revenues. Favorable retail growth and usage of $15 million was driven by both an increase in the average usage per retail customer and an approximate increase in the average number of customers of 28,000 as of March 31, 2007, compared to March 31, 2006. The impact of weather was $9 million favorable with heating degree days 3 percent higher than 2006 and cooling degree days 93 percent higher than 2006. The decrease in miscellaneous revenues was primarily due to lower gains on forward sales of excess generation during 2007 as compared to 2006.

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 $409 million for the three months ended March 31, 2007, which represents a $49 million increase compared to the same period in 2006. Fuel used in electric generation increased $55 million to $351 million compared to the prior year. This increase is due to a $35 million increase in fuel used in generation primarily due to a change in generation mix as the percentage of generation supplied by natural gas increased in

52

response to higher system requirements due to cold weather in February 2007. A $20 million increase in deferred fuel expense primarily due to an increase in the fuel recovery rates for North Carolina, also contributed to the increase in fuel expense. Current year purchased power costs were $6 million lower than the three months ended March 31, 2006, due to lower cogeneration as a result of contract changes with one of our co-generators.

Operation and Maintenance

O&M expenses were $248 million for the three months ended March 31, 2007, which represents an $8 million decrease compared to the same period in 2006. O&M expenses decreased $23 million due to recording additional estimated environmental remediation expenses during 2006 (See Note 11A). This was partially offset by $8 million of higher outage costs, $3 million of incremental labor costs due to filling vacant positions and $2 million of higher costs related to the operation of emission control equipment installed at our coal-fired plants.

Depreciation and Amortization

Depreciation and amortization expense was $117 million for the three months ended March 31, 2007, which represents a $9 million decrease compared to the same period in 2006. Depreciation expense decreased $14 million due to lower North Carolina Clean Smokestacks Act (Clean Smokestacks Act) amortization, partially offset by the impact of depreciable asset base increases.

Taxes other than on Income

Taxes other than on income was $50 million for the three months ended March 31, 2007, which represents a $4 million increase compared to the same period in 2006. The increase is primarily due to a $3 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 $9 million increased $3 million for the three months ended March 31, 2007, compared to the same period in 2006, primarily due to a $2 million gain on the sale of investments during 2007 and a $1 million increase in the equity component of allowance for funds used during construction (AFUDC).

Income Tax Expense

Income tax expense increased $11 million for the three months ended March 31, 2007, as compared to the same period in 2006, primarily due to the $20 million impact of higher earnings compared to the prior year. This was partially offset by $5 million of favorable changes related to prior year federal and state income tax returns and a $3 million favorable change related to tax levelization. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEC’s income tax expense was reduced $1 million for the three months ended March 31, 2007 compared to an increase of $2 million for the three months ended March 31, 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 and temporary deductions can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

53

Progress Energy Florida

PEF contributed segment profits of $60 million and $52 million for the three months ended March 31, 2007 and 2006, respectively. The increase in profits for the three months ended March 31, 2007, when compared to 2006, was primarily due to higher wholesale revenues and other miscellaneous service revenues.

REVENUES

PEF’s revenues for the three months ended March 31, 2007 and 2006, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended March 31,
Customer Class	2007			Change			% Change			2006
Residential	$	491		$	(15	)		(3.0	)	$	506
Commercial		247			2			0.8			245
Industrial		74			(9	)		(10.8	)		83
Governmental		67			1			1.5			66
Retail revenue sharing		-			(1	)		-			1
Total retail revenues		879			(22	)		(2.4	)		901
Wholesale		80			11			15.9			69
Unbilled		8			7			-			1
Miscellaneous		44			8			22.2			36
Total electric revenues		1,011			4			0.4			1,007
Less: Fuel and other pass-through revenues		(645	)		9			-			(654	)
Revenues excluding fuel and other pass-through revenues	$	366		$	13			3.7		$	353

PEF’s electric energy sales for the three months ended March 31, 2007 and 2006, and the amount and percentage change by customer class are as follows:

(in millions of kWh)	Three Months Ended March 31,
Customer Class	2007		Change			% Change			2006
Residential		4,155		(156	)		(3.6	)		4,311
Commercial		2,624		74			2.9			2,550
Industrial		895		(111	)		(11.0	)		1,006
Governmental		748		27			3.7			721
Total retail energy sales		8,422		(166	)		(1.9	)		8,588
Wholesale		1,170		163			16.2			1,007
Unbilled		190		340			-			(150	)
Total kWh sales		9,782		337			3.6			9,445

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $645 million and $654 million for the three months ended March 31, 2007 and 2006, respectively, increased $13 million. The increase in revenues is primarily due to increased wholesale revenues and other miscellaneous service revenues. Wholesale revenues increased primarily due to the $7 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 $4 million. Industrial revenues and sales have decreased primarily due to a change in the service provided to a large customer; however, this decrease has been partially offset by a reduction in the associated purchased power expense and therefore has no material impact on earnings. Although overall growth and usage did not have a material impact on revenues, favorable growth of $5 million driven by an approximate average net increase in the number of customers of 31,000 as of March 31, 2007, compared to March 31, 2006 was offset by lower usage per customer.

54

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 $548 million for the three months ended March 31, 2007, which represents an $11 million decrease compared to the same period in 2006. This decrease is due to decreases in fuel used in electric generation and purchased power expenses of $9 million and $2 million, respectively. Fuel used in electric generation decreased primarily due to lower deferred fuel expense of $44 million partially offset by increased current year fuel costs of $36 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 decrease in purchased power expense was primarily due to lower recovery of deferred capacity costs.

Operation and Maintenance

O&M expenses were $175 million for the three months ended March 31, 2007, which represents a $9 million increase, when compared to the same period in 2006. O&M expenses increased $8 million related to higher environmental cost recovery (ECRC) and higher energy conservation cost recovery (ECCR) costs. The ECRC and ECCR expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings.

Total Other Income

Total other income of $8 million increased $4 million for the three months ended March 31, 2007 compared to the same period in 2006, primarily due to a $5 million increase in AFUDC equity related to costs associated with large construction projects partially offset by lower interest income. Interest income decreased due primarily to lower short-term investment balances and lower interest on unrecovered storm restoration costs. We expect AFUDC equity to continue to increase during 2007.

Income Tax Expense

Income tax expense decreased $2 million for the three months ended March 31, 2007, as compared to the same period in 2006, primarily due to the impact of the increase in AFUDC equity discussed above and current year miscellaneous tax adjustments. AFUDC equity is excluded from the calculation of income tax expense.

Coal and Synthetic Fuels

The operations of the Coal and Synthetic Fuels segment include synthetic fuels production and coal terminal operations. The following summarizes the Coal and Synthetic Fuels segment profits:

	Three Months Ended March 31,
(in millions)	2007			2006
Synthetic fuels operations	$	62		$	3
Coal terminals and marketing		(2	)		14
Corporate overhead and other operations		(3	)		(8	)
Segment profits	$	57		$	9

55

SYNTHETIC FUELS OPERATIONS

The production and sale of 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 March 31,
(in millions)	2007			2006
Tons sold		2.1			1.2
After-tax profits (losses) (excluding tax credits)	$	10		$	(26	)
Tax credits generated		61			35
Tax credit inflation adjustment		-			10
Tax credits reserve increase due to estimated phase-out		(9	)		(16	)
Net profit	$	62		$	3

Synthetic fuels operations’ net profit increased $59 million for the three months ended March 31, 2007, as compared to the same period in 2006. After-tax profits (excluding tax credits) for synthetic fuels operations increased $36 million for the three months ended March 31, 2007 compared to the same period in 2006 primarily due to the $29 million unrealized after-tax mark-to-market gain recorded on derivative contracts entered into in January 2007 (See Note 8A). After-tax profits (excluding tax credits) were also positively impacted by lower royalty expenses and lower depreciation expense both due to the second quarter 2006 impairment of our synthetic fuel assets. These were partially offset by lower margins due to the increase in synthetic fuels production. Tax credits generated during the three months ended March 31, 2007 compared to the same period in 2006 increased due to higher production. We increased synthetic fuels production in 2007 as a result of lower current year oil prices, lower futures prices based on the oil futures curve which reduced the potential tax credit phase-out and the protection against oil price increases provided by the derivative contracts. The change in the tax credit reserve is primarily due to the change in the relative level of oil prices which indicated an estimated phase-out of 18 percent in 2007 compared to an estimated phase-out of 47 percent in 2006. The 2007 tax credit reserve increase includes $11 million due to the potential phase-out of the 2007 tax credits partially offset by the reversal of $2 million of credits reserved in 2006. 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 lower than our December 31, 2006 phase-out estimate of 35 percent.

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 unrelated third-party buyer (see Note 3H and “Other Matters - Synthetic Fuels Tax Credits”). We will continue 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 anticipate recording a 100 percent minority interest and anticipate that there will be no net earnings impact. Consequently, future net operating results and tax credits generated by Ceredo will be excluded from our Coal and Synthetic Fuels segment. A portion of the derivative contracts discussed above were entered into by Ceredo and contributed $10 million of the total $29 million unrealized after-tax mark-to-market gain recorded for the three months ended March 31, 2007. Future mark-to-market changes on the Ceredo portion of the derivative contracts will also be excluded from the results of our Coal and Synthetic Fuels segment.

Our synthetic fuels production levels for 2007 remain uncertain due to the recent volatility of oil prices. See “Other Matters - Synthetic Fuels Tax Credits” below for additional information on the impact of oil prices on Section 29/45K tax credits and a discussion of uncertainties surrounding our synthetic fuels production in 2007.

COAL TERMINALS AND MARKETING

Coal terminals and marketing (Coal) operations blend and transload coal as part of the trucking, rail and barge network for coal delivery. This business also has an operating fee agreement with our synthetic fuels operations for procuring and processing of coal and the transloading and marketing of synthetic fuels. As a result of the relationship with the synthetic fuels operations, fluctuations in Coal’s annual earnings are primarily related to production volumes at our synthetic fuels facilities. Coal operations had losses of $2 million for the three months ended

56

March 31, 2007 compared to earnings of $14 million for the same period in 2006. Coal’s 2007 results were negatively impacted by a decrease in sales to external customers and the prior year impact of the $11 million pre-tax expense reduction due to restructuring a coal supply contract in 2006.

CORPORATE OVERHEAD AND OTHER OPERATIONS

Corporate overhead and other operations incurred losses of $3 million and $8 million for the three months ended March 31, 2007 and 2006, respectively. The decrease in losses for 2007 compared to 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 March 31,
(in millions)	2007			2006
Other interest expense	$	(48	)	$	(64	)
Contingent value obligations		1			(25	)
Tax levelization		7			(14	)
Other income tax benefit		20			26
Other		-			16
Corporate and Other after-tax expense	$	(20	)	$	(61	)

Other interest expense decreased $16 million for the three months ended March 31, 2007 compared to the same period in 2006 primarily due to the $1.7 billion reduction in holding company debt during 2006 partially offset by a decrease in the interest allocated to discontinued operations. The decrease in interest expense allocated to discontinued operations resulted from the allocations of interest expense in early 2006 for operations that were sold later in 2006.

Progress Energy issued 98.6 million contingent value obligations (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 March 31, 2007 and 2006, the CVOs had fair market values of approximately $31 million and $33 million, respectively. Progress Energy recorded unrealized gains of $1 million for the three months ended March 31, 2007 and unrealized losses of $25 million for the three months ended March 31, 2006, to record the changes in fair value of the CVOs, which had average unit prices of $0.31 and $0.33 at March 31, 2007 and 2006, respectively.

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 $7 million for the three months ended March 31, 2007 compared to an increase of $14 million for the three months ended March 31, 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 decreased $16 million primarily due to the $13 million gain, net of minority interest, on the sale of Level 3 Communications, Inc. (Level 3) stock subsequent to the sale of PT LLC in 2006 (See Note 3D).

57

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 Operations

On March 9, 2007, our subsidiary, Progress Ventures, Inc. (PVI), entered into a series of transactions to sell substantially all of its CCO physical and commercial assets and liabilities. Assets to be divested include 1,900 megawatts (MW) of gas-fired generation assets in Georgia. The sale of the generation assets is expected to close in the summer of 2007 for a net sales price of $603 million and is subject to federal regulatory approvals and customary closing conditions. 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 noncash impairment recorded in 2006.

Additionally, PVI has agreed, subject to obtaining federal regulatory approvals, customer consents and customary closing conditions, to assign the CCO 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. As a result of the assignment, PVI will make a net cash payment of $347 million, which will represent the net cost to assign the Georgia Contracts and other related contracts. As of March 31, 2007, we estimated, as a result of the assignments, the charge associated with exit costs will be in excess of $320 million after-tax. The actual amount of the exit costs to be recorded may vary based on changes in commodity prices. However, any variation in the estimated exit costs will have an offsetting impact in net earnings from discontinued operations. The contract assignment agreement is expected to close in the summer of 2007.

We estimate pre-tax net proceeds on these transactions to be $256 million (approximately $476 million after estimated tax benefits.) Proceeds will be used for general corporate purposes (see Note 3A).

CCO’s operations generated net earnings from discontinued operations of $43 million for the three months ended March 31, 2007 compared to net losses from discontinued operations of $60 million for the same period in 2006. The change in earnings for 2007 compared to 2006 is primarily due to a $52 million after-tax increase in unrealized mark-to-market gains, primarily related to the increase in natural gas prices in 2007 compared to 2006, and the impact of the $39 million after-tax impairment of goodwill recorded in 2006. In addition, earnings increased due to realized mark-to-market gains due to favorable changes in gas and power prices and favorable margins on our Georgia contracts due to serving an increased load at higher rates.

CCO - DeSoto and Rowan Generation Facilities

On May 2, 2006, our board of directors approved a plan to divest of PVI’s subsidiaries, 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 a gross purchase price of approximately $80 million and $325 million, respectively. We used the proceeds from the sales to reduce debt and for other corporate purposes (See Note 3C).

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 of $67 million during the year ended December 31, 2006, on the sale of DeSoto and Rowan. Discontinued DeSoto and Rowan operations had combined losses of $3 million for the three months ended March 31, 2006.

58

GAS OPERATIONS

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 Corporation (Progress Fuels). Proceeds from the sale have been used primarily to reduce holding company debt and for other corporate purposes (See Note 3B).

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 $21 million for the three months ended March 31, 2006.

PROGRESS TELECOM, LLC

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

Based on the net proceeds associated with the sale and after consideration of minority interest, we recorded an estimated after-tax gain on disposal of $24 million during the three months ended March 31, 2006. Net loss from discontinued operations for PT LLC was $6 million for the three months ended March 31, 2006.

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 under long-term contracts with PEF. Dixie Fuels primarily transports coal from the lower Mississippi River to Progress Energy’s Crystal River Facility. We recorded an after-tax gain of $2 million on the sale of Dixie Fuels. The other fuels business is expected to be sold in 2007 (See Note 3E).

Net earnings from discontinued operations for Dixie Fuels and other fuels business were $1 million and $2 million for the three months ended March 31, 2007 and 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. 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 three months ended March 31, 2006, we recorded an estimated after-tax loss of $15 million for the sale of these assets. The remaining coal mining operations are expected to be sold in 2007 (See Note 3F).

Net losses from discontinued operations for the coal mining business were $4 million and $5 million for the three months ended March 31, 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’

59

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 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 and employee benefit and stock option plans are expected to fund capital expenditures, common stock dividends, and debt service for 2007. For the fiscal year 2007, we expect to realize an aggregate amount of approximately $130 million from the sale of stock through these plans.

We believe our internal and external liquidity resources will be sufficient to fund our current business plans. Risk factors associated with credit facilities and credit ratings are discussed in the “Risk Factors” section in the 2006 Form 10-K.

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

Historical for 2007 as 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 $173 million for the three months ended March 31, 2007, when compared to the corresponding period in the prior year. The decrease in operating cash flow was primarily due to a $64 million decrease from the change in accounts receivable, primarily at PEC, $65 million in premiums paid for derivative contracts (see Note 8A), and approximately $100 million related to income tax payments, largely driven by the sale of Gas. These impacts were partially offset by $47 million in net refunds of cash collateral previously paid to counterparties on derivative contracts at PEF.

INVESTING ACTIVITIES

Net cash used in investing activities increased by $161 million for the three months ended March 31, 2007, when compared to the corresponding period in the prior year. This is due primarily to a $165 million increase in capital expenditures for utility property and a $73 million decrease in proceeds from sales of discontinued operations and other assets, partially offset by a $76 million decrease in net purchases of short-term investments included in available-for-sale securities and other investments. 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 steam production projects, partially offset by lower spending at the Hines Unit 4 facility. 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 three months ended March 31, 2007, proceeds from sales of discontinued operations and other assets primarily included working capital adjustments for Gas and the sale of poles at Progress Telecommunications

60

Corporation. During the three months ended March 31, 2006, proceeds from sales of discontinued operations and other assets primarily included $70 million in cash proceeds from the sale of PT LLC (See Note 3D) and approximately $15 million in net cash proceeds from the sale of Dixie Fuels, net of cash divested (See Note 3E).

FINANCING ACTIVITIES

Net cash used in financing activities was $6 million for the three months ended March 31, 2007, compared to net cash used by financing activities of $508 million for the three months ended March 31, 2006, for a net decrease of $502 million. The change in cash used in financing activities was due primarily to 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, 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.

At December 31, 2006, we had 500 million shares of common stock authorized under our charter, of which approximately 256 million were outstanding. For the three months ended March 31, 2007 and 2006, respectively, we issued approximately 1.5 million shares and 0.7 million shares of common stock resulting in approximately $65 million and $28 million in proceeds. Included in these amounts were approximately 0.2 million shares and 0.3 million shares for proceeds of approximately $11 million and $14 million, respectively, to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan.

Future Liquidity and Capital Resources

At March 31, 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. It is expected 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 do not currently produce positive operating cash flow due to the difference in timing of when tax credits are recognized for financial reporting purposes and when tax credits are realized for tax purposes (See “Other Matters - Synthetic Fuels Tax Credits”).

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

Over the long term, meeting the anticipated load growth at the Utilities will require the Utilities to make significant capital investments. These anticipated capital investments are expected 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.

As of March 31, 2007, the current portion of our long-term debt was $404 million, which we expect to fund with cash from operations, proceeds from sales of assets, commercial paper borrowings and/or long-term debt issuances. See Note 3 for additional information on asset sales.

61

CREDIT RATING MATTERS

On March 15, 2007, Standard & Poor’s Rating Services (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 11 and in “Other Matters - Environmental Matters,” in 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.

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. 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 customers. PEC is asking the SCPSC to approve a $12 million increase in rates. PEC requested the increase for underrecovered fuel costs associated with prior year settlements and to meet future expected fuel costs. If approved, the increase would take effect July 1, 2007 and would increase residential electric bills by $1.76 per 1,000 kilowatt hours (kWhs), or 1.9 percent, for fuel cost recovery. A hearing on the matter has been scheduled by the SCPSC for June 13, 2007. We cannot predict the outcome of this matter.

PEF Pass-through Clause Cost Recovery

On August 10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the Florida Public Service Commission (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. The FPSC held a hearing on the matter from April 2 through April 5, 2007. We anticipate that the FPSC will reach a decision on this matter later in 2007. PEF believes that its coal procurement practices were prudent and that it has sound legal and factual arguments to successfully defend its position. We cannot predict the outcome of this matter.

On February 8, 2007, the FPSC issued an order approving PEF’s request for a need determination to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) 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 uprate costs should be recovered through the fuel recovery clause. On May 4, 2007, PEF filed amended testimony clarifying the scope of the project. The FPSC has scheduled an August 7, 2007, hearing on this matter. If PEF does not receive approval to recover the uprate costs through the fuel recovery clause, these costs will be recoverable through base rates, similar to other utility plant additions. We cannot predict the outcome of this matter.

62

Other Regulatory Matters

PEF filed a cost-recovery petition with the FPSC on April 30, 2007, to recover the current estimate of in-service cost of Hines Unit 4 through a base rate increase, as provided for by PEF’s base rate agreement. The base rate increase would be effective upon placing Hines Unit 4 in service, which PEF anticipates will be on December 1, 2007.

As discussed further in “Other Matters - Regulatory Environment”, new South Carolina energy legislation that became law on May 2, 2007 may impact our liquidity in the future. PEC cannot determine at this time how the final rules and regulation resulting from this legislation will impact its operations and financial condition.

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 March 31, 2007, we have issued $1.481 billion of guarantees for future financial or performance assurance, including $83 million at PEC, $2 million at PEF and approximately $900 million related to CCO. Included in this amount is $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries issued by the Parent (See Note 13). 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 Investors Service, Inc. (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 March 31, 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 approximate amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for Progress Energy’s nonregulated portfolio and power supply agreements, was $548 million at March 31, 2007. While we believe that we would be able to meet this obligation with cash or letters of credit, if we cannot, our financial condition, liquidity and results of operations will be materially and adversely impacted.

At March 31, 2007, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuels operations as discussed in Note 12A.

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

63

Contractual Obligations

As of March 31, 2007, our contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2006 Form 10-K.

OTHER MATTERS

Synthetic Fuels Tax Credits

Historically, we have had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Code (Section 29). The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied, including a requirement that the synthetic 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.

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 synthetic fuels than we have historically produced, should we choose to do so.

Total Section 29/45K credits generated through March 31, 2007 (including those generated by Florida Progress Corporation (Florida Progress) prior to our acquisition), were approximately $1.884 billion, of which $1.075 billion has been used to offset regular federal income tax liability, $798 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 $11 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 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, there was a 33 percent, or approximately $35 million, reduction of our synthetic fuels tax credits generated during 2006.

64

We estimate that the 2007 Threshold Price will be approximately $56 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 $7 lower than the corresponding daily New York Mercantile Exchange (NYMEX) prompt month settlement price for light sweet crude oil. Through March 31, 2007, the average NYMEX settlement price for light sweet crude oil was $58.23 per barrel, and as of March 31, 2007, the average NYMEX futures price for light sweet crude oil for the remainder of calendar year 2007 was $67.46 per barrel. This results in a weighted-average annual price for light sweet crude oil of approximately $65.25 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 $65.25 per barrel for the entire year in 2007, we currently estimate that the synthetic fuels tax credit amount for 2007 would be reduced by approximately 18 percent. Therefore, we reserved 18 percent or approximately $11 million of the $61 million of tax credits generated during the first quarter of 2007. The NYMEX price of oil for the remainder of 2007 would have to be $64.01 to have no reduction in value of tax credits generated during 2007 and would have to be $82.86 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 may cause quarterly adjustments to our results of operations and the amount of tax credits we record or reserve, either positive or negative, depending on current and futures oil prices at the end of the quarter, which impact the estimated weighted average annual price of oil for 2007.

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 3H, we disposed of our 100 percent ownership interest in Ceredo in March 2007. Our synthetic fuels production levels for 2007 remain uncertain because we cannot predict with any certainty the Annual Average Price of oil for 2007. We will continue to monitor the environment surrounding synthetic fuels production and will adjust our production as warranted by changing conditions. See Note 8 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

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 qualifying synthetic fuels, to an unrelated 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 will be received as we produce and sell qualified synthetic fuels on behalf of the buyer during 2007. Actual proceeds could differ based on actual production levels, which shall be determined by the buyer. The estimated production level of Ceredo is 2.8 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 from the disposal will be recognized over time as we produce and sell qualified synthetic fuels for the buyer. The reconfirmation private letter ruling request has been submitted to the IRS. Subsequent to the disposal, we remain the primary beneficiary of Ceredo and will continue to consolidate Ceredo in accordance with FIN 46R, but we anticipate recording a 100 percent minority interest. Consequently, we anticipate that there will be no net earnings impact. 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 the deferred gain. The ultimate resolution of these matters could result in adjustments to the gain on disposal in future periods. See Note 3H for additional discussion of this transaction and Note 12A 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 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

65

proceeds have become fixed or determinable and collectability is reasonably assured. 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 the gain recognition criteria are met, gains from selling interests in Colona will be deferred. It is possible that gains will be deferred to subsequent quarters, or to a subsequent calendar year, until there is persuasive evidence that no tax credit phase-out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters in a calendar year or to a subsequent calendar year. 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 March 31, 2007, a pre-tax gain on monetization of $12 million has been deferred. Based on the current level of oil prices, we cannot predict how much of this gain will be recognized in 2007. Beginning with the payment for the second quarter of 2006, the minority interest parties have elected to defer their cash payments in consideration of the idling of the synthetic fuels facilities at that time. In consideration of the resumption of limited synthetic fuels production in the fourth quarter of 2006, the minority interest parties made a partial payment in January 2007.

See Note 12B 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.

PEC and PEF continue to monitor developments impacting retail competition in their respective service territories. Movement toward deregulation throughout the nation has effectively ceased due to numerous factors including, but not limited to, California’s experience with retail deregulation. To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give retail customers 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.

The South Carolina legislature ratified new energy legislation on April 26, 2007, which became law on May 2, 2007. Key elements of the legislation include expansion of the annual fuel clause mechanism to include recovery of the costs of reagents (ammonia, limestone, etc.) used in the operation of PEC’s emissions control technologies. The legislation also includes provisions to provide cost-recovery mechanisms for upfront development costs associated with nuclear baseload generation, cost-recovery mechanisms for construction costs associated with nuclear or coal baseload generation and the ability to recover financing costs for new nuclear baseload generation through annual riders. PEC cannot determine at this time how the final rules and regulations resulting from this legislation will impact its operations and financial condition.

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.

Legal

We are subject to federal, state and local legislation and court orders. These matters are discussed in detail in Note 12B. This discussion identifies specific issues, the status of the issues, accruals associated with issue resolutions and our associated exposures.

66

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.

Our nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications (See Note 12B).

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.

We have announced that we are pursuing development of combined license (COL) applications. Our announcement is not a commitment to build a nuclear plant. It is a necessary step to keep open the option of building a plant or plants. On January 23, 2006, we announced that PEC selected a site at the Shearon Harris Nuclear Plant (Harris) to evaluate for possible future nuclear expansion. We currently expect to file the application for the COL for PEC’s Harris site in 2007. We have selected for PEC the Westinghouse Electric AP-1000 reactor design as the technology upon which to base the potential application submission. On December 12, 2006, we announced that PEF selected a site in Levy County, Fla., to evaluate for possible future nuclear expansion, and PEF expects to file the application for the COL in 2008. We have not selected the reactor design technology upon which to base the PEF potential application submission. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, construction activities could begin as early as 2010, and new plants could be online in late 2016. The NRC estimates that it will take approximately three to four years to review and process the COL applications.

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. The extent and timing of the NRC’s application of the case is unclear at this time, and the impact, if any, on PEC’s pending Harris operating license renewal application or any future PEC or PEF operating licensing proceedings cannot be predicted at this time.

A new nuclear plant may be eligible for the federal production tax credits and risk insurance provided by the Energy Policy Act of 2005 (EPACT). EPACT provides an annual tax credit of 1.8 cents per kWh for nuclear facilities for the first eight years of operation. The credit is limited to the first 6,000 MW of new nuclear generation in the United States and has an annual cap of $125 million per 1,000 MW of national MW capacity limitation allocated to the unit. In April 2006, the IRS provided interim guidance that the 6,000 MW of production tax credits generally will be allocated to new nuclear facilities 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 discussed above, in December 2006, the FPSC ordered new rules 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

67

requirements.

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 11). 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 11.

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 oxide (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. Estimated expenditures for the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) include the cost to install NOx controls under North Carolina’s and South Carolina’s programs to comply with the federal eight-hour ozone standard. The air quality controls installed to comply with the NOx SIP Call and Clean Smokestacks Act will result in a reduction of the costs to meet the CAIR requirements for our North Carolina units at PEC. We review our estimates on an ongoing basis. The timing and extent of the costs for future projects will depend upon final compliance strategies.

68

Progress Energy

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through March 31, 2007
NOx SIP Call	2002-2007	$345 - $350	$341
Clean Smokestacks Act	2002-2013	1,100 - 1,400	666
CAIR/CAMR/CAVR	2005-2018	1,100 - 2,000	59
Total air quality		2,545 - 3,750	1,066
Clean Water Act Section 316(b) (a)		-	1
North Carolina Groundwater Standard(b)		-	-
Total water quality		-	1
Total air and water quality		$2,545 - $3,750	$1,067

PEC

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through March 31, 2007
NOx SIP Call	2002-2007	$345 - $350	$341
Clean Smokestacks Act	2002-2013	1,100 - 1,400	666
CAIR/CAMR/CAVR	2005-2018	200 - 300	2
Total air quality		1,645 - 2,050	1,009
Clean Water Act Section 316(b) (a)		-	-
North Carolina Groundwater Standard(b)		-	-
Total water quality		-	-
Total air and water quality		$1,645 - $2,050	$1,009

PEF

Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable	Total Estimated Expenditures	Cumulative Spent through March 31, 2007
CAIR/CAMR/CAVR	2005-2018	$900 - $1,700	$57
Clean Water Act Section 316(b) (a)		-	1
Total air and water quality		$900 - $1,700	$58

^(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 related to an appeal of a decision issued by the U.S. Court of Appeals for the Fourth Circuit, in a case involving an unaffiliated utility. 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 there is an emissions increase.

69

On March 17, 2006, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) 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. Circuit Court 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. Circuit Court’s 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. Circuit Court 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, South Carolina and Georgia, to further reduce NOx emissions. The NOx SIP Call is not applicable to Florida. Further technical analysis and rulemaking may result in requirements for additional controls at some units. Increased O&M expenses relating to the NOx SIP Call are not expected to be material to our or PEC’s results of operations.

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. 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. See further discussion about the Clean Smokestacks Act in Note 4A.

Two of PEC’s largest coal-fired generation plants (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. 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 11B).

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

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

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

PEF has joined a coalition of Florida utilities that has filed a challenge to the CAIR as it applies to Florida. A petition for reconsideration and stay and a petition for judicial review of the CAIR were filed on July 11, 2005. On October 27, 2005, the D.C. Circuit Court issued an order granting the motion for stay of the proceedings. On December 2, 2005, the EPA announced a reconsideration of four aspects of the CAIR, including its applicability to Florida. On March 16, 2006, the EPA denied all pending reconsiderations, allowing the challenge to proceed. While

70

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 by November 17, 2006, to adopt mercury rules implementing the CAMR that are subject to review and approval by the EPA. A number of states, including North Carolina, South Carolina and Florida, did not meet the deadline for submission to the EPA. The EPA has indicated it will defer action. The three states in which the Utilities operate formally proposed mercury regulations. North Carolina and Florida have submitted their state rules to the EPA. The North Carolina Environmental Management Commission adopted the North Carolina rule on November 9, 2006. North Carolina's rule adopts 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. South Carolina’s rule is subject to final approval by the South Carolina legislature. On June 29, 2006, the Florida Environmental Regulation Commission adopted the Florida CAMR. The Florida rule adopts the EPA’s cap-and-trade approach with changes to the EPA’s mercury allowance allocations in the rule’s first phase. 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. Circuit Court 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.

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

71

estimated capital costs expected to be spent through 2016, to plan, design, build and install pollution control equipment at our Anclote and Crystal River plants. On October 27, 2006, PEF filed supplemental testimony to inform the FPSC that estimated capital costs for the series of compliance alternatives are likely to increase by approximately 25 percent to 30 percent from the estimates filed in March 2006, primarily due to the higher cost of labor and construction materials, such as concrete and steel, and refinement of cost and scope estimates for the current projects. 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. 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.

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. Circuit Court 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 U.S. Circuit Court of Appeals for the District of Columbia Circuit 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.

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

72

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 March 20, 2007, the EPA directed the Regional Administrators to consider the July 2004 rule as suspended. No formal notice has been published in the Federal Register. 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.

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 to address global climate change that would regulate CO₂ and other greenhouse gases. Reductions in CO₂ emissions to the levels specified by the Kyoto Protocol and some additional proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from 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 voluntary action on this important issue as part of our commitment to environmental stewardship and responsible corporate citizenship.

In a decision issued July 15, 2005, the D.C. Circuit Court 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.

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.

New Accounting Standards

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

73

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 decreased $27 million for the three months ended March 31, 2007, when compared to the corresponding period in the prior year. The decrease in operating cash flow was primarily due to a $54 million decrease from the change in accounts receivable, principally driven by the timing of wholesale sales, and a $64 million decrease from payables, primarily related to the timing of settlements with affiliates. These impacts were largely offset by approximately $100 million in tax payments paid in the prior year.

Cash used in investing activities increased $24 million for the three months ended March 31, 2007, when compared to the corresponding period in the prior year, primarily due to a $57 million increase in capital expenditures for utility property additions, primarily related to an increase in spending for compliance with the Clean Smokestacks Act, partially offset by a $24 million decrease in note receivable from affiliate.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

As of March 31, 2007, PEC’s off-balance sheet arrangements and contractual obligations have not changed materially from what was reported in the 2006 Form 10-K.

Market Risk and Derivatives

Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 8 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

Contractual Obligations

As of March 31, 2007, PEC’s contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2006 Form 10-K.

OTHER MATTERS

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

74

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

Cash provided by operating activities increased $96 million for the three months ended March 31, 2007, when compared to the corresponding period in the prior year. The increase was primarily due to higher coal inventory purchases in the prior year of $54 million, $47 million in net refunds of cash collateral previously paid to counterparties on derivative contracts, and $53 million related to lower income tax payments. These impacts were partially offset by a $46 million decrease in the recovery of fuel costs.

Cash used in investing activities increased $58 million for the three months ended March 31, 2007, when compared to the corresponding period in the prior year. The increase in cash used in investing activities was primarily due to a $99 million increase in capital expenditures for utility property additions, primarily due to repowering the Bartow plant to more efficient natural gas-burning technology and steam production projects, partially offset by lower spending at the Hines Unit 4 facility; and a $17 million increase in nuclear fuel additions. These impacts were partially offset by a $55 million decrease in net purchases of short-term investments included in available-for-sale securities and other investments. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

See Progress Energy’s MD&A, “Liquidity and Capital Resources” for a discussion of PEF’s financing activities.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

As of March 31, 2007, PEF’s off-balance sheet arrangements and contractual obligations have not changed materially from what was reported in the 2006 Form 10-K.

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

Contractual Obligations

As of March 31, 2007, PEF’s contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2006 Form 10-K.

OTHER MATTERS

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

75

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 8).

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 March 31, 2007, has changed from December 31, 2006. The total notional amount of fixed rate long-term debt at March 31, 2007, was $7.830 billion, with an average interest rate of 6.26% and fair market value of $8.144 billion. The total notional amount of variable rate long-term debt at March 31, 2007, was $1.411 billion, with an average interest rate of 4.39% and fair market value of $1.411 billion.

In addition to our variable rate long-term debt, we typically have commercial paper and/or loans outstanding under our RCA facilities, which are also exposed to floating interest rates. At March 31, 2007, approximately 16.9 percent of consolidated debt, including interest rate swaps, was in floating rate mode compared to 15.8 percent at the end of 2006.

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

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

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

76

In accordance with SFAS No. 133, interest rate derivatives that qualify as hedges are separated into one of two categories, cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest rate changes.

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

Cash Flow Hedges

At March 31, 2007 and December 31, 2006, the Utilities had a combined $150 million notional and $100 million notional, respectively, 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 March 31, 2007 and December 31, 2006.

Cash Flow Hedges (dollars in millions)	Notional Amount	Pay	Receive(a)	Fair Value	Exposure(b)
PEC
Risk hedged at March 31, 2007:
Anticipated 10-year debt issue(c)	$50	5.61%	3-month LIBOR	$(2)	$(1)
Risk hedged at December 31, 2006:
Anticipated 10-year debt issue(c)	$50	5.61%	3-month LIBOR	$(1)	$(1)
PEF
Risk hedged at March 31, 2007:
Anticipated 10-year debt issue(c)	$50	5.61%	3-month LIBOR	$(2)	$(1)
Anticipated 10-year debt issue(d)	$50	5.20%	3-month LIBOR	-	(1)
Total	$100	5.40%		$(2)	$(2)
Risk hedged at December 31, 2006:
Anticipated 10-year debt issue(c)	$50	5.61%	3-month LIBOR	$(1)	$(1)

^(a)   3-month LIBOR rate was 5.35% at March 31, 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 hedges mature on October 1, 2017, and require mandatory cash settlement on October 1, 2007.

^(d)   Anticipated 10-year debt issue hedge matures on June 1, 2017, and requires mandatory cash settlement on June 1, 2007.

PEF entered into a $50 million forward starting swap on February 16, 2007, to mitigate exposure to interest rate risk in anticipation of future debt issuances.

77

Fair Value Hedges

At March 31, 2007 and December 31, 2006, the Parent had $50 million notional of fixed rate debt swapped to floating rate debt. Under terms of these swap agreements, we will receive a fixed rate and pay a floating rate based on 3-month LIBOR. At March 31, 2007 and December 31, 2006, the Utilities had no open interest rate fair value hedges.

Fair Value Hedges (dollars in millions)
Progress Energy	Notional Amount	Receive	Pay(a)	Fair Value	Exposure (b)
Risk hedged at March 31, 2007
7.10% Notes due 3/1/2011	$50	4.65%	3-month LIBOR	$(1)	$-
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 5.35% at March 31, 2007 and 5.36% as of December 31, 2006.

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

MARKETABLE SECURITIES PRICE RISK

At March 31, 2007 and December 31, 2006, the fair value of our nuclear decommissioning trust funds was $1.307 billion and $1.287 billion, respectively, including $749 million and $735 million, respectively, for PEC and $558 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 March 31, 2007 and December 31, 2006, the fair value of CVOs was $31 million and $32 million, respectively. A hypothetical 10 percent decrease in the March 31, 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 the “Other Matters” section of Item 2.

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.

As discussed in Note 3, on March 9, 2007, we entered into two separate agreements to dispose of substantially all of PVI’s remaining CCO physical and commercial assets and on October 2, 2006, we sold Gas. Due to these divestiture plans, 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. This increased our exposure to

78

potential earnings impacts in the near term from changes in commodity market prices.

At March 31, 2007 and December 31, 2006, derivative assets of $178 million and $107 million, respectively, were included in assets of discontinued operations and derivative liabilities of $10 million and $31 million, respectively, were included in liabilities of discontinued operations on the Consolidated Balance Sheets. For the three months ending March 31, 2007, gains from derivative instruments of $59 million were included in discontinued operations, net of tax on the Consolidated Statement of Income. For the three months ending March 31, 2006, net gains and losses from derivative instruments of discontinued operations were not material. For the three months ending March 31, 2007 and 2006, there were no reclassifications to earnings due to discontinuance of the related cash flow hedges.

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments, which are not eligible for recovery from ratepayers. As described above, at March 31, 2007, a portion of these derivative commodity instruments are included in discontinued operations. At December 31, 2006, all of these derivative commodity instruments are included in discontinued operations. 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. A decrease of 10 percent in the market prices of energy commodities from their March 31, 2007, levels would decrease after-tax earnings by approximately $87 million, including a $79 million decrease in after-tax earnings of 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 physical purchases of natural gas and power to which the hedges relate. Additionally, our derivative commodity portfolio is managed to complement the physical transaction portfolio, reducing overall risk within set limits. Therefore, the potential impact to earnings of discontinued operations 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 8 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.

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. PEC and PEF did not have material outstanding positions in such contracts at March 31, 2007 and December 31, 2006, other than those receiving regulatory accounting treatment, as discussed below.

At March 31, 2007, the fair value of PEC’s derivative instruments was recorded as a $4 million long-term derivative asset position included in other assets and deferred debits on the Consolidated Balance Sheet. At December 31, 2006, PEC did not have material outstanding positions in such contracts.

At March 31, 2007, the fair value of PEF’s derivative instruments was recorded as a $2 million short-term derivative asset position included in derivative assets, a $17 million long-term derivative asset position included in

79

other assets and deferred debits, a $31 million short-term derivative liability position included in other current liabilities, and an $11 million long-term derivative liability position included in other liabilities and deferred credits on the Consolidated 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 other current liabilities and a $36 million long-term derivative liability position included in other liabilities and deferred credits on the Consolidated Balance Sheet.

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 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 3H, 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. At March 31, 2007, the fair value of these contracts was recorded as a $110 million short-term derivative asset position, including $37 million at Ceredo. The fair value of these contracts was included in derivative assets on the Consolidated Balance Sheet. During the three months ended March 31, 2007, we recorded net pre-tax gains of $45 million in diversified business revenues related to these contracts. We anticipate that future mark-to-market changes on the Ceredo portion of the derivatives contracts will have no net earnings impact. 

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 March 31, 2007, we and the Utilities did not have material outstanding positions in such contracts.

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.

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).

80

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 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 March 31, 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 March 31, 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 March 31, 2007, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

81

PART II.OTHER INFORMATION

Item 1.Legal Proceedings

Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 12B).

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. There have been no material changes to the risk factors as set forth in the 2006 Form 10-K.

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

RESTRICTED STOCK AWARDS

(a)   Securities Delivered. On March 12, 2007, 7,000 restricted shares of our common stock were granted to a key employee pursuant to the terms of the Progress Energy 2002 Equity Incentive Plan (EIP), which was approved by the Progress Energy’s shareholders on May 8, 2002. Section 9 of the EIP provides for the granting of Restricted Stock by the Organization and Compensation Committee of the Board of Directors, (the Committee) to key employees, including our Affiliates or any successor, and to our outside directors. The shares of common stock delivered pursuant to the EIP were acquired in market transactions directly for the accounts of the recipient and do not represent newly issued shares of Progress Energy.

(b)   Underwriters and Other Purchasers. No underwriters were used in connection with the delivery of our common stock described above. The shares were delivered to a certain key employee. The EIP defines "key employee" as an officer or other employee of Progress Energy who is selected for participation in the EIP.

(c)   Consideration. The shares of our common stock were delivered to provide an incentive to the employee recipient to exert her utmost efforts on Progress Energy’s behalf and thus enhance our performance while aligning the employee's interest with those of our shareholders.

(d)   Exemption from Registration Claimed. The common shares described in this Item were delivered on the basis of an exemption from registration under Section 4(2) of the Securities Act of 1933. Receipt of the shares of our common stock required no investment decision on the part of the recipient.

PERFORMANCE SHARE SUB-PLAN AWARD PAYOUT

(a)   Securities Delivered. On January 9, 2007, 19 shares of our common stock were delivered to a former employee pursuant to the terms of the 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.

82

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

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

ISSUER PURCHASES OF EQUITY SECURITIES FOR FIRST QUARTER OF 2007

Period	(a) Total Number of Shares (or Units) Purchased (1)	(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)
January 1 - January 31	31,807 (2)	$47.40	N/A	N/A
February 1 - February 28	-	-	N/A	N/A
March 1 - March 31	36,000 (3)	$48.56	N/A	N/A
Total	67,807	$48.02	N/A	N/A

   (1) As of March 31, 2007, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

 (2) The plan administrator purchased 31,807 shares of our common stock at an average price of $47.40 in open-market transactions to meet share delivery obligations under the 401(k).

(3) The plan administrator purchased 29,000 shares of our common stock at an average price of $48.32 in open market transactions to meet share delivery obligations under our 401(k). Open market transactions also were executed to purchase 7,000 shares of our common stock at an average price of $49.54 in connection with a restricted stock award that was granted to a certain employee pursuant to the terms of our Equity Incentive Plan.

Item 5.Other Information

Effective May 8, 2007, each of Robert B. McGehee, William D. Johnson, Peter M. Scott III, Clayton S. Hinnant, Fredrick N. Day IV and John R. McArthur entered into Employment Agreements (the “Employment Agreements” and each an “Employment Agreement”) with our subsidiaries for which they are employed respectively. The Employment Agreements replace the previous employment agreements in effect for each of these officers, except that, (i) with respect to Mr. Scott, the Amendment to Employment Agreement dated August 5, 2005 remains in force in accordance with its terms and (ii) with respect to Mr. Hinnant, the Selected Executives Supplemental Deferred Compensation Program Agreement remains in force in accordance with its terms, both of which have been previously filed with the SEC.

The initial term of each Employment Agreement expires on December 31, 2009, with the term automatically extending by an additional year on January 1 of each year. We can choose not to extend an Employment Agreement upon providing notice of such nonrenewal to the applicable officer at least 60 days prior to the automatic extension date. Except for the application of previously granted years of service credit to our post-employment health and welfare benefit plans as discussed below, the Employment Agreements do not effect the compensation, benefits or incentive targets payable to the applicable officers, and such programs remain as previously disclosed in the our Proxy Statement filed on March 30, 2007.

With respect to Messrs. McGehee, Johnson and Scott, the Employment Agreements specify that the years of service

83

credit we previously granted to them for purposes of determining eligibility and benefits in the Supplemental Senior Executive Retirement Plan will also be applicable for purposes of determining eligibility and benefits in our post-employment health and welfare benefit plans.

Each Employment Agreement provides that if the applicable officer is terminated without cause or is constructively terminated (as defined in Paragraph 8(a)(i) of the agreement), then the officer will receive (i) severance equal to 2.99 times the officer’s then-current base salary and (ii) reimbursement for the costs of continued coverage under certain of our health and welfare benefit plans for a period of up to 18 months.

The Employment Agreements each contain restrictive covenants imposing non-competition obligations, restricting solicitation of employees and protecting our confidential information and trade secrets for specified periods if the applicable officer is terminated without cause or otherwise becomes eligible for the benefits available under the agreement.

The above description of the Employment Agreements is qualified by reference to the Form of Executive Employment Agreement, which is attached hereto as Exhibit 10 and is incorporated by reference in its entirety.

Item 6.Exhibits

(a) Exhibits

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

84

SIGNATURES

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

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY
	FLORIDA POWER CORPORATION
Date: May 8, 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
	Florida Power Corporation

85