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, 2006

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______.

Commission File Number	Exact name of registrants as specified in their charters, states of incorporation, addresses of principal executive offices, and telephone numbers	I.R.S. Employer Identification Number
1-15929	Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina	56-2155481
1-3382	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina	56-0165465
1-3274	Florida Power Corporation d/b/a Progress Energy Florida, Inc. 100 Central Avenue St. Petersburg, Florida 33701 Telephone (727) 820-5151 State of Incorporation: Florida	59-0247770

NONE

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

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, Inc. (Progress Energy)	Large accelerated filer	x	Accelerated filer	o	Non-accelerated filer	o
Carolina Power & Light Company (PEC)	Large accelerated filer	o	Accelerated filer	o	Non-accelerated filer	x
Florida Power Corporation (PEF)	Large accelerated filer	o	Accelerated filer	o	Non-accelerated filer	x

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

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

Indicate the number of shares outstanding of each registrants’ classes of common stock, as of the latest practicable date. At April 30, 2006, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	252,970,295
PEC	Common Stock (Without Par Value)	159,608,055 (all of which were held directly by Progress Energy, Inc.)
PEF	Common Stock (Without par value)	100 (all of which were held indirectly by Progress Energy, Inc.)

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

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

2

PROGRESS ENERGY, INC., PROGRESS ENERGY CAROLINAS, INC.

AND PROGRESS ENERGY FLORIDA, INC.

FORM 10-Q - For the Quarter Ended March 31, 2006

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Interim Financial Statements:

Progress Energy, Inc. (Progress Energy)

Carolina Power & Light Company

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

Florida Power Corporation

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

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

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

Item 6. Exhibits

Signatures

3

GLOSSARY OF TERMS

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

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

TERM	DEFINITION
2005 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2005
401(k)	Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC	Allowance for funds used during construction
AHI	Affordable housing investment
APB	Accounting Principles Board
APB No. 25	Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”
APB No. 28	Accounting Principles Board Opinion No. 28, “Interim Financial Reporting”
ARO	Asset retirement obligation
Annual Average Price	Average wellhead price per barrel for unregulated domestic crude oil for the year
BART	Best Available Retrofit Technology
Base Rate Settlement	Settlement reached with the FPSC on September 7, 2005 on PEF’s base rate proceeding
Bcf	Billion cubic feet
Broad River	Broad River LLC’s Broad River Facility
Brunswick	Brunswick Nuclear Plant
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Smokestacks Act	North Carolina Clean Smokestacks Act, enacted in June 2002
Coal	Coal terminals and marketing operations that blend and transload coal as part of the transportation network for coal delivery
Coal and Synthetic Fuel	Business segment primarily engaged in synthetic fuel production and sales operations, the operation of synthetic fuel facilities for third parties and coal terminal services
the Code	Internal Revenue Code
CO2	Carbon dioxide
COL	Combined license
Colona	Colona Synfuel Limited Partnership, LLLP
Corporate	Collectively, the Parent, PESC and consolidation entities
Corporate and Other	Corporate and Other segment includes Corporate as well as other nonregulated business areas
CR3	Crystal River Unit No. 3 Nuclear Plant
CVO	Contingent value obligation
DeSoto	DeSoto County Generating Co., LLC
DIG Issue C20	FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”
Dixie Fuels	Dixie Fuels Limited
DOE	United States Department of Energy
Earthco	Four wholly owned coal-based solid synthetic fuel limited liability companies
ECRC	Environmental Cost Recovery Clause

4

EIA	Energy Information Agency
EIP	Progress Energy 2002 Equity Incentive Plan
EITF	Emerging Issues Task Force
EITF 03-1	Emerging Issues Task Force No. 03-1, “The Meaning of Other-Than-Temporary Impairments and Its Application to Certain Investments”
EITF 03-4	Emerging Issues Task Force No. 03-4, “Determining the Classification and Benefit Attribution Method for a ‘Cash Balance’ Pension Plan”
EITF 04-5	Emerging Issues Task Force No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights”
EMCs	Electric Membership Cooperatives
Energy Delivery	Distribution operations of the Utilities
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company
FIN 45	FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIN 46R	FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51”
FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143”
Florida Global Case	U.S. Global LLC v. Progress Energy, Inc. et al
Florida Progress or FPC	Florida Progress Corporation, one of our wholly owned subsidiaries
FPSC	Florida Public Service Commission
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Georgia Power	Georgia Power Company, a subsidiary of Southern Company
Georgia Region	Reporting unit consisting of our Effingham, Monroe, Walton and Washington nonregulated generation plants in service
GITS	Georgia Integrated Transmission System
Global	U.S. Global LLC
Gulfstream	Gulfstream Gas System, L.L.C.
Harris	Shearon Harris Nuclear Plant
IBEW	International Brotherhood of Electrical Workers
IRS	Internal Revenue Service
Jackson	Jackson Electric Membership Corporation
kV	Kilovolt
kVA	Kilovolt-ampere
kW	Kilowatt
kWh	Kilowatt-hour
Level 3	Level 3 Communications, Inc.
LIBOR	London Inter Bank Offering Rate
MACT	Maximum Achievable Control Technology
MDC	Maximum Dependable Capability
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
MW	Megawatt
MWh	Megawatt-hour
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCNG	North Carolina Natural Gas Corporation

5

NSR	New Source Review requirement by EPA
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
the Notes Guarantee	Florida Progress’ full and unconditional guarantee of the Subordinated Notes
NOx	Nitrogen Oxide
NOx SIP Call	EPA rule which requires 22 states including North and South Carolina (but excluding Florida) to further reduce nitrogen oxide emissions.
NRC	United States Nuclear Regulatory Commission
Nuclear Waste Act	Nuclear Waste Policy Act of 1982
NYMEX	New York Mercantile Exchange
OCI	Other comprehensive income as defined by GAAP
O&M	Operation and maintenance expense
OPEB	Postretirement benefits other than pensions
P11	Intercession City Unit P11
the Parent	Progress Energy, Inc. holding company on an unconsolidated basis
PEC	Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company
PEF	Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation
PESC	Progress Energy Service Company, LLC
the Phase-out Price	Price per barrel of unregulated domestic crude oil at which Section 29/45K tax credits are fully eliminated
Power Agency	North Carolina Eastern Municipal Power Agency
Preferred Securities	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Energy	Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants	The individual reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
Progress Fuels	Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail	Progress Rail Services Corporation
Progress Ventures	Business segment primarily engaged in nonregulated energy generation, energy marketing activities and natural gas drilling and production
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
PTC	Progress Telecommunications Corporation
PT LLC	Progress Telecom, LLC
PUHCA	Public Utility Holding Company Act of 1935, as amended
PURPA	Public Utilities Regulatory Policies Act of 1978
PVI	Progress Energy Ventures, Inc. (formerly referred to as Progress Ventures, Inc.)
PWC	Public Works Commission of the City of Fayetteville, North Carolina
PWR	Pressurized water reactor
QF	Qualifying facility
RCA	Revolving credit agreement
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	Robinson Nuclear Plant
ROE	Return on equity
Rowan	Rowan County Power, Inc., 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

6

Section 29	Section 29 of the Internal Revenue Service Code
Section 29/45K	General business tax credits earned after December 31, 2005 for synthetic fuel production activities in accordance with Section 29
Section 45K	General business tax credit
(See Note/s “#”)	For all sections, this is a cross-reference to the Combined Notes to the Unaudited Interim Financial Statements contained in PART I, Item 1
S&P	Standard & Poor’s Rating Services
SFAS	Statement of Financial Accounting Standards
SFAS No. 5	Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”
SFAS No. 71	Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 87	Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions”
SFAS No. 109	Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
SFAS No. 115	Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”
SFAS No. 123	Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”
SFAS No. 123R	Statement of Financial Accounting Standards No. 123R, “Share-Based Payment”
SFAS No. 131	Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information”
SFAS No. 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative and Hedging Activities”
SFAS No. 138	Statement of Financial Accounting Standards No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133”
SFAS No. 142	Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 143	Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 144	Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS No. 148	Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123”
SFAS No. 149	Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
SFAS No. 150	Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”
SNG	Southern Natural Gas Company
SO2	Sulfur dioxide
SPC	Southern Power Company, a subsidiary of Southern Company
SRS	Strategic Resource Solutions Corp.
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
the Threshold Price	Price per barrel of unregulated domestic crude oil at which Section 29/45K tax credits begin to be reduced
the Trust	FPC Capital I, a wholly owned subsidiary of Florida Progress
the Utilities	Collectively, PEC and PEF
Winchester Production	Winchester Production Company, Ltd., an indirectly owned subsidiary of Progress Fuels Corporation

7

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

In this combined report, each of the Progress Registrants makes forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-Q that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In addition, examples of forward-looking statements discussed in this Form 10-Q include, but are not limited to, statements made in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” including, but not limited to, statements under the sub-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 fuel facilities and environmental matters.

Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and the recently enacted Energy Policy Act of 2005; the financial resources and capital needed to comply with environmental laws and our ability to recover eligible costs under cost recovery clauses; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered or stranded costs; weather conditions that directly influence the production, delivery and demand for electricity; the ability to recover through the regulatory process costs associated with future significant weather events; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding impact on our commercial and industrial customers; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the impact on our facilities and businesses from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the anticipated future need for additional baseload generation in our regulated service territories and the accompanying regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the Progress Registrants’ ability to maintain their current credit ratings and the impact on the Progress Registrants’ financial condition and ability to meet their cash and other financial obligations in the event their credit ratings are downgraded below investment grade; the impact that increases in leverage may have on each of the Progress Registrants; the impact of derivative contracts used in the normal course of business; the investment performance of our pension and benefit plans; the Progress Registrants’ ability to control costs, including pension and benefit expense, and achieve our cost-management targets for 2007; our continued ability to use Internal Revenue Code Section 29/45K (Section 29/45K) tax credits related to our coal-based solid synthetic fuel businesses; the impact that future crude oil prices may have on the value of our Section 29/45K tax credits; our ability to manage the risks involved with the operation of nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history of such plants; the ability to manage the risks associated with our energy marketing operations, including potential impairment charges caused by adverse changes in market or business conditions; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact our nonreporting subsidiaries.

These and other risk factors are disclosed in the Progress Registrants’ periodic filings with the United States Securities and Exchange Commission (SEC). Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors section of the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2005 (2005 Form 10-K), which was filed with the SEC on March 10, 2006 and are updated for material changes, if any, in PART II, Item 1A of this Form 10-Q. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on the Progress Registrants.

8

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PROGRESS ENERGY, INC.

 CONSOLIDATED INTERIM FINANCIAL STATEMENTS

March 31, 2006

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
(in millions except per share data)
Three Months Ended March 31	2006			2005
Operating revenues
Electric	$	1,985		$	1,783
Diversified business		448			370
Total operating revenues		2,433			2,153
Operating expenses
Utility
Fuel used in electric generation		690			550
Purchased power		229			198
Operation and maintenance		416			406
Depreciation and amortization		228			208
Taxes other than on income		119			117
Other		(2	)		-
Diversified business
Cost of sales		405			365
Depreciation and amortization		36			32
Impairment of goodwill		64			-
Gain on the sale of assets		(7	)		(4	)
Other		23			29
Total operating expenses		2,201			1,901
Operating income		232			252
Other income (expense)
Interest income		17			4
Other, net		(2	)		1
Total other income		15			5
Interest charges
Net interest charges		182			165
Allowance for borrowed funds used during construction		(2	)		(3	)
Total interest charges, net		180			162
Income from continuing operations before income tax and minority interest		67			95
Income tax expense (benefit)		13			(1	)
Income from continuing operations before minority interest		54			96
Minority interest in subsidiaries’ (income) loss, net of tax		(7	)		8
Income from continuing operations		47			104
Discontinued operations, net of tax		(2	)		(11	)
Net income	$	45		$	93
Average common shares outstanding - basic		249			244
Basic earnings per common share
Income from continuing operations	$	0.19		$	0.43
Discontinued operations, net of tax		(0.01	)		(0.05	)
Net income	$	0.18		$	0.38
Diluted earnings per common share
Income from continuing operations	$	0.19		$	0.43
Discontinued operations, net of tax		(0.01	)		(0.05	)
Net income	$	0.18		$	0.38
Dividends declared per common share	$	0.605		$	0.590

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

9

PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions)	March 31, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	23,035		$	22,940
Accumulated depreciation		(9,713	)		(9,602	)
Utility plant in service, net		13,322			13,338
Held for future use		12			12
Construction work in progress		964			813
Nuclear fuel, net of amortization		272			279
Total utility plant, net		14,570			14,442
Current assets
Cash and cash equivalents		263			606
Short-term investments		217			191
Receivables, net		1,014			1,099
Inventory		908			859
Deferred fuel cost		474			602
Deferred income taxes		2			50
Assets of discontinued operations		86			225
Prepayments and other current assets		242			209
Total current assets		3,206			3,841
Deferred debits and other assets
Regulatory assets		852			854
Nuclear decommissioning trust funds		1,175			1,133
Diversified business property, net		1,792			1,798
Miscellaneous other property and investments		482			476
Goodwill		3,655			3,719
Intangibles, net		295			302
Other assets and deferred debits		461			477
Total deferred debits and other assets		8,712			8,759
Total assets	$	26,488		$	27,042
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 253 and 252 million shares issued and outstanding, respectively	$	5,614		$	5,571
Unearned ESOP shares (2 million and 3 million shares, respectively)		(54	)		(63	)
Accumulated other comprehensive loss		(90	)		(104	)
Retained earnings		2,527			2,634
Total common stock equity		7,997			8,038
Preferred stock of subsidiaries - not subject to mandatory redemption		93			93
Minority interest		58			43
Long-term debt, affiliate		270			270
Long-term debt, net		10,178			10,176
Total capitalization		18,596			18,620
Current liabilities
Current portion of long-term debt		109			513
Accounts payable		542			676
Interest accrued		164			208
Dividends declared		153			152
Short-term obligations		254			175
Customer deposits		207			200
Liabilities of discontinued operations		33			87
Other current liabilities		743			871
Total current liabilities		2,205			2,882
Deferred credits and other liabilities
Noncurrent income tax liabilities		265			296
Accumulated deferred investment tax credits		160			163
Regulatory liabilities		2,568			2,527
Asset retirement obligations		1,261			1,249
Accrued pension and other benefits		893			870
Other liabilities and deferred credits		540			435
Total deferred credits and other liabilities		5,687			5,540
Commitments and contingencies (Note 13)
Total capitalization and liabilities	$	26,488		$	27,042

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	2006			2005
Operating activities
Net income	$	45		$	93
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax		2			11
Impairment of goodwill		64			-
Depreciation and amortization		294			268
Deferred income taxes		35			13
Investment tax credit		(3	)		(3	)
Tax levelization		16			3
Deferred fuel cost		134			19
Other adjustments to net income		72			50
Cash provided (used) by changes in operating assets and liabilities:
Receivables		154			-
Inventories		(58	)		(45	)
Prepayments and other current assets		(5	)		13
Accounts payable		(109	)		46
Other current liabilities		(180	)		(156	)
Regulatory assets and liabilities		(2	)		(57	)
Other operating activities		41			(23	)
Net cash provided by operating activities		500			232
Investing activities
Gross utility property additions		(304	)		(267	)
Diversified business property additions		(47	)		(40	)
Nuclear fuel additions		(52	)		(64	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		103			398
Purchases of available-for-sale securities and other investments		(538	)		(2,012	)
Proceeds from sales of available-for-sale securities and other investments		522			1,853
Other investing activities		(11	)		(12	)
Net cash used in investing activities		(327	)		(144	)
Financing activities
Issuance of common stock		28			60
Proceeds from issuance of long-term debt, net		397			495
Net increase in short-term indebtedness		79			7
Retirement of long-term debt		(801	)		(216	)
Dividends paid on common stock		(151	)		(145	)
Other financing activities		(60	)		(38	)
Net cash (used in) provided by financing activities		(508	)		163
Cash used by discontinued operations
Operating activities		(5	)		(18	)
Investing activities		(3	)		(9	)
Financing activities		-			-
Net (decrease) increase in cash and cash equivalents		(343	)		224
Cash and cash equivalents at beginning of period		606			56
Cash and cash equivalents at end of period	$	263		$	280

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, 2006

UNAUDITED CONSOLIDATED STATEMENTS of INCOME
(in millions)
Three Months Ended March 31	2006			2005
Operating revenues	$	978		$	935
Operating expenses
Fuel used in electric generation		296			248
Purchased power		64			67
Operation and maintenance		256			224
Depreciation and amortization		126			129
Taxes other than on income		46			46
Other		1			-
Total operating expenses		789			714
Operating income		189			221
Other income (expense)
Interest income		7			2
Other, net		(1	)		1
Total other income		6			3
Interest charges
Interest charges		57			52
Allowance for borrowed funds used during construction		(1	)		(1	)
Total interest charges, net		56			51
Income before income tax		139			173
Income tax expense		53			57
Net income		86			116
Preferred stock dividend requirement		1			1
Earnings for common stock	$	85		$	115

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, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	14,041		$	13,994
Accumulated depreciation		(6,182	)		(6,120	)
Utility plant in service, net		7,859			7,874
Held for future use		3			3
Construction work in progress		483			399
Nuclear fuel, net of amortization		201			203
Total utility plant, net		8,546			8,479
Current assets
Cash and cash equivalents		105			125
Short-term investments		136			191
Receivables, net		440			518
Receivables from affiliated companies		19			24
Inventory		458			451
Deferred fuel cost		243			261
Prepayments and other current assets		25			20
Total current assets		1,426			1,590
Deferred debits and other assets
Regulatory assets		410			421
Nuclear decommissioning trust funds		664			640
Miscellaneous other property and investments		193			188
Other assets and deferred debits		179			184
Total deferred debits and other assets		1,446			1,433
Total assets	$	11,418		$	11,502
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$	1,996		$	1,981
Unearned ESOP common stock		(54	)		(63	)
Accumulated other comprehensive loss		(119	)		(120	)
Retained earnings		1,320			1,320
Total common stock equity		3,143			3,118
Preferred stock - not subject to mandatory redemption		59			59
Long-term debt, net		3,667			3,667
Total capitalization		6,869			6,844
Current liabilities
Accounts payable		212			247
Payables to affiliated companies		62			73
Notes payable to affiliated companies		10			11
Interest accrued		62			73
Short-term obligations		52			73
Customer deposits		54			52
Taxes accrued		8			100
Other current liabilities		256			255
Total current liabilities		716			884
Deferred credits and other liabilities
Noncurrent income tax liabilities		803			814
Accumulated deferred investment tax credits		131			133
Regulatory liabilities		1,241			1,196
Asset retirement obligations		964			949
Accrued pension and other benefits		526			511
Other liabilities and deferred credits		168			171
Total deferred credits and other liabilities		3,833			3,774
Commitments and contingencies (Note 13)
Total capitalization and liabilities	$	11,418		$	11,502

See Notes to PEC Consolidated Interim Financial Statements.

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CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Three Months Ended March 31	2006			2005
Operating activities
Net income	$	86		$	116
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		147			149
Deferred income taxes		26			30
Investment tax credit		(2	)		(2	)
Deferred fuel cost (credit)		24			(17	)
Other adjustments to net income		44			21
Cash provided (used) by changes in operating assets and liabilities
Receivables		79			(1	)
Receivables from affiliated companies		12			(7	)
Inventories		(15	)		(22	)
Prepayments and other current assets		2			5
Accounts payable		(6	)		27
Payables to affiliated companies		(13	)		(23	)
Other current liabilities		(136	)		2
Other operating activities		(11	)		(16	)
Net cash provided by operating activities		237			262
Investing activities
Gross utility property additions		(151	)		(142	)
Nuclear fuel additions		(46	)		(30	)
Purchases of available-for-sale securities and other investments		(238	)		(861	)
Proceeds from sales of available-for-sale securities and other investments		285			798
Other investing activities		-			(4	)
Net cash used in investing activities		(150	)		(239	)
Financing activities
Proceeds from issuance of long-term debt, net		-			495
Net decrease in short-term indebtedness		(21	)		(113	)
Changes in advances from affiliates		(1	)		(93	)
Dividends paid to parent		(85	)		(146	)
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		1			-
Net cash (used in) provided by financing activities		(107	)		142
Net (decrease) increase in cash and cash equivalents		(20	)		165
Cash and cash equivalents at beginning of period		125			18
Cash and cash equivalents at end of period	$	105		$	183

See Notes to PEC Consolidated Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

INTERIM FINANCIAL STATEMENTS

March 31, 2006

UNAUDITED STATEMENTS of INCOME
(in millions)
Three Months Ended March 31	2006			2005
Operating revenues	$	1,007		$	848
Operating expenses
Fuel used in electric generation		394			302
Purchased power		165			131
Operation and maintenance		166			189
Depreciation and amortization		95			70
Taxes other than on income		73			67
Other		(3	)		-
Total operating expenses		890			759
Operating income		117			89
Other income (expense)
Interest income		5			-
Other, net		(1	)		3
Total other income		4			3
Interest charges
Interest charges		40			34
Allowance for borrowed funds used during construction		(1	)		(2	)
Total interest charges, net		39			32
Income before income taxes		82			60
Income tax expense		29			16
Net income		53			44
Preferred stock dividend requirement		1			1
Earnings for common stock	$	52		$	43

See Notes to PEF Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED BALANCE SHEETS
(in millions)	March 31, 2006			December 31, 2005
ASSETS
Utility plant
Utility plant in service	$	8,810		$	8,756
Accumulated depreciation		(3,482	)		(3,434	)
Utility plant in service, net		5,328			5,322
Held for future use		9			9
Construction work in progress		481			414
Nuclear fuel, net of amortization		71			76
Total utility plant, net		5,889			5,821
Current assets
Cash and cash equivalents		133			218
Short-term investments		55			-
Receivables, net		288			331
Receivables from affiliated companies		11			11
Deferred income taxes		-			12
Inventory		376			311
Deferred fuel cost		231			341
Prepayments and other current assets		109			100
Total current assets		1,203			1,324
Deferred debits and other assets
Regulatory assets		358			351
Debt issuance costs		22			22
Nuclear decommissioning trust funds		511			493
Miscellaneous other property and investments		46			47
Prepaid pension costs		204			200
Other assets and deferred debits		62			60
Total deferred debits and other assets		1,203			1,173
Total assets	$	8,295		$	8,318
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$	1,098		$	1,097
Retained earnings		1,492			1,498
Total common stock equity		2,590			2,595
Preferred stock - not subject to mandatory redemption		34			34
Long-term debt, net		2,555			2,554
Total capitalization		5,179			5,183
Current liabilities
Current portion of long-term debt		48			48
Accounts payable		207			237
Payables to affiliated companies		73			101
Notes payable to affiliated companies		-			13
Short-term obligations		102			102
Customer deposits		153			148
Interest accrued		31			42
Other current liabilities		118			101
Total current liabilities		732			792
Deferred credits and other liabilities
Noncurrent income tax liabilities		424			433
Accumulated deferred investment tax credits		28			30
Regulatory liabilities		1,192			1,189
Asset retirement obligations		287			290
Accrued pension and other benefits		261			257
Other liabilities and deferred credits		192			144
Total deferred credits and other liabilities		2,384			2,343
Commitments and contingencies (Note 13)
Total capitalization and liabilities	$	8,295		$	8,318

See Notes to PEF Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED STATEMENTS of CASH FLOWS
(in millions)
Three Months Ended March 31	2006			2005
Operating activities
Net income	$	53		$	44
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		101			79
Deferred income taxes and investment tax credits, net		19			13
Deferred fuel cost		110			36
Other adjustments to net income		10			22
Cash provided (used) by changes in operating assets and liabilities:
Receivables		40			22
Receivables from affiliated companies		4			10
Inventories		(66	)		(22	)
Prepayments and other current assets		4			-
Accounts payable		(29	)		(1	)
Payables to affiliated companies		(28	)		5
Other current liabilities		(19	)		(79	)
Regulatory assets and liabilities		(2	)		(57	)
Other operating activities		16			(3	)
Net cash provided by operating activities		213			69
Investing activities
Gross utility property additions		(162	)		(132	)
Nuclear fuel additions		(6	)		(34	)
Purchases of available-for-sale securities and other investments		(126	)		(68	)
Proceeds from sales of available-for-sale securities and other investments		71			68
Other investing activities		(3	)		(1	)
Net cash used in investing activities		(226	)		(167	)
Financing activities
Net decrease in short-term indebtedness		-			(140	)
Retirement of long-term debt		-			(55	)
Changes in advances from affiliates		(13	)		301
Dividends paid to parent		(58	)		-
Dividends paid on preferred stock		(1	)		(1	)
Other financing activities		-			(1	)
Net cash (used in) provided by financing activities		(72	)		104
Net (decrease) increase in cash and cash equivalents		(85	)		6
Cash and cash equivalents at beginning of period		218			12
Cash and cash equivalents at end of period	$	133		$	18

See Notes to PEF Interim Financial Statements.

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO INTERIM FINANCIAL STATEMENTS

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

Each of the following combined notes to the interim financial statements of the Progress Registrants are applicable to Progress Energy, Inc. but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF.

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

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO INTERIM FINANCIAL STATEMENTS

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

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Organization

The Parent is a holding company headquartered in Raleigh, N.C. and is subject to the regulatory provisions of the Federal Energy Regulatory Commission (FERC).

Our reportable segments are: PEC, PEF, Progress Ventures, and Coal and Synthetic Fuels. Our PEC and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity. Our Progress Ventures segment is primarily engaged in nonregulated electric generation, energy marketing activities and natural gas drilling and production. Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuel as defined under the Internal Revenue Code (the Code), the operation of synthetic fuel facilities for third parties, and coal terminal services. Through our other business units, we engage in other nonregulated business areas, which are included in our Corporate and Other segment (Corporate and Other).

PEC and PEF are public service corporations. PEC’s service territory covers portions of North Carolina and South Carolina and PEF’s covers portions of Florida. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory provisions of the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC); PEF is subject to the regulatory provisions of the Florida Public Service Commission (FPSC). Both 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, 2005 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2005 (2005 Form 10-K).

In accordance with the provisions of Accounting Principles Board (APB) Opinion No. 28, “Interim Financial Reporting” (APB No. 28), GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. The intra-period tax allocation, which will have no impact on total year net income, maintains an effective tax rate consistent with the estimated annual effective tax rate. The fluctuations in the effective tax rate for interim periods are primarily due to the recognition of synthetic fuel tax credits and seasonal fluctuations in energy sales and earnings from the Utilities. Income tax expense was increased for the Progress Registrants for the three months ended March 31, 2006 and 2005, as follows:

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	Three Months Ended March 31,
(in millions)	2006		2005
Progress Energy	$	16	$	3
PEC		2		-
PEF		-		-

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

	Three Months Ended March 31,
(in millions)	2006		2005
Progress Energy	$	65	$	57
PEC		22		22
PEF		43		35

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 with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.

Certain amounts for 2005 have been reclassified to conform to the 2006 presentation.

C. Consolidation of Variable Interest Entities

We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities for which we are the primary beneficiary in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46R, “Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51” (FIN 46R).

Progress Energy

In addition to the variable interests listed below for PEC and PEF, we have interests through other subsidiaries in several variable interest entities for which we are not the primary beneficiary. These arrangements include investments in five limited liability partnerships and limited liability corporations. At March 31, 2006, the aggregate additional maximum loss exposure that we could be required to record in our income statement as a result of these arrangements was approximately $8 million, which represents our net remaining investment in the entities. The creditors of these variable interest entities do not have recourse to our general credit in excess of the aggregate maximum loss exposure.

PEC

PEC is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Code. At March 31, 2006, the total assets of the two entities were $38 million, the majority of which are collateral for the entities’ obligations and are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

PEC has an interest in and consolidates a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. PEC also has an interest in one power plant resulting from long-term power purchase contracts. PEC has requested the necessary information to determine if the 17 partnerships and the power plant owner are variable interest entities or to identify the primary beneficiaries; all entities from which the necessary

20

financial information was requested declined to provide the information to PEC and accordingly, PEC has applied the information scope exception in FIN No. 46R, paragraph 4(g), to the 17 partnerships and the power plant. PEC believes that if it is determined to be the primary beneficiary of these entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings or cash flows.

PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include investments in approximately 21 limited liability partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. At March 31, 2006, the aggregate maximum loss exposure that PEC could be required to record on its income statement as a result of these arrangements totals approximately $22 million, which primarily represents its net remaining investment in these entities. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure. See Note 2 of the 2005 Form 10-K for additional information.

PEF

PEF has interests in three variable interest entities for which PEF is not the primary beneficiary. These arrangements include investments in one limited liability corporation, one venture capital fund and one building lease with a special-purpose entity. At March 31, 2006, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was approximately $1 million. The creditors of these variable interest entities do not have recourse to the general credit of PEF in excess of the aggregate maximum loss exposure.

2. NEW ACCOUNTING STANDARDS

FASB EXPOSURE DRAFT ON ACCOUNTING FOR UNCERTAIN TAX POSITIONS, AN INTERPRETATION OF SFAS NO. 109, “ACCOUNTING FOR INCOME TAXES”

On July 14, 2005, the FASB issued an exposure draft of a proposed interpretation of SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), that would address the accounting for uncertain tax positions. The proposed interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. We currently account for uncertain tax benefits in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5). Under SFAS No. 5, contingent losses are recorded when it is probable that the tax position will not be sustained and the amount of the disallowance can be reasonably estimated. During subsequent deliberations in November 2005, the FASB voted to tentatively adopt a more-likely-than-not criterion that the uncertain tax position will be sustained rather than the original probable criterion. As originally drafted, the proposed interpretation would apply to all uncertain tax positions. On January 11, 2006, the FASB voted to delay the effective date of the final interpretation until the first annual period beginning after December 15, 2006, which for us would be January 1, 2007. The FASB has publicly stated that it expects to issue the final interpretation in the second quarter of 2006. We have not yet determined how the proposed interpretation or the final interpretation would impact our various income tax positions.

3. DIVESTITURES

A. 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% interest in PT LLC. See Note 11 for a discussion of the subsequent sale of the Level 3 stock.

Based on the gross proceeds associated with the sale and after consideration of minority interest, we recorded an estimated after-tax gain on disposal of $24 million during the three months ended March 31, 2006.

The accompanying consolidated financial statements have been restated for all periods presented to reflect the operations of PT LLC as discontinued operations. Interest expense has been allocated to discontinued operations

21

based on the net assets of PT LLC, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated for the three months ended March 31, 2006 and 2005 was less than $1 million. We ceased recording depreciation upon classification of the assets as discontinued operations in January 2006. After-tax depreciation expense recorded by PT LLC during the three months ended March 31, 2006 and 2005 was $1 million and $2 million, respectively. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2006			2005
Revenues	$	18		$	18
Earnings before income taxes and minority interest		1			-
Income tax expense		4			-
Minority interest		3			-
Net loss from discontinued operations		(6	)		-
Estimated 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 13A. The ultimate resolution of these matters could result in adjustments to the gain on sale in future periods.

B. Progress Rail Divestiture

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

Based on the gross proceeds associated with the sale, we recorded an estimated after-tax loss on disposal of $17 million during the three months ended March 31, 2005. During the remainder of 2005, we recorded an additional loss of $8 million after finalizing the working capital adjustment and other operating estimates.

The accompanying consolidated interim financial statements for the three months ended March 31, 2005 reflect the operations of Progress Rail as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of Progress Rail, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated for the three months ended March 31, 2005 was $4 million. We ceased recording depreciation upon classification of the assets as discontinued operations in February 2005. After-tax depreciation expense during the three months ended March 31, 2005 was $3 million. Results of discontinued operations for the three months ended March 31, 2005 were as follows:

(in millions)
Revenues	$	358
Earnings before income taxes		8
Income tax expense		3
Net earnings from discontinued operations		5
Loss on disposal of discontinued operations, including income tax benefit of $14		(17	)
Loss from discontinued operations	$	(12	)

In connection with the sale, Progress Fuels Corporation (Progress Fuels) and Progress Energy provided guarantees and indemnifications of certain legal, tax and environmental matters to One Equity Partners, LLC. See general discussion of guarantees at Note 13A. The ultimate resolution of these matters could result in adjustments to the loss on sale in future periods.

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C. Coal Mines Divestiture

On November 14, 2005, our board of directors approved a plan to divest five subsidiaries of Progress Fuels engaged in the coal mining business. On April 6, 2006, we signed an agreement to sell certain net assets of the coal mining business to Alpha Natural Resources, LLC for gross proceeds of $23 million plus an estimated $4 million working capital adjustment. The sale closed on May 1, 2006. As a result, during the three months ended March 31, 2006, we recorded an estimated after-tax loss of $15 million on the expected sale of these assets. The remaining coal mining operations are expected to be sold by the end of 2006. The accompanying consolidated financial statements have been restated for all periods presented to reflect the coal mining operations as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of the coal mines, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated was $1 million for the three months ended March 31, 2006 and 2005. We ceased recording depreciation expense upon classification of the coal mining operations as discontinued operations in November 2005. After-tax depreciation expense during the three months ended March 31, 2005 was $2 million. Results of discontinued operations for the three months ended March 31 were as follows:

(in millions)	2006			2005
Revenues	$	35		$	50
(Loss) earnings before income taxes		(7	)		1
Income tax benefit		2			-
Net (loss) earnings from discontinued operations		(5	)		1
Estimated loss on disposal of discontinued operations, including income tax benefit of $9		(15	)		-
(Loss) earnings from discontinued operations	$	(20	)	$	1

D.  Net Assets of Discontinued Operations

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

(in millions)	March 31, 2006		December 31, 2005
Accounts receivable	$	6	$	18
Inventory		6		13
Other current assets		2		5
Total property, plant and equipment, net		51		155
Total other assets		21		34
Assets of discontinued operations	$	86	$	225
Accounts payable	$	2	$	12
Accrued expenses		8		20
Long-term liabilities		23		55
Liabilities of discontinued operations	$	33	$	87

4. REGULATORY MATTERS

A. PEC Retail Rate Matters

FUEL COST RECOVERY

On May 3, 2006, PEC filed with the SCPSC for an increase in the fuel rate charged to its South Carolina customers. PEC is asking the SCPSC to approve a $27 million, or 5.4 percent, increase in rates. PEC requested the increase for underrecovered fuel costs associated with a settlement from the 2005 fuel case and to meet future expected fuel costs. If approved, the increase would take effect July 1, 2006 and would increase residential electric bills by $3.55 per 1,000 kWhs for fuel cost recovery. We cannot predict the outcome of this matter.

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B. PEF Retail Rate Matters

STORM COST RECOVERY

On June 1, 2005, the governor of Florida signed into law a bill that allows utilities to petition the FPSC to use securitized bonds to recover storm-related costs. PEF has decided not to pursue the issuance of securitized bonds either to recover its 2004 storm-related costs or to replenish its storm reserve fund. On April 25, 2006, PEF entered into a settlement agreement with the interveners in its storm cost recovery docket that would allow PEF to extend its current two-year storm surcharge, which equals approximately $3.61 on the average residential monthly customer bill of 1,000 kWhs, for an additional 12-month period. The extension would replenish the existing storm reserve by an estimated additional $130 million. In the event future storms cause the reserve to be depleted, the settlement would further allow PEF to automatically collect from customers 80% of any future depletion of the storm reserve pending the FPSC’s ultimate review and determination of the actual costs incurred and recoverable by PEF. The parties have sought the FPSC’s approval of the settlement. In addition, PEF’s base rates provide $6 million annually for storm reserve replenishment. The FPSC has the right to review PEF’s storm costs for prudence and has the authority to determine the manner and timing of recovery. We cannot predict the outcome of this matter.

C. Other Matters

REGIONAL TRANSMISSION ORGANIZATION

PEF was one of three major investor-owned Florida utilities that formed a regional transmission organization (RTO), GridFlorida, in 2000. A cost-benefit study conducted during 2005 concluded that the GridFlorida RTO was not cost effective for jurisdictional customers and shifted benefits to nonjurisdictional customers. In light of these findings, the GridFlorida applicants filed a motion to withdraw the GridFlorida compliance filing and filed a petition to close the docketed proceeding on January 27, 2006. At a hearing held on April 18, 2006, the FPSC approved the request to close the docketed proceeding. The closing of the docketed proceeding did not impact PEF’s results of operations as PEF has fully recovered its GridFlorida startup costs from retail ratepayers.

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)	2006		2005
Weighted-average common shares - basic		249		244
Restricted stock awards		-		1
Weighted-average shares - fully dilutive		249		245

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B. Comprehensive Income

Progress Energy

	Three Months Ended March 31,
(in millions)	2006			2005
Net income	$	45		$	93
Other comprehensive (loss) income
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax (benefit) expense of ($2) and $1, respectively)		(4	)		2
Foreign currency translation adjustments included in discontinued operations		−			(6	)
Minimum pension liability adjustment included in discontinued operations (net of tax expense of $1)		−			1
Changes in net unrealized gains on cash flow hedges (net of tax expense of $7 and $5, respectively)		13			6
Other (net of tax expense of $2 and $−, respectively)		5			2
Other comprehensive income		14			5
Comprehensive income	$	59		$	98

PEC

	Three Months Ended March 31,
(in millions)	2006		2005
Net income	$	86	$	116
Other comprehensive income:
Changes in net unrealized gains on cash flow hedges (net of tax expense of $1)		-		2
Other		1		-
Other comprehensive income		1		2
Comprehensive income	$	87	$	118

PEF

Comprehensive income and net income for PEF for the three months ended March 31, 2006 and 2005 were $53 million and $44 million, respectively.

C. Common Stock

At December 31, 2005, we had 500 million shares of common stock authorized under our charter, of which approximately 252 million were outstanding. For the three months ended March 31, 2006 and 2005, respectively, we issued approximately 0.7 million shares and 1.4 million shares of common stock resulting in approximately $28 million and $60 million in proceeds, net of purchases of restricted shares. Included in these amounts were approximately 0.3 million shares and 1.3 million shares for net proceeds of approximately $14 million and $58 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, 2005, we had approximately 58 million unissued shares of common stock reserved, primarily to satisfy the requirements of our stock plans. In 2002, the board of directors authorized meeting the requirements of the 401(k) and the Investor Plus Stock Purchase Plan with original issue shares.

D. Stock-Based Compensation

As discussed in Note 10 of the 2005 Form 10-K, we adopted SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), as of July 1, 2005, using the required modified prospective method. Under that method we began recording

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compensation expense as of July 1, 2005. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), and we made that election. The intrinsic value method resulted in our recording no compensation expense for stock options granted to employees.

Progress Energy

The following table illustrates the effect on our net income and earnings per share if the fair value method had been applied to all outstanding and nonvested awards during the three months ended March 31, 2005:

(in millions except per share data)
Net income, as reported	$	93
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1
Pro forma net income	$	92
Earnings per share
Basic - as reported	$	0.38
Basic - pro forma	$	0.38
Diluted - as reported	$	0.38
Diluted - pro forma	$	0.38

PEC

PEC participates in Progress Energy’s stock option and other stock-based compensation plans. The information below should be read in conjunction with the plan descriptions and other pertinent information disclosed in Note 10 of the 2005 Form 10-K. The following table illustrates the effect on PEC’s net income if the fair value method had been applied to all outstanding and nonvested awards during the three months ended March 31, 2005:

(in millions except per share data)
Net income, as reported	$	116
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		1
Pro forma net income	$	115

PEF

PEF participates in Progress Energy’s stock option and other stock-based compensation plans. The information below should be read in conjunction with the plan descriptions and other pertinent information disclosed in Note 10 of the 2005 Form 10-K. The following table illustrates the effect on PEF’s net income if the fair value method had been applied to all outstanding and nonvested awards during the three months ended March 31, 2005:

(in millions except per share data)
Net income, as reported	$	44
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		-
Pro forma net income	$	44

6. GOODWILL

As discussed in Note 8 of the 2005 Form 10-K, we perform annual goodwill impairment tests in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).

For our Progress Ventures segment, the goodwill impairment tests are performed at the reporting unit level of our

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Effingham, Monroe, Walton and Washington nonregulated generation plants (Georgia Region), which is one level below the Progress Ventures segment. As a result of our evaluation of certain business opportunities that may impact the future cash flows of our Georgia Region operations, we performed an interim goodwill impairment test during the first quarter of 2006. As a result of this test, for the three months ended March 31, 2006, we recognized a pre-tax goodwill impairment loss of $64 million. We estimated the fair value of that reporting unit using the expected present value of future cash flows.

Under SFAS No. 142, all goodwill is assigned to our reporting units that are expected to benefit from the synergies of the business combination. The changes in the carrying amount of goodwill, by reportable segment, were as follows:

(in millions)	PEC		PEF		Progress Ventures			Total
Balance at January 1, 2005	$	1,922	$	1,733	$	64		$	3,719
Balance at December 31, 2005		1,922		1,733		64			3,719
Impairment		-		-		(64	)		(64	)
Balance at March 31, 2006	$	1,922	$	1,733	$	-		$	3,655

7. DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES

Changes to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2005, are described below.

On January 13, 2006, Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100 million of Series A Floating Rate Senior Notes due 2010. These senior notes are unsecured. Interest on the Floating Rate Senior Notes will be based on three-month London Inter Bank Offering Rate (LIBOR) plus 45 basis points and will be reset quarterly. We used the net proceeds from the sale of these senior notes and a combination of available cash and commercial paper proceeds to retire the $800 million aggregate principal amount of our 6.75% Senior Notes on March 1, 2006. Prior to the application of proceeds as described above, we invested the net proceeds in short-term, interest-bearing, investment-grade securities.

Progress Energy entered into a new $800 million 364-day credit agreement on November 21, 2005, which was restricted for the retirement of $800 million of 6.75% Senior Notes due March 1, 2006. On March 1, 2006, we retired $800 million of our 6.75% Senior Notes, thus effectively terminating the 364-day credit agreement.

On March 31, 2006, Progress Energy filed a shelf registration statement with the SEC to provide unlimited financing capacity. The registration statement became effective upon filing with the SEC and will allow Progress Energy to issue various securities, including Senior Debt Securities, Junior Subordinated Debentures, Common Stock, Preferred Stock, Stock Purchase Contracts, Stock Purchase Units, and Trust Preferred Securities and Guarantees. The board of directors has authorized the issuance and sale of up to $1 billion aggregate principal amount of various securities off this new shelf registration statement, in addition to the $679 million of various securities which were not sold from our prior shelf registration statement. Therefore, effective March 31, 2006, Progress Energy has the authority to issue and sell up to $1.679 billion aggregate principal amount of various securities.

On May 3, 2006, Progress Energy restructured its existing $1.13 billion five-year revolving credit agreement (RCA) with a syndication of financial institutions. The new RCA is scheduled to expire on May 3, 2011, and is replacing an existing $1.13 billion five-year facility, which was terminated effective May 3, 2006. The Progress Energy RCA will continue to be used to provide liquidity support for Progress Energy’s issuances of commercial paper and other short-term obligations. The new RCA still includes a defined maximum total debt to capital ratio of 68 percent and contains various cross-default and other acceleration provisions. However, the new RCA no longer includes a material adverse change representation for borrowings or a financial covenant for interest coverage. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of Progress Energy’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa2 by Moody’s and BBB- by S&P.

On May 3, 2006, PEC’s five-year $450 million credit facility was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to

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be determined based upon the credit rating of PEC’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P. The amended PEC RCA is still scheduled to expire on June 28, 2010.

On May 3, 2006, PEF’s five-year $450 million credit facility was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of PEF’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P. The amended PEF RCA is still scheduled to expire on March 28, 2010.

8. BENEFIT PLANS

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

Progress Energy

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

^(a) Relates to the acquisition of Florida Progress. See Note 16B to the 2005 Form 10-K.

PEC

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

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PEF

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

9. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a Risk Management Committee comprised of senior executives from various functional areas. The Risk Management Committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk for nonperformance by the counterparty. We minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. Additionally, in the normal course of business, some of our affiliates may enter into hedge transactions with one another. See Note 18 to the 2005 Form 10-K.

A. Commodity Derivatives

GENERAL

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

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” (DIG Issue C20). The related liability is being amortized to earnings over the term of the related contract (See Note 11). At March 31, 2006 and December 31, 2005, the remaining liability was $18 million and $19 million, respectively.

ECONOMIC DERIVATIVES

Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. We manage open positions according to established policies and guidelines that limit our exposure to market risk and require daily reporting to management of financial exposures. Gains and losses from such contracts were not material to our or the Utilities’ results of operations for the three months ended March 31, 2006 and 2005. PEC did not have material outstanding positions in such contracts at March 31, 2006 and December 31, 2005. We and PEF did not have material outstanding positions in such contracts at March 31, 2006 and December 31, 2005, other than those receiving regulatory accounting treatment at PEF, as discussed below.

PEF has derivative instruments related to its exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause. At March 31, 2006, the fair values of these instruments were a $79 million short-term derivative asset position included in other current assets, a $56 million long-term derivative asset position included in other assets and deferred debits, a $4 million short-term derivative liability position included in other current liabilities and a $1 million long-term derivative liability position included in other liabilities and deferred

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credits. At December 31, 2005, the fair values of the instruments were a $77 million short-term derivative asset position included in other current assets, a $45 million long-term derivative asset position included in other assets and deferred debits and a $6 million long-term derivative liability position included in other liabilities and deferred credits.

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. The ineffective portion of commodity cash flow hedges for the three months ended March 31, 2006 and 2005, was not material to our or the Utilities’ results of operations.

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

	March 31, 2006						December 31, 2005
(in millions)	Progress Energy		PEC		PEF		Progress Energy		PEC		PEF
Fair value of assets	$	144	$	3	$	-	$	170	$	7	$	-
Fair value of liabilities		(21)		-		-		(58)		(4)		-
Fair value, net	$	123	$	3	$	-	$	112	$	3	$	-

The following table presents selected information related to our commodity cash flow hedges at March 31, 2006:

	Maximum Term(a)						Accumulated Other Comprehensive Income/(Loss), net of tax(b)						Portion Expected to be Reclassified to Earnings during the Next 12 Months(c)
(term in years/ millions of dollars)	Progress Energy		PEC		PEF		Progress Energy		PEC		PEF		Progress Energy		PEC		PEF
Commodity cash flow hedges		9		Less than 1		-	$	77	$	2	$	-	$	(3)	$	2	$	-

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

^(b) Includes amounts related to de-designated hedges.

^(c) Due to the volatility of the commodities markets, the value in accumulated other comprehensive income/(loss) (OCI) is subject to change prior to its reclassification into earnings.

At December 31, 2005, we had $69 million of after-tax deferred income and PEC had $2 million in after-tax deferred income recorded in accumulated other comprehensive loss related to commodity cash flow hedges. PEF had no amount recorded in accumulated other comprehensive loss related to commodity cash flow hedges.

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

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

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

	March 31, 2006						December 31, 2005
(in millions)	Progress Energy		PEC		PEF		Progress Energy		PEC		PEF
Interest rate cash flow hedges	$	-	$	-	$	-	$	1	$	-	$	-
Interest rate fair value hedges	$	(4)	$	-	$	-	$	(2)	$	-	$	-

CASH FLOW HEDGES

Gains and losses from cash flow hedges are recorded in OCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in OCI 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, 2006 and 2005, was not material to our or the Utilities’ results of operations.

At December 31, 2005, we had $13 million of after-tax deferred loss and PEC had $5 million in after-tax deferred loss recorded in accumulated other comprehensive loss related to interest rate cash flow hedges. PEF had no amount recorded in accumulated other comprehensive loss related to interest rate cash flow hedges. These balances were not materially different at March 31, 2006.

At December 31, 2005, we had $100 million notional of interest rate cash flow hedges, which were settled during the three months ended March 31, 2006. The Utilities had no open interest rate cash flow hedges at December 31, 2005.

FAIR VALUE HEDGES

For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At March 31, 2006 and December 31, 2005, we had $150 million notional of interest rate fair value hedges and the Utilities had no open interest rate fair value hedges.

10. FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

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

Our Progress Ventures segment is primarily engaged in nonregulated electric generation, energy marketing activities and natural gas drilling and production.

Our Coal and Synthetic Fuels segment is primarily engaged in the production and sale of coal-based solid synthetic fuel (as defined under the Code), the operation of synthetic fuel facilities for third parties, and coal terminal services.

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

Prior to 2006, PT LLC was included within the Corporate and Other segment. In connection with its divestiture (See Note 3A), the operations of PT LLC were reclassified to discontinued operations in the first quarter of 2006 and therefore are not included in the results from continuing operations during the periods reported. During the fourth quarter of 2005, we reclassified our coal mining operations as discontinued operations (See Note 3C). 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:

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											Income (loss)
	Revenues										from
(in millions)	Unaffiliated		Intersegment			Total			Severance Charges		Continuing Operations			Assets
2006
PEC	$	978	$	-		$	978		$	-	$	85		$	11,418
PEF		1,007		-			1,007			-		52			8,295
Progress Ventures		226		-			226			-		(35	)		2,235
Coal and Synthetic Fuels		222		75			297			-		14			453
Corporate and Other		-		89			89			-		(69	)		17,738
Eliminations		-		(164	)		(164	)		-		-			(13,737	)
Totals	$	2,433	$	-		$	2,433		$	-	$	47		$	26,402
2005
PEC	$	935	$	-		$	935		$	14	$	115
PEF		848		-			848			14		43
Progress Ventures		97		-			97			1		7
Coal and Synthetic Fuels		273		84			357			2		(4	)
Corporate and Other		-		100			100			-		(57	)
Eliminations		-		(184	)		(184	)		-		-
Totals	$	2,153	$	-		$	2,153		$	31	$	104

 The severance charges incurred in 2005 resulted from a cost-management initiative that was approved in February 2005 and concluded in December 2005.

11. OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income and other income and expense items as discussed below. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities. Allowance for funds used during construction (AFUDC) equity represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets. Contingent value obligations (CVOs) unrealized loss is due to changes in the fair market value of the liability. See Note 15 to the 2005 Form 10-K for more information on CVOs. The components of other, net as shown on the accompanying Statements of Income were as follows:

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Progress Energy

	Three Months Ended March 31,
(in millions)	2006			2005
Other income
Nonregulated energy and delivery services income	$	8		$	6
DIG Issue C20 amortization (see Note 9)		1			1
Gain on sale of Level 3 stock (a)		25			-
Investment gains		2			2
Income from equity investments		-			2
AFUDC equity		3			3
Other		5			6
Total other income	$	44		$	20
Other expense
Nonregulated energy and delivery services expenses	$	6		$	5
Donations		7			5
Loss from equity investments		2			5
CVOs unrealized loss		25			-
Other		6			4
Total other expense	$	46		$	19
Other, net - Progress Energy	$	(2	)	$	1

(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 3A). This gain is prior to the consideration of minority interest.

PEC

	Three Months Ended March 31,
(in millions)	2006			2005
Other income
Nonregulated energy and delivery services income	$	2		$	2
DIG Issue C20 amortization (see Note 9)		1			1
AFUDC equity		1			-
Other		3			3
Total other income	$	7		$	6
Other expense
Nonregulated energy and delivery services expenses	$	1		$	2
Donations		3			2
Other		4			1
Total other expense	$	8		$	5
Other, net - PEC	$	(1	)	$	1

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PEF

	Three Months Ended March 31,
(in millions)	2006			2005
Other income
Nonregulated energy and delivery services income	$	6		$	4
Investment gains		1			1
AFUDC equity		2			3
Other		-			1
Total other income	$	9		$	9
Other expense
Nonregulated energy and delivery services expenses	$	5		$	3
Donations		3			3
Other		2			-
Total other expense	$	10		$	6
Other, net - PEF	$	(1	)	$	3

12. ENVIRONMENTAL MATTERS

We are subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. See Note 22 to the 2005 Form 10-K.

A.  Hazardous and Solid Waste Management

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina or the state of Florida, as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. A discussion of sites by legal entity follows below.

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

PEC and PEF filed claims with general liability insurance carriers to recover costs arising from actual or potential environmental liabilities for remediation of certain sites. No material claims are currently pending. We may file further claims with respect to sites for which claims were not previously presented.

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.

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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. In 2003, the accrual was reduced to $4 million based on a change in estimate. At March 31, 2006 and December 31, 2005, the remaining accrual balance was approximately $3 million. Expenditures related to this liability were not material during the three months ended March 31, 2006 and 2005.

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

PEC

There are currently eight former MGP sites and a number of other sites associated with PEC that have required or are anticipated to require investigation and/or remediation.

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 the reimbursement of approximately $36 million to the EPA for past expenditures in addressing conditions at the site. 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 obligation for remediation of the Carolina Transformer site. PEC may file claims with respect to this site. The outcome of this matter cannot be predicted.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC and a number of other PRPs the opportunity to negotiate cleanup of the site and reimbursement to the EPA for EPA’s past expenditures in addressing conditions at the site. In September 2005, PEC and several other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the site. In 2005, PEC accrued approximately $3 million for its portion of the EPA’s estimated remediation costs and the EPA's past costs. For the quarter ended March 31, 2006, based upon additional assessment work performed at the site, PEC recorded an additional $9 million accrual for its portion of the estimated additional remediation costs. Actual experience may differ from current estimates and it is possible that estimates will continue to change in the future. PEC may file claims with respect to this site. The outcome of this matter cannot be predicted.

In March 2006, based upon newly available data for several of PEC’s MGP sites, which had individual site remediation costs ranging from approximately $2 million to $4 million, a remediation liability of approximately $12 million was estimated and recorded for the minimum total remediation cost for all of PEC’s remaining MGP sites. However, the maximum amount of the range for all the sites cannot be determined at this time as one of the remaining sites is significantly larger than the sites for which we have historical experience.

At March 31, 2006 and December 31, 2005, PEC’s accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over one to five years, were $25 million and $7 million, respectively. The amounts include insurance fund proceeds that PEC received to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these sites are charged against a specific fund containing these proceeds. For the three months ended March 31, 2006, PEC spent approximately $3 million, accrued approximately $21 million, and received no insurance proceeds related to environmental remediation. For the three months ended March 31, 2005, PEC made no additional accruals, spent approximately $2 million and received no insurance proceeds. PEC is planning to propose to the NCUC to defer and amortize these costs, net of insurance proceeds, over a period of years. We cannot predict the outcome of this matter.

On March 30, 2005, the North Carolina Division of Water Quality renewed a PEC permit for the continued use of coal combustion products generated at any of its coal-fired plants located in the state. Following review of the permit conditions, which could significantly restrict the reuse of coal ash and result in higher ash management costs, the permit was adjudicated. The outcome of this matter cannot be predicted.

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PEF

At March 31, 2006 and December 31, 2005, PEF’s accruals for probable and estimable costs related to various environmental sites, which were included in other liabilities and deferred credits and are expected to be paid out over one to 15 years, were:

(in millions)	March 31, 2006		December 31, 2005
Remediation of distribution and substation transformers	$	57	$	20
MGP and other sites		18		18
Total accrual for environmental sites	$	75	$	38

PEF has received approval from the FPSC for recovery of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection (FDEP), PEF is in the process of examining distribution transformer sites and substation sites for mineral oil-impacted soil remediation caused by equipment integrity issues. PEF has reviewed a number of distribution transformer sites and all substation sites. Based on changes to the estimated time frame for review of distribution transformer sites, PEF currently expects to have completed its review by the end of 2008. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC. For the three months ended March 31, 2006, PEF accrued approximately $38 million due to additional sites expected to require remediation and spent approximately $1 million related to the remediation of transformers. For the three months ended March 31, 2005, PEF made no additional accruals and spent approximately $2 million related to the remediation of transformers. PEF records a regulatory asset for the probable recovery of these costs through the ECRC.

The amounts for MGP and other sites, in the table above, relate to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation. The amounts include approximately $12 million in insurance claim settlement proceeds received in 2004, which are restricted for use in addressing costs associated with environmental liabilities. For the three months ended March 31, 2006 and 2005, PEF made no additional accruals or material expenditures and received no insurance proceeds.

B.  Air Quality

We are subject to various current and proposed federal, state and local environmental compliance laws and regulations, which would likely result in increased planned capital expenditures and O&M expenses. Significant updates to these laws and regulations and related impacts to us since December 31, 2005, are discussed below. Additionally, Congress is considering legislation that would require additional reductions in air emissions of nitrogen oxide (NOx), sulfur dioxide (SO₂), carbon dioxide (CO₂) and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multipollutant approach to air pollution control could involve significant capital costs that could be material to our financial position or results of operations. Control equipment that will be installed on North Carolina coal-fired generating facilities as part of the Clean Smokestacks Act, enacted in 2002 and discussed below, may address some of the issues outlined above as they relate to PEC. However, the outcome of the matter cannot be predicted.

NEW SOURCE REVIEW (NSR)

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 NSR requirements or New Source Performance Standards under the Clean Air Act. We were asked to provide information to the EPA as part of this initiative and cooperated in supplying the requested information. The EPA initiated civil enforcement actions against unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities in excess of $1.0 billion. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related costs through rate adjustments or similar mechanisms.

On March 17, 2006, the Court of Appeals for the District of Columbia Circuit set aside the EPA’s 2003 New Source Review equipment replacement rule. The rule would have provided a more uniform definition of routine equipment

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replacement. The court had earlier set aside a provision in the NSR rule, which 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 (NOX SIP CALL)

The NOx SIP Call is an EPA rule that requires 22 states, including North Carolina, South Carolina and Georgia, to further reduce nitrogen oxide emissions. The NOx SIP Call is not applicable to Florida. Total capital costs to meet the requirements of the final rule under the NOx SIP Call in North Carolina and South Carolina could reach approximately $355 million at PEC, of which approximately $341 million has been incurred through March 31, 2006. This amount also includes the cost to install NOx controls under North Carolina’s and South Carolina’s programs to comply with the federal eight-hour ozone standard. However, further technical analysis and rulemaking may result in requirements for additional controls at some units. Increased O&M expenses relating to the NOx SIP Call are not expected to be material to our or PEC’s results of operations.

Parties unrelated to us have undertaken efforts to have Georgia excluded from the rule and its requirements. Georgia has not yet submitted a state implementation plan to comply with the NOx SIP Call. The outcome of this matter and the impact to our nonregulated operations in Georgia cannot be predicted.

CLEAN SMOKESTACKS ACT

In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO₂ from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by the Clean Smokestacks Act. To meet SO₂ emission targets, PEC plans to install devices that neutralize sulfur compounds formed during coal combustion (scrubbers) on some of its coal-fired units. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that are then removed. In March 2006, PEC filed its annual estimate with the NCUC of the total capital expenditures to meet emission targets for NOx and SO₂ from coal-fired plants under the Clean Smokestacks Act of approximately $1.1 billion to $1.4 billion by the end of 2013, of which approximately $351 million has been spent through March 31, 2006. The increase in estimated total capital expenditures from the original 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 evaluating various design, technology, and new generation options that could materially reduce expenditures required by the Clean Smokestacks Act.

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

The Clean Smokestacks Act also freezes the state’s utilities' base rates for five years, which ends in 2007, unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. The Clean Smokestacks Act requires PEC to amortize $569 million, representing 70 percent of the original cost estimate of $813 million, during the five-year rate freeze period. PEC recognized amortization of $22 million and $27 million for the three months ended March 31 2006 and 2005, respectively, and has recognized $417 million in cumulative amortization through March 31, 2006. The remaining amortization requirement of $152 million will be recorded over the 21-month period ending December 31, 2007. The Clean Smokestacks Act permits PEC the flexibility to vary the amortization schedule for recording of the compliance costs from none up to $174 million per year. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods.

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Pursuant to the Clean Smokestacks Act, PEC entered into an agreement with the state of North Carolina to transfer to the state certain NOx and SO₂ emissions allowances that result from compliance with the collective NOx and SO₂ emissions limitations set out in the Clean Smokestacks Act. The Clean Smokestacks Act also required the state to undertake a study of mercury and CO₂ emissions in North Carolina. O&M expenses will significantly increase due to the additional personnel, materials and general maintenance associated with the equipment. O&M expenses are recoverable through base rates, rather than as part of this program. The future regulatory interpretation, implementation or impact of the Clean Smokestacks Act cannot be predicted.

CLEAN AIR INTERSTATE RULE, MERCURY RULE AND CLEAN AIR VISIBILITY RULE

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

PEF has joined a coalition of Florida utilities that has filed a challenge to the CAIR as it applies to Florida. A petition for reconsideration and stay and a petition for judicial review of the CAIR were filed on July 11, 2005. On October 27, 2005, the DC Circuit Court issued an order granting the motion for stay of the proceedings. On December 2, 2005, the EPA announced a reconsideration of four aspects of the CAIR, including its applicability to Florida. On March 16, 2006, the EPA denied all pending reconsiderations, allowing the challenge to proceed. While we consider it unlikely that this challenge would eliminate the compliance requirements of the CAIR, it could potentially reduce or delay our costs to comply with the CAIR. The outcome of this matter cannot be predicted.

On March 15, 2005, the EPA finalized two separate but related rules: the Clean Air Mercury Rule (CAMR) that sets emissions limits to be met in two phases beginning in 2010 and 2018, respectively, and encourages a cap and trade approach to achieving those caps, and a de-listing rule that eliminated any requirement to pursue a maximum achievable control technology (MACT) approach for limiting mercury emissions from coal-fired power plants. NOx and SO₂ controls also are effective in reducing mercury emissions. However, according to the EPA the second phase cap reflects a level of mercury emissions reduction that exceeds the level that would be achieved solely as a co-benefit of controlling NOx and SO₂ under CAIR. States are required to adopt mercury rules implementing the CAMR by November 11, 2006, which must be reviewed and approved by the EPA. As of May 1, 2006, of the three states in which the Utilities operate, only North Carolina had formally proposed a mercury regulation. North Carolina's proposed rule would adopt the federal cap-and-trade approach and would require the addition of mercury controls on certain of PEC's North Carolina units that do not have scrubbers by 2023. Formal rulemaking in South Carolina and Florida is expected to occur in the late spring and summer of 2006. The outcome of this matter cannot be predicted.

The de-listing rule has been challenged by a number of parties; the resolution of the challenges could impact our final compliance plans and costs. On October 21, 2005, the EPA announced a reconsideration of the CAMR. The outcome of this matter cannot be predicted.

On June 15, 2005, the EPA issued the final Clean Air Visibility Rule (CAVR). The EPA’s rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in 156 specially protected areas. To help restore visibility in those areas, states must require the identified facilities to install Best Available Retrofit Technology (BART) to control their emissions. Depending on the approach taken by the states, the reductions associated with BART would begin to take effect in 2014. CAVR included the EPA’s determination that compliance with the NOx and SO₂ requirements of CAIR may be used by states as a BART substitute. We expect that our compliance plans to comply with the CAIR and CAMR will fulfill BART obligations, but the states could require the installation of additional air quality controls if they do not achieve reasonable progress on improving visibility. PEC’s BART-eligible units are Asheville Unit No. 1 and No. 2, Roxboro Unit No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Unit No. 1, Bartow Unit No. 3, and Crystal River Unit No. 1 and No. 2. The outcome of this matter cannot be predicted.

On an ongoing basis, we review our compliance plans and the cost to comply with the CAIR and CAMR. Installation of additional air quality controls is needed to meet the CAIR and the CAMR requirements.

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The air quality controls needed to meet compliance with the NOx SIP Call and Clean Smokestacks Act will reduce the costs to meet the CAIR requirements for our North Carolina units at PEC. We currently estimate the total additional compliance costs related to CAIR for PEC could be in a range of approximately $100 million to $200 million. We will continue to review these estimates as compliance plans are further developed. The timing and extent of the costs for future projects will depend upon the final compliance strategy.

We expect PEF to incur significant additional capital and O&M expenses to achieve compliance with the CAIR and CAMR through 2018. PEF is developing an integrated compliance strategy for the CAIR and CAMR rules because NOx and SO2 controls are effective in reducing mercury emissions. We currently estimate the total compliance costs for PEF based on various compliance plan alternatives could be as much as approximately $1.4 billion, of which approximately $4 million has been incurred through March 31, 2006. We will continue to review these estimates as compliance plans are further developed. The timing and extent of the costs for future projects will depend upon the final compliance strategy. We are evaluating various design, technology, and new generation options that could materially reduce PEF’s costs required by the CAIR and CAMR.

On October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs associated with the development and implementation of an integrated strategy to comply with the CAIR and CAMR through the ECRC. On March 31, 2006, PEF filed a proposed compliance plan with the FPSC to meet these federal environmental rules. The proposed compliance plan includes approximately $740 million of estimated capital costs expected to be spent through 2016, to plan, design, build and install pollution control equipment at our Anclote and Crystal River plants. We expect this matter to be addressed during the FPSC hearings in November 2006, but cannot predict whether this proposed compliance plan will be approved by the FPSC. These costs may increase or decrease depending upon the results of the engineering and strategy development work and FPSC approval of the final compliance plan. Subsequent rule interpretations, equipment availability, or the unexpected acceleration of the initial NOx or other compliance dates, among other things, could require acceleration of some projects and therefore result in additional costs in 2006.

NORTH CAROLINA ATTORNEY GENERAL PETITION UNDER SECTION 126 OF THE CLEAN AIR ACT

In March 2004, the North Carolina Attorney General filed a petition with the EPA, under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO₂ emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina’s ability to meet national air quality standards for ozone and particulate matter. On March 16, 2006, the EPA issued a final response denying the petition. The EPA's rationale for denial is that compliance with CAIR will reduce the emissions from surrounding states sufficiently to address North Carolina's concerns.

NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS)

On December 21, 2005, the EPA announced proposed changes to the NAAQS for particulate matter. The EPA proposed to lower the 24-hour standard for particulate matter less than 2.5 microns in diameter from 65 micrograms per cubic meter to 35 micrograms per cubic meter. In addition, the EPA proposed to establish a new 24-hour standard of 70 micrograms per cubic meter for particulate matter that is between 2.5 and 10 microns in diameter. The EPA also proposed to eliminate the current standards for particulate matter less than 10 microns in diameter. The EPA is scheduled to finalize the standards by September 27, 2006. The changes could ultimately result in increased costs for installation of additional pollution controls at facilities operated by PEC and PEF. The outcome of this matter cannot be predicted.

C.  Water Quality

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

Section 316(b) of the Clean Water Act requires assessment of the environmental effect of withdrawal of water at our facilities. We are conducting studies and currently estimate that total compliance costs through 2010 to meet Section 316(b) requirements of the Clean Water Act will be approximately $70 million to $95 million, of which an

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immaterial amount has been incurred through March 31, 2006. The range includes approximately $5 million to $10 million at PEC and approximately $65 million to $85 million at PEF.

The majority of compliance costs associated with water quality requirements for PEF are eligible for consideration for recovery through the ECRC. The outcome of future petitions for recovery through the ECRC cannot be predicted.

D.  Other Environmental Matters

GLOBAL CLIMATE CHANGE

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO₂ and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. There are proposals to address global climate change that would regulate CO₂ and other greenhouse gases. Reductions in CO₂ emissions to the levels specified by the Kyoto Protocol and some additional proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. We have articulated principles that we believe should be incorporated into any global climate change policy. While the outcome of this matter cannot be predicted, we are taking voluntary action on this important issue as part of our commitment to environmental stewardship and responsible corporate citizenship.

In a decision issued July 15, 2005, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit denied petitions for review filed by several states, cities and organizations seeking the regulation by the EPA of CO₂ emissions under the Clean Air Act. In a 2-1 decision, the court held that the EPA administrator properly exercised his discretion in denying the request for regulation. Officials from five states and the District of Columbia asked the full U.S. Court of Appeals for the D.C. Circuit to review the decision made by the three-judge panel. On December 2, 2005, the U.S. Court of Appeals denied the request for rehearing. On March 2, 2006, the petitioners filed a petition for writ of certiorari with the U.S. Supreme Court, seeking a review of the U.S. Court of Appeals decision. The outcome of this matter cannot be predicted.

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

13. COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 23 to the 2005 Form 10-K are described below.

A. Guarantees

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45). Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2006, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Balance Sheets.

At March 31, 2006, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuel operations. Related to the sales of businesses, the latest notice period extends until 2012 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain environmental indemnifications have no limitations as to time or maximum potential future payments. In 2005, PEC entered into a contract with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a

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liability related to this indemnification (See Note 12B). PEC’s maximum exposure cannot be determined. At March 31, 2006, the maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $201 million, including $32 million at PEF. At March 31, 2006 and December 31, 2005, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $49 million and $41 million, respectively. These amounts include $16 million for PEC at March 31, 2006 and December 31, 2005, respectively, and $8 million for PEF at March 31, 2006. PEF had no liabilities related to guarantees and indemnifications to third parties at December 31, 2005. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries. See Note 14 for additional information.

B. Other Commitments and Contingencies

1. Spent Nuclear Fuel Matters

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

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities on or before January 31, 1998. Our damages due to the DOE’s breach will be significant, but have yet to be determined. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

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

In July 2002, Congress passed an override resolution to Nevada’s veto of the DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.; and Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. These same parties also challenged the EPA’s radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. In August 2005, the EPA issued new proposed standards. The proposed standards include a 1,000,000-year compliance period in the radiation protection standard. Comments were due November 21, 2005, and are being reviewed by the EPA. The EPA plans to issue a new safety standard for the repository by 2007. The DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004. However, in November 2004, the DOE announced it would not submit the license application until mid-2005 or later. The DOE did not submit the license application in 2005 and recently reported that the license application will not be submitted until after September 2007. Congress approved $450 million for fiscal year 2006 for the Yucca Mountain project, approximately $201 million less than requested by the DOE. The DOE has acknowledged that a working

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repository will not be operational until sometime after 2010. The DOE has not identified a new target date for placing the repository in service, but they have stated that they expect it to be open by 2020. The Utilities cannot predict the outcome of this matter.

With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at Robinson Nuclear Plant (Robinson) and Brunswick Nuclear Plant, (Brunswick), PEC’s spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC’s system through the expiration of the operating licenses for all of PEC’s nuclear generating units.

With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at PEF’s nuclear unit, Crystal River Unit No. 3 (CR3), PEF’s spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEF’s system through the expiration of the operating license for CR3.

2. Synthetic Fuel Matters

On May 15, 2005, the original owners of the Earthco synthetic fuel facilities filed suit in New York state court alleging breach of contract against the Progress Fuels subsidiaries that purchased the Earthco facilities (Progress Fuels Subsidiaries). The plaintiffs also named us as a defendant.

The plaintiffs’ position in the lawsuit is that periodic payments otherwise due to them under the sales arrangement with the Progress Fuels Subsidiaries are, contrary to the sales agreement, being escrowed pending the outcome of the Internal Revenue Service (IRS) audit of the Earthco facilities. The Progress Fuels Subsidiaries believe that the parties’ agreements allow for the payments to be escrowed in such event and also allow for the use of such escrowed amounts to satisfy any potential disallowance of tax credits that arises out of such an event. Currently, the escrowed amount in question is $97 million, which reflects periodic payments that would have been paid to the plaintiffs beginning April 30, 2003 through March 31, 2006. This amount will increase as future periodic payments are made to the escrow which would otherwise have been payable to the plaintiffs. So long as the case is pending, we intend to vigorously defend against the plaintiffs' position, but cannot predict the outcome of this matter. Although the case is still pending, in light of the successful outcome of the IRS audit of the Earthco facilities, we have contacted the plaintiffs to discuss terms under which we would release escrowed money and the plaintiffs would dismiss the lawsuit.

We have also escrowed $39 million that otherwise would have been paid to U.S. Global LLC (Global) through March 31, 2006. These funds are being escrowed on the same basis as the funds that were escrowed for the original owners of the Earthco facilities. We have sent communication to Global regarding the negotiation of terms under which the funds might be released given the successful resolution of the IRS audit of the Earthco facilities.

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 Global, Earthco, certain affiliates of Earthco (collectively the Earthco Sellers), EFC Synfuel LLC (which is owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC, Solid Fuel LLC, Ceredo Synfuel LLC, Gulf Coast Synfuel LLC (currently named Sandy River Synfuel LLC) (collectively the Progress Affiliates), as amended by an amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase Agreement). Global has asserted that (1) pursuant to the Asset Purchase Agreement it is entitled to an interest in two synthetic fuel facilities currently owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuel facilities, (2) that it is entitled to damages because Progress Affiliates prohibited it from procuring purchasers for the synthetic fuel facilities, and (3) that it is entitled to immediate payment of tonnage fees held in escrow (this claim is identical to the position taken by Earthco as described above).

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

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

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

We cannot predict the outcome of these matters, but will vigorously defend against the allegations.

3. Other Litigation Matters

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

14. CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 24 to the 2005 Form 10-K, we have guaranteed certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.) since September 2005. Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress Corporation (Florida Progress). Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 12B to the 2005 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a special-purpose entity and was deconsolidated in 2003 in accordance with the provisions of FIN No. 46. The deconsolidation was not material to our financial statements. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.

Presented below are the condensed consolidating Statements of Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed consolidating statements, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the financial results of Florida Progress. The Other column includes the consolidated financial results of all other non-guarantor subsidiaries and elimination entries for all intercompany transactions. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities.

43

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		−			282			166			448
Total operating revenues		−			1,289			1,144			2,433
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		−			256			149			405
Depreciation and amortization		−			18			18			36
Impairment of goodwill		−			−			64			64
Other		−			7			9			16
Total operating expenses		4			1,171			1,026			2,201
Other (expense) income, net		(10	)		29			(4	)		15
Interest charges, net		77			52			51			180
(Loss) income from continuing operations before income tax and minority interest		(91	)		95			63			67
Income tax (benefit) expense		(33	)		27			19			13
Equity in earnings of consolidated subsidiaries		103			−			(103	)		−
Minority interest in subsidiaries’ income, net of tax		−			(7	)		−			(7	)
Income (loss) from continuing operations		45			61			(59	)		47
Discontinued operations, net of tax		−			(1	)		(1	)		(2	)
Net income (loss)	$	45		$	60		$	(60	)	$	45

Condensed Consolidating Statement of Income Three Months Ended March 31, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Operating revenues
Electric	$	−		$	848		$	935		$	1,783
Diversified business		−			299			71			370
Total operating revenues		−			1,147			1,006			2,153
Operating expenses
Utility
Fuel used in electric generation		−			302			248			550
Purchased power		−			131			67			198
Operation and maintenance		4			189			213			406
Depreciation and amortization		−			70			138			208
Taxes other than on income		4			67			46			117
Diversified business
Cost of sales		−			281			84			365
Depreciation and amortization		−			16			16			32
Other		−			16			9			25
Total operating expenses		8			1,072			821			1,901
Other income (expense), net		18			(1	)		(12	)		5
Interest charges, net		79			44			39			162
(Loss) income from continuing operations before income tax and minority interest		(69	)		30			134			95
Income tax (benefit) expense		(19	)		(6	)		24			(1	)
Equity in earnings of consolidated subsidiaries		143			−			(143	)		−
Minority interest in subsidiaries’ loss, net of tax		−			8			−			8
Income (loss) from continuing operations		93			44			(33	)		104
Discontinued operations, net of tax		−			(26	)		15			(11	)
Net income (loss)	$	93		$	18		$	(18	)	$	93

44

Condensed Consolidating Balance Sheet March 31, 2006
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−	$	5,889	$	8,681		$	14,570
Current assets
Cash and cash equivalents		4		152		107			263
Short-term investments		−		81		136			217
Notes receivables from affiliated companies		332		60		(392	)		−
Deferred fuel cost		−		231		243			474
Assets of discontinued operations		−		85		1			86
Other current assets		59		1,098		1,009			2,166
Total current assets		395		1,707		1,104			3,206
Deferred debits and other assets
Investment in consolidated subsidiaries		11,596		−		(11,596	)		−
Goodwill		−		2		3,653			3,655
Other assets and deferred debits		260		2,063		2,734			5,057
Total deferred debits and other assets		11,856		2,065		(5,209	)		8,712
Total assets	$	12,251	$	9,661	$	4,576		$	26,488
Capitalization
Common stock equity	$	7,997	$	3,076	$	(3,076	)	$	7,997
Preferred stock of subsidiaries - not subject to mandatory redemption		−		34		59			93
Minority interest		−		53		5			58
Long-term debt, affiliate		−		440		(170	)		270
Long-term debt, net		3,874		2,636		3,668			10,178
Total capitalization		11,871		6,239		486			18,596
Current liabilities
Current portion of long-term debt		−		109		−			109
Notes payable to affiliated companies		−		188		(188	)		−
Short-term obligations		100		102		52			254
Liabilities of discontinued operations		−		33		−			33
Other current liabilities		231		844		734			1,809
Total current liabilities		331		1,276		598			2,205
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		9		256			265
Regulatory liabilities		−		1,192		1,376			2,568
Accrued pension and other benefits		12		311		570			893
Other liabilities and deferred credits		37		634		1,290			1,961
Total deferred credits and other liabilities		49		2,146		3,492			5,687
Total capitalization and liabilities	$	12,251	$	9,661	$	4,576		$	26,488

45

Condensed Consolidating Balance Sheet December 31, 2005
(in millions)	Parent		Subsidiary Guarantor		Other			Progress Energy, Inc.
Utility plant, net	$	−	$	5,821	$	8,621		$	14,442
Current assets
Cash and cash equivalents		239		241		126			606
Short-term investments		−		−		191			191
Notes receivables from affiliated companies		467		−		(467	)		−
Deferred fuel cost		−		341		261			602
Assets of discontinued operations		−		223		2			225
Other current assets		22		1,057		1,138			2,217
Total current assets		728		1,862		1,251			3,841
Deferred debits and other assets
Investment in consolidated subsidiaries		11,594		−		(11,594	)		−
Goodwill		−		2		3,717			3,719
Other assets and deferred debits		259		2,072		2,709			5,040
Total deferred debits and other assets		11,853		2,074		(5,168	)		8,759
Total assets	$	12,581	$	9,757	$	4,704		$	27,042
Capitalization
Common stock equity	$	8,038	$	3,039	$	(3,039	)	$	8,038
Preferred stock of subsidiaries - not subject to mandatory redemption		−		34		59			93
Minority interest		−		38		5			43
Long-term debt, affiliate		−		440		(170	)		270
Long-term debt, net		3,873		2,636		3,667			10,176
Total capitalization		11,911		6,187		522			18,620
Current liabilities
Current portion of long-term debt		404		109		−			513
Notes payable to affiliated companies		−		315		(315	)		−
Short-term obligations		−		102		73			175
Liabilities of discontinued operations		−		87		−			87
Other current liabilities		245		843		1,019			2,107
Total current liabilities		649		1,456		777			2,882
Deferred credits and other liabilities
Noncurrent income tax liabilities		−		62		234			296
Regulatory liabilities		−		1,189		1,338			2,527
Accrued pension and other benefits		12		307		551			870
Other liabilities and deferred credits		9		556		1,282			1,847
Total deferred credits and other liabilities		21		2,114		3,405			5,540
Total capitalization and liabilities	$	12,581	$	9,757	$	4,704		$	27,042

46

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		$	362		$	74		$	500
Investing activities
Gross utility property additions		−			(153	)		(151	)		(304	)
Diversified business property additions		−			(47	)		−			(47	)
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 by (used in) investing activities		132			(232	)		(227	)		(327	)
Financing activities
Issuance of common stock		28			−			−			28
Proceeds from issuance of long-term debt		397			−			−			397
Net increase (decrease) in short-term indebtedness		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 in) provided by financing activities		(431	)		(211	)		134			(508	)
Cash used by discontinued operations
Operating activities		−			(5	)		−			(5	)
Investing activities		−			(3	)		−			(3	)
Financing activities		−			−			−			−
Net decrease in cash and cash equivalents		(235	)		(89	)		(19	)		(343	)
Cash and cash equivalents at beginning of period		239			241			126			606
Cash and cash equivalents at end of period	$	4		$	152		$	107		$	263

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Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2005
(in millions)	Parent			Subsidiary Guarantor			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	62		$	41		$	129		$	232
Investing activities
Gross utility property additions		−			(132	)		(135	)		(267	)
Diversified business property additions		−			(24	)		(16	)		(40	)
Nuclear fuel additions		−			(34	)		(30	)		(64	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		−			397			1			398
Purchases of available-for-sale securities and other investments		(1,075	)		(68	)		(869	)		(2,012	)
Proceeds from sales of available-for-sale securities and other investments		981			68			804			1,853
Changes in advances to affiliates		(281	)		5			276			−
Proceeds from repayment of long-term affiliate debt		369			−			(369	)		−
Other investing activities		(7	)		(4	)		(1	)		(12	)
Net cash (used in) provided by investing activities		(13	)		208			(339	)		(144	)
Financing activities
Issuance of common stock		60			−			−			60
Proceeds from issuance of long-term debt		−			−			495			495
Net increase (decrease) in short-term indebtedness		260			(140	)		(113	)		7
Retirement of long-term debt		(160	)		(56	)		−			(216	)
Retirement of long-term affiliate debt		−			(369	)		369			−
Dividends paid on common stock		(145	)		−			−			(145	)
Changes in advances from affiliates		−			330			(330	)		−
Other financing activities		(4	)		17			(51	)		(38	)
Net cash provided by (used in) financing activities		11			(218	)		370			163
Cash used by discontinued operations
Operating activities		−			(18	)		−			(18	)
Investing activities		−			(9	)		−			(9	)
Financing activities		−			−			−			−
Net increase in cash and cash equivalents		60			4			160			224
Cash and cash equivalents at beginning of period		5			24			27			56
Cash and cash equivalents at end of period	$	65		$	28		$	187		$	280

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15. SUBSEQUENT EVENT

On May 2, 2006, our board of directors approved a plan to divest of our DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (Rowan) subsidiaries. DeSoto and Rowan are subsidiaries of Progress Energy Ventures, Inc. DeSoto owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Florida and Rowan owns a 925 MW dual-fuel combined cycle and combustion turbine electric generation facility in Rowan County, North Carolina. 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 total purchase price of approximately $405 million. We expect to use the proceeds from the sale to reduce debt.

The sale of DeSoto is expected to close during the second quarter of 2006 and the sale of Rowan is expected to close during the third quarter of 2006. Both sales are subject to state and federal regulatory approvals and customary closing conditions. In addition, the agreement for the sale of Rowan provides Southern Company with an option to terminate the agreement through June 15, 2006 without penalty. We expect to report DeSoto and Rowan as discontinued operations in the second quarter of 2006 and anticipate recording an estimated after-tax loss on the expected sale of approximately $70 million. The carrying amounts for the assets and liabilities of the discontinued operations disposal group included in the Consolidated Balance Sheet were as follows:

(in millions)	March 31, 2006		December 31, 2006
Total current assets	$	13	$	13
Total property, plant and equipment, net		477		480
Total other assets		25		25
Total current liabilities		1		1
Total long-term liabilities		20		19
Total capitalization		494		498

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

The following combined Management’s Discussion and Analysis is separately filed by Progress Energy, Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF). Information contained herein relating to PEC and PEF individually is filed by such company on its own behalf. As used in this report, Progress Energy [which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis] is at times referred to as “we”, “our” or “us.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF.

The following Management’s Discussion and Analysis contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS” and Item 1A, “Risk Factors” of the 2005 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

Amounts reported in the interim statements of income are not necessarily indicative of amounts expected for the respective annual or future periods due to the effects of seasonal temperature variations on energy consumption and the timing of maintenance on electric generating units, among other factors.

This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2005 Form 10-K.

RESULTS OF OPERATIONS

Our reportable business segments and their primary operations include:

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

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

·      Progress Ventures - primarily engaged in nonregulated electric generation operations and energy marketing activities mainly in Georgia, North Carolina and Florida, as well as natural gas drilling and production in Texas and Louisiana; and

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

The Corporate and Other segment includes businesses which do not meet the requirements for separate segment reporting disclosure. These businesses are engaged in other nonregulated business areas including holding company operations and Progress Energy Service Company, LLC (PESC) operations.

In 2005, we changed our reportable segments due to changes in the operations of certain businesses and the reclassification of our coal mining business as discontinued operations. In addition, with our sale of our share of Progress Telecom, LLC (PT LLC) in the first quarter of 2006, we reclassified PT LLC’s operations as discontinued operations. These reportable segment changes reflect the current reporting structure. 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, 2006 are compared to the same periods in 2005. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

OVERVIEW

For the quarter ended March 31, 2006, our net income was $45 million, or $0.18 per share, compared to net income of $93 million, or $0.38 per share, for the same period in 2005. The decrease in net income as compared to

50

prior year was due primarily to:

·   Impairment of goodwill related to our nonregulated plants in Georgia.

·   Unrealized losses recorded on contingent value obligations.

·   Additional outage expenses at PEC.

·   Additional estimated environmental remediation expenses at PEC.

·   Unfavorable retail sales at PEC, primarily due to weather.

·   The impact of tax levelization.

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

·   Increased interest expense.

Partially offsetting these items were:

 ·   Prior year severance expenses related to the 2005 cost-managment initiative.

·   Gain on sale of Level 3 stock acquired as part of the divestiture of PT LLC.

·   Increased wholesale excess generation margin at PEC.

·   The impact of restructuring a long-term coal supply contract.

Our segments contributed the following profits or losses for the three months ended March 31, 2006 and 2005:

	Three Months Ended March 31,
(in millions)	2006			2005
Business Segment
PEC	$	85		$	115
PEF		52			43
Progress Ventures		(35	)		7
Coal and synthetic fuels		14			(4	)
Total segment profit		116			161
Corporate and Other		(69	)		(57	)
Income from continuing operations		47			104
Discontinued operations, net of tax		(2	)		(11	)
Net income	$	45		$	93

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $85 million and $115 million for the three months ended March 31, 2006 and 2005, respectively. Results for 2006 were impacted by higher O&M expenses related to outages at nuclear facilities, additional estimated environmental remediation expenses, unfavorable weather and unfavorable retail customer growth and usage. These were partially offset by nonrecurring severance expenses in 2005 and favorable wholesale sales.

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Revenues

PEC’s revenues for the three months ended March 31, 2006 and 2005, and the percentage change by customer class were as follows:

(in millions)	Three Months Ended March 31,
Customer Class	2006			Change			% Change			2005
Residential	$	376		$	2			0.5		$	374
Commercial		226			11			5.1			215
Industrial		163			14			9.4			149
Governmental		20			1			5.3			19
Total retail revenues		785			28			3.7			757
Wholesale		192			18			10.3			174
Unbilled		(27	)		(8	)					(19	)
Miscellaneous		28			5			21.7			23
Total electric revenues		978			43			4.6			935
Less: Fuel revenues		(317	)		(46	)					(271	)
Revenues excluding fuel	$	661		$	(3	)		(0.5	)	$	664

PEC’s energy sales for the three months ended March 31, 2006 and 2005, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended March 31,
Customer Class	2006			Change			% Change			2005
Residential		4,417			(255	)		(5.5	)		4,672
Commercial		3,052			(28	)		(0.9	)		3,080
Industrial		2,933			2			0.1			2,931
Governmental		320			(7	)		(2.1	)		327
Total retail energy sales		10,722			(288	)		(2.6	)		11,010
Wholesale		3,958			20			0.5			3,938
Unbilled		(378	)		(75	)					(303	)
Total kWh sales		14,302			(343	)		(2.3	)		14,645

PEC’s revenues, excluding fuel revenues of $317 million and $271 million for the three months ended March 31, 2006 and 2005, respectively, decreased $3 million. The decrease in revenues is attributable primarily to unfavorable weather and unfavorable retail growth and usage, partially offset by increased wholesale revenues less fuel. The impact of weather was $15 million unfavorable with heating degree days 9 percent below prior year. Unfavorable retail growth and usage of $4 million was driven by a decline in the average usage per retail customer partially offset by an approximate increase in the average number of customers of 30,000 as of March 31, 2006, compared to March 31, 2005. The increase in wholesale revenues less fuel of $20 million was driven primarily by the impact of increased capacity under contract, higher excess generation sales due to favorable market conditions in the Pennsylvania-New Jersey-Maryland region and gains on forward sales of excess generation. The favorable increases in wholesale revenues less fuel were partially offset by the impact of unfavorable weather.

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 $360 million for the three months ended March 31, 2006, which represents

52

a $45 million increase compared to the same period in the prior year. Fuel used in electric generation increased $48 million to $296 million compared to the prior year. This increase is due to a $41 million increase in deferred fuel expense due to an increase in the fuel recovery rates for North Carolina and South Carolina. In addition, fuel used in generation increased $7 million due primarily to higher fuel costs which are being driven by rising coal, oil and natural gas prices partially offset by lower system requirements and a change in generation mix primarily due to lower gas and oil generation. Current year purchased power costs were $3 million lower than the three months ended March 31, 2005, primarily due to lower system requirements in the first quarter of 2006 partially offset by price increases.

Operation and Maintenance

O&M expenses were $256 million for the three months ended March 31, 2006, which represents a $32 million increase compared to the same period in 2005. O&M expenses increased $21 million due to outages at nuclear facilities and $21 million due to recording additional estimated environmental remediation expenses (See Note 12A). These were partially offset by $14 million of severance expense recorded in the prior year related to the 2005 cost-management initiative.

Depreciation and Amortization

Depreciation and amortization expense was $126 million for the three months ended March 31, 2006, which represents a $3 million decrease compared to the same period in 2005. Depreciation expense decreased $5 million due to lower Clean Smokestacks Act amortization, partially offset by the impact of changes in the depreciable base.

Total Other Income

Total other income of $6 million increased $3 million compared to the three months ended March 31, 2005 primarily due to a $5 million increase in interest income driven by cash equivalents and short-term investments.

Total Interest Charges, net

Interest expense increased $5 million for the three months ended March 31, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to the net impact of 2005 long-term debt issuances and redemptions.

Income Tax Expense

Income tax expense decreased $4 million for the three months ended March 31, 2006, as compared to the same period in the prior year, primarily due to the impact of lower earnings compared to prior year, partially offset by increases as discussed below. 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 increased by $2 million for the three months ended March 31, 2006 compared to no change for the three months ended March 31, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent and temporary deductions can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year. Income tax expense also increased due to the allocation of $6 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 that is no longer allocated in 2006 and the $3 million impact of a 2005 tax credit related to state audit settlements. See Corporate and Other below for additional information on the change in the tax benefit allocation in 2006.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $52 million and $43 million for the three months ended March 31, 2006 and 2005, respectively. The increase in profits for the three months ended March 31, 2006, when compared to 2005, was primarily due to lower O&M expenses, which includes nonrecurring severance expenses in 2005, and customer growth partially offset by higher interest expense. 

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Revenues

PEF’s revenues for the three months ended March 31, 2006 and 2005, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended March 31,
Customer Class	2006			Change			% Change			2005
Residential	$	506		$	75			17.4		$	431
Commercial		245			44			21.9			201
Industrial		83			20			31.7			63
Governmental		66			13			24.5			53
Retail revenue sharing		1			3						(2	)
Total retail revenues		901			155			20.8			746
Wholesale		69			(4	)		(5.5	)		73
Unbilled		1			6						(5	)
Miscellaneous		36			2			5.9			34
Total electric revenues		1,007			159			18.8			848
Less: Fuel and other pass-through revenues		(654	)		(153	)					(501	)
Revenues excluding fuel and pass-through revenues	$	353		$	6			1.7		$	347

PEF’s electric energy sales for the three months ended March 31, 2006 and 2005, and the amount and percentage change by customer class are as follows:

(in millions of kWh)	Three Months Ended March 31,
Customer Class	2006			Change			% Change			2005
Residential		4,311			(36	)		(0.8	)		4,347
Commercial		2,550			(21	)		(0.8	)		2,571
Industrial		1,006			66			7.0			940
Governmental		721			12			1.7			709
Total retail energy sales		8,588			21			0.2			8,567
Wholesale		1,007			(331	)		(24.7	)		1,338
Unbilled		(150	)		(47	)					(103	)
Total kWh sales		9,445			(357	)		(3.6	)		9,802

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $654 million and $501 million for the three months ended March 31, 2006 and 2005, respectively, increased $6 million. The increase in revenues is primarily due to favorable growth and usage of $3 million driven by an approximate average net increase in the number of customers of 31,000 as of March 31, 2006, compared to March 31, 2005, even though Winter Park customers were transferred from retail sales to wholesale sales in June of 2005. The increase in revenues is also due to a $3 million reduction in the provision for rate refund, increased industrial sales and favorable weather. These increases were partially offset by a $3 million decrease in wholesale revenues due to the expiration of certain contracts in 2005 partially offset by new contracts in 2005 and 2006, including the addition of Winter Park, and higher demand charges.

Expenses

Fuel and Purchased Power

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

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PEF’s fuel and purchased power expenses were $559 million for the three months ended March 31, 2006, which represents a $126 million increase compared to prior year. This increase is due to increases in fuel used in electric generation and purchased power expenses of $92 million and $34 million, respectively. Increased fuel costs in the current year account for $24 million of the increase in fuel used in electric generation. Increased deferred fuel expense of $68 million represents the remaining increase. Deferred fuel expenses increased due to an increase in fuel recovery rates on January 1, 2006. The increase in purchased power expense was primarily due to higher prices of purchases in the current year as a result of increased fuel costs.

Operation and Maintenance

O&M expenses were $166 million for the three months ended March 31, 2006, which represents a decrease of $23 million, when compared to the $189 million incurred during the three months ended March 31, 2005. O&M expenses decreased $14 million due to severance expense recorded in the prior year related to the 2005 cost-management initiative and $5 million related to a decreased workers’ compensation benefit accrual adjustment compared to the prior year and $5 million related to lower ECRC costs. ECRC costs are pass-through expenses and have no impact on earnings.

Depreciation and Amortization

Depreciation and amortization expense increased $25 million to $95 million for the three months ended March 31, 2006. The increase is primarily due to the amortization of $27 million in storm costs which began in August 2005. Storm cost amortization is a pass-through expense and has no impact on earnings.

Taxes other than on Income

Taxes other than on income increased $6 million to $73 million compared to the three months ended March 31, 2005. The increase is primarily due to higher gross receipts taxes and franchise taxes due to higher revenues partially offset by lower payroll and property taxes. Gross receipts taxes and franchise taxes are pass-through expenses and have no impact on earnings.

Total Interest Charges, net

Interest expense increased $7 million for the three months ended March 31, 2006, as compared to the same period in the prior year. This fluctuation is due primarily to the impact of long-term debt balances on interest expense. The higher long-term debt balances are primarily due to under-recovered storm and fuel costs. Interest costs associated with these items are recovered separately pursuant to fuel and storm recovery rate orders.

Income Tax Expense

Income tax expense increased $13 million for the three months ended March 31, 2006, as compared to the same period in the prior year, primarily due to higher earnings compared to prior year. In addition, income tax expense increased due to the allocation of $3 million of the Parent’s tax benefit not related to acquisition interest expense in 2005 that is no longer allocated in 2006. See Corporate and Other below for additional information on the change in the tax benefit allocation in 2006.

DIVERSIFIED BUSINESSES

Our diversified businesses consist of the Progress Ventures segment and the Coal and Synthetic Fuels segment. These businesses are explained in more detail below.

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PROGRESS VENTURES

The Progress Ventures segment is primarily engaged in nonregulated electric generation operations, energy marketing activities and natural gas drilling and production.

Progress Ventures generated losses of $35 million for the three months ended March 31, 2006 compared to profits of $7 million in the prior year. The decrease in earnings compared to prior year is due primarily to recognizing the $64 million pre-tax impairment ($39 million after-tax) on goodwill described below, increased mark-to-market losses on gas and power hedges due to market volatility, lower electricity contract margins and additional corporate overhead allocations. Although electric revenues increased during the quarter due to new full-requirements contracts and additional system requirements, electricity contract margins decreased primarily due to higher fuel and power prices. These factors were partially offset by increased gas production at our Texas and Louisiana facilities and higher gas prices. Although commodity price volatility impacted both the nonregulated electric generation and natural gas operations, the Progress Ventures segment earnings were not significantly impacted by this volatility due to the hedged nature of our portfolio.

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

	Three Months Ended March 31,
($ in millions)	2006			2005
Gas production in Bcf equivalent		7			5
Electric revenues	$	157		$	65
Gas revenues		69			33
Total revenues	$	226		$	98
Gross margin
In millions of $	$	63		$	48
As a % of revenues		28	%		49	%
Segment profits (losses)	$	(35	)	$	7

In accordance with accounting standards for goodwill, we monitor the carrying value of our goodwill associated with our Progress Ventures operations. The Progress Ventures electric generation operations are divided into three regions where it has generation plants: South Florida, North Carolina and Georgia. As part of our evaluation of certain business opportunities that may impact the future cash flows of our Georgia Region operations discussed under RECENT DEVELOPMENTS below, we performed an interim goodwill impairment test during the first quarter of 2006. As a result of this test, we recognized a pre-tax goodwill impairment loss of $64 million, the entire amount of goodwill assigned to Progress Ventures (See Note 6).

In accordance with accounting standards for long-lived assets, we monitor the carrying value of our long-lived assets associated with our Progress Ventures operations. Our analyses have continued to support the carrying value of the approximate $1.4 billion of long-lived and intangible assets at March 31, 2006. In May 2006, as discussed under RECENT DEVELOPMENTS below, we entered into transactions to sell the Rowan and DeSoto facilities and we anticipate recording an estimated loss on the sale in the second quarter of 2006. Future adverse changes in market conditions or changes in business conditions, including the manner in which the remaining long-lived assets are deployed, could require future impairment evaluations of the $940 million of remaining long-lived and intangible assets, which could result in an impairment charge.

RECENT DEVELOPMENTS

As part of our strategy to reduce Progress Venture’s risk profile and continue our efforts to reduce holding company debt through selected asset sales, we recently entered into the following transactions.

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During March and April 2006, we entered into three tolling agreements for the sale of approximately 1,039 MW of combustion turbine capacity and associated energy to Georgia Power Company (Georgia Power), a subsidiary of Southern Company. The three separate tolling agreements were executed by our Progress Ventures subsidiaries Washington County Power, LLC (302 MW), Walton County Power, LLC (436 MW) and MPC Generating, LLC (301 MW). The term of each of the agreements is from June 1, 2009 until May 31, 2024. Under the tolling agreements, we will receive payments for capacity, variable operating and maintenance costs, and startup costs. Georgia Power will deliver fuel (gas or oil as applicable) and receive electrical energy delivered onto the Georgia Integrated Transmission System (GITS) at each plant’s transmission interconnection. In conjunction with the tolling agreements, the Parent has incurred certain guaranty obligations on behalf of its subsidiaries with an initial amount of $23 million at March 31, 2006.

The foregoing capacity supported Progress Ventures’ obligations under its agreements with 16 Georgia Electric Membership Cooperatives (EMCs). Progress Ventures plans to satisfy those obligations in the future through a tolling agreement for the purchase of approximately 621 MW of combined cycle capacity from Southern Power Company (SPC), a subsidiary of Southern Company. The tolling agreement, which was executed in April 2006, begins on January 1, 2009 and terminates on December 31, 2015. Contractual access to this combined cycle resource will help support Progress Ventures’ obligations under its EMC agreements. Under the tolling agreement, we will pay SPC for capacity, variable operating and maintenance costs, and start up costs. We will also deliver fuel (gas or oil as applicable) to the combined cycle facility and receive electrical energy delivered onto the GITS. In conjunction with the SPC tolling agreement, the Parent may incur certain future guaranty obligations on behalf of its subsidiaries with an initial amount of $31 million.

On May 8, 2006, we entered into definitive agreements to sell our DeSoto County Generating Co., LLC (DeSoto) and Rowan County Power, LLC (Rowan) subsidiaries, including certain existing power supply contracts, to SPC for a total purchase price of approximately $405 million in cash, subject to adjustments as provided in the purchase agreements. DeSoto owns a 320 MW dual-fuel combustion turbine electric generation facility in DeSoto County, Florida. The sale of DeSoto is expected to close during the second quarter of 2006. Rowan owns a 925 MW dual-fuel combined cycle and combustion turbine electric generation facility in Rowan County, North Carolina. The sale of Rowan is expected to close during the third quarter of 2006. The closings of both the DeSoto and Rowan transactions are subject to state and federal regulatory approvals and customary closing conditions. In addition, the agreement for the sale of Rowan provides Southern Company with an option to terminate the agreement through June 15, 2006 without penalty.

We expect to report the operations of DeSoto and Rowan as discontinued operations in the second quarter of 2006 and anticipate recording an estimated after-tax loss on the expected sale of approximately $70 million in the second quarter of 2006 (See Note 15).

COAL AND SYNTHETIC FUELS

The Coal and Synthetic Fuels’ segment includes synthetic fuels operations and coal terminal operations. The following summarizes Coal and Synthetic Fuels’ segment profits:

	Three Months Ended March 31,
(in millions)	2006			2005
Synthetic fuel operations	$	3		$	(1	)
Coal terminals and marketing		18			8
Corporate overhead and other operations		(7	)		(11	)
Segment profits (losses)	$	14		$	(4	)

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SYNTHETIC FUEL OPERATIONS

The production and sale of synthetic fuels generate operating losses, but qualify for tax credits under Section 29/45K, which more than offset the effect of such losses. Our synthetic fuel operations resulted in the following for the three months ended March 31:

(in millions)	2006			2005
Tons sold		1.2			2.0
After-tax losses, excluding tax credits	$	(26	)	$	(38	)
Tax credits generated		35			54
Tax credit inflation adjustment		10			-
Tax credits reserved due to potential phase-out		(16	)		-
Tax credits reversed		-			(17	)
Net profit (loss)	$	3		$	(1	)

Prior to 2006, our synthetic fuel production levels and the amount of tax credits we could claim each year were a function of our projected consolidated regular federal income tax liability. With the redesignation of Section 29 tax credits as Section 45K general business credits, that limitation was removed effective January 1, 2006.

Synthetic fuels’ earnings for the three months ended March 31, 2006, as compared to the same period in the prior year, were positively impacted by the reversal of $17 million of tax credits in the first quarter of 2005 due to the loss on sale of Progress Rail, the recording of an $10 million inflation adjustment to 2005 tax credits and lower 2006 production which resulted in lower pre-tax losses. These were partially offset by the recording of fewer tax credits in 2006 due to lower production and recording a $16 million tax credit reserve at March 31, 2006 due to high oil prices which increased the potential for a phase-out of tax credits in 2006. 

See OTHER MATTERS below for additional information on the impact of oil prices on Section 29/45K tax credits, the results of our interim impairment review and a discussion of uncertainties surrounding our synthetic fuel production in 2006 and 2007.

COAL TERMINALS AND MARKETING

Coal terminals and marketing (Coal) operations blend and transload coal as part of the trucking, rail and barge network for coal delivery. This business also has an operating fee agreement with our synthetic fuel operations for procuring and processing of coal and the transloading and marketing of synthetic fuels. As a result of the relationship with the synthetic fuels operations, fluctuations in Coal’s annual earnings are typically related to production volumes at our synthetic fuel plants. Coal operations contributed earnings of $18 million and $8 million for the three months ended March 31, 2006 and 2005, respectively. During the first quarter of 2006 one of Coal’s supply contracts was restructured resulting in a payment of $103 million to Coal. These proceeds covered long-term coal supply commitments from 2005 through 2007 and will be recognized over the life of the contract as coal is received and the related inventory is utilized, effectively reducing the cost of future purchases. For the three months ended March 31, 2006, Coal recognized an $11 million pre-tax reduction in expense related to the restructured coal supply contract for 2005 coal commitments that were not delivered; future recognition of the proceeds is not expected to materially impact net income. In addition to the $11 million of reduced expenses noted above, Coal’s results were impacted by a $3 million pre-tax gain on the sale of Dixie Fuels Limited (Dixie Fuels) partially offset by lower revenues related to lower production at our synthetic fuels plants and higher cost of sales due to higher coal prices.

On March 1, 2006, we sold our 65 percent interest in Dixie Fuels to Kirby Corporation who owned the remaining 35 percent interest. Dixie Fuels operated four barge and tugboat units under long-term contracts with PEF and an outside party. The estimated $16 million cash purchase price will be finalized based on post-closing working capital adjustments. Proceeds from the sale will be used to reduce debt.

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CORPORATE OVERHEAD AND OTHER OPERATIONS

Corporate overhead and other operations recorded after-tax expenses of $7 million and $11 million for the three months ended March 31, 2006 and 2005, respectively. The decrease in after-tax expenses for 2006 is primarily due to additional corporate overhead allocations to Progress Ventures and severance expense recorded in the prior year related to the 2005 cost-management initiative.

CORPORATE AND OTHER

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

	Three Months Ended March 31,
(in millions)	2006			2005
Other interest expense	$	(76	)	$	(71	)
Contingent value obligations		(25	)		-
Tax levelization		(14	)		(3	)
Tax reallocation		-			(9	)
Other income tax benefit		30			29
Other		16			(3	)
Corporate and Other after-tax expense	$	(69	)	$	(57	)

Other interest expense, which includes elimination entries, increased $5 million to $76 million for the three months ended March 31, 2006 compared to $71 million for the three months ended March 31, 2005. Interest expense increased primarily due to a decrease in the elimination of intercompany interest expense resulting from lower intercompany debt balances. This was partially offset by having no revolving credit agreement (RCA) balances outstanding or related interest during the three months ended March 31, 2006 compared to $2 million of interest expense related to outstanding RCA balances during the three months ended March 31, 2005.

Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the 2000 acquisition of Florida Progress. Each CVO represents the right of the holder to receive contingent payments based on the performance of four synthetic fuel facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At March 31, 2006 and 2005, the CVOs had fair market values of approximately $33 million and $13 million, respectively. Progress Energy recorded unrealized losses of $25 million for the three months ended March 31, 2006 and an immaterial unrealized gain for the three months ended March 31, 2005, to record the changes in fair value of the CVOs, which had average unit prices of $0.33 and $0.13 at March 31, 2006 and 2005, 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 increased by $14 million and $3 million for the three months ended March 31, 2006 and 2005, respectively, in order to maintain an effective rate consistent with the estimated annual rate. The tax credits associated with our synthetic fuel operations and seasonal fluctuations in our annual earnings primarily drive the fluctuations in the effective tax rate for interim periods. The tax levelization adjustment will vary each quarter, but it will have no effect on net income for the year.

For the three months ended March 31, 2006, income tax expense was not increased by the allocation of the Parent’s income tax benefits not related to acquisition interest expense to profitable subsidiaries. Due to the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA) we will no longer allocate the Parent income tax benefits not related to acquisition interest expense to profitable subsidiaries beginning in 2006. Since 2002, Parent income tax benefits not related to acquisition interest expense were allocated to profitable subsidiaries, in accordance with a PUHCA order. For the three months ended March 31, 2005, income tax expense was increased by $9 million due to the allocation of the Parent’s income tax benefit.

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Other increased $19 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 (See Notes 3A and 11). In addition, expenses in 2005 included $4 million for South Carolina corporate license related to the South Carolina audit settlement.

DISCONTINUED OPERATIONS

PROGRESS TELECOM LLC

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

Based on the gross proceeds associated with the sale and after consideration of minority interest, we recorded an estimated after-tax gain on disposal of $24 million during the three months ended March 31, 2006. Discontinued PT LLC operations had earnings of $18 million for the three months ended March 31, 2006 and less than a million for the same period in 2005.

COAL MINING OPERATIONS

On November 14, 2005, our board of directors approved a plan to divest of five subsidiaries of Progress Fuels engaged in the coal mining business. On April 6, 2006, we signed an agreement to sell certain net assets of the coal mining business to Alpha Natural Resources, LLC for gross proceeds of $23 million plus a working capital adjustment. The sale closed on May 1, 2006. 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 by the end of 2006 (See Note 3C).

Discontinued coal mining operations incurred a net loss of $20 million for the three months ended March 31, 2006 and net income of $1 million for the three months ended March 31, 2005.

PROGRESS RAIL

On March 24, 2005, we completed the sale of Progress Rail to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds from the sale were approximately $429 million, consisting of $405 million base proceeds plus a working capital adjustment. Proceeds from the sale were used to reduce debt (See Note 3B).

Rail discontinued operations resulted in losses of $12 million for the three months ended March 31, 2005. Results for the three months ended March 31, 2006 do not include any income or loss from operations as the sale closed in the first quarter of 2005.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Progress Energy, Inc. is a holding company and, as such, has no operations of its own. Our primary cash needs at the Parent level are our common stock dividend and interest and principal payments on our $3.9 billion of senior unsecured debt. Our ability to meet these needs is dependent on the earnings and cash flows of the Utilities and our nonregulated subsidiaries, and the ability of our subsidiaries to pay dividends or repay funds to us.

Our other significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations and expenditures for our diversified businesses, primarily those of the Progress Ventures segment.

We rely upon our operating cash flow, primarily generated by the Utilities, commercial paper and bank facilities, and our ability to access the long-term debt and equity capital markets for sources of liquidity.

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The majority of our operating costs are related to the Utilities. Such costs are recovered from customers in accordance with various rate plans. We are allowed to recover certain fuel, purchased power and other costs incurred by PEC and PEF through their respective recovery clauses. The types of costs recovered through clauses vary by jurisdiction. Fuel price volatility can lead to over- or under-recovery of fuel costs, as changes in fuel prices are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility can be both a source of and a use of liquidity resources, depending on what phase of the cycle of price volatility we are experiencing. Changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows, but not materially affect net income.

Cash from operations, asset sales and limited ongoing equity sales from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans are expected to fund capital expenditures and common stock dividends for 2006. We expect to use excess cash proceeds, if any, to reduce debt. To the extent necessary, short-term and long-term debt may also be used as a source of liquidity.

We believe our internal and external liquidity resources will be sufficient to fund our current business plans. Risk factors associated with credit facilities and credit ratings are discussed in the “Risk Factors” section of our 2005 Form 10-K.

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

CASH FLOWS FROM OPERATIONS

Net cash provided by operating activities increased by $268 million for the three months ended March 31, 2006, when compared to the corresponding period in the prior year. The increase in operating cash flow was primarily due to a $115 million increase in the recovery of fuel costs at the Utilities, a $154 million increase from the change in accounts receivable, approximately $103 million of proceeds received from the restructuring of a long-term coal supply contract, and $62 million of storm restoration costs incurred in the prior year at PEF. These impacts were partially offset by a $155 million decrease from the change in accounts payable, primarily driven by the timing of purchases and payments to vendors at the Utilities, and reduced purchases at our nonregulated operations. In 2005, the Utilities requested and received approval from their respective state commissions for rate increases for fuel cost recovery, including amounts for previous under-recoveries. PEF also received approval from the FPSC authorizing PEF to recover $245 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004. See Note 4 for additional information.

INVESTING ACTIVITIES

Net cash used in investing activities increased by $183 million for the three months ended March 31, 2006, when compared to the corresponding period in the prior year. This is due primarily to a $295 million decrease in proceeds from sales of discontinued operations and other assets for 2006 when compared to the corresponding period in the prior year.

Excluding proceeds from sales of discontinued operations and other assets, cash used in investing activities decreased approximately $112 million in 2006 when compared with 2005. The decrease is due primarily to a $143 million decrease in net purchases of available-for-sale securities and other investments, partially offset by $32 million in additional capital expenditures for property and nuclear fuel additions. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning and benefit investment trusts. The increase in property additions is primarily due to higher spending at the Hines 4 facility and distribution projects at PEF, partially offset by lower spending at the Hines 3 facility.

During the 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 3A) and approximately $15 million in net cash proceeds from the sale of Dixie Fuels, net of cash divested. During the same period in 2005, proceeds from sales of discontinued operations and other assets primarily included $393 million in proceeds from the sale of Progress Rail in March 2005, net of cash divested (See Note 3B).

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FINANCING ACTIVITIES

Net cash used in financing activities was $508 million for the three months ended March 31, 2006, compared to net cash provided by financing activities of $163 million for the three months ended March 31, 2005, for a net decrease of $671 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, as discussed below, and a combination of cash and commercial paper proceeds.

On January 13, 2006, Progress Energy issued $300 million of 5.625% Senior Notes due 2016 and $100 million of Series A Floating Rate Senior Notes due 2010. These senior notes are unsecured. Interest on the Floating Rate Senior Notes will be based on three-month London Inter Bank Offering Rate (LIBOR) plus 45 basis points and will be reset quarterly. We used the net proceeds from the sale of these senior notes and a combination of available cash and commercial paper proceeds to retire the $800 million aggregate principal amount of our 6.75% Senior Notes on March 1, 2006. Pending the application of proceeds as described above, we invested the net proceeds in short-term, interest-bearing, investment-grade securities.

Progress Energy entered into a new $800 million 364-day credit agreement on November 21, 2005, which was restricted for the retirement of $800 million of 6.75% Senior Notes due March 1, 2006. On March 1, 2006, we retired $800 million of our 6.75% Senior Notes, thus effectively terminating the 364-day credit agreement.

On March 31, 2006, Progress Energy filed a shelf registration statement with the SEC to provide unlimited financing capacity. The registration statement became effective upon filing with the SEC and will allow Progress Energy to issue various securities, including Senior Debt Securities, Junior Subordinated Debentures, Common Stock, Preferred Stock, Stock Purchase Contracts, Stock Purchase Units, and Trust Preferred Securities and Guarantees. The Board of Directors has authorized the issuance and sale of up to $1 billion aggregate principal amount of various securities off the new shelf registration statement, in addition to $679 million of various securities, which were not sold from our prior shelf registration statement. Therefore, effective March 31, 2006, Progress Energy has the authority to issue and sell up to $1.679 billion aggregate principal amount of various securities.

On May 3, 2006, Progress Energy restructured its existing $1.13 billion five-year revolving credit agreement (RCA) with a syndication of financial institutions. The new RCA is scheduled to expire on May 3, 2011, and is replacing an existing $1.13 billion five-year facility, which was terminated effective May 3, 2006. The Progress Energy RCA will continue to be used to provide liquidity support for Progress Energy’s issuances of commercial paper and other short-term obligations. The new RCA still includes a defined maximum total debt to capital ratio of 68 percent and contains various cross-default and other acceleration provisions. However, the new RCA no longer includes a material adverse change representation for borrowings or a financial covenant for interest coverage. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of Progress Energy’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa2 by Moody’s and BBB- by S&P.

On May 3, 2006, PEC’s five-year $450 million credit facility was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of PEC’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P. The amended PEC RCA is still scheduled to expire on June 28, 2010.

On May 3, 2006, PEF’s five-year $450 million credit facility was amended to take advantage of favorable market conditions and reduce the pricing associated with the facility. Fees and interest rates under the RCA will continue to be determined based upon the credit rating of PEF’s long-term unsecured senior noncredit-enhanced debt, currently rated as Baa1 by Moody’s and BBB- by S&P. The amended PEF RCA is still scheduled to expire on March 28, 2010.

For the three months ended March 31, 2006 and 2005, we issued approximately 0.7 million shares and 1.4 million shares, respectively, resulting in approximately $28 million and $60 million in proceeds from our Investor Plus Stock Purchase Plan and our employee benefit and stock option plans, net of purchases of restricted shares. For the fiscal year 2006, we expect to realize approximately $100 million aggregate amount from the sale of stock through these plans.

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FUTURE LIQUIDITY AND CAPITAL RESOURCES

As of March 31, 2006, there were no material changes in our “Capital Expenditures,” “Other Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 of the 2005 Form 10-K, other than as described above under “Financing Activities.”

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

As of March 31, 2006, the current portion of our long-term debt was $109 million, which we expect to fund with cash from operations, proceeds from sales of assets and/or commercial paper borrowings. See Notes 3 and 15 for additional information on asset sales.

The following regulatory matters may impact our future liquidity and financing activities: PEC’s fuel cost recovery as discussed in Note 4, PEF’s recovery of storm costs as discussed in Note 4, and PEF’s ECRC filings for recovery of environmental costs as discussed in Note 12.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45). These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. Our guarantees also include standby letters of credit, surety bonds and guarantees in support of nuclear decommissioning. At March 31, 2006, we have issued $1.80 billion of guarantees for future financial or performance assurance. Included in this amount is $300 million of Parent-issued guarantees of certain payments of two wholly owned indirect subsidiaries (See Note 14). We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below BBB- or Baa3) by S&P or Moody’s, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. At March 31, 2006, no guarantee obligations had been triggered. If the guarantee obligations were triggered, the approximate amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for Progress Energy’s nonregulated portfolio and power supply agreements, was $558 million. While we believe that we would be able to meet this obligation with cash or letters of credit, if we cannot, our financial condition, liquidity and results of operations will be materially and adversely impacted.

At March 31, 2006, we have issued guarantees and indemnifications of certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, and for timely payment of obligations in support of our nonwholly owned synthetic fuel operations. Related to the sales of businesses, the latest notice period extends until 2012 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain environmental indemnifications have no limitations as to time or maximum potential future payments. In 2005, PEC entered into a contract with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a

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liability related to this indemnification (See Note 12B). PEC’s maximum exposure cannot be determined. At March 31, 2006, the maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $201 million, including $32 million at PEF. At March 31, 2006 and December 31, 2005, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $49 million and $41 million, respectively. These amounts include $16 million for PEC at March 31, 2006 and December 31, 2005, respectively, and $8 million for PEF at March 31, 2006. PEF had no liabilities related to guarantees and indemnifications to third parties at December 31, 2005. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

MARKET RISK AND DERIVATIVES

Under our risk management policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 9 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

As of March 31, 2006, our contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2005 Form 10-K.

OTHER MATTERS

SYNTHETIC FUELS TAX CREDITS

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

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

Total Section 29/45K credits generated through March 31, 2006 (including those generated by Florida Progress prior to our acquisition), were approximately $1.8 billion, of which $868 million has been used to offset regular federal income tax liability, $901 million is being carried forward as deferred tax credits and $16 million has been reserved due to the potential phase-out of tax credits due to high oil prices, as described below.

IMPACT OF CRUDE OIL PRICES

Although the Section 29/45K tax credit program is expected to continue through 2007, recent market conditions, world events and catastrophic weather events have increased the volatility and level of oil prices that could limit the amount of those credits or eliminate them entirely for 2006 and 2007. This possibility is due to a provision of

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Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the Annual Average Price) exceeds a certain threshold price (the Threshold Price), the amount of Section 29/45K tax credits is reduced for that year. Also, if the Annual Average Price increases high enough (the Phase-out Price), the Section 29/45K tax credits are eliminated for that year. The Threshold Price and the Phase-out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase-out Price for a year, the amount by which Section 29/45K tax credits are reduced will depend on where the Annual Average Price falls in that continuum. For example, for 2005, the Threshold Price was $53.20 per barrel and the Phase-out Price was $66.78 per barrel. If the Annual Average Price had been $59.99 per barrel, there would have been a 50 percent reduction in the amount of Section 29 tax credits for that year.

The Department of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three-month lag, the secretary of the Treasury finalizes the calculations three months after the year in question ends. The Annual Average Price for calendar year 2005 was published on April 11, 2006. Based on the Annual Average Price of $50.26, there was no phase-out of our synthetic fuel tax credits in 2005.

We estimate that the 2006 Threshold Price will be approximately $55 per barrel and the Phase-out Price will be approximately $69 per barrel, based on an estimated inflation adjustment for 2006. The monthly Domestic Crude Oil First Purchases Price published by the EIA has recently averaged approximately $6 lower than the corresponding monthly New York Mercantile Exchange (NYMEX) settlement price for light sweet crude oil. Through March 31, 2006, the average NYMEX settlement price for light sweet crude oil was $62 per barrel, and as of March 31, 2006, the average NYMEX futures price for light sweet crude oil for the remainder of calendar year 2006 was $69 per barrel. This results in a weighted-average annual price for light sweet crude oil of approximately $67 per barrel for calendar year 2006. Based upon the estimated 2006 Threshold Price and Phase-out Price, if oil prices for 2006 averaged this weighted price of approximately $67 per barrel for the entire year in 2006, we currently estimate that the synthetic fuel tax credit amount for 2006 would be reduced by approximately 47 percent. Therefore, we recorded approximately 53 percent of the value of the $35 million in tax credits generated during the first quarter of 2006 and reserved approximately $16 million of these credits. The final calculations of any reductions in the value of the tax credits will not be determined until the end of 2006 when final oil prices are known. Additional fluctuations in oil prices may cause quarterly adjustments to our results of operations and the amount of tax credits we record or reserve, either positive or negative, depending on current and futures oil prices at the end of the quarter, which impact the estimated weighted average annual price of oil for 2006.

In November 2005, the U.S. Senate passed Senate Bill 2020, the Tax Relief Act of 2005, which includes proposed modifications to the Section 29/45K synthetic fuel tax credit program. This legislation would provide synthetic fuel producers with additional certainty around future synthetic fuel production decisions. The proposed modifications include amendments of the phase-out calculation and the annual inflation adjustment for the value of the synthetic fuel tax credits. Under Senate Bill 2020, the Annual Average Price, Threshold Price and the Phase-out Price for 2006 and 2007 would be based on the calculated amounts for the previous calendar year. In addition, the annual inflation adjustment for the synthetic fuel tax credits for 2005, 2006 and 2007 would be eliminated. The U.S. House version of the Tax Reconciliation bill does not include these same provisions. The differences in the Senate and House versions of the bill will be reconciled in conference.

As noted above, the 2005 Annual Average Price did not cause a phase-out of the synthetic fuel tax credits related to synthetic fuel production in 2005. Therefore, if the provisions of Senate Bill 2020 regarding changes to the Section 29/45K synthetic fuel tax credit program were enacted into law, there would be no phase-out of these tax credits in calendar year 2006. However, we cannot predict with any certainty the price of oil for 2006 or 2007 and, therefore, we cannot predict what impact, if any, this proposed legislation would have on the value of tax credits in 2007.

Our future synthetic fuel production levels for 2006 and 2007 remain uncertain because we cannot predict with any certainty the Annual Average Price of oil for 2006 or 2007. If the March 31, 2006 average futures price level of $69 per barrel oil does not change during the remainder of 2006, and the provisions of Senate Bill 2020 regarding changes to the Section 29/45K synthetic fuel tax credit program are not enacted into law, it is unlikely that we will produce significant amounts of synthetic fuel during 2006 and could potentially reverse previously recorded credits associated with any 2006 synthetic fuel production. This could have a material adverse impact on our results of

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operations. We will continue to monitor the level of oil prices and retain the ability to adjust production based on future oil price levels.

Due to the previously discussed significant uncertainty surrounding our synthetic fuel production in 2006 and 2007, we evaluated our synthetic fuel and other related operating long-lived assets for impairment during the first quarter of 2006. We determined that no impairment of these assets was required. However, an increase in oil prices, the failure of the proposed tax legislation to be enacted into law, or a decrease in future synthetic fuel production and cash flows could require additional impairment evaluations in the future, which could result in a future impairment of some or all of the $103 million of assets used in our synthetic fuel operations. The majority of these assets will be fully depreciated by the end of 2007, the scheduled end of the synthetic fuel tax credit program. The outcome of this matter cannot be determined.

PERMANENT SUBCOMMITTEE

In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel, and other aspects of Section 29 and is not specific to our synthetic fuel operations. Progress Energy provided information in connection with this investigation. We cannot predict the outcome of this matter.

SALE OF PARTNERSHIP INTEREST

In June 2004, through our subsidiary Progress Fuels, we sold in two transactions a combined 49.8 percent partnership interest in Colona, one of our synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gains from the sales will be recognized on a cost recovery basis as the facility produces and sells synthetic fuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Gain recognition is dependent on the synthetic fuel production qualifying for Section 29/45K tax credits and the value of such tax credits as discussed above. Until the gain recognition criteria are met, gains from selling interests in Colona will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase-out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters in a calendar year. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted. As of March 31, 2006, a pre-tax gain on monetization of $3 million has been deferred. Based on the current level of oil prices, we cannot predict whether this gain will be recorded this year.

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

REGULATORY ENVIRONMENT

The Utilities’ operations in North Carolina, South Carolina and Florida are regulated by the NCUC, SCPSC and the FPSC, respectively. The electric businesses are also subject to regulation by the FERC, the NRC and other federal and state agencies common to the utility industry. In addition, until February 8, 2006, we were subject to SEC regulation as a registered holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Subsequent to the repeal of PUHCA, we became subject to additional regulation by the FERC. As a result of regulation, many of our fundamental business decisions, as well as the rate of return the Utilities are permitted to earn, are subject to the approval of these governmental agencies.

On May 5, 2006, the Florida state legislature passed a comprehensive energy bill. If signed by the governor, the legislation would create a new energy council tasked with developing a statewide energy policy, provide incentives to renewable energy sources and would foster the construction of new nuclear power plants, including streamlining the siting of nuclear power plants and related transmission facilities, exempting new nuclear plants from the FPSC bid rule and requiring the FPSC to issue rules authorizing alternative cost-recovery mechanisms for pre-construction costs and construction cost financing.

Due to the damage to electric utility facilities suffered during recent hurricanes, the FPSC and the Florida state

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legislature are continuing to review proposals that seek to minimize future damage and resulting customer outages. Several bills have been introduced in the legislature that would, among other things, promote the placement of electric facilities underground and impose more stringent utility infrastructure construction standards. While these bills did not pass in the current legislative session, similar rulemaking proceedings and workshops regarding changes in construction standards have been initiated by the FPSC. If enacted, these rules could materially increase PEF’s costs. We cannot predict the outcome of this matter.

On April 26, 2006, PEC submitted a license renewal application with the FERC seeking a 50-year license for its Tillery and Blewett hydroelectric generating plants. The license for these plants currently expires in April 2008 and the requested renewal will allow the plants to continue operations until 2058. The remaining phase of the application process will take approximately two years and includes review by the FERC and solicitation of public comment.

APPLICATIONS FOR NUCLEAR POWER PLANT LICENSES

We have announced that we are pursuing development of Combined License (COL) applications, which is not a commitment to build a nuclear plant but is a necessary step to keep open the option of building a potential plant or plants. On January 23, 2006, we announced that PEC had selected the Shearon Harris Nuclear Plant (Harris) site to evaluate for possible future nuclear expansion and we announced the selection of the Westinghouse Electric AP1000 reactor design as the technology upon which to base any potential application submission. We currently expect to file the application for the COL for PEC’s Harris site in late September or early October 2007. We expect to file the application for the COL for an as-yet unspecified site in Florida in late second quarter 2008. We plan to announce the selection of the Florida site in the second quarter of 2006. If we receive approval from the NRC, and if the decision to build is made, construction could begin as early as 2010, and a new plant could be in service around 2016. We estimate that it will take approximately 36 months for the NRC to review the COL applications and grant approval.

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/kWh for nuclear facilities for the first eight years of operation. The credit is limited to the first 6,000 MW of new nuclear generation in the United States and has an annual cap of $125 million per 1,000 MW of national MW capacity limitation allocated to the unit. In April 2006, the IRS provided interim guidance that the 6,000 MW of production tax credits generally will be allocated to new nuclear facilities which filed license applications with the NRC by December 31, 2008 and which were placed in service before January 1, 2021.

There is no guarantee that the interim guidance will be incorporated into the final regulations governing the allocation of production tax credits. Other utilities have announced plans to pursue new nuclear plants, and there is no guarantee that any nuclear plant constructed by us would qualify for these additional incentives.

ENVIRONMENTAL MATTERS

We are subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. We currently estimate total compliance costs for the Utilities, related to environmental laws and regulations addressing air and water quality, which will primarily be for capital expenditures, could be in excess of $1.0 billion each at PEC and PEF, respectively, through 2018, which is the latest compliance target date for current air and water quality regulations. These costs are eligible for regulatory recovery through either base rates or pass-through clauses. These environmental matters are discussed in further detail in Note 12. This discussion identifies specific environmental issues, the status of the issues, accruals associated with issue resolutions and our associated exposures. We accrue costs to the extent they are probable and can be reasonably estimated. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

NEW ACCOUNTING STANDARDS

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

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PEC

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PEC: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and OTHER MATTERS.

The following Management’s Discussion and Analysis and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS and Item 1A, “Risk Factors” in the 2005 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities decreased $25 million for the three months ended March 31, 2006, when compared to the corresponding period in the prior year. The decrease in operating cash flow was primarily due to approximately $174 million resulting from tax payments and timing of purchases and payments to vendors, largely offset by an $80 million increase related to the change in accounts receivable and a $41 million increase in the recovery of fuel costs. In 2005, PEC requested and received approval from the North Carolina and South Carolina state commissions for rate increases for fuel cost recovery, including amounts for previous under-recoveries.

Cash used in investing activities decreased $89 million for the three months ended March 31, 2006, when compared to the corresponding period in the prior year primarily due to net proceeds from available-for-sale securities and other investments for the period in 2006 versus net purchases for the period in 2005, partially offset by an increase in nuclear fuel additions related to nuclear facility outages. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

See Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, “LIQUIDITY AND CAPITAL RESOURCES”, for a discussion of PEC’s financing activities.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

As of March 31, 2006, PEC’s off-balance sheet arrangements and contractual obligations have not changed materially from what was reported in PEC’s 2005 Form 10-K.

MARKET RISK AND DERIVATIVES

Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 9 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

As of March 31, 2006, PEC’s contractual cash obligations and other commercial commitments have not changed materially from what was reported in PEC’s 2005 annual report on Form 10-K.

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PEF

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PEF: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and OTHER MATTERS.

The following Management’s Discussion and Analysis and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS and Item 1A, “Risk Factors” in the 2005 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

LIQUIDITY AND CAPITAL RESOURCES

PEF’s net cash provided by operating activities increased by $144 million for the three months ended March 31, 2006, when compared to the corresponding period in the prior year. The increase was due primarily to a $74 million increase in the recovery of fuel costs, $62 million of storm restoration costs incurred in the prior year, and $40 million related to lower tax payments. In 2005, PEF requested and received approval from the FPSC for rate increases for fuel cost recovery, including amounts for previous under-recoveries. PEF also received approval from the FPSC authorizing PEF to recover $245 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004. See Note 4 for additional information. These impacts were partially offset by a $72 million decrease from increased inventory levels, primarily coal, and timing of purchases and payments to vendors.

Cash used in investing activities increased $59 million for the three months ended March 31, 2006, when compared to the corresponding period in the prior year. The increase in cash used in investing activities is primarily due to a $55 million increase in net purchases of short-term investments included in available-for-sale securities and other investments and $30 million of property additions primarily related to higher spending at the Hines 4 facility and distribution projects, partially offset by lower spending at the Hines 3 facility and a $28 million decrease in nuclear fuel additions. Available-for-sale securities and other investments include marketable debt securities and investments held in nuclear decommissioning trusts.

See Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, LIQUIDITY AND CAPITAL RESOURCES, for a discussion of PEF’s financing activities.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk 

We are exposed to various risks related to changes in market conditions. We have a Risk Management Committee comprised of senior executives from various functional areas. The Risk Management Committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk for nonperformance by the counterparty. We minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. Additionally, in the normal course of business, some of our affiliates may enter into hedge transactions with one another (See Note 9).

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

PROGRESS ENERGY, INC.

Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2005.

INTEREST RATE RISK

Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at March 31, 2006, has changed from December 31, 2005. The total notional amount of fixed rate long-term debt at March 31, 2006, was $9.240 billion, with an average interest rate of 6.30% and fair market value of $9.455 billion. The total notional amount of variable rate long-term debt at March 31, 2006, was $1.411 billion, with an average interest rate of 3.89% 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, 2006, approximately 16.7 percent of consolidated debt, including interest rate swaps, was in floating rate mode compared to 12.8 percent at the end of 2005.

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

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

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

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

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

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CASH FLOW HEDGES

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

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

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

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

^(c)   Anticipated 10-year debt issue hedges terminated on March 1, 2006 with required mandatory cash settlement.

FAIR VALUE HEDGES

At March 31, 2006 and December 31, 2005, we had $150 million notional of fixed rate debt swapped to floating rate debt. Under terms of these swap agreements, we will receive a fixed rate and pay a floating rate based on 3-month LIBOR. At March 31, 2006 and December 31, 2005, the Utilities had no open interest rate fair value hedges.

Fair Value Hedges (dollars in millions)
Progress Energy, Inc.	Notional Amount	Receive	Pay(b)	Fair Value	Exposure (c)
Risk hedged at March 31, 2006
5.85% Notes due 10/30/2008	$100	4.10%	3-month LIBOR	$(3)	$(1)
7.10% Notes due 3/1/2011	50	4.65%	3-month LIBOR	(1)	-
Total	$150	4.28%(a)		$(4)	$(1)
Risk hedged at December 31, 2005
5.85% Notes due 10/30/2008	$100	4.10%	3-month LIBOR	$(2)	$(1)
7.10% Notes due 3/1/2011	50	4.65%	3-month LIBOR	-	-
Total	$150	4.28%(a)		$(2)	$(1)

^(a) Weighted average interest rate.

^(b) 3-month LIBOR rate was 5.00% at March 31, 2006 and 4.54% as of December 31, 2005.

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

MARKETABLE SECURITIES PRICE RISK

At March 31, 2006 and December 31, 2005, the fair value of our nuclear decommissioning trust funds was $1.175 billion and $1.133 billion, respectively, including $664 million and $640 million, respectively, for PEC and $511 million and $493 million, respectively, for PEF. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

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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, 2006 and December 31, 2005, the fair value of CVOs was $33 million and $7 million, respectively. At March 31, 2006, a hypothetical 10 percent change in the market price would not have had a material effect on our financial position, results of operations or cash flows.

COMMODITY PRICE RISK

We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of our ownership of energy-related assets. Our exposure to these fluctuations is significantly limited by the cost-based regulation of the Utilities. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, many of our long-term power sales contracts shift substantially all fuel responsibility to the purchaser. We also have oil price risk exposure related to synthetic fuel tax credits as discussed in the OTHER MATTERS section of Item 2.

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

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

GENERAL

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

ECONOMIC DERIVATIVES

Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. We manage open positions according to established policies and guidelines that limit our exposure to market risk and require daily reporting to management of financial exposures. Gains and losses from such contracts were not material to our or the Utilities’ results of operations for the three months ended March 31, 2006 and 2005. PEC did not have material outstanding positions in such contracts at March 31, 2006 and December 31, 2005. We and PEF did not have material outstanding positions in such contracts at March 31, 2006 and December 31, 2005, other than those receiving regulatory accounting treatment at PEF, as discussed below.

PEF has derivative instruments related to its exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause. At March 31, 2006, the fair values of these instruments were a $79 million short-term derivative asset position included in other current assets, a $56 million long-term derivative asset position included in other assets and deferred debits, a $4 million short-term derivative liability position included in other current liabilities and a $1 million long-term derivative liability position included in other liabilities and deferred credits. At December 31, 2005, the fair values of the instruments were a $77 million short-term derivative asset position included in other current assets, a $45 million long-term derivative asset position included in other assets and deferred debits and a $6 million long-term derivative liability position included in other liabilities and deferred credits.

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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.

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

	March 31, 2006					December 31, 2005
(in millions)	Progress Energy			PEC		Progress Energy			PEC
Fair value of assets	$	144		$	3	$	170		$	7
Fair value of liabilities		(21	)		-		(58	)		(4	)
Fair value, net	$	123		$	3	$	112		$	3

PEC

The information required by this item is incorporated herein by reference to the “Quantitative and Qualitative Disclosures about Market Risk” discussed above insofar as it relates to PEC.

PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC’s primary exposures are changes in interest rates with respect to long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds, and changes in energy related commodity prices. Other than as discussed above, PEC’s exposure to these risks has not materially changed since December 31, 2005.

PEF

Other than as discussed above, the information called for by Item 3 is omitted pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).

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Item 4: Controls and Procedures

Progress Energy, Inc.

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

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2006, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PEC

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

There has been no change in PEC’s internal control over financial reporting during the quarter ended March 31, 2006, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

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

There has been no change in PEF’s internal control over financial reporting during the quarter ended March 31, 2006, that has materially affected, or is reasonably likely to materially affect, PEF’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors of the 2005 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2005 Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes to the risk factors as set forth in the 2005 Form 10-K.

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

(a)  RESTRICTED STOCK AWARDS

(a)   Securities Delivered. On January 3, 2006 and March 14, 2006, 6,500 and 100,100 restricted shares, respectively, of our common stock were granted to certain key employees pursuant to the terms of the Progress Energy 2002 Equity Incentive Plan (EIP), which was approved by the Progress Energy’s shareholders on May 8, 2002. Section 9 of the EIP provides for the granting of Restricted Stock by the Organization and Compensation Committee of the Board of Directors, (the Committee) to key employees, including our Affiliates or any successor, and to our outside directors. The shares of common stock delivered pursuant to the EIP were acquired in market transactions directly for the accounts of the recipients and do not represent newly issued shares of Progress Energy.

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

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

 

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

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(c) ISSUER PURCHASES OF EQUITY SECURITIES FOR FIRST QUARTER OF 2006

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	42,000 (2)	$43.03	N/A	N/A
February 1- February 28	-	N/A	N/A	N/A
March 1 - March 31	100,100 (3)	$44.56	N/A	N/A
Total	142,100	$44.11	N/A	N/A

(1) As of March 31, 2006, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) The plan administrator purchased 35,500 shares of our common stock at an average price of $43.07 in open-market transactions to meet share delivery obligations under the 401(k). Open-market transactions were executed to purchase 6,500 shares of our common stock at an average price of $42.79 in connection with restricted stock awards that were granted to certain key employees pursuant to the terms of the EIP.

(3) Open-market transactions were executed to purchase 100,100 shares of our common stock at an average price of $44.56 in connection with restricted stock awards that were granted to certain key employees pursuant to the terms of the EIP.

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Item 6. Exhibits

(a) Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
10(a)	Amended Management Incentive Compensation Plan of Progress Energy, Inc., as amended January 1, 2006	X	X	X
10(b)	Progress Energy, Inc., Amended and Restated Management Deferred Compensation Plan, adopted as of January 1, 2000 (As Revised and Restated effective April 1, 2005)	X	X	X
10(c)	$1,130,000,000 5-Year Credit Agreement, dated as of May 3, 2006, among Progress Energy, Inc., Certain Lenders, Citibank, N.A. as Administrative Agent and SunTrust Bank as Issuing Bank	X
10(d)	Amendment dated May 3, 2006 to 5-1/4-Year $450,000,000 Credit Agreement, dated March 28, 2005, among PEC, Certain Lenders and Wachovia Bank, N.A. as Administrative Agent		X
10(e)	Amendment dated May 3, 2006 to 5-Year $450,000,000 Credit Agreement, dated March 28, 2005, between PEF, Certain Lenders and Bank of America, N.A. as Administrative Agent			X
10(f)	Benefits Agreement, dated May 12, 2006, between PEC and Don K. Davis		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

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32(d)	906 Certifications of Chief Financial Officer	X
32(e)	906 Certifications of Chief Executive Officer		X
32(f)	906 Certifications of Chief Financial Officer		X

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SIGNATURES

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

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY
	FLORIDA POWER CORPORATION
Date: May 9, 2006	(Registrants)
	By: /s/ Peter M. Scott III
	Peter M. Scott III
	Executive Vice President and Chief Financial Officer
	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer and Controller
	Progress Energy, Inc.
	Chief Accounting Officer
	Carolina Power & Light Company
	Florida Power Corporation