Duke Energy Progress 10Q 2009 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

o TRANSITION REPORT PURSUANT TO SECTION 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number	Exact name of registrants as specified in their charters, states of incorporation, addresses of principal executive offices, and telephone numbers	I.R.S. Employer Identification Number


1-15929	Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina	56-2155481

1-3382	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina	56-0165465

1-3274	Florida Power Corporation d/b/a Progress Energy Florida, Inc. 299 First Avenue North St. Petersburg, Florida 33701 Telephone: (727) 820-5151 State of Incorporation: Florida	59-0247770

NONE

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

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

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

Indicate by check mark whether each registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

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

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

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

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

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

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

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

At May 4, 2009, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	279,038,627

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.

TABLE OF CONTENTS
GLOSSARY OF TERMS

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

PART I. FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS

	Unaudited Condensed Interim Financial Statements:

	Progress Energy, Inc. (Progress Energy)
	Unaudited Condensed Consolidated Statements of Income
	Unaudited Condensed Consolidated Balance Sheets
	Unaudited Condensed Consolidated Statements of Cash Flows

	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
	Unaudited Condensed Consolidated Statements of Income
	Unaudited Condensed Consolidated Balance Sheets
	Unaudited Condensed Consolidated Statements of Cash Flows

	Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
	Unaudited Condensed Statements of Income
	Unaudited Condensed Balance Sheets
	Unaudited Condensed Statements of Cash Flows

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

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

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

ITEM 4T.	CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS

ITEM 1A.	RISK FACTORS

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

ITEM 6.	EXHIBITS

SIGNATURES

GLOSSARY OF TERMS

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

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

TERM	DEFINITION

2008 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2008
401(k)	Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
Audit Committee	Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART	Best Available Retrofit Technology
Broad River	Broad River LLC’s Broad River Facility
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CCO	Competitive Commercial Operations
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Ceredo	Ceredo Synfuel LLC
Clean Smokestacks Act	North Carolina Clean Smokestacks Act, enacted in June 2002
Coal Mining	Two Progress Fuels subsidiaries engaged in the coal mining business
the Code	Internal Revenue Code
CO2	Carbon dioxide
COL	Combined license
Colona	Colona Synfuel Limited Partnership, LLLP
Corporate and Other	Corporate and Other segment primarily includes the Parent, Progress Energy Service Company and miscellaneous other nonregulated businesses
CR1 and CR2	PEF’s Crystal River Units No. 1 and 2 coal-fired steam turbines
CR3	PEF’s Crystal River Unit No. 3 Nuclear Plant
CR4 and CR5	PEF’s Crystal River Units No. 4 and 5 coal-fired steam turbines
CVO	Contingent value obligation
D.C. Court of Appeals	U.S. Court of Appeals for the District of Columbia Circuit
DeSoto	DeSoto County Generating Co., LLC
DIG Issue C20	FASB Derivatives Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”
Dixie Fuels	Dixie Fuels Limited
DOE	United States Department of Energy
DSM	Demand-side management
Earthco	Four coal-based solid synthetic fuels limited liability companies of which three were wholly owned
ECCR	Energy Conservation Cost Recovery Clause
ECRC	Environmental Cost Recovery Clause
EIP	Equity Incentive Plan
EPACT	Energy Policy Act of 2005
EPC	Engineering, procurement and construction

ERO	Electric reliability organization
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company, LLC
FIN 45	FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIN 46R	FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51”
FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
the Florida Global Case	U.S. Global, LLC v. Progress Energy, Inc. et al
Florida Progress	Florida Progress Corporation
Florida RPS	Florida renewable portfolio standard
FPSC	Florida Public Service Commission
FRCC	Florida Reliability Coordinating Council
FSP	FASB Staff Position
FSP EITF 03-6-1	FASB Staff Position EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”
FSP FAS 115-2	FASB Staff Position FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”
FSP FAS 132R-1	FASB Staff Position FAS 132(R)-1, “Employers’ Disclosures about Post Retirement Benefit Plan Assets”
FSP FAS 157-2	FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157”
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
Gas	Natural gas drilling and production business
the Georgia Contracts	Full-requirements contracts with 16 Georgia electric membership cooperatives formerly serviced by CCO
Georgia Operations	Former reporting unit consisting of the Effingham, Monroe, Walton and Washington nonregulated generation plants in service and the Georgia Contracts
Global	U.S. Global, LLC
GridSouth	GridSouth Transco, LLC
Harris	PEC’s Shearon Harris Nuclear Plant
kV	Kilovolt
kVA	Kilovolt-ampere
kWh	Kilowatt-hours
Levy	Proposed nuclear plant in Levy County, Florida
LIBOR	London Inter Bank Offering Rate
MACT	Maximum achievable control technology
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in Part I, Item 2 of this Form 10-Q
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
MW	Megawatts
MWh	Megawatt-hours
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NC REPS	North Carolina Renewable Energy and Energy Efficiency Portfolio Standard
NCUC	North Carolina Utilities Commission
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC

the Notes Guarantee	Florida Progress’ full and unconditional guarantee of the Subordinated Notes
NOx	Nitrogen Oxides
NOx SIP Call	EPA rule which requires 22 states including North Carolina, South Carolina and Georgia (but excluding Florida) to further reduce emissions of nitrogen oxides
NSR	New Source Review requirements by the EPA
NRC	United States Nuclear Regulatory Commission
O&M	Operation and maintenance expense
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income
OPC	Florida’s Office of Public Counsel
OPEB	Postretirement benefits other than pensions
the Parent	Progress Energy, Inc. holding company on an unconsolidated basis
PEC	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
PEF	Florida Power Corporation d/b/a Progress Energy Florida, Inc.
PESC	Progress Energy Service Company, LLC
Power Agency	North Carolina Eastern Municipal Power Agency
Preferred Securities	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Affiliates	Five affiliated coal-based solid synthetic fuels facilities
Progress Energy	Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants	The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
Progress Fuels	Progress Fuels Corporation, formerly Electric Fuels Corporation
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
PUHCA 1935	Public Utility Holding Company Act of 1935, as amended
PUHCA 2005	Public Utility Holding Company Act of 2005
PVI	Progress Energy Ventures, Inc., formerly referred to as Progress Ventures, Inc.
QF	Qualifying facility
RCA	Revolving credit agreement
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
REC	Renewable energy certificates
Rockport	Indiana Michigan Power Company’s Rockport Unit No. 2
Robinson	PEC’s Robinson Nuclear Plant
RSU	Restricted stock unit
RTO	Regional transmission organization
SCPSC	Public Service Commission of South Carolina
Section 29	Section 29 of the Code
Section 29/45K	General business tax credits earned after December 31, 2005 for synthetic fuels production in accordance with Section 29
Section 316(b)	Section 316(b) of the Clean Water Act
(See Note/s “#”)	For all sections, this is a cross-reference to the Combined Notes to the Unaudited Condensed Interim Financial Statements contained in PART I, Item 1 of this Form 10-Q
SERC	SERC Reliability Corporation
S&P	Standard & Poor’s Rating Services
SFAS No. 5	Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”
SFAS No. 71	Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 87	Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions”
SFAS No. 109	Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
SFAS No. 115	Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities”

SFAS No. 123R	Statement of Financial Accounting Standards No. 123R, “Share-Based Payment”
SFAS No. 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS No. 141R	Statement of Financial Accounting Standards No. 141R, “Business Combinations”
SFAS No. 142	Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 143	Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 144	Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS No. 157	Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”
SFAS No. 158	Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS No. 159	Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”
SFAS No. 160	Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”
SFAS No. 161	Statement of Financial Accounting Standards No. 161, “Disclosures About Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”
SNG	Southern Natural Gas Company
SO2	Sulfur dioxide
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
Terminals	Coal terminals and docks in West Virginia and Kentucky
the Trust	FPC Capital I
the Utilities	Collectively, PEC and PEF
VIE	Variable interest entity
Ward	Ward Transformer site located in Raleigh, N.C.
Ward OU1	Operable unit for stream segments downstream from the Ward site
Ward OU2	Operable unit for further investigation at the Ward facility and certain adjacent areas

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

In addition, examples of forward-looking statements discussed in this Form 10-Q include, but are not limited to, statements made in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the sub-heading “Results of Operations” about trends and uncertainties; “Liquidity and Capital Resources” about operating cash flows, future liquidity requirements and estimated capital expenditures and “Other Matters” about our synthetic fuels tax credits, the effects of new environmental regulations, meeting anticipated demand in our regulated service territories, potential nuclear construction and changes in the regulatory environment.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and the Energy Policy Act of 2005 (EPACT); the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; the financial resources and capital needed to comply with environmental laws and renewable energy portfolio standards and our ability to recover related eligible costs under cost-recovery clauses or base rates; our ability to meet current and future renewable energy requirements; the inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, regulatory and financial risks; the impact on our facilities and businesses from a terrorist attack; weather and drought conditions that directly influence the production, delivery and demand for electricity; recurring seasonal fluctuations in demand for electricity; the ability to recover in a timely manner, if at all, costs associated with future significant weather events through the regulatory process; economic fluctuations and the corresponding impact on our customers, including downturns in the housing and consumer credit markets; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; the Progress Registrants’ ability to control costs, including operations and maintenance expense (O&M) and large construction projects; the ability of our subsidiaries to pay upstream dividends or distributions to Progress Energy, Inc. holding company (the Parent); the duration and severity of the current financial market distress that began in the third quarter of 2008; the ability to successfully access capital markets on favorable terms; the stability of commercial credit markets and our access to short- and long-term credit; the impact that increases in leverage may have on each of the Progress Registrants; the Progress Registrants’ ability to maintain their current credit ratings and the impact on the Progress Registrants’ financial condition and ability to meet their cash and other financial obligations in the event their credit ratings are downgraded; our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); the investment performance of our nuclear decommissioning trust funds; the investment performance of the assets of our pension and benefit plans and resulting impact on future funding requirements; the impact of goodwill impairments; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact our nonreporting subsidiaries.

These and other risk factors are detailed from time to time in the Progress Registrants’ filings with the SEC. Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors section in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2008 (2008 Form 10-K), which was filed with the SEC on March 2, 2009, and is updated for material changes, if any, in this Form 10-Q and in our other SEC filings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on the Progress Registrants.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

March 31, 2009

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
(in millions except per share data)
Three months ended March 31	2009			2008
Operating revenues	$	2,442		$	2,066
Operating expenses
Fuel used in electric generation		954			697
Purchased power		217			232
Operation and maintenance		453			443
Depreciation, amortization and accretion		280			206
Taxes other than on income		143			121
Other		2			2
Total operating expenses		2,049			1,701
Operating income		393			365
Other income (expense)
Interest income		4			7
Allowance for equity funds used during construction		39			23
Other, net		(1	)		(5	)
Total other income, net		42			25
Interest charges
Interest charges		179			161
Allowance for borrowed funds used during construction		(12	)		(8	)
Total interest charges, net		167			153
Income from continuing operations before income tax		268			237
Income tax expense		85			84
Income from continuing operations		183			153
Discontinued operations, net of tax		–			61
Net income		183			214
Net income attributable to noncontrolling interests, net of tax		(1	)		(5	)
Net income attributable to controlling interests	$	182		$	209
Average common shares outstanding – basic		277			260
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	0.66		$	0.57
Discontinued operations attributable to controlling interests, net of tax		–			0.23
Net income attributable to controlling interests	$	0.66		$	0.80
Dividends declared per common share	$	0.620		$	0.615
Amounts attributable to controlling interests
Income from continuing operations attributable to controlling interests, net of tax	$	182		$	149
Discontinued operations attributable to controlling interests, net of tax		–			60
Net income attributable to controlling interests	$	182		$	209

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

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	March 31, 2009			December 31, 2008
ASSETS
Utility plant
Utility plant in service	$	26,600		$	26,326
Accumulated depreciation		(11,441	)		(11,298	)
Utility plant in service, net		15,159			15,028
Held for future use		38			38
Construction work in progress		2,973			2,745
Nuclear fuel, net of amortization		466			482
Total utility plant, net		18,636			18,293
Current assets
Cash and cash equivalents		632			180
Receivables, net		844			867
Inventory		1,300			1,239
Regulatory assets		389			533
Derivative collateral posted		563			353
Income taxes receivable		30			194
Prepayments and other current assets		230			154
Total current assets		3,988			3,520
Deferred debits and other assets
Regulatory assets		2,845			2,567
Nuclear decommissioning trust funds		1,044			1,089
Miscellaneous other property and investments		443			446
Goodwill		3,655			3,655
Other assets and deferred debits		292			303
Total deferred debits and other assets		8,279			8,060
Total assets	$	30,903		$	29,873
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 279 million and 264 million shares issued and outstanding, respectively	$	6,764		$	6,206
Unearned ESOP shares (1 million shares)		(17	)		(25	)
Accumulated other comprehensive loss		(107	)		(116	)
Retained earnings		2,621			2,622
Total common stock equity		9,261			8,687
Noncontrolling interests		6			6
Total equity		9,267			8,693
Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		272			272
Long-term debt, net		11,133			10,387
Total capitalization		20,765			19,445
Current liabilities
Current portion of long-term debt		100			–
Short-term debt		630			1,050
Accounts payable		780			912
Interest accrued		154			167
Dividends declared		174			164
Customer deposits		286			282
Derivative liabilities		556			493
Other current liabilities		383			418
Total current liabilities		3,063			3,486
Deferred credits and other liabilities
Noncurrent income tax liabilities		888			818
Accumulated deferred investment tax credits		125			127
Regulatory liabilities		2,141			2,181
Asset retirement obligations		1,496			1,471
Accrued pension and other benefits		1,597			1,594
Capital lease obligations		230			231
Derivative liabilities		352			269
Other liabilities and deferred credits		246			251
Total deferred credits and other liabilities		7,075			6,942
Commitments and contingencies (Notes 14 and 15)
Total capitalization and liabilities	$	30,903		$	29,873

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

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Three months ended March 31	2009			2008
Operating activities
Net income	$	183		$	214
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		313			235
Deferred income taxes and investment tax credits, net		(26	)		5
Deferred fuel cost		128			24
Allowance for equity funds used during construction		(39	)		(23	)
Other adjustments to net income		63			(29	)
Cash provided (used) by changes in operating assets and liabilities
Receivables		5			390
Inventory		(62	)		4
Derivative collateral posted		(216	)		–
Prepayments and other current assets		(6	)		14
Income taxes, net		183			60
Accounts payable		(76	)		79
Other current liabilities		(62	)		(171	)
Other assets and deferred debits		35			(38	)
Other liabilities and deferred credits		(28	)		13
Net cash provided by operating activities		395			777
Investing activities
Gross property additions		(639	)		(618	)
Nuclear fuel additions		(37	)		(41	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			95
Purchases of available-for-sale securities and other investments		(716	)		(488	)
Proceeds from available-for-sale securities and other investments		706			473
Other investing activities		(5	)		(6	)
Net cash used by investing activities		(691	)		(585	)
Financing activities
Issuance of common stock		545			20
Dividends paid on common stock		(173	)		(159	)
Payments of short-term debt with original maturities greater than 90 days		(29	)		(176	)
Net (decrease) increase in short-term debt		(490	)		180
Proceeds from issuance of long-term debt, net		1,338			322
Retirement of long-term debt		(400	)		(80	)
Cash distributions to noncontrolling interests of consolidated subsidiaries		(1	)		(85	)
Other financing activities		(42	)		(69	)
Net cash provided (used) by financing activities		748			(47	)
Net increase in cash and cash equivalents		452			145
Cash and cash equivalents at beginning of period		180			255
Cash and cash equivalents at end of period	$	632		$	400
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	238		$	276

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

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

March 31, 2009

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
(in millions)
Three months ended March 31	2009			2008
Operating revenues	$	1,178		$	1,068
Operating expenses
Fuel used in electric generation		442			356
Purchased power		57			49
Operation and maintenance		259			248
Depreciation, amortization and accretion		117			126
Taxes other than on income		54			50
Other		–			(1	)
Total operating expenses		929			828
Operating income		249			240
Other income (expense)
Interest income		2			5
Allowance for equity funds used during construction		9			4
Other, net		(7	)		–
Total other income, net		4			9
Interest charges
Interest charges		57			58
Allowance for borrowed funds used during construction		(3	)		(2	)
Total interest charges, net		54			56
Income before income tax		199			193
Income tax expense		71			70
Net income		128			123
Preferred stock dividend requirement		1			1
Net income available to common stockholders	$	127		$	122

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

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	March 31, 2009			December 31, 2008
ASSETS
Utility plant
Utility plant in service	$	15,788		$	15,698
Accumulated depreciation		(7,429	)		(7,352	)
Utility plant in service, net		8,359			8,346
Held for future use		3			3
Construction work in progress		739			660
Nuclear fuel, net of amortization		359			376
Total utility plant, net		9,460			9,385
Current assets
Cash and cash equivalents		21			18
Receivables, net		480			502
Receivables from affiliated companies		15			29
Notes receivable from affiliated companies		120			55
Inventory		651			633
Deferred fuel cost		163			207
Income taxes receivable		22			98
Prepayments and other current assets		50			28
Total current assets		1,522			1,570
Deferred debits and other assets
Regulatory assets		1,279			1,243
Nuclear decommissioning trust funds		651			672
Miscellaneous other property and investments		203			197
Other assets and deferred debits		95			98
Total deferred debits and other assets		2,228			2,210
Total assets	$	13,210		$	13,165
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,092		$	2,083
Unearned ESOP common stock		(17	)		(25	)
Accumulated other comprehensive loss		(35	)		(35	)
Retained earnings		2,204			2,278
Total common stock equity		4,244			4,301
Noncontrolling interests		4			4
Total equity		4,248			4,305
Preferred stock		59			59
Long-term debt, net		3,708			3,509
Total capitalization		8,015			7,873
Current liabilities
Short-term debt		–			110
Accounts payable		315			377
Payables to affiliated companies		61			82
Interest accrued		56			59
Customer deposits		87			82
Derivative liabilities		60			82
Other current liabilities		186			173
Total current liabilities		765			965
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,162			1,111
Accumulated deferred investment tax credits		115			115
Regulatory liabilities		995			987
Asset retirement obligations		1,141			1,122
Accrued pension and other benefits		860			856
Other liabilities and deferred credits		157			136
Total deferred credits and other liabilities		4,430			4,327
Commitments and contingencies (Notes 14 and 15)
Total capitalization and liabilities	$	13,210		$	13,165

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

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Three months ended March 31	2009			2008
Operating activities
Net income	$	128		$	123
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		141			151
Deferred income taxes and investment tax credits, net		32			6
Deferred fuel cost		61			42
Allowance for equity funds used during construction		(9	)		(4	)
Other adjustments to net income		25			17
Cash provided (used) by changes in operating assets and liabilities
Receivables		15			38
Receivables from affiliated companies		14			13
Inventory		(20	)		8
Prepayments and other current assets		(14	)		17
Income taxes, net		106			50
Accounts payable		(33	)		22
Payables to affiliated companies		(21	)		(13	)
Other current liabilities		(35	)		(28	)
Other assets and deferred debits		18			(19	)
Other liabilities and deferred credits		(11	)		(4	)
Net cash provided by operating activities		397			419
Investing activities
Gross property additions		(181	)		(173	)
Nuclear fuel additions		(28	)		(41	)
Purchases of available-for-sale securities and other investments		(420	)		(193	)
Proceeds from available-for-sale securities and other investments		407			185
Changes in advances to affiliated companies		(65	)		(85	)
Other investing activities		–			(4	)
Net cash used by investing activities		(287	)		(311	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		(200	)		–
Net decrease in short-term debt		(110	)		–
Proceeds from issuance of long-term debt, net		595			322
Retirement of long-term debt		(400	)		–
Changes in advances from affiliated companies		–			(154	)
Other financing activities		9			(3	)
Net cash (used) provided by financing activities		(107	)		164
Net increase in cash and cash equivalents		3			272
Cash and cash equivalents at beginning of period		18			25
Cash and cash equivalents at end of period	$	21		$	297
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	77		$	76

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

FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

March 31, 2009

UNAUDITED CONDENSED STATEMENTS of INCOME
(in millions)
Three months ended March 31	2009			2008
Operating revenues	$	1,262		$	996
Operating expenses
Fuel used in electric generation		512			341
Purchased power		160			183
Operation and maintenance		202			203
Depreciation, amortization and accretion		160			76
Taxes other than on income		88			71
Total operating expenses		1,122			874
Operating income		140			122
Other income (expense)
Interest income		1			1
Allowance for equity funds used during construction		30			19
Other, net		–			(2	)
Total other income, net		31			18
Interest charges
Interest charges		67			50
Allowance for borrowed funds used during construction		(9	)		(6	)
Total interest charges, net		58			44
Income before income tax		113			96
Income tax expense		24			29
Net income		89			67
Preferred stock dividend requirement		1			1
Net income available to common stockholders	$	88		$	66

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

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	March 31, 2009			December 31, 2008
ASSETS
Utility plant
Utility plant in service	$	10,630		$	10,449
Accumulated depreciation		(3,950	)		(3,885	)
Utility plant in service, net		6,680			6,564
Held for future use		35			35
Construction work in progress		2,234			2,085
Nuclear fuel, net of amortization		107			106
Total utility plant, net		9,056			8,790
Current assets
Cash and cash equivalents		20			19
Receivables, net		362			362
Receivables from affiliated companies		7			15
Inventory		650			606
Regulatory assets		226			326
Derivative collateral posted		535			335
Prepayments and other current assets		159			139
Total current assets		1,959			1,802
Deferred debits and other assets
Regulatory assets		1,567			1,324
Nuclear decommissioning trust funds		393			417
Miscellaneous other property and investments		36			37
Other assets and deferred debits		82			101
Total deferred debits and other assets		2,078			1,879
Total assets	$	13,093		$	12,471
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,273		$	1,116
Accumulated other comprehensive loss		(1	)		(1	)
Retained earnings		2,372			2,284
Total common stock equity		3,644			3,399
Preferred stock		34			34
Long-term debt, net		4,182			4,182
Total capitalization		7,860			7,615
Current liabilities
Short-term debt		130			371
Notes payable to affiliated companies		514			72
Accounts payable		445			514
Payables to affiliated companies		52			55
Interest accrued		56			51
Customer deposits		199			200
Derivative liabilities		496			380
Other current liabilities		169			128
Total current liabilities		2,061			1,771
Deferred credits and other liabilities
Noncurrent income tax liabilities		701			634
Accumulated deferred investment tax credits		10			12
Regulatory liabilities		1,029			1,076
Asset retirement obligations		355			349
Accrued pension and other benefits		495			494
Capital lease obligations		215			216
Derivative liabilities		275			209
Other liabilities and deferred credits		92			95
Total deferred credits and other liabilities		3,172			3,085
Commitments and contingencies (Notes 14 and 15)
Total capitalization and liabilities	$	13,093		$	12,471

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

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Three months ended March 31	2009			2008
Operating activities
Net income	$	89		$	67
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		166			80
Deferred income taxes and investment tax credits, net		(18	)		15
Deferred fuel cost (credit)		67			(18	)
Allowance for equity funds used during construction		(30	)		(19	)
Other adjustments to net income		32			6
Cash (used) provided by changes in operating assets and liabilities
Receivables		(10	)		40
Receivables from affiliated companies		8			(7	)
Inventory		(43	)		(8	)
Derivative collateral posted		(204	)		–
Prepayments and other current assets		2			(3	)
Income taxes, net		72			43
Accounts payable		(43	)		70
Payables to affiliated companies		(3	)		(33	)
Other current liabilities		19			35
Other assets and deferred debits		17			(17	)
Other liabilities and deferred credits		(9	)		19
Net cash provided by operating activities		112			270
Investing activities
Gross property additions		(462	)		(446	)
Nuclear fuel additions		(9	)		–
Purchases of available-for-sale securities and other investments		(273	)		(247	)
Proceeds from available-for-sale securities and other investments		279			247
Changes in advances to affiliated companies		–			149
Proceeds from sales of assets to affiliated companies		–			8
Other investing activities		(2	)		(2	)
Net cash used by investing activities		(467	)		(291	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Net decrease in short-term debt		(241	)		–
Retirement of long-term debt		–			(80	)
Changes in advances from affiliated companies		442			95
Contributions from parent		155			–
Other financing activities		1			–
Net cash provided by financing activities		356			14
Net increase (decrease) in cash and cash equivalents		1			(7	)
Cash and cash equivalents at beginning of period		19			23
Cash and cash equivalents at end of period	$	20		$	16
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	160		$	198

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

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

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

Each of the following combined notes to the unaudited condensed interim financial statements of the Progress Registrants are applicable to Progress Energy, Inc. but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF. The notes that are not listed below for PEC or PEF are not, and shall not be deemed to be, part of PEC’s or PEF’s financial statements contained herein.

Registrant	Applicable Notes

PEC	1, 2, 4, 6, 8 through 11, and 13 through 15

PEF	1, 2, 4, 6, 8 through 11, and 13 through 15

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED INTERIM FINANCIAL STATEMENTS

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. ORGANIZATION

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.

PROGRESS ENERGY

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

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 12 for further information about our segments.

PEC

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

PEF

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

B. BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2008 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, 2008 (2008 Form 10-K).

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.

The amount of gross receipts tax, franchise taxes and other excise taxes included in electric operating revenues and taxes other than on income in the statements of income were as follows:


	Three Months Ended March 31,
(in millions)	2009		2008
Progress Energy	$	79	$	64
PEC		26		24
PEF		53		40

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants’ financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods.

In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Certain amounts for 2008 have been reclassified to conform to the 2009 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 (VIEs) 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).

In general, we determine whether we are the primary beneficiary of a VIE through a qualitative analysis of risk that identifies which variable interest holder absorbs the majority of the financial risk and variability of the VIE. In performing this analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE’s variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity. If the qualitative analysis is inconclusive, a specific quantitative analysis is performed in accordance with FIN 46R. For purposes of the following disclosures, the maximum loss amounts represent the maximum exposure that would be absorbed by the Progress Registrants in the event that all of the assets of the VIE are deemed worthless, including any additional costs that the Progress Registrants would incur.

PROGRESS ENERGY

In addition to the following variable interests listed for PEC and PEF, Progress Energy, through its subsidiary Progress Fuels Corporation (Progress Fuels), is the primary beneficiary of, and consolidates, Ceredo Synfuel, LLC (Ceredo), a coal-based solid synthetic fuels production facility that qualified for federal tax credits under Section 45K of the Internal Revenue Code (the Code). See Note 1C in the 2008 Form 10-K for discussion of our variable interest in Ceredo. There were no changes to our assessment of the primary beneficiary during 2008 or for the period ended March 31, 2009. No financial or other support has been provided to Ceredo during the periods presented. At March 31, 2009, we had no assets and $20 million of liabilities related to the legal and tax indemnifications provided to the buyer included in other liabilities and deferred credits in the Progress Energy Consolidated Balance Sheets. The ultimate resolution of the indemnifications could result in adjustments to the loss on disposal in future periods. The creditors of Ceredo do not have recourse to the general credit of Progress Energy. See Note 3D for additional information on the disposal of Ceredo and Note 15B for a general discussion of guarantees.

PEC

VARIABLE INTEREST ENTITIES FOR WHICH PEC IS THE PRIMARY BENEFICIARY

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. PEC’s variable interests are debt and equity investments in the two VIEs. PEC performed quantitative analyses to determine the primary beneficiaries of the two VIEs. The primary factors in the analyses were the estimated economic lives of the partnerships and their net cash flow projections, estimates of available tax credits, and the likelihood of default on debt and other commitments. There were no changes to PEC’s assessment of the primary beneficiary during 2008 or for the period ended March 31, 2009. No financial or other support has been provided to the VIEs during the periods presented. At March 31, 2009, PEC had assets of $40 million, substantially all of which was reflected in miscellaneous other property and investments, $16 million in long-term debt, $7 million in other liabilities and deferred credits and $4 million in accounts payable in the PEC Consolidated Balance Sheets related to the two VIEs. The assets of the two VIEs are collateral for, and can only be used to settle, their obligations. The creditors of these VIEs do not have recourse to the general credit of PEC and there are no other arrangements that could expose PEC to losses.

OTHER VARIABLE INTERESTS

PEC has an equity investment in, and consolidates, one limited partnership investment fund that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. The investment fund accounts for the 17 partnerships on the equity method of accounting. PEC also has an interest in one power plant resulting from long-term power purchase contracts. PEC’s only significant exposure to variability from the power purchase contracts results from fluctuations in the market price of fuel used by the entity’s plants to produce the power purchased by PEC. We are able to recover these fuel costs under PEC’s fuel clause. The generation capacity of the entity’s power plant is approximately 847 megawatts (MW). PEC has requested the necessary information to determine if the investment fund’s 17 partnerships and the power plant owner are VIEs or to identify the primary beneficiaries; all entities from which the necessary financial information was requested declined to provide the information to PEC, and, accordingly, PEC has applied the information scope exception in FIN 46R, paragraph 4(g), to the 17 partnerships and the power plant. PEC believes that if it is determined to be the primary beneficiary of these entities, the effect of consolidating the power plant and the investment fund consolidating the 17 partnerships would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings or cash flows. However, because PEC has not received any financial information from the counterparties, the impact cannot be determined at this time.

PEF

The following information is provided for PEF’s significant variable interests in VIEs for which PEF is not the primary beneficiary:

PEF has a prepayment clause in a building capital lease with a special purpose entity that is a VIE. In accordance with the lease agreement, PEF is not required to make any lease payments over the last 20 years of the lease, during which period $51 million of rental expense will be recorded in the PEF Statements of Income. The prepayment clause is PEF’s only variable interest in the VIE and, therefore, PEF’s exposure to loss primarily relates to the recovery of the prepayments through future use of the rental property. PEF performed qualitative and quantitative analyses and concluded that it is not the primary beneficiary of the VIE. The primary factors in the analyses were the lease term, the fact that the lease payments are not variable interests, the likelihood of construction and casualty risks to the building and the existence of insurance to offset those risks, and the estimated fair value of the building at the end of the lease term. There were no changes to PEF’s assessment of the primary beneficiary during 2008 or for the period ended March 31, 2009. No financial or other support has been provided to the VIE during the periods presented. At March 31, 2009, PEF had a $5 million prepayment included in other assets and deferred debits on the PEF Balance Sheets. No liabilities associated with the prepayment clause were recorded. The aggregate maximum exposure to loss at March 31, 2009, is $51 million, which represents the loss if the maximum prepayment of rent at the end of year 20 was not recovered through future use of the rental property or from third-party insurers at that time.

PEF has a residual value guarantee in an operating railcar lease agreement with a special purpose entity that is a VIE. The lease agreement has an early termination clause that permits PEF to terminate the lease in certain

circumstances. If PEF terminates the lease in accordance with the agreement, it must sell the railcars and remit the proceeds to the lessor plus any amount for which the residual value guarantee exceeds the realized value of the equipment. The residual value guarantee is PEF’s primary variable interest in the VIE and, therefore, PEF’s exposure to loss is from the potential decrease in the fair value of the railcars. PEF performed qualitative and quantitative analyses and concluded that it is not the primary beneficiary of the VIE. The primary factors in the analyses were the terms of the lease, the probability of exercising the early termination clause, and the estimated fair value of the railcars. There were no changes to PEF’s assessment of the primary beneficiary during 2008 or for the period ended March 31, 2009. No financial or other support has been provided to the VIE during the periods presented. No liabilities associated with the residual value guarantee were recorded at March 31, 2009, because the early termination clause was not exercised. The aggregate maximum exposure to loss at March 31, 2009, is $18 million, which represents the maximum loss if the early termination clause were exercised in 2009 and the related railcars were deemed worthless.

2.	NEW ACCOUNTING STANDARDS

FSP FAS 157-2, “Effective Date of FASB Statement No. 157”

In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP FAS 157-2), which for us and the Utilities delayed the effective date of SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), for all nonfinancial assets and nonfinancial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. The adoption of SFAS No. 157, including FSP FAS 157-2, did not have a material impact on our or the Utilities' financial position or results of operations. See Note 9 for information regarding our implementation of SFAS No. 157 and FSP FAS 157-2.

SFAS No. 141R, “Business Combinations”

In December 2007, the FASB issued SFAS Statement No. 141R, “Business Combinations” (SFAS No. 141R), which introduces significant changes in the accounting for business acquisitions. SFAS No. 141R considerably broadens the definition of a “business” and a “business combination,” which should result in an increased number of transactions or other events that will qualify as business combinations. Other significant changes include the expensing of all acquisition-related transaction costs and most acquisition-related restructuring costs, the fair value remeasurement of certain earn-out arrangements and the discontinuance of the expense at acquisition of acquired-in-process research and development. SFAS No. 141R was effective for us for business combinations for which the acquisition date is on or after January 1, 2009. The adoption of SFAS No. 141R did not have any impact on our or the Utilities' financial position or results of operations.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”

In conjunction with the issuance of SFAS No. 141R, in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160), which introduces significant changes in the accounting for noncontrolling interests in a partially owned consolidated subsidiary. SFAS No. 160 was adopted concurrently with the effective date of SFAS No. 141R, which for us was January 1, 2009. See Note 6B for information regarding our first quarter 2009 implementation of SFAS No. 160. The adoption of SFAS No. 160 resulted in a change in presentation of the financial statements and additional disclosures but did not have a material impact on our or the Utilities' financial position or results of operations.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”

On January 1, 2009, we implemented SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (SFAS No. 161), which requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. See Note 11 for information regarding our first quarter 2009 implementation of SFAS No. 161. The adoption of SFAS No. 161 did not have a material impact on our or the Utilities' financial position or results of operations.

FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”

On January 1, 2009, we implemented FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1), which requires that certain unvested share-based payment awards (e.g. restricted stock) that contain nonforfeitable rights to dividends or dividend equivalents be included in the computation of earnings per share using the two-class method. FSP EITF 03-6-1 required a retrospective adjustment for all prior-period earnings per share data. The adoption of FSP EITF 03-6-1 did not have a material impact on our or the Utilities' financial position, results of operations or earnings per share amounts.

New FSPs for Fair Value Measurement and Disclosures and Other-Than-Temporary Impairments

In April 2009, the FASB issued three FSPs for guidance on accounting for fair value measurement and other-than-temporary impairments.

FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That are Not Orderly,” provides guidance on determining fair value when market activity has decreased for an asset or liability. FSP FAS 107-1 and APB 28-1, “Interim Disclosures About Fair Value of Financial Instruments,” increases the frequency of fair value disclosures required by SFAS No. 107, “Disclosures of Fair Value of Financial Instruments,” from annual only to quarterly.

FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2), revises the recognition and reporting requirements for other-than-temporary impairments of debt securities and increases the frequency of disclosures for debt and equity securities. Under FSP FAS 115-2, if an entity intends to sell an impaired debt security or more likely than not will be required to sell the security before recovery of its amortized cost basis less any current-period credit loss, an other-than-temporary impairment must be recognized currently in earnings equal to the difference between the investment’s amortized cost and its fair value at the balance sheet date.

The three FSPs are effective for us for the three month period ending June 30, 2009. Their adoption will change certain disclosures in the notes to the financial statements, but we do not expect their adoption to have a material impact on our or the Utilities’ financial position or results of operations.

FSP FAS 132R-1, “Employers’ Disclosures about Post Retirement Benefit Plan Assets”

In December 2008, the FASB issued FSP FAS 132R-1, “Employers’ Disclosures about Post Retirement Benefit Plan Assets” (FSP FAS 132R-1), which requires additional disclosures on the investment allocation decision making process, the fair value of each major category of plan assets and the inputs and valuation techniques used to remeasure the fair value of plan assets. FSP FAS 132R-1 is effective for us on December 31, 2009. The adoption of FSP FAS 132R-1 will change certain disclosures in the notes to the financial statements but we do not expect the adoption of FSP FAS 132R-1 to have a material impact on our or the Utilities’ financial position or results of operations.

3.	DIVESTITURES

A.	TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky (Terminals) for $71 million in gross cash proceeds. The terminals had a total annual capacity in excess of 40 million tons for transloading, blending and storing coal and other commodities. Proceeds from the sale were used for general corporate purposes. During the three months ended March 31, 2008, we recorded an after-tax gain of $46 million on the sale of these assets. The accompanying consolidated financial statements reflect the operations of Terminals as discontinued operations.

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

December 31, 2007. The accompanying consolidated statements of income reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

Results of discontinued operations for the three months ended March 31 for Terminals and Synthetic Fuels were as follows:


(in millions)	2008
Revenues	$	17
Earnings before income taxes and noncontrolling interest		10
Income tax benefit, including tax credits and tax levelization		3
Earnings attributable to noncontrolling interests of synthetic fuel		(1	)
Net earnings from discontinued operations attributable to controlling interests		12
Gain on disposal of discontinued operations, including income tax expense of $7		46
Earnings from discontinued operations attributable to controlling interests	$	58

B.	COAL MINING BUSINESSES

On March 7, 2008, we sold the remaining operations of Progress Fuels subsidiaries engaged in the coal mining business (Coal Mining) for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. These assets included Powell Mountain Coal Co. and Dulcimer Land Co., which consisted of about 30,000 acres in Lee County, Va. and Harlan County, Ky. As a result of the sale, during the three months ended March 31, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.

The accompanying consolidated financial statements reflect Coal Mining as discontinued operations. Results of Coal Mining discontinued operations for the three months ended March 31 were as follows:


(in millions)	2008
Revenues	$	2
Loss before income taxes		(7	)
Income tax benefit		1
Net loss from discontinued operations		(6	)
Gain on disposal of discontinued operations, including income tax expense of $2		7
Earnings from discontinued operations	$	1

C.	OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations in 2008 are amounts related to adjustments of our prior sales of other diversified businesses, primarily natural gas drilling and production business (Gas) and Progress Rail Services Corporation (Progress Rail). These adjustments are mainly due to the finalization of working capital and in connection with guarantees and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters (See Note 15B). The ultimate resolution of these matters could result in additional adjustments in future periods. For the three months ended March 31, 2008, we recorded additional gains of $1 million, net of tax.

D.	CEREDO SYNTHETIC FUELS INTERESTS

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

During the three months ended March 31, 2008, we recognized previously deferred gains on disposal of $5 million based on the final value of the 2007 Section 29/45K tax credits. The operations of Ceredo ceased as of December 31, 2007, and are recorded as discontinued operations for all periods presented. See discussion of the abandonment of our synthetic fuels operations at Note 3A. In connection with the disposal, Progress Fuels and Progress Energy provided guarantees and indemnifications for certain legal and tax matters to the buyer. The ultimate resolution of these matters could result in adjustments to the loss on disposal in future periods. See general discussion of guarantees at Note 15B.

4.	REGULATORY MATTERS

A.	PEC RETAIL RATE MATTERS

FUEL COST RECOVERY

On May 7, 2009, PEC filed with the SCPSC for a decrease in the fuel rate charged to its South Carolina ratepayers. PEC is asking the SCPSC to approve a $13 million decrease in fuel rates driven by declining fuel prices. If approved, the decrease would take effect July 1, 2009, and would decrease residential electric bills by $2.05 per 1,000 kilowatt-hours (kWh), or 2.0 percent, for fuel cost recovery. A hearing on the matter has been scheduled by the SCPSC for June 11, 2009. We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT AND ENERGY-EFFICIENCY COST RECOVERY

During 2007, the North Carolina legislature passed comprehensive energy legislation, which became law on August 20, 2007. Among other provisions, the law allows the utility to recover the costs of demand-side management (DSM) and energy-efficiency programs through an annual DSM clause. The law allows PEC to capitalize those costs intended to produce future benefits and authorizes the NCUC to approve other forms of financial incentives to the utility for DSM and energy-efficiency programs. DSM programs include, but are not limited to, any program or initiative that shifts the timing of electricity use from peak to nonpeak periods and includes load management, electricity system and operating controls, direct load control, interruptible load and electric system equipment and operating controls. PEC has implemented a series of DSM and energy-efficiency programs and will continue to pursue additional programs. In 2008, PEC filed for NCUC approval of multiple DSM and energy-efficiency programs. The majority of the programs has been approved by the NCUC or is pending further review. We cannot predict the outcome of the DSM and energy-efficiency filings pending further approval by the NCUC or whether the programs will produce the expected operational and economic results.

On June 6, 2008, and as subsequently amended, PEC filed an application with the NCUC for approval of a DSM and energy-efficiency clause to recover the costs of these programs and a return on the costs. On November 14, 2008, the NCUC issued an order allowing PEC to implement the rates requested in PEC’s November 14, 2008 revision to its initial application. The new rates were implemented on December 1, 2008 increasing residential electrical bills by $0.74 per 1,000 kWh, or 0.8 percent. The new rates will be subject to true-up when a final order is received in the cost-recovery proceeding. On December 9, 2008, the North Carolina Public Staff filed an Agreement and Stipulation of Partial Settlement with PEC and some of the other parties to the proceedings. The NCUC held a hearing on the matter on January 7, 2009. We cannot predict the outcome of this matter.

PEC filed a petition on November 30, 2007, with the SCPSC seeking authorization to create a deferred account for DSM and energy-efficiency expenses. On December 21, 2007, the SCPSC issued an order granting PEC’s petition. On June 27, 2008, PEC filed an application with the SCPSC to establish procedures that encourage investment in cost-effective energy-efficient technologies and energy conservation programs and approve the establishment of an annual rider to allow recovery for all costs associated with such programs, as well as the recovery of appropriate incentives for investing in such programs. On January 23, 2009, PEC filed a Stipulation Agreement between PEC and some of the other parties to the proceeding. On May 6, 2009, the SCPSC approved the Stipulation Agreement.

PEF RETAIL RATE MATTERS

BASE RATE FILING

As a result of a base rate proceeding in 2005, PEF is party to a base rate settlement agreement that was effective with the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009.

On March 20, 2009, in anticipation of the expiration of its current base rate settlement agreement, PEF filed with the FPSC a proposal for an increase in base rates effective January 1, 2010. In its filing, PEF requested the FPSC to approve calendar year 2010 as the projected test period for setting new base rates and approve annual rate relief for PEF of $499 million, which includes PEF’s petition for a combined $76 million of new base rates in 2009 as discussed below. The request for increased base rates is based, in part, on investments PEF is making in its generating fleet and in its transmission and distribution systems. If approved by the FPSC, this portion of the new base rates would increase residential bills by approximately $9.07 per 1,000 kWh, or 7.1 percent, effective January 1, 2010. A ruling by the FPSC is expected in November 2009. We cannot predict the outcome of this matter.

Included within the base rate proposal is a request for an interim base rate increase of $13 million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a limited proceeding to include in base rates revenue requirements of $63 million for the repowered Bartow power plant, which is expected to begin commercial operation in June 2009. If approved by the FPSC, PEF’s petitions for a combined $76 million of new base rates would increase residential bills by approximately $4.76 per 1,000 kWh, or 3.9 percent, effective July 1, 2009. On May 7, 2009, the staff of the FPSC recommended that PEF be allowed to increase its base rates, subject to refund, by a total of $70 million, effective the first billing cycle 30 days following the commercial operation in-sevice date of the repowered Bartow power plant. However, a ruling by the FPSC is expected later in May 2009. We cannot predict the outcome of this matter.

FUEL COST RECOVERY

On April 6, 2009, PEF received approval from the FPSC to reduce its 2009 fuel cost-recovery factors by an amount sufficient to achieve a $206 million reduction in fuel charges to retail customers as a result of effective fuel purchasing strategies and lower fuel prices. The approval reduces residential customers’ fuel charges by $6.90 per 1,000 kWh, or 5.0 percent, starting with the first April 2009 billing cycle. Commercial and industrial customers will see similar reductions.

In 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $135 million, plus interest, of alleged excessive past fuel recovery charges and sulfur dioxide (SO2) allowance costs during the period 1996 to 2005. The OPC claimed that although Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) were designed to burn a blend of coals, PEF failed to act to lower ratepayers’ costs by purchasing the most economical blends of coal. During the period specified in the petition, PEF’s costs recovered through fuel recovery clauses were annually reviewed for prudence and approval by the FPSC. On October 10, 2007, the FPSC issued its order rejecting most of the OPC’s contentions. However, the FPSC found that PEF had not been prudent in purchasing a portion of its coal requirements during the period from 2003 to 2005. Accordingly, the FPSC ordered PEF to refund its ratepayers $14 million, inclusive of interest, over a 12-month period beginning January 1, 2008. The refund was returned to ratepayers through a reduction of prior year under-recovered fuel costs. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish a separate docket on the prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. On February 2, 2009, the OPC filed direct testimony in this hearing alleging that during 2006 and 2007, PEF collected excessive fuel costs and SO2 allowance costs of $61 million before interest. The OPC claimed that these excessive costs were attributed to PEF’s ongoing practice of not blending the most economical sources of coal at its CR4 and CR5 plants. A hearing on PEF’s 2006 and 2007 coal purchases was held April 13-15, 2009. During the hearing, the OPC reduced the alleged excessive fuel costs to $33 million before interest. We expect a decision by the FPSC in June 2009. PEF believes its coal procurement practices have been prudent. We cannot predict the outcome of this matter.

NUCLEAR COST RECOVERY

On April 6, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear preconstruction costs for PEF’s proposed nuclear plant in Levy County, Florida (Levy), which the FPSC had authorized to be collected in 2009. The approval reduces residential customers’ nuclear cost-recovery charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first April 2009 billing cycle. Commercial and industrial customers will see similar reductions.

On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 as well as the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to help mitigate the initial price impact on its customers, as part of its filing, PEF has proposed collecting certain costs over a five-year period, with associated carrying costs. The deferral would result in a nuclear cost-recovery charge of $6.69 per 1,000 kWh for residential customers, which is approximately half of the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery rule. If approved, the charges would begin with the first January 2010 billing cycle. The FPSC has scheduled hearings in this matter for September 8-11, 2009, with a decision expected in October 2009. We cannot predict the outcome of this matter.

OTHER MATTERS

On March 20, 2009, PEF filed a petition with the FPSC for expedited approval of the deferral of $53 million in 2009 pension expenses and the authorization to charge $33 million in estimated 2009 storm hardening expenses to its storm damage reserve. The deferral of pension expense will not result in a change in PEF’s 2009 retail rates or prices, nor will charging storm hardening expenses to the storm damage reserve. PEF requested that the deferral of pension expense continue until the recovery of these costs is provided for in FPSC-approved base rates. We cannot predict the outcome of this matter.

GOODWILL

We account for goodwill in accordance with SFAS No. 142 “Goodwill and Other Intangible Assets”, which requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist. For our utility segments, the goodwill impairment tests are performed at the utility segment level. We performed the annual goodwill impairment tests for both the PEC and PEF segments as of April 1, 2008, each of which indicated no impairment. We are in the process of finalizing the annual goodwill impairment tests as of April 1, 2009, for both the PEC and PEF segments. While these tests are not fully completed, we do not believe the results of the tests will indicate any impairment.

The carrying amounts of goodwill at March 31, 2009 and December 31, 2008, for reportable segments PEC and PEF, were $1.922 billion and $1.733 billion, respectively. The amounts assigned to PEC and PEF are recorded in our Corporate and Other business segment.

6.	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)	2009		2008
Weighted-average common shares – basic		277		260
Net effect of dilutive stock-based compensation plans		–		–
Weighted-average shares – fully dilutive		277		260

B. RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

The consolidated financial statements include the accounts of Progress Energy and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of our subsidiary, Progress Telecom Holdings LLC and several variable interest entities (see Note 1C).

The following table presents changes in total equity for the year to date:



(in millions)	Total Common Stock Equity			Noncontrolling Interests			Total Equity
Balance, December 31, 2008	$	8,687		$	6		$	8,693
Net income		182			1			183
Other comprehensive income		9			–			9
Comprehensive income								192
Issuance of shares through offerings and stock-based compensation plans (See Note 6D)		565			–			565
Dividends paid and declared		(182	)		–			(182	)
Distributions to noncontrolling interest		–			(1	)		(1	)
Balance, March 31, 2009	$	9,261		$	6		$	9,267



(in millions)	Total Common Stock Equity			Noncontrolling Interests			Total Equity
Balance, December 31, 2007	$	8,395		$	84		$	8,479
Net income		209			5			214
Other comprehensive loss		(8	)		–			(8	)
Comprehensive income								206
Issuance of shares through offerings and stock-based compensation plans (See Note 6D)		53			–			53
Dividends paid and declared		(159	)		–			(159	)
Contributions from noncontrolling interest					2			2
Distributions to noncontrolling interest		–			(85	)		(85	)
Balance, March 31, 2008	$	8,490		$	6		$	8,496

PEC

The consolidated financial statements include the accounts of PEC and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of several variable interest entities (see Note 1C).

The following table presents changes in total equity for the year to date:



(in millions)	Total Common Stock Equity			Noncontrolling Interests		Total Equity
Balance, December 31, 2008	$	4,301		$	4	$	4,305
Net income		128			–		128
Other comprehensive income		–			–		–
Comprehensive income							128
Issuance of shares through stock-based compensation plans		17			–		17
Dividends paid to parent		(200	)		–		(200	)
Preferred stock dividends at stated rate		(1	)		–		(1	)
Tax benefit dividend		(1	)		–		(1	)
Balance, March 31, 2009	$	4,244		$	4	$	4,248



(in millions)	Total Common Stock Equity			Noncontrolling Interests		Total Equity
Balance, December 31, 2007	$	3,752		$	4	$	3,756
Net income		123			–		123
Other comprehensive loss		(5	)		–		(5	)
Comprehensive income							118
Issuance of shares through stock-based compensation plans		29			–		29
Preferred stock dividends at stated rate		(1	)		–		(1	)
Balance, March 31, 2008	$	3,898		$	4	$	3,902

PEF

Interim disclosures of changes in equity are required if the reporting entity has less than wholly-owned subsidiaries, of which PEF has none. Therefore, an equity reconciliation for PEF has not been provided.

C. COMPREHENSIVE INCOME

Progress Energy
	Three Months Ended March 31,
(in millions)	2009			2008
Net income	$	183		$	214
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $-, respectively)		1			1
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $-)		1			–
Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of $(4) and $6)		6			(9	)
Other (net of tax expense of $-)		1			–
Other comprehensive income (loss)		9			(8	)
Comprehensive income		192			206
Comprehensive income attributable to noncontrolling interests		(1	)		(5	)
Comprehensive income attributable to controlling interests	$	191		$	201

PEC
	Three Months Ended March 31,
(in millions)	2009		2008
Net income	$	128	$	123
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $3)		–		(5	)
Other comprehensive loss		–		(5	)
Comprehensive income	$	128	$	118

PEF
	Three Months Ended March 31,
(in millions)	2009		2008
Net income	$	89	$	67
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $3)		–		(4	)
Other comprehensive loss		–		(4	)
Comprehensive income	$	89	$	63

D. COMMON STOCK

At December 31, 2008, we had 500 million shares of common stock authorized under our charter, of which approximately 264 million were outstanding. For the three months ended March 31, 2009 and 2008, respectively, we issued approximately 15.5 million shares and 1.0 million shares of common stock resulting in approximately $545 million and $20 million in net proceeds. Included in these amounts were approximately 0.6 million shares and 0.4 million shares, respectively, for net proceeds of approximately $22 million and $19 million, respectively, to meet the requirements of the Progress Energy 401(k) Savings & Stock Ownership Plan and the Investor Plus Stock Purchase Plan.

The 15.5 million shares disclosed above also included the Parent’s issuance of 14.4 million shares of common stock at a public offering price of $37.50 per share on January 12, 2009. Net proceeds from this offering were $523 million. We used $100 million of the proceeds to reduce the Parent’s revolving credit agreement (RCA) borrowings and the remainder was used for general corporate purposes.

7.	PREFERRED STOCK OF SUBSIDIARIES

As discussed in Note 10 in the 2008 Form 10-K, all of our preferred stock was issued by the Utilities. The preferred stock is considered temporary equity due to certain provisions that could require us to redeem the preferred stock for cash. In the event of a default by PEC or PEF equivalent to the payment of four quarterly dividends on the preferred stock, the holders of the preferred stock are entitled to elect a majority of PEC or PEF’s respective Board of Directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities’ respective Board of Directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share plus any accumulated unpaid dividends except for PEF’s 4.75%, $100 par value class which does not have a liquidation preference. Each holder of PEC’s preferred stock is entitled to one vote. Each holder of PEF’s preferred stock has no right to vote except for certain circumstances regarding dividends payable on preferred stock in default or potential changes to the preferred stock’s rights and preferences.

8.	DEBT AND CREDIT FACILITIES

Material changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2008, are as follows.

On January 15, 2009, PEC issued $600 million of First Mortgage Bonds, 5.30% Series due 2019. A portion of the proceeds was used to repay the maturity of PEC’s $400 million 5.95% Senior Notes, due March 1, 2009. The remaining proceeds were used to repay PEC’s outstanding short-term debt and for general corporate purposes.

On February 3, 2009, the Parent repaid $100 million of the $600 million outstanding balance at December 31, 2008, borrowed under its RCA with proceeds from our 14.4 million share common stock issuance discussed in Note 6D. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining $500 million outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity.

On March 19, 2009, the Parent issued an aggregate $750 million of Senior Notes consisting of $300 million of 6.05% Senior Notes due 2014 and $450 million of 7.05% Senior Notes due 2019. A portion of the proceeds was used to fund PEF’s capital expenditures through an equity contribution. The remaining proceeds will be used for general corporate purposes.

9.	FAIR VALUE MEASUREMENTS

We implemented SFAS No. 157 as of January 1, 2008, for all recurring financial assets and liabilities. The adoption of SFAS No. 157 for recurring financial assets and liabilities did not have a material impact on our or the Utilities' financial position or results of operations. We utilized the deferral provision of FSP FAS 157-2 for all nonrecurring nonfinancial assets and liabilities within its scope. Major categories of our assets and liabilities to which the deferral applied included reporting units and long-lived asset groups measured at fair value for impairment purposes, asset retirement obligations initially recognized at fair value, and nonfinancial liabilities for exit and disposal costs and indemnifications initially measured at fair value. During the quarter ended March 31, 2009, neither our or the Utilities’ nonfinancial assets or liabilities were subject to remeasurement. Therefore, the adoption of FSP FAS 157-2 did not have a material impact on our or the Utilities’ financial position or results of operations.

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

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

priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

Level 3 – The pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods where quoted prices or other observable inputs are not available.

The following tables set forth by level within the fair value hierarchy our and the Utilities’ financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 2009. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Progress Energy
(in millions)	Level 1		Level 2			Level 3			Total
Assets:
Commodity derivatives	$	–	$	5		$	–		$	5
Nuclear decommissioning trust funds		621		423			–			1,044
Other marketable securities		25		39			–			64
Total assets	$	646	$	467		$	–		$	1,113

Liabilities:
Commodity derivatives	$	–	$	(858	)	$	(43	)	$	(901	)
CVO derivatives		–		(27	)		–			(27	)
Total liabilities	$	–	$	(885	)	$	(43	)	$	(928	)

PEC
(in millions)	Level 1		Level 2			Level 3			Total
Assets:
Interest rate derivatives	$	–	$	1		$	–		$	1
Nuclear decommissioning trust funds		422		229			–			651
Other marketable securities		8		–			–			8
Total assets	$	430	$	230		$	–		$	660

Liabilities:
Commodity derivatives	$	–	$	(107	)	$	(23	)	$	(130	)

PEF
(in millions)	Level 1		Level 2			Level 3			Total
Assets:
Commodity derivatives	$	–	$	5		$	–		$	5
Nuclear decommissioning trust funds		199		194			–			393
Total assets	$	199	$	199		$	–		$	398

Liabilities:
Commodity derivatives	$	–	$	(751	)	$	(20	)	$	(771	)

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

Commodity and interest rate derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity and interest rate derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 11 for discussion of risk management activities and derivative transactions.

Nuclear decommissioning trust funds reflect the assets of the Utilities’ nuclear decommissioning trusts, as discussed in Note 13 of the 2008 Form 10-K. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments, and are classified within Level 2.

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

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the 2008 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less than active market and are classified as Level 2.

The following tables set forth a reconciliation of changes in the fair value of our and the Utilities’ commodity derivatives classified as Level 3 in the fair value hierarchy.

Progress Energy
(in millions)	2009			2008
Derivatives, net at January 1	$	(41	)	$	26
Total gains (losses), realized and unrealized:
Included in earnings		–			–
Included in other comprehensive income		–			–
Deferred as regulatory assets and liabilities, net		(2	)		29
Purchases, issuances and settlements, net		–			–
Transfers in (out) of Level 3, net		–			–
Derivatives, net at March 31	$	(43	)	$	55

PEC
(in millions)	2009			2008
Derivatives, net at January 1	$	(22	)	$	6
Total gains (losses), realized and unrealized:
Included in earnings		–			–
Included in other comprehensive income		–			–
Deferred as regulatory assets and liabilities, net		(1	)		6
Purchases, issuances and settlements, net		–			–
Transfers in (out) of Level 3, net		–			–
Derivatives, net at March 31	$	(23	)	$	12

PEF
(in millions)	2009			2008
Derivatives, net at January 1	$	(19	)	$	20
Total gains (losses), realized and unrealized:
Included in earnings		–			–
Included in other comprehensive income		–			–
Deferred as regulatory assets and liabilities, net		(1	)		23
Purchases, issuances and settlements, net		–			–
Transfers in (out) of Level 3, net		–			–
Derivatives, net at March 31	$	(20	)	$	43

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

Transfers in (out) of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers into or out of Level 3 during the periods ended March 31, 2009 and 2008.

10.	BENEFIT PLANS

We have noncontributory defined benefit retirement plans that provide pension benefits for substantially all full-time employees. We also have supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, we provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria.

The components of the net periodic benefit cost for the respective Progress Registrants for the three months ended March 31 were:

Progress Energy
	Pension Benefits						Other Postretirement Benefits
(in millions)	2009			2008			2009			2008
Service cost	$	10		$	12		$	2		$	2
Interest cost		34			31			9			8
Expected return on plan assets		(35	)		(41	)		(1	)		(2	)
Amortization of actuarial loss (a)		12			3			1			1
Other amortization, net (a)		2			–			1			1
Net periodic cost	$	23		$	5		$	12		$	10

(a) Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2008 Form 10-K.

PEC
	Pension Benefits						Other Postretirement Benefits
(in millions)	2009			2008			2009			2008
Service cost	$	4		$	6		$	1		$	1
Interest cost		16			14			5			4
Expected return on plan assets		(17	)		(16	)		(1	)		(1	)
Amortization of actuarial loss		2			2			1			–
Other amortization, net		1			–			–			–
Net periodic cost	$	6		$	6		$	6		$	4

PEF
	Pension Benefits						Other Postretirement Benefits
(in millions)	2009			2008			2009		2008
Service cost	$	5		$	4		$	1	$	1
Interest cost		14			13			3		3
Expected return on plan assets		(15	)		(21	)		–		–
Amortization of actuarial loss		9			–			–		–
Other amortization, net		–			–			1		1
Net periodic cost (benefit)	$	13		$	(4	)	$	5	$	5

In 2009, contributions directly to pension plan assets are expected to approximate $222 million for us, $164 million for PEC and $57 million for PEF. An immaterial amount was contributed during the three months ended March 31, 2009.

11.	RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and 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.

A. COMMODITY DERIVATIVES

GENERAL

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

ECONOMIC DERIVATIVES

Derivative products, primarily natural gas and oil 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.

Certain counterparties have posted or held cash collateral in support of these instruments. PEC had a cash collateral asset included in prepayments and other current assets of $28 million and $18 million on the PEC Consolidated Balance Sheet at March 31, 2009 and December 31, 2008, respectively. At March 31, 2009, PEC had 61.4 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases. Due to the significant decline in natural gas prices since December 31, 2008, PEF's cash collateral asset included in derivative collateral posted was $535 million and $335 million on the PEF Balance Sheet at March 31, 2009 and December 31, 2008, respectively. At March 31, 2009, PEF had 263.8 million MMBtu notional of natural gas and 3.5 million barrels notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted oil and natural gas purchases.

CASH FLOW HEDGES

The Utilities designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. From time to time we hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. We also hedge exposure to market risk associated with fluctuations in the price of fuel for fleet vehicles. At March 31, 2009, we had 0.7 million gallons notional of gasoline and 0.6 million gallons notional of diesel related to outstanding commodity derivative swaps at each of PEC and PEF that were entered into to hedge forecasted gasoline and diesel purchases. Realized gains and losses are recorded net as part of fleet vehicle fuel costs. At March 31, 2009 and December 31, 2008, neither we nor the Utilities had material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for the three months ended March 31, 2009 and 2008.

At March 31, 2009 and December 31, 2008, the amount recorded in our or the Utilities’ accumulated other comprehensive income related to commodity cash flow hedges was not material.

B. INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the

event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates.

CASH FLOW HEDGES

At March 31, 2009, all open interest rate hedges will reach their mandatory termination dates within three and a half years. It is expected that in the next twelve months $3 million and $4 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at the Parent and PEC, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates and changes in the timing of debt issuances.

At December 31, 2008, the Parent had $200 million notional of interest rate cash flow hedges. All of these forward starting swaps were terminated on March 16, 2009, in conjunction with the Parent’s issuance of $450 million of 7.05% Senior Notes due 2019. In January 2009, the Parent entered into a $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances. At March 31, 2009, the Parent had $50 million notional of interest rate cash flow hedges.

At December 31, 2008, PEC had $250 million notional of interest rate cash flow hedges. All of these forward starting swaps were terminated on January 8, 2009, in conjunction with PEC’s issuance of $600 million First Mortgage Bonds 5.30% Series due 2019. In January 2009, PEC entered into a $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances. At March 31, 2009, PEC had $50 million notional of interest rate cash flow hedges.

At December 31, 2008, PEF had no outstanding interest rate cash flow hedges. In January 2009, PEF entered into a $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances. At March 31, 2009, PEF had $50 million notional of interest rate cash flow hedges.

FAIR VALUE HEDGES

For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At March 31, 2009, and December 31, 2008, neither we nor the Utilities had any outstanding positions in such contracts.

C. CONTINGENT FEATURES

Certain of our derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from each of the major credit rating agencies. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.

The aggregate fair value of all derivative instruments at PEC with credit risk-related contingent features that are in a liability position at March 31, 2009 is $130 million, for which PEC has posted collateral of $28 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2009, PEC would have been required to post an additional $102 million of collateral with its counterparties.

The aggregate fair value of all derivative instruments at PEF with credit risk-related contingent features that are in a liability position at March 31, 2009 is $771 million, for which PEF has posted collateral of $535 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on March 31, 2009, PEF would have been required to post an additional $231 million of collateral with its counterparties.

D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

Progress Energy

The following table presents the fair value of derivative instruments at March 31, 2009 and December 31, 2008:


(in millions)	March 31, 2009					December 31, 2008
Instrument / Balance sheet location	Asset		Liability			Asset		Liability

Derivatives designated as hedging instruments under SFAS No. 133
Commodity cash flow derivatives
Derivative liabilities, current			$	(1	)			$	(2	)
Interest rate derivatives
Derivative liabilities, current				–					(65	)
Total derivatives designated as hedging instruments under SFAS No. 133				(1	)				(67	)

Derivatives not designated as hedging instruments under SFAS No. 133
Commodity derivatives(a)
Prepayments and other current assets	$	5				$	9
Other assets and deferred debits		–					1
Derivative liabilities, current				(553	)				(425	)
Derivative liabilities, long-term				(347	)				(263	)
CVOs(c)
Other liabilities and deferred credits				(27	)				(34	)
Fair value of derivatives not designated as hedging instruments under SFAS No. 133		5		(927	)		10		(722	)
DIG Issue C20(b)
Derivative liabilities, current				(2	)				(1	)
Derivative liabilities, long-term				(5	)				(6	)
Total derivatives not designated as hedging instruments under SFAS No. 133		5		(934	)		10		(729	)
Total derivatives	$	5	$	(935	)	$	10	$	(796	)

(a)	Substantially all of these contracts receive regulatory treatment.

(b)

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 13).

(c)	As discussed in Note 15 of the 2008 Form 10-K, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000.

The following tables present the effect of derivative instruments on other comprehensive income (OCI) (See Note 6C) and the Consolidated Statements of Income for the three months ended March 31, 2009 and 2008:


Derivatives Designated as Hedging Instruments under SFAS No. 133
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)					Location of Gain or (Loss) Reclassified from Accumulated OCI into Income(a)	Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)						Location of Gain or (Loss) Recognized in Income on Derivatives(b)	Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2009		2008				2009			2008				2009			2008
Commodity cash flow derivatives	$	–	$	(2	)		$	–		$	–			$	–		$	–
Interest rate derivatives(c)		6		(7	)	Interest charges		(1	)		(1	)	Interest charges		(3	)		–
Total	$	6	$	(9	)		$	(1	)	$	(1	)		$	(3	)	$	–

(a)	Effective portion.

(b)	Related to ineffective portion and amount excluded from effectiveness testing.

(c)	Amounts in accumulated other comprehensive income related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.



Derivatives Not Designated as Hedging Instruments under SFAS No. 133
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(127	)	$	16	$	(95	)	$	245

(a)	After settlement of the derivaties and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.


Instrument	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)		2009			2008
Commodity derivatives	Other, net	$	(1	)	$	–
DIG Issue C20	Other, net		–			1
CVOs	Other, net		7			–
Total		$	6		$	1

PEC

The following table presents the fair value of derivative instruments at March 31, 2009 and December 31, 2008:


(in millions)	March 31, 2009					December 31, 2008
Instrument / Balance sheet location	Asset		Liability			Asset		Liability

Derivatives designated as hedging instruments under SFAS No. 133
Commodity cash flow derivatives
Derivative liabilities, current			$	(1	)			$	(1	)
Interest rate derivatives
Prepayments and other current assets	$	1				$	–
Derivative liabilities, current				–					(35	)
Total derivatives designated as hedging instruments under SFAS No. 133		1		(1	)		–		(36	)

Derivatives not designated as hedging instruments under SFAS No. 133
Commodity derivatives(a)
Derivative liabilities, current				(57	)				(45	)
Other liabilities and deferred credits				(72	)				(54	)
Fair value of derivatives not designated as hedging instruments under SFAS No. 133				(129	)				(99	)
DIG Issue C20(b)
Derivative liabilities, current				(2	)				(1	)
Other liabilities and deferred credits				(5	)				(6	)
Total derivatives not designated as hedging instruments under SFAS No. 133		–		(136	)		–		(106	)
Total derivatives	$	1	$	(137	)	$	–	$	(142	)

(a)	Substantially all of these contracts receive regulatory treatment.

(b)	In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of DIG Issue C20. The related liability is being amortized to earnings over the term of the related contract (See Note 13).

The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Consolidated Statements of Income for the three months ended March 31, 2009 and 2008:


Derivatives Designated as Hedging Instruments under SFAS No. 133
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)					Location of Gain or (Loss) Reclassified from Accumulated OCI into Income(a)	Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Location of Gain or (Loss) Recognized in Income on Derivatives(b)	Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2009		2008				2009		2008			2009			2008
Commodity cash flow derivatives	$	–	$	(2	)		$	–	$	–		$	–		$	–
Interest rate derivatives(c)		–		(3	)	Interest charges		–		–	Interest charges		(2	)		–
Total	$	–	$	(5	)		$	–	$	–		$	(2	)	$	–

(a)	Effective portion.

(b)	Related to ineffective portion and amount excluded from effectiveness testing.

(c)	Amounts in accumulated other comprehensive income related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.


Derivatives Not Designated as Hedging Instruments under SFAS No. 133
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(18	)	$	–	$	(11	)	$	31

(a)	After settlement of the derivaties and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.


Instrument	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)		2009			2008
Commodity derivatives	Other, net	$	(1	)	$	–
DIG Issue C20	Other, net		–			1
Total		$	(1	)	$	1

PEF

The following table presents the fair value of derivative instruments at March 31, 2009 and December 31, 2008:


(in millions)	March 31, 2009					December 31, 2008
Instrument / Balance sheet location	Asset		Liability			Asset		Liability

Derivatives not designated as hedging instruments under SFAS No. 133
Commodity derivatives(a)
Prepayments and other current assets	$	5				$	9
Other assets and deferred debits		–					1
Derivative liabilities, current			$	(496	)			$	(380	)
Derivative liabilities, long-term				(275	)				(209	)
Total derivatives not designated as hedging instruments under SFAS No. 133	$	5	$	(771	)	$	10	$	(589	)

(a) Substantially all of these contracts receive regulatory treatment.

The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Statements of Income for the three months ended March 31, 2009 and 2008:


Derivatives Designated as Hedging Instruments under SFAS No. 133
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)					Location of Gain or (Loss) Reclassified from Accumulated OCI into Income(a)	Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Location of Gain or (Loss) Recognized in Income on Derivatives(b)	Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2009		2008				2009		2008			2009		2008
Interest rate derivatives(c)	$	–	$	(4	)	Interest charges	$	–	$	–	Interest charges	$	–	$	–

(a)	Effective portion.

(b)	Related to ineffective portion and amount excluded from effectiveness testing.

(c)	Amounts in accumulated other comprehensive income related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.


Derivatives Not Designated as Hedging Instruments under SFAS No. 133
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(109	)	$	16	$	(84	)	$	214

(a)	After settlement of the derivaties and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.

12.	FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

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

Income of discontinued operations is not included in the table presented below. The following information is for the three months ended March 31:


									Income (Loss)
	Revenues								From Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
2009
PEC	$	1,178	$	–		$	1,178		$	127		$	13,210
PEF		1,262		–			1,262			88			13,093
Corporate and Other		2		65			67			(32	)		18,824
Eliminations		–		(65	)		(65	)		–			(14,224	)
Totals	$	2,442	$	–		$	2,442		$	183		$	30,903

2008
PEC	$	1,068	$	–		$	1,068		$	122
PEF		996		–			996			66
Corporate and Other		2		82			84			(35	)
Eliminations		–		(82	)		(82	)		–
Totals	$	2,066	$	–		$	2,066		$	153

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

Progress Energy
	Three Months Ended March 31,
(in millions)	2009			2008
Other income
Nonregulated energy and delivery services income	$	5		$	7
DIG Issue C20 amortization (see Note 11)		–			1
CVOs unrealized gain, net		7			–
Total other income		12			8
Other expense
Nonregulated energy and delivery services expenses		4			4
Donations		3			4
Investment losses, net		–			2
Loss from equity investments, net		3			1
Derivative mark-to-market losses, net		1			–
Other, net		2			2
Total other expense		13			13
Other, net – Progress Energy	$	(1	)	$	(5	)

PEC
	Three Months Ended March 31,
(in millions)	2009			2008
Other income
Nonregulated energy and delivery services income	$	–		$	3
DIG Issue C20 amortization (see Note 11)		–			1
Investment gains, net		1			1
Total other income		1			5
Other expense
Nonregulated energy and delivery services expenses		2			1
Donations		1			2
Loss from equity investments, net		2			1
Derivative mark-to-market losses, net		1			–
Other, net		2			1
Total other expense		8			5
Other, net – PEC	$	(7	)	$	–

PEF
	Three Months Ended March 31,
(in millions)	2009		2008
Other income
Nonregulated energy and delivery services income	$	5	$	4
Other, net		–		1
Total other income		5		5
Other expense
Nonregulated energy and delivery services expenses		2		3
Donations		2		2
Investment losses, net		1		2
Total other expense		5		7
Other, net – PEF	$	–	$	(2	)

14.	ENVIRONMENTAL MATTERS

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

A.	HAZARDOUS AND SOLID WASTE

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.

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

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


(in millions)	March 31, 2009		December 31, 2008
PEC
MGP and other sites(a)	$	17	$	16
PEF
Remediation of distribution and substation transformers		19		22
MGP and other sites		15		15
Total PEF environmental remediation accruals(b)		34		37
Total Progress Energy environmental remediation accruals	$	51	$	53

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

(b)	Expected to be paid out over one to 15 years.

PROGRESS ENERGY

In addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 15B).

PEC

In 2006, the NCUC and the SCPSC authorized PEC to defer and amortize certain environmental remediation expenses. Remediation expenses not authorized to be deferred are included in operation and maintenance (O&M) expense.

Including the Ward Transformer site located in Raleigh, N.C. (Ward), and MGP sites discussed below, for the three months ended March 31, 2009, PEC accrued approximately $3 million and spent approximately $2 million. For the three months ended March 31, 2008, PEC accrued approximately $1 million and spent approximately $2 million. These amounts primarily relate to the Ward site.

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

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At March 31, 2009 and December 31, 2008, PEC’s recorded liability for the site was approximately $8 million and $7 million, respectively. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. On September 12, 2008, PEC filed an initial civil action against a number of PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. On March 13, 2009, a subsequent action was filed against additional PRPs, and on April 30, 2009, suit was filed against the remaining approximately 160 PRPs. PEC and many of the PRPs against whom suit has been filed are in active settlement negotiations. The federal district court in which this matter is pending requires that alternative dispute resolution be pursued initially in civil litigation. The outcome of these matters cannot be predicted.

On September 30, 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial

investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. On January 19, 2009, PEC and several of the other participating PRPs at the Ward site submitted a letter containing a good faith response to the EPA’s special notice letter. Another group of PRPs separately submitted a good faith response, which the EPA has advised will be used to negotiate implementation of the required actions. Although a loss is considered probable, an agreement among the PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation for Ward OU1 and Ward OU2.

PEF

PEF has received approval from the FPSC for recovery through the environmental cost recovery clause (ECRC) of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed all distribution transformer sites and all substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should further distribution transformer sites be identified outside of this population, the distribution O&M costs will not be recoverable through the ECRC. Based on historical experience, PEF projects costs will be between approximately $3 million and $4 million per year. For the three months ended March 31, 2009, PEF made no material accruals and spent approximately $3 million related to the remediation of transformers. For the three months ended March 31, 2008, PEF accrued $2 million due to increases in estimated remediation costs and spent approximately $6 million related to the remediation of transformers. At March 31, 2009, PEF had recorded a regulatory asset for the probable recovery of these costs through the ECRC.

The accruals for MGP and other sites, in the previous table, 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, 2009 and 2008, PEF made no material accruals or expenditures.

B.	AIR AND WATER QUALITY

At March 31, 2009 and December 31, 2008, we were subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury regulation. PEC’s and PEF’s environmental compliance capital expenditures related to these regulations began in 2002 and 2005, respectively. At March 31, 2009, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.955 billion, including $1.032 billion at PEC and $923 million at PEF. At December 31, 2008, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.859 billion, including $1.012 billion at PEC, which primarily relates to Clean Smokestacks Act projects, and $847 million at PEF.

PEF participated in a coalition of Florida utilities that filed a challenge to the CAIR as it applied to Florida. PEF withdrew from the coalition during the fourth quarter of 2008. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) issued its decision on multiple challenges to the CAIR, including the Florida challenge, which vacated the CAIR in its entirety. On September 24, 2008, petitions for rehearing were filed by a number of parties. On December 23, 2008, the D.C. Court of Appeals remanded the CAIR without vacating the rule for the EPA to conduct further proceedings consistent with the D.C. Court of Appeals’ prior opinion. The outcome of the EPA’s further proceedings cannot be predicted. The D.C. Court of Appeals’ December 23, 2008 decision remanding the CAIR maintained its current implementation such that CAIR satisfies best available retrofit technology (BART) for SO2 and nitrogen oxides (NOx) for BART-affected units under the CAVR. Should this determination change as the CAIR is revised, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units.

On February 8, 2008, the D.C. Court of Appeals vacated the delisting determination and the Clean Air Mercury Rule (CAMR). The three states in which the Utilities operate adopted mercury regulations implementing CAMR and submitted their state implementation rules to the EPA. It is uncertain how the decision that vacated the federal CAMR will affect the state rules; however, state-specific provisions are likely to remain in effect. The North

Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of these decisions. The outcome of these matters cannot be predicted.

PEF is continuing construction of its in-process emission control projects. On December 18, 2008, PEF and the FDEP announced an agreement under which PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and complete construction of its emission control projects at CR 4 and CR 5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was anticipated to be around 2020. On May 1, 2009, PEF announced that it expects the construction schedule to shift by a minimum of 20 months from the originally estimated 2016 to 2018 timeframe for the commercial operation dates of Levy. We are currently evaluating the impacts of the schedule shift. We cannot predict the outcome of this matter.

We account for emission allowances as inventory using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. The EPA is continuing to record allowance allocations under the CAIR NOx trading program, in some cases for years beyond the estimated two-year period for promulgation of a replacement rule. The EPA’s continued recording of CAIR NOx allowance allocations does not guarantee that allowances will continue to be usable for compliance after a replacement rule is finalized or that they will continue to have value in the future. SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements. PEF’s CAIR expenses, including NOx allowance inventory expense, are recoverable through the ECRC. PEC’s and PEF’s emission allowance inventory balances have not materially changed from December 31, 2008.

In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. Two of PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements, the joint owners are required to pay a portion of the costs of owning and operating these plants. PEC has determined that the most cost-effective Clean Smokestacks Act compliance strategy is to maximize the SO2 removal from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to avoid the installation of expensive emission controls on its smaller coal-fired units. In order to address the joint owner's concerns that such a compliance strategy would result in a disproportionate share of the cost of compliance for the jointly owned units, in 2005 PEC entered into an agreement with the joint owner to limit its aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act to approximately $38 million. PEC recorded a related liability for the joint owner's share of estimated costs in excess of the contract amount. At March 31, 2009 and December 31, 2008, the amount of the liability was $6 million and $10 million, respectively, based upon the respective estimates for the remaining Clean Smokestacks Act compliance costs. During the three months ended March 31, 2009, PEC made no additional accruals and spent approximately $4 million that exceeded the joint owner limit. Because PEC has taken a system-wide compliance approach, its North Carolina retail ratepayers have significantly benefited from the strategy of focusing emission reduction efforts on the jointly owned units, and, therefore, PEC believes that any costs in excess of the joint owner’s share should be recovered from North Carolina retail ratepayers, consistent with other capital expenditures associated with PEC’s compliance with the Clean Smokestacks Act. On September 5, 2008, the NCUC ordered that PEC shall be allowed to include in rate base all reasonable and prudently incurred environmental compliance costs in excess of $584 million, including eligible compliance costs in excess of the joint owner’s share, as the projects are closed to plant in service.

15.	COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2008 Form 10-K are described below.

A.	PURCHASE OBLIGATIONS

commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities' future needs. At March 31, 2009, our and the Utilities contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2008 Form 10-K. However, on May 1, 2009, PEF annouced that it expects the construction schedule for Levy to shift. Although the overall schedule impact is not certain at this time, PEF expects the schedule to shift from the 2016 to 2018 timeframe by a minimum of 20 months. We anticipate amending the Levy Engineering, Procurement, and Construction agreement due to the schedule shift but cannot currently predict the impact such amendment might have on the project's cost, if any.

B.	GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2009, 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, 2009, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses, which are within the scope of FIN 45. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. In 2005, PEC entered into an agreement with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 14B). PEC’s maximum exposure cannot be determined. At March 31, 2009, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $458 million, including $32 million at PEF. At March 31, 2009 and December 31, 2008, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $57 million and $61 million, respectively. These amounts include $6 million and $10 million, respectively, for PEC and $8 million for PEF at March 31, 2009, and December 31, 2008. During the three months ended March 31, 2009, PEC made no additional accruals and spent approximately $4 million that exceeded the joint owner limit. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent and a subsidiary have issued $300 million of guarantees for certain payments of two wholly owned indirect subsidiaries. See Note 16 for additional information.

C.	OTHER COMMITMENTS AND CONTINGENCIES

SPENT NUCLEAR FUEL MATTERS

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

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

A trial was held in November 2007, and closing arguments were presented on April 4, 2008. On May 19, 2008, the Utilities received a ruling from the United States Court of Federal Claims awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. The United States Department of Justice requested that the Trial Court reconsider its ruling. The Trial Court did reconsider its ruling

and reduced the damage award by an immaterial amount. On August 15, 2008, the Department of Justice appealed the United States Court of Federal Claims ruling to the D.C. Court of Appeals. Oral arguments were held on May 4, 2009. In the event that the Utilities recover damages in this matter, such recovery is not expected to have a material impact on the Utilities’ results of operations given the anticipated regulatory and accounting treatment. However, the Utilities cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

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

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

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

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

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

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

OTHER LITIGATION MATTERS

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

16.	CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2008 Form 10-K, we have guaranteed certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.) since September 2005. Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 11B in the 2008 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a special-purpose entity and was deconsolidated in 2003 in accordance with the provisions of FIN 46R. The deconsolidation was not material to our financial statements. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.

Presented below are the condensed consolidating Statements of Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed consolidating statements, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the consolidated financial results of Florida Progress only, which is primarily comprised of its wholly owned subsidiary PEF. The Non-guarantor Subsidiary column includes the consolidated financial results of our wholly owned subsidiary PEC. The Other column includes the consolidated financial results of all other non-guarantor subsidiaries and elimination entries for all intercompany transactions. Financial statements for PEC and PEF are separately presented elsewhere in this Form 10-Q. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities.

Condensed Consolidating Statement of Income Three Months Ended March 31, 2009
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiary			Other			Progress Energy, Inc.
Operating revenues	$	–		$	1,264		$	1,178		$	–		$	2,442
Operating expenses
Fuel used in electric generation		–			512			442			–			954
Purchased power		–			160			57			–			217
Operation and maintenance		1			202			259			(9	)		453
Depreciation, amortization and accretion		–			160			117			3			280
Taxes other than on income		–			88			54			1			143
Other		–			2			–			–			2
Total operating expenses		1			1,124			929			(5	)		2,049
Operating (loss) income		(1	)		140			249			5			393
Other income (expense)
Interest income		3			1			2			(2	)		4
Allowance for equity funds used during construction		–			30			9			–			39
Other, net		7			–			(7	)		(1	)		(1	)
Total other income (expense), net		10			31			4			(3	)		42
Interest charges
Interest charges		52			72			57			(2	)		179
Allowance for borrowed funds used during construction		–			(9	)		(3	)		–			(12	)
Total interest charges, net		52			63			54			(2	)		167
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(43	)		108			199			4			268
Income tax (benefit) expense		(13	)		21			71			6			85
Equity in earnings of consolidated subsidiaries		211			–			–			(211	)		–
Income (loss) from continuing operations		181			87			128			(213	)		183
Discontinued operations, net of tax		1			(1	)		–			–			–
Net income (loss)		182			86			128			(213	)		183
Net income attributable to noncontrolling interests, net of tax		–			(1	)		–			–			(1	)
Net income (loss) attributable to controlling interests	$	182		$	85		$	128		$	(213	)	$	182

Condensed Consolidating Statement of Income Three Months Ended March 31, 2008
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiary			Other			Progress Energy, Inc.
Operating revenues	$	–		$	998		$	1,068		$	–		$	2,066
Operating expenses
Fuel used in electric generation		–			341			356			–			697
Purchased power		–			183			49			–			232
Operation and maintenance		–			203			248			(8	)		443
Depreciation, amortization and accretion		–			76			126			4			206
Taxes other than on income		–			71			50			–			121
Other		–			2			(1	)		1			2
Total operating expenses		–			876			828			(3	)		1,701
Operating income		–			122			240			3			365
Other income (expense)
Interest income		4			–			5			(2	)		7
Allowance for equity funds used during construction		–			19			4			–			23
Other, net		–			(4	)		–			(1	)		(5	)
Total other income (expense), net		4			15			9			(3	)		25
Interest charges
Interest charges		48			57			58			(2	)		161
Allowance for borrowed funds used during construction		–			(6	)		(2	)		–			(8	)
Total interest charges, net		48			51			56			(2	)		153
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(44	)		86			193			2			237
Income tax (benefit) expense		(18	)		27			70			5			84
Equity in earnings of consolidated subsidiaries		235			–			–			(235	)		–
Income (loss) from continuing operations		209			59			123			(238	)		153
Discontinued operations, net of tax		–			57			–			4			61
Net income (loss)		209			116			123			(234	)		214
Net income attributable to noncontrolling interests, net of tax		–			(5	)		–			–			(5	)
Net income (loss) attributable to controlling interests	$	209		$	111		$	123		$	(234	)	$	209

Condensed Consolidating Balance Sheet March 31, 2009
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiary		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	9,056	$	9,460	$	120		$	18,636
Current assets
Cash and cash equivalents		586		24		21		1			632
Notes receivable from affiliated companies		446		73		120		(639	)		–
Regulatory assets		–		226		163		–			389
Derivative collateral posted		–		535		28		–			563
Prepayments and other current assets		26		1,186		1,190		2			2,404
Total current assets		1,058		2,044		1,522		(636	)		3,988
Deferred debits and other assets
Investment in consolidated subsidiaries		12,134		–		–		(12,134	)		–
Regulatory assets		–		1,567		1,279		(1	)		2,845
Goodwill		–		–		–		3,655			3,655
Other assets and deferred debits		164		572		949		94			1,779
Total deferred debits and other assets		12,298		2,139		2,228		(8,386	)		8,279
Total assets	$	13,356	$	13,239	$	13,210	$	(8,902	)	$	30,903
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	9,261	$	3,792	$	4,244	$	(8,036	)	$	9,261
Noncontrolling interests		–		2		4		–			6
Total equity		9,261		3,794		4,248		(8,036	)		9,267
Preferred stock of subsidiaries		–		34		59		–			93
Long-term debt, affiliate		–		309		–		(37	)		272
Long-term debt, net		3,243		4,182		3,708		–			11,133
Total capitalization		12,504		8,319		8,015		(8,073	)		20,765
Current liabilities
Short-term debt		500		130		–		–			630
Notes payable to affiliated companies		–		660		–		(660	)		–
Derivative liabilities		–		496		60		–			556
Other current liabilities		316		922		705		(66	)		1,877
Total current liabilities		816		2,208		765		(726	)		3,063
Deferred credits and other liabilities
Noncurrent income tax liabilities		–		136		1,162		(410	)		888
Regulatory liabilities		–		1,029		995		117			2,141
Other liabilities and deferred credits		36		1,547		2,273		190			4,046
Total deferred credits and other liabilities		36		2,712		4,430		(103	)		7,075
Total capitalization and liabilities	$	13,356	$	13,239	$	13,210	$	(8,902	)	$	30,903

Condensed Consolidating Balance Sheet December 31, 2008
(in millions)	Parent		Subsidiary Guarantor		Non-Guarantor Subsidiary		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	8,790	$	9,385	$	118		$	18,293
Current assets
Cash and cash equivalents		88		73		18		1			180
Notes receivable from affiliated companies		34		44		55		(133	)		–
Regulatory assets		–		326		207		–			533
Derivative collateral posted		–		335		18		–			353
Prepayments and other current assets		48		1,138		1,272		(4	)		2,454
Total current assets		170		1,916		1,570		(136	)		3,520
Deferred debits and other assets
Investment in consolidated subsidiaries		11,924		–		–		(11,924	)		–
Regulatory assets		–		1,324		1,243		–			2,567
Goodwill		–		–		–		3,655			3,655
Other assets and deferred debits		155		613		967		103			1,838
Total deferred debits and other assets		12,079		1,937		2,210		(8,166	)		8,060
Total assets	$	12,249	$	12,643	$	13,165	$	(8,184	)	$	29,873
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	8,687	$	3,519	$	4,301	$	(7,820	)	$	8,687
Noncontrolling interests		–		3		4		(1	)		6
Total equity		8,687		3,522		4,305		(7,821	)		8,693
Preferred stock of subsidiaries		–		34		59		–			93
Long-term debt, affiliate		–		309		–		(37	)		272
Long-term debt, net		2,696		4,182		3,509		–			10,387
Total capitalization		11,383		8,047		7,873		(7,858	)		19,445
Current liabilities
Short-term debt		569		371		110		–			1,050
Notes payable to affiliated companies		–		206		–		(206	)		–
Derivative liabilities		31		380		82		–			493
Other current liabilities		220		964		773		(14	)		1,943
Total current liabilities		820		1,921		965		(220	)		3,486
Deferred credits and other liabilities
Noncurrent income tax liabilities		1		118		1,111		(412	)		818
Regulatory liabilities		–		1,076		987		118			2,181
Other liabilities and deferred credits		45		1,481		2,229		188			3,943
Total deferred credits and other liabilities		46		2,675		4,327		(106	)		6,942
Total capitalization and liabilities	$	12,249	$	12,643	$	13,165	$	(8,184	)	$	29,873

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2009
(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiary			Other			Progress Energy, Inc.
Net cash provided (used) by operating activities	$	143		$	53		$	397		$	(198	)	$	395
Investing activities
Gross property additions		–			(462	)		(181	)		4			(639	)
Nuclear fuel additions		–			(9	)		(28	)		–			(37	)
Purchases of available-for-sale securities and other investments		–			(277	)		(420	)		(19	)		(716	)
Proceeds from available-for-sale securities and other investments		–			280			407			19			706
Changes in advances to affiliated companies		(412	)		(29	)		(65	)		506			–
Return of investment in consolidated subsidiaries		12			–			–			(12	)		–
Contributions to consolidated subsidiaries		(191	)		–			–			191			–
Other investing activities		–			(3	)		–			(2	)		(5	)
Net cash (used) provided by investing activities		(591	)		(500	)		(287	)		687			(691	)
Financing activities
Issuance of common stock		545			–			–			–			545
Dividends paid on common stock		(173	)		–			–			–			(173	)
Dividends paid to parent		–			(1	)		(200	)		201			–
Payments of short-term debt with original maturities greater than 90 days		(29	)		–			–			–			(29	)
Net decrease in short-term debt		(139	)		(241	)		(110	)		–			(490	)
Proceeds from issuance of long-term debt, net		743			–			595			–			1,338
Retirement of long-term debt		–			–			(400	)		–			(400	)
Cash distributions to noncontrolling interests of consolidated subsidiaries		–			(1	)		–			–			(1	)
Changes in advances from affiliated companies		–			454			–			(454	)		–
Contributions from parent		–			188			8			(196	)		–
Other financing activities		(1	)		(1	)		–			(40	)		(42	)
Net cash provided (used) by financing activities		946			398			(107	)		(489	)		748
Net increase (decrease) in cash and cash equivalents		498			(49	)		3			–			452
Cash and cash equivalents at beginning of period		88			73			18			1			180
Cash and cash equivalents at end of period	$	586		$	24		$	21		$	1		$	632

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2008
(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiary			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(55	)	$	393		$	419		$	20		$	777
Investing activities
Gross property additions		–			(446	)		(173	)		1			(618	)
Nuclear fuel additions		–			–			(41	)		–			(41	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			94			1			–			95
Proceeds from sales of assets to affiliated companies		–			8			–			(8	)		–
Purchases of available-for-sale securities and other investments		–			(247	)		(193	)		(48	)		(488	)
Proceeds from available-for-sale securities and other investments		–			247			185			41			473
Changes in advances to affiliated companies		122			111			(85	)		(148	)		–
Contributions to consolidated subsidiaries		(97	)		–			–			97			–
Other investing activities		–			14			(5	)		(15	)		(6	)
Net cash provided (used) by investing activities		25			(219	)		(311	)		(80	)		(585	)
Financing activities
Issuance of common stock		20			–			–			–			20
Dividends paid on common stock		(159	)		–			–			–			(159	)
Dividends paid to parent		–			(3	)		–			3			–
Payments of short-term debt with original maturities greater than 90 days		(176	)		–			–			–			(176	)
Net increase in short-term debt		180			–			–			–			180
Proceeds from issuance of long-term debt		–			–			322			–			322
Retirement of long-term debt		–			(80	)		–			–			(80	)
Cash distributions to noncontrolling interests of consolidated subsidiaries		–			(85	)		–			–			(85	)
Changes in advances from affiliated companies		–			(53	)		(154	)		207			–
Contributions from parent		–			85			13			(98	)		–
Other financing activities		(1	)		2			(17	)		(53	)		(69	)
Net cash (used) provided by financing activities		(136	)		(134	)		164			59			(47	)
Net (decrease) increase in cash and cash equivalents		(166	)		40			272			(1	)		145
Cash and cash equivalents at beginning of period		185			43			25			2			255
Cash and cash equivalents at end of period	$	19		$	83		$	297		$	1		$	400

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

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

The following MD&A contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors” found within Part II of this Form 10-Q and Item 1A, “Risk Factors” to the Progress Registrant’s annual report on Form 10-K for the fiscal year ended December 31, 2008 (2008 Form 10-K) for a discussion of the factors that may impact any such forward-looking statements made herein.

Amounts reported in the interim statements of income are not necessarily indicative of amounts expected for the respective annual or future periods due to the effects of weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, among other factors.

This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2008 Form 10-K.

PROGRESS ENERGY

RESULTS OF OPERATIONS

In this section, earnings and the factors affecting earnings for the three months ended March 31, 2009, are compared to the same period in 2008. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

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

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

OVERVIEW

For the quarter ended March 31, 2009, our net income attributable to controlling interests was $182 million, or $0.66 per share, compared to net income attributable to controlling interests of $209 million, or $0.80 per share, for the same period in 2008. For the quarter ended March 31, 2009, our income from continuing operations was $183 million compared to $153 million for the same period in 2008. The increase in income from continuing operations as compared to prior year was primarily due to:

·	favorable weather at the Utilities;

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

·	higher wholesale revenues at the Utilities; and

·	lower income tax expense resulting from the deduction related to nuclear decommissioning trust funds.

Offsetting these items were:

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

·	higher interest expense at PEF; and

·	unfavorable net retail customer growth and usage at the Utilities.

Our segments contributed the following profits or losses for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in millions)	2009			2008
Business Segment
PEC	$	127		$	122
PEF		88			66
Total segment profit		215			188
Corporate and Other		(32	)		(35	)
Income from continuing operations		183			153
Discontinued operations, net of tax		–			61
Net income attributable to noncontrolling interests, net of tax		(1	)		(5	)
Net income attributable to controlling interests	$	182		$	209

PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $127 million and $122 million for the three months ended March 31, 2009 and 2008, respectively. The increase in profits for the three months ended March 31, 2009, compared to the same period in 2008, was primarily due to lower North Carolina Clean Smokestacks Act (Clean Smokestacks Act) amortization and the favorable impact of weather, partially offset by higher O&M expenses and the unfavorable impact of tax levelization.

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

REVENUES

PEC’s electric revenues for the three months ended March 31, 2009 and 2008, and the amount and percentage change by customer class were as follows:


(in millions)	Three Months Ended March 31,
Customer Class	2009			Change			% Change			2008
Residential	$	512		$	86			20.2		$	426
Commercial		290			28			10.7			262
Industrial		164			(4	)		(2.4	)		168
Governmental		26			3			13.0			23
Total retail revenues		992			113			12.9			879
Wholesale		193			12			6.6			181
Unbilled		(38	)		(21	)		–			(17	)
Miscellaneous		31			7			29.2			24
Total electric revenues		1,178			111			10.4			1,067
Less: Fuel and other pass-through revenues		(479	)		(92	)		–			(387	)
Revenues excluding fuel and other pass-through revenues	$	699		$	19			2.8		$	680

PEC’s revenues, excluding fuel and other pass-through revenues of $479 million and $387 million for the three months ended March 31, 2009 and 2008, respectively, increased $19 million. The increase in revenues was primarily due to $13 million favorable impact of weather, $7 million higher miscellaneous revenues and $4 million higher wholesale revenues, excluding fuel and other pass-through revenues, partially offset by $5 million unfavorable impact of net retail customer growth and usage. The favorable impact of weather was primarily driven by 8 percent higher heating degree days than 2008. Heating degree days were comparable to normal in 2009 and 7 percent lower than normal in 2008. Higher miscellaneous revenues were primarily due to higher transmission revenues resulting from the Open Access Transmission Tariff rates that went into effect on July 1, 2008. Higher wholesale revenues were primarily due to contracts with two major customers driven by weather-related capacity increases, partially offset by lower excess generation sales due to unfavorable market dynamics resulting from normal weather in 2009 and higher relative fuel costs. The unfavorable impact of net retail customer growth and usage was driven by a decrease in the average usage per retail customer, partially offset by a net 18,000 increase in the average number of customers for the three months ended March 31, 2009, compared to the same period in 2008.

PEC’s electric energy sales for the three months ended March 31, 2009 and 2008, and the amount and percentage change by customer class were as follows:


(in millions of kWh)	Three Months Ended March 31,
Customer Class	2009			Change			% Change			2008
Residential		5,138			460			9.8			4,678
Commercial		3,315			37			1.1			3,278
Industrial		2,420			(352	)		(12.7	)		2,772
Governmental		343			10			3.0			333
Total retail energy sales		11,216			155			1.4			11,061
Wholesale		3,676			(96	)		(2.5	)		3,772
Unbilled		(464	)		(223	)		–			(241	)
Total kWh sales		14,428			(164	)		(1.1	)		14,592

Wholesale revenues increased for the three months ended March 31, 2009, despite a decrease in wholesale kilowatt-hours (kWh) sales for the same period primarily due to the impact of increased fuel revenues as a result of higher energy costs. Wholesale kWh sales decreased for the three months ended March 31, 2009, primarily due to decreased excess generation sales resulting from unfavorable market dynamics.

PEC has experienced some decline in the rate of residential and commercial sales growth due to the current recession in the United States. Additionally, PEC’s industrial kWh sales have decreased 12.4 percent from 2008, but industrial revenues have only decreased 12.7 percent due in part to the demand charges component of industrial

revenues. Many of the manufacturers in PEC’s service territory have been adversely impacted by the recession, and we expect continued industrial sales weakness until the broader economy recovers. We cannot predict how long the recession may last or the extent to which it may impact revenues. In the future, PEC’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates.

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 $499 million for the three months ended March 31, 2009, which represents a $94 million increase compared to the same period in 2008. Fuel used in electric generation increased $86 million to $442 million primarily due to the $65 million impact of higher coal prices and $16 million higher deferred fuel expense. The increase in deferred fuel expense was primarily due to the implementation of new fuel rates in North Carolina. Purchased power expense increased $8 million to $57 million compared to the same period in 2008 primarily due to an increase in interchange purchases of $13 million and purchases from renewable energy sources of $3 million, partially offset by lower cogeneration of $7 million. The increase in interchange purchases was primarily due to timing of plant outages in 2009.

Operation and Maintenance

O&M expense was $259 million for the three months ended March 31, 2009, which represents an $11 million increase compared to the same period in 2008. This increase is primarily due to $14 million higher nuclear plant outage and maintenance costs driven by the timing of outages and $5 million lower nuclear insurance refund, partially offset by $8 million lower emission expense primarily due to sales of nitrogen oxides (NOx) emission allowances.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $117 million for the three months ended March 31, 2009, which represents a $9 million decrease compared to the same period in 2008. Depreciation, amortization and accretion expense decreased primarily due to $15 million lower Clean Smokestacks Act amortization, partially offset by the $4 million impact of depreciable asset base increases. In accordance with a regulatory order, PEC ceased to amortize Clean Smokestacks Act compliance costs, but will record depreciation over the useful life of the assets.

Taxes Other Than on Income

Taxes other than on income was $54 million for the three months ended March 31, 2009, which represents a $4 million increase compared to the same period in 2008. This increase is primarily due to a $2 million increase in gross receipts taxes due to higher retail revenues. Gross receipts taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Total Other Income, Net

Total other income, net was $4 million for the three months ended March 31, 2009, which represents a $5 million decrease compared to the same period in 2008. This decrease is primarily due to seasonal losses on a balanced billing program of $4 million, lower interest income of $3 million and investment losses of $2 million, partially offset by favorable AFUDC equity of $5 million. The favorable AFUDC equity is related to increased eligible construction project costs, which we expect to continue for the remainder of 2009.

Income Tax Expense

Income tax expense increased $1 million for the three months ended March 31, 2009, as compared to the same period in 2008, primarily due to the $5 million impact of tax levelization, discussed below, offset by the $5 million favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from nonqualified nuclear decommissioning trusts to qualified nuclear decommissioning trusts. 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, 2009 compared to a decrease of $3 million for the three months ended March 31, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $88 million and $66 million for the three months ended March 31, 2009 and 2008, respectively. The increase in profits for the three months ended March 31, 2009, compared to the same period in 2008, was primarily due to favorable AFUDC equity, lower income tax expense resulting from the deduction related to nuclear decommissioning trust funds, higher wholesale revenues and the favorable impact of weather, partially offset by higher interest expense, the unfavorable impact of net retail customer growth and usage, and higher O&M expenses.

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

REVENUES

PEF’s electric revenues for the three months ended March 31, 2009 and 2008, and the amount and percentage change by customer class were as follows:


(in millions)	Three Months Ended March 31,
Customer Class	2009			Change			% Change			2008
Residential	$	625		$	161			34.7		$	464
Commercial		304			62			25.6			242
Industrial		84			15			21.7			69
Governmental		83			16			23.9			67
Total retail revenues		1,096			254			30.2			842
Wholesale		117			14			13.6			103
Unbilled		5			(1	)		–			6
Miscellaneous		44			(1	)		(2.2	)		45
Total electric revenues		1,262			266			26.7			996
Less: Fuel and other pass-through revenues		(853	)		(245	)		–			(608	)
Revenues excluding fuel and other pass-through revenues	$	409		$	21			5.4		$	388

PEF’s revenues, excluding fuel and other pass-through revenues of $853 million and $608 million for the three months ended March 31, 2009 and 2008, respectively, increased $21 million. The increase in revenues was primarily due to the $17 million favorable impact of weather and $17 million higher wholesale revenues, excluding fuel and other pass-through revenues, partially offset by the $11 million unfavorable impact of net retail customer growth and usage. The favorable impact of weather was primarily driven by 41 percent higher heating degree days

than 2008. Heating degree days were comparable to normal in 2009 and 27 percent lower than normal in 2008. Wholesale revenues increased primarily due to new and amended contracts that were not in effect in the same period in 2008.

The current recession in the United States has contributed to a slowdown in customer growth and usage in PEF’s service territory. In addition to lower average usage per customer, PEF’s average number of customer for the three months ended March 31, 2009, compared to the same period in 2008, decreased a net 8,000 customers. In comparison, PEF’s average number of customers for the three months ended March 31, 2008, compared to the same period in 2007, increased a net 7,000 customers. We cannot predict how long the recession may last or the extent to which it may impact revenues. In the future, PEF’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates.

PEF’s electric energy sales for the three months ended March 31, 2009 and 2008, and the amount and percentage change by customer class were as follows:


(in millions of kWh)	Three Months Ended March 31,
Customer Class	2009			Change			% Change			2008
Residential		4,287			282			7.0			4,005
Commercial		2,554			(107	)		(4.0	)		2,661
Industrial		791			(74	)		(8.6	)		865
Governmental		732			(35	)		(4.6	)		767
Total retail energy sales		8,364			66			0.8			8,298
Wholesale		1,207			(183	)		(13.2	)		1,390
Unbilled		(170	)		(390	)		–			220
Total kWh sales		9,401			(507	)		(5.1	)		9,908

Commercial, industrial and governmental revenues increased for the three months ended March 31, 2009, despite a decrease in kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates and the recovery of nuclear costs in accordance with a regulatory order issued in late 2008.

Wholesale revenues increased for the three months ended March 31, 2009, despite a decrease in kWh sales for the same period primarily due to peak demand charges and increased fixed capacity.

EXPENSES

Fuel and Purchased Power

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

Fuel and purchased power expenses were $672 million for the three months ended March 31, 2009, which represents a $148 million increase compared to the same period in 2008. Fuel used in electric generation increased $171 million to $512 million compared to the same period in 2008. This increase was primarily due to higher deferred fuel expense of $93 million driven by the implementation of new fuel rates to collect fuel costs from customers that had been previously under-recovered and increased current year fuel costs of $78 million. The increase in current year fuel costs was primarily due to increased fuel prices and a change in generation mix. Purchased power expense decreased $23 million to $160 million compared to the same period in 2008. This decrease was primarily due to a decrease in interchange purchases of $19 million resulting from lower system requirements.

Operation and Maintenance

O&M expense was $202 million for the three months ended March 31, 2009, which represents a $1 million decrease when compared to the same period in 2008. O&M expense decreased $26 million due to the storm damage reserve replenishment surcharge that ended in July 2008, partially offset by $16 million higher environmental cost recovery

(ECRC) costs due to increased rates resulting primarily from the recovery of emission allowances and higher pension costs of $9 million resulting from revised actuarial estimates. The replenishment of storm damage reserves and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. In aggregate, O&M expenses recoverable through base rates increased $6 million compared to the same period in 2008.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $160 million for the three months ended March 31, 2009, which represents an $84 million increase compared to the same period in 2008. Depreciation, amortization and accretion expense increased primarily due to $80 million higher nuclear cost-recovery amortization which began in January 2009 in accordance with a 2008 regulatory order. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and, therefore, has no material impact on earnings. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates increased $2 million compared to the same period in 2008.

Taxes Other Than on Income

Taxes other than on income was $88 million for the three months ended March 31, 2009, which represents a $17 million increase compared to the same period in 2008. This increase is primarily due to a $13 million increase in gross receipts and franchise taxes due to higher retail revenues. Gross receipts and franchise taxes are collected from customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.

Total Other Income, Net

Total other income, net was $31 million for the three months ended March 31, 2009, which represents a $13 million increase compared to the same period in 2008. This increase was primarily due to $11 million favorable AFUDC equity related to eligible construction project costs.

Total Interest Charges, net

Total interest charges, net was $58 million for the three months ended March 31, 2009, which represents a $14 million increase compared to the same period in 2008. This increase was primarily due to $15 million higher interest as a result of higher average debt outstanding, partially offset by $3 million favorable AFUDC debt related to eligible construction project costs.

Income Tax Expense

Income tax expense decreased $5 million for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to the $11 million impact of the favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from the nonqualified nuclear decommissioning trust to the qualified nuclear decommissioning trust, and the $4 million impact of the increase in AFUDC equity discussed above, partially offset by the $6 million tax impact of higher pre-tax earnings and the $2 million impact of tax levelization. AFUDC equity is excluded from the calculation of income tax expense. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was increased by $3 million for the three months ended March 31, 2009 compared to $1 million for the three months ended March 31, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

CORPORATE AND OTHER

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


	Three Months Ended March 31,
(in millions)	2009			2008
Other interest expense	$	(55	)	$	(54	)
Contingent value obligations		7			–
Tax levelization		(1	)		(1	)
Other income tax benefit		10			17
Continuing income attributable to noncontrolling interests, net of tax		1			4
Other		6			(1	)
Corporate and Other after-tax expense	$	(32	)	$	(35	)

At March 31, 2009 and 2008, the contingent value obligations (CVOs) had fair values of approximately $27 million and $34 million, respectively. We recorded an unrealized gain of $7 million for the three months ended March 31, 2009, and no adjustment for the three months ended March 31, 2008, to record the changes in fair value of the CVOs, which had average unit prices of $0.28 and $0.35 at March 31, 2009 and 2008, respectively. See Note 15 in the 2008 Form 10-K for further information.

Other income tax benefit decreased $7 million for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to the tax impact of employee benefits as well as the unfavorable impact on the Corporate tax position resulting from the deductions taken by the Utilities related to nuclear decommissioning trust funds (See “Progress Energy Carolinas – Income Tax Expense” and “Progress Energy Florida – Income Tax Expense”).

Other increased $7 million for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to lower workers' compensation expense, higher investment gains of certain employee benefit trusts resulting from market conditions and higher interest income.

DISCONTINUED OPERATIONS

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

TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky (Terminals) for $71 million in gross cash proceeds. The coal terminals had a total annual capacity in excess of 40 million tons for transloading, blending and storing coal and other commodities. Proceeds from the sale were used for general corporate purposes. During the three months ended March 31, 2008, we recorded an after-tax gain of $46 million on the sale of these assets.

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

Terminals and the synthetic fuels businesses collectively generated net earnings from discontinued operations attributable to controlling interests of $12 million for the three months ended March 31, 2008.

COAL MINING BUSINESSES

On March 7, 2008, we sold the remaining operations of Progress Fuels Corporation (Progress Fuels) subsidiaries engaged in the coal mining business for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. These assets included Powell Mountain Coal Co. and Dulcimer Land Co., which

consisted of approximately 30,000 acres in Lee County, Va., and Harlan County, Ky. As a result of the sale, during the three months ended March 31, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.

Net losses from discontinued operations for Coal Mining, excluding gain on disposal, were $6 million for the three months ended March 31, 2008.

OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations in 2008 are amounts related to adjustments of our prior sales of other diversified businesses, primarily our natural gas drilling and production business (Gas) and Progress Rail Services Corporation (Progress Rail). These adjustments are mainly due to the finalization of working capital and in connection with guarantees and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters (See Note 15B). The ultimate resolution of these matters could result in additional adjustments in future periods. For the three months ended March 31, 2008, we recorded additional gains of $1 million, net of tax.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Our significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations, including expenditures for environmental compliance. We rely upon our operating cash flow, substantially all of which is generated by the Utilities, commercial paper and bank facilities, and our ability to access the long-term debt and equity capital markets for sources of liquidity. As discussed in “Future Liquidity and Capital Resources” below, synthetic fuels tax credits provide an additional source of liquidity as those credits are realized.

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

As a registered holding company, we are subject to regulation by the Federal Energy Regulatory Commission (FERC) for, among other things, the establishment of intercompany extensions of credit (utility and non-utility money pools). Our subsidiaries participate in internal money pools, operated by Progress Energy, to more effectively utilize cash resources and reduce outside short-term borrowings. The utility money pool allows the Utilities to lend to and borrow from each other. The non-utility money pool allows our nonregulated operations to lend to and borrow from each other. The Parent can lend money to the utility and non-utility money pools but cannot borrow funds.

The Parent is a holding company and, as such, has no revenue-generating operations of its own. The primary cash needs at the Parent level are our common stock dividend, interest and principal payments on the Parent’s $3.35 billion of senior unsecured debt and potentially funding the Utilities’ capital expenditures through equity contributions. The Parent’s ability to meet these needs is typically funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; repayment of funds due to the Parent by its subsidiaries; the Parent’s bank facility; and/or the Parent’s ability to access the short- and long-term debt and equity capital markets. In recent years, rather than paying dividends to the Parent, the Utilities, to a large extent, have retained their free cash flow to fund their capital expenditures. The Utilities did not pay dividends to the Parent in 2008. In the first quarter of 2009, PEC paid dividends of $200 million to the Parent, and PEF received a $155 million equity contribution from the Parent. There are a number of factors that impact the Utilities’ decision or ability to pay dividends to the Parent or to seek equity contributions from the Parent, including capital expenditure decisions and the timing of recovery of fuel and other pass-through costs. Therefore, we cannot predict the level of dividends or equity contributions between the Utilities and the Parent from year-to-year. We do not currently expect changes to the Parent’s common stock dividend policy.

Cash from operations, commercial paper issuance, borrowings under our credit facilities, long-term debt financings, equity offerings, and limited ongoing sales of common stock from our Investor Plus Stock Purchase Plan, employee benefit and stock option plans are expected to fund capital expenditures and common stock dividends for 2009. For the fiscal year 2009, we expect to realize approximately $600 million in the aggregate from the sale of stock through marketed and ongoing equity sales (see discussion that follows under “Financing Activities”).

We have addressed the challenges presented by current financial market conditions and will continue to monitor the credit markets to maintain an appropriate level of liquidity. Despite the tightened credit market that began with the extreme market turmoil in the third quarter of 2008, we have been able to issue additional equity and short- and long-term debt.

As shown in the table that follows, we have a number of financial institutions that support our combined $2.030 billion revolving credit facilities for the Parent, PEC and PEF, thereby limiting our dependence on any one institution. The credit facilities serve as back-ups to our commercial paper programs. To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At March 31, 2009, the Parent had $500 million of outstanding borrowings under its credit facility. In addition, at March 31, 2009, PEF had an outstanding commercial paper balance of $130 million and the Parent had issued $29 million of letters of credit, which were supported by the revolving credit agreement (RCA). Based on these amounts outstanding at March 31, 2009, $1.371 billion was available for additional borrowings under our combined revolving credit facilities.


(in millions)	Total Commitment
Credit Provider	Progress Energy		Parent		PEC		PEF
JPMorgan Chase Bank, N.A.	$	225.0	$	141.0	$	44.0	$	40.0
Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch		200.0		95.0		45.0		60.0
Barclays Bank PLC		190.5		100.0		20.5		70.0
Bank of America, N.A.		190.0		98.0		22.0		70.0
Citibank, N.A.		180.0		111.0		34.0		35.0
Wachovia Bank, N.A.		175.5		53.0		82.5		40.0
Royal Bank of Scotland plc		169.0		92.0		77.0		–
The Bank of New York Mellon		120.0		35.0		40.0		45.0
SunTrust Bank		115.0		50.0		20.0		45.0
Morgan Stanley Bank. NA		100.0		50.0		50.0		–
William Street Commitment Corporation		100.0		100.0		–		–
Deutsche Bank AG, New York Branch		95.0		50.0		–		45.0
UBS Loan Finance LLC		80.0		80.0		–		–
BNP Paribas		50.0		50.0		–		–
Branch Banking & Trust Co.		25.0		25.0		–		–
First Tennessee Bank N.A.		15.0		–		15.0		–
Total commitment	$	2,030.0	$	1,130.0	$	450.0	$	450.0

At March 31, 2009, PEC and PEF had limited counterparty mark-to-market exposure for financial commodity hedges (primarily gas and oil hedges) due to spreading our concentration risk over a number of counterparties. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. At March 31, 2009, the majority of the Utilities’ open financial commodity hedges were in net mark-to-market liability positions. See Note 11A for additional information with regard to our commodity derivatives.

At March 31, 2009, we had limited mark-to-market exposure to certain financial institutions under pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions for each of the Parent, PEC and PEF. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. At March 31, 2009, the Parent’s, PEC’s and PEF’s mark-to-market positions were not material. See Note 11B for additional information with regard to our interest rate derivatives.

Our pension trust funds and nuclear decommissioning trust funds are managed by a number of financial institutions, and the assets being managed are diversified in order to limit concentration risk in any one institution or business sector.

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 below and in Item 1A, “Risk Factors” in the 2008 Form 10-K.

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

HISTORICAL FOR 2009 AS COMPARED TO 2008

CASH FLOWS FROM OPERATIONS

Net cash provided by operating activities decreased $382 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to a $385 million decrease from receivables; a $216 million decrease resulting from cash collateral posted with counterparties, primarily by PEF due to the significant decline in natural gas prices; and a $155 million decrease from accounts payable, primarily driven by the timing of PEF’s payments to vendors and higher payments for fuel purchases due to increased fuel costs in 2009. The change in receivables was primarily driven by the 2008 settlement of $247 million of derivative receivables largely related to derivative contracts for our former synthetic fuels businesses and increases in accounts receivable at the Utilities in 2009 driven by higher revenues. These impacts were partially offset by a $123 million increase from income taxes, net primarily driven by the receipt of a $70 million federal income tax refund at PEC; a $108 million decrease in collateral held in 2008 associated with the synthetic fuels derivative contracts discussed above; a $104 million increase in the recovery of deferred fuel costs due to higher fuel rates, primarily at PEF; and an $80 million increase in the recovery of nuclear construction costs under Florida’s nuclear cost-recovery rule at PEF.

INVESTING ACTIVITIES

Net cash used by investing activities increased by $106 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. This increase was primarily due to $95 million in proceeds received in 2008 from sales of discontinued operations and other assets, net of cash divested and a $21 million increase in 2009 in capital expenditures for gross property additions, primarily at PEF. During 2008, proceeds from sales of discontinued operations and other assets primarily included proceeds of $94 million from the sale of Terminals and Coal Mining (See Notes 3A and 3B).

FINANCING ACTIVITIES

Net cash provided by financing activities increased by $795 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $1.016 billion increase in proceeds from long-term debt issuances, net due to PEC’s $600 million issuance and the Parent’s $750 million issuance in 2009 compared to PEC’s $325 million issuance in 2008; a $525 million increase from the issuance of common stock, primarily related to the Parent’s January 2009 common stock offering; and a $147 million decrease in payments on short-term debt compared to 2008. These impacts were partially offset by a $670 million decrease in short-term indebtedness, primarily driven by commercial paper repayments and the Parent’s $100 million repayment of borrowings outstanding under its RCA and a $320 million increase in long-term debt retirements, primarily related to PEC’s $400 million March 1, 2009 retirement. A discussion of our 2009 financing activities follows.

On January 12, 2009, the Parent issued 14.4 million shares of common stock at a public offering price of $37.50 per share, which are included in the 15.5 million shares discussed below. Net proceeds from this offering were $523 million. On February 3, 2009, we used $100 million of the proceeds to reduce the Parent’s $600 million RCA balance outstanding at December 31, 2008, and the remainder was used for general corporate purposes. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining $500 million outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity.

At December 31, 2008, we had 500 million shares of common stock authorized under our charter, of which 264 million shares were outstanding. For the three months ended March 31, 2009 and 2008, respectively, we issued approximately 15.5 million shares and 1.0 million shares of common stock resulting in approximately $545 million and $20 million in net proceeds. Included in these amounts were approximately 0.6 million shares and 0.4 million shares for net proceeds of approximately $22 million and $19 million, respectively, to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan and the Investor Plus Stock Purchase Plan.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2009, there were no material changes in our “Capital Expenditures,” “Other Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 to the 2008 Form 10-K, other than as described below and under “Credit Rating Matters”, “Regulatory Matters and Recovery of Costs” and “Financing Activities.”

The Utilities produce substantially all of our consolidated cash from operations. We anticipate that the Utilities will continue to produce substantially all of the consolidated cash flows from operations over the next several years. Our discontinued synthetic fuels operations historically produced significant net earnings from the generation of tax credits (See “Other Matters – Synthetic Fuels Tax Credits”). A portion of these tax credits has yet to be realized in cash due to the difference in timing of when tax credits are recognized for financial reporting purposes and realized for tax purposes. At March 31, 2009, we have carried forward $847 million of deferred tax credits. Realization of these tax credits is dependent upon our future taxable income, which is expected to be generated primarily by the Utilities.

We expect to be able to meet our future liquidity needs through cash from operations, commercial paper issuance, availability under our credit facilities, long-term debt financings and equity offerings. We may also use periodic ongoing sales of common stock from our Investor Plus Stock Purchase Plan and employee benefit and stock option plans to meet our liquidity requirements.

We issue commercial paper to meet short-term liquidity needs. As a result of financial and economic conditions in 2008, the short-term credit markets tightened, resulting in volatility in commercial paper durations and interest rates. In November 2008, the Parent borrowed $600 million under its RCA to reduce rollover risk in the commercial paper markets. A portion of the RCA was repaid with proceeds from the January 2009 equity issuance, and we will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining balance of the RCA loan, while maintaining an appropriate level of liquidity. If liquidity conditions deteriorate further and negatively impact the commercial paper market, we will need to evaluate other, potentially more expensive, options for meeting our short-term liquidity needs, which may include extending the term and amount of our borrowings under the Parent’s RCA, issuing short-term floating rate notes, and/or issuing long-term debt.

Progress Energy and its subsidiaries have approximately $11.505 billion in outstanding long-term debt. Currently, approximately $860 million of the Utilities’ debt obligations, approximately $620 million at PEC and approximately $240 million at PEF, are tax-exempt auction rate securities insured by bond insurance. Bond insurance generally allows companies to issue tax-exempt bonds with the insurance company’s higher credit rating. Ambac Assurance Corporation insures PEC’s bonds and Syncora Guarantee Inc., formerly XL Capital Assurance, Inc., insures PEF’s bonds.

The tax-exempt bonds continue to experience failed auctions. In the event of a failed auction, the bond holders cannot sell their bonds and the interest rate is calculated based on a multiple of a market index such as the Securities Industry and Financial Markets Association’s Municipal Swap Index or the London Interbank Offered Rate (LIBOR). The interest rates for most of PEC’s portfolio of tax-exempt securities reset based on the Securities

Industry and Financial Markets Association’s Municipal Swap Index. The interest rates for PEF’s portfolio of tax-exempt securities reset based on one-month LIBOR. The multiple on our auction rate bonds is stable as long as the bonds are rated A3 or higher by Moody’s Investors Service, Inc. (Moody’s) or A- or higher by Standard & Poor’s Rating Services (S&P). If the insurance company’s rating falls below the Utilities’ ratings, then the bonds will be rated at the Utilities’ senior secured debt rating, which is currently A2 by Moody’s and A- by S&P for both Utilities. We do not expect any future rating actions on Syncora Guarantee Inc. and Ambac Assurance Corporation to materially impact the reset rates of the tax-exempt securities.

Assuming the failed auctions persist, future interest rate resets on our tax-exempt auction rate bond portfolio will be dependent on the volatility experienced in the indices that dictate our interest rate resets and/or rating agency actions that may move our tax-exempt bonds below A3/A-. We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations under our defined benefit pension plans. Although a number of factors impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the obligations under our defined benefit pension plans. In 2009, contributions directly to pension plan assets are expected to approximate $222 million for us, $164 million for PEC and $57 million for PEF. An immaterial amount was contributed during the three months ended March 31, 2009 (See Note 10).

As discussed in “Other Matters – Environmental Matters,” over the long term, compliance with environmental regulations and meeting the anticipated load growth at the Utilities as described under “Other Matters – Increasing Energy Demand” will require the Utilities to make significant capital investments. These anticipated capital investments are expected to be funded through a combination of cash from operations and issuance of long-term debt, preferred stock and common equity, which are dependent on our ability to successfully access capital markets. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation. As discussed under "Other Matters - Nuclear," PEF expects the schedule for its proposed nuclear plant in Levy County, Florida (Levy) to shift by a minimum of 20 months from the 2016 to 2018 timeframe, which will reduce the near-term capital expenditures for the project.

Certain hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. Substantially all derivative commodity instrument positions are subject to retail regulatory treatment. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause. Due to the significant decline in natural gas prices since December 31, 2008, we have posted additional collateral with counterparties. At March 31, 2009, we had posted approximately $556 million of cash collateral compared to $340 million of cash collateral posted at December 31, 2008. The majority of our financial hedge agreements will settle in 2009 and 2010. Additional commodity market price decreases could result in significant increases in the derivative collateral that we are required to post with counterparties. We continually monitor our derivative positions in relation to market price activity.

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

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, including nuclear cost recovery, as discussed in Note 4 and “Other Matters – Regulatory Environment,” and filings for recovery of environmental costs, as discussed in Note 14 and in “Other Matters – Environmental Matters,” may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Regulatory developments expected to have a material impact on our liquidity are discussed below.

As discussed further in Note 4 and in “Other Matters – Regulatory Environment,” the North Carolina, South Carolina and Florida legislatures passed energy legislation that became law in recent years. These laws may impact

our liquidity over the long term, including among others, provisions regarding cost recovery, mandated renewable portfolio standards, demand-side management (DSM) and energy efficiency.

PEC Cost-Recovery Clause

On May 7, 2009, PEC filed with the Public Service Commission of South Carolina (SCPSC) for a decrease in the fuel rate charged to its South Carolina ratepayers. PEC is asking the SCPSC to approve a $13 million decrease in fuel rates driven by declining fuel prices. If approved, the decrease would take effect July 1, 2009, and would decrease residential electric bills by $2.05 per 1,000 kWh, or 2.0 percent, for fuel cost recovery. A hearing on the matter has been scheduled by the SCPSC for June 11, 2009. We cannot predict the outcome of this matter.

In 2008, PEC filed an application with the SCPSC to establish procedures that encourage investment in cost-effective energy-efficient technologies and energy conservation programs and approve the establishment of an annual rider to allow recovery for all costs associated with such programs, as well as the recovery of appropriate incentives for investing in such programs. On January 23, 2009, PEC filed a Stipulation Agreement between PEC and some of the other parties to the proceeding. A hearing on this matter was held on February 12, 2009. We cannot predict the outcome of this matter. On May 6, 2009, the SCPSC approved the Stipulation Agreement.

PEF Base Rates

On March 20, 2009, in anticipation of the expiration of its current base rate settlement agreement, PEF filed with the Florida Public Service Commission (FPSC) a proposal for an increase in base rates effective January 1, 2010. In its filing, PEF requested the FPSC to approve calendar year 2010 as the projected test period for setting new base rates and approve annual rate relief for PEF of $499 million, which includes PEF’s petition for a combined $76 million of new base rates in 2009 as discussed below. The request for increased base rates is based, in part, on investments PEF is making in its generating fleet and in its transmission and distribution systems. If approved by the FPSC, this portion of the new base rates would increase residential bills by approximately $9.07 per 1,000 kWh, or 7.1 percent, effective January 1, 2010. A ruling by the FPSC is expected in November 2009. We cannot predict the outcome of this matter.

Included within the base rate proposal is a request for an interim rate increase of $13 million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a limited proceeding to include in base rates revenue requirements of $63 million for the repowered Bartow power plant, which is expected to begin commercial operation in June 2009. If approved by the FPSC, PEF’s petitions for a combined $76 million of new base rates would increase residential bills by approximately $4.76 per 1,000 kWh, or 3.9 percent, effective July 1, 2009. On May 7, 2009, the staff of the FPSC recommended that PEF be allowed to increase its base rates, subject to refund, by a total of $70 million, effective the first billing cycle 30 days following the commercial operation in-sevice date of the repowered Bartow power plant. However, a ruling by the FPSC is expected later in May 2009. We cannot predict the outcome of this matter.

PEF Cost-Recovery Clause

On October 10, 2007, the FPSC issued an order requiring PEF to refund its ratepayers $14 million, including interest, over a 12-month period beginning January 1, 2008. The refund was returned to the ratepayers through a reduction of prior year under-recovered fuel costs. The FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On February 2, 2009, Florida’s Office of Public Counsel (OPC) filed direct testimony in this hearing alleging that during 2006 and 2007, PEF collected excessive fuel costs and sulfur dioxide (SO2) allowance costs of $61 million before interest. The OPC claimed that these excessive costs were attributed to PEF’s ongoing practice of not blending the most economical sources of coal at its CR4 and CR5 plants. A hearing on PEF’s 2006 and 2007 coal purchases was held April 13-15, 2009. During the hearing, the OPC

reduced the alleged excessive fuel costs to $33 million before interest. We expect a decision by the FPSC in June 2009. PEF believes its coal procurement practices have been prudent. We cannot predict the outcome of this matter.

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of distribution and substation transformers, which were estimated to be $19 million at March 31, 2009. The FPSC has approved cost recovery of PEF’s prudently incurred costs necessary to achieve its integrated strategy to address compliance with the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule (CAMR) and the Clean Air Visibility Rule (CAVR) through the ECRC (See “Other Matters – Environmental Matters” for discussion regarding the CAIR, CAMR and CAVR).

Nuclear Cost Recovery

PEF is allowed to recover prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balances on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in PEF’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility. On April 6, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear preconstruction costs for PEF’s proposed nuclear plant in Levy, which the FPSC had authorized to be collected in 2009. The approval reduces residential customers’ nuclear cost-recovery charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first April 2009 billing cycle. Commercial and industrial customers will see similar reductions.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

At March 31, 2009, our guarantees have not changed materially from what was reported in the 2008 Form 10-K.

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 11 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2008 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities' future needs. At March 31, 2009, our and the Utilities contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2008 Form 10-K however, PEF now expects to shift the schedule for its planned Levy nuclear project. Although the overall schedule impact is not certain at this time, PEF expects the schedule to shift from the 2016 to 2018 timeframe by a minimum of 20 months. We anticipate amending the Levy Engineering, Procurement and Construction ("EPC") agreement due to the schedule shift but cannot predict the impact such amendment might have on the project's cost, if any. Refer to "Other Matters - Nuclear" below for further discussion of the Levy nuclear project.

OTHER MATTERS

SYNTHETIC FUELS TAX CREDITS

Historically, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Internal Revenue Code (the Code) (Section 29) and as redesignated effective 2006 as Section 45K of the Code as discussed below. The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. Qualifying synthetic fuels facilities entitled their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The synthetic fuels tax credit program expired at the end of 2007 and the synthetic fuels businesses were abandoned and reclassified to discontinued operations.

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

Total Section 29/45K credits generated under the synthetic fuels tax credit program (including those generated by Florida Progress prior to our acquisition), were $1.891 billion, of which $1.044 billion has been used through March 31, 2009, to offset regular federal income tax liability and $847 million is being carried forward as deferred tax credits.

See Note 15C for additional discussion related to our previous synthetic fuels operations.

REGULATORY ENVIRONMENT

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

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

The American Recovery and Reinvestment Act signed into law in February 2009 contains provisions promoting energy efficiency and renewable energy, including $11 billion for Smart Grid-related technologies, $6.3 billion for energy-efficiency and conservation grants and $2 billion in tax credits for the purchase of plug-in electric vehicles.

Also, the Obama administration has announced a goal of sparking a new energy revolution by stimulating transmission and promoting renewable resources while also pricing greenhouse gas emissions and setting a federal requirement for renewable energy. We are currently reviewing the impact the new legislation might have on our operations. The impact of the new legislation and regulation resulting from other federal initiatives cannot be determined at this time.

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

Florida energy law enacted in 2008 includes provisions that would, among other things, (1) help enhance the ability to cost-effectively site transmission lines; (2) require the FPSC to develop a renewable portfolio standard that the FPSC would present to the legislature for ratification in 2009; (3) direct the Florida Department of Environmental Protection (FDEP) to develop rules establishing a cap-and-trade program to regulate greenhouse gas emissions that the FDEP would present to the legislature no earlier than January 2010 for ratification by the legislature; and (4) establish a new Florida Energy and Climate Commission as the principal governmental body to develop energy and climate policy for the state and to make recommendations to the governor and legislature on energy and climate issues. In complying with the provisions of the law, PEF would be able to recover its reasonable prudent compliance costs. However, until the rulemaking processes are completed, we cannot predict the costs of complying with the law.

On July 13, 2007, the governor of Florida issued executive orders to address reduction of greenhouse gas emissions. The executive orders call for the first southeastern state cap-and-trade program and include adoption of a maximum allowable emissions level of greenhouse gases for Florida utilities. The standard will require, at a minimum, the following three reduction milestones: by 2017, emissions not greater than Year 2000 utility sector emissions; by 2025, emissions not greater than Year 1990 utility sector emissions; and by 2050, emissions not greater than 20 percent of Year 1990 utility sector emissions. The FDEP’s first workshop on the greenhouse gas cap-and-trade rulemaking was held December 11, 2008. The rulemaking is expected to continue through 2009, and the rule requires legislative ratification before implementation.

The executive orders also requested that the FPSC initiate a rulemaking by September 1, 2007, that would (1) require Florida utilities to produce at least 20 percent of their electricity from renewable sources; (2) reduce the cost of connecting solar and other renewable energy technologies to Florida’s power grid by adopting uniform statewide interconnection standards for all utilities; and (3) authorize a uniform, statewide method to enable residential and commercial customers, who generate electricity from on-site renewable technologies of up to 1 megawatt (MW) in capacity, to offset their consumption over a billing period by allowing their electric meters to turn backward when they generate electricity (net metering). On January 12, 2009, the FPSC approved a draft Florida renewable portfolio standard (Florida RPS) rule with a goal of 20 percent renewable energy production by 2020. The FPSC provided the draft Florida RPS rule to the Florida legislature in February 2009. The legislature will review, ratify as is, make revisions, or decide not to have a Florida RPS rule at all. We cannot predict the outcome of this matter.

We cannot predict the costs of complying with the laws and regulations that may ultimately result from these executive orders. Our balanced solution, as described in “Increasing Energy Demand,” includes greater investment in energy efficiency, renewable energy and state-of-the-art generation and demonstrates our commitment to environmental responsibility.

North Carolina energy law enacted in 2007 includes provisions for a North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), expansion of the definition of the traditional fuel clause and recovery of the costs of new DSM and energy-efficiency programs through an annual DSM clause. On February 29, 2008, the NCUC issued an order adopting final rules for implementing North Carolina’s 2007 energy law. The rules include filing requirements regarding NC REPS compliance and inclusion in the Utility’s integrated resource plan. The order also establishes a schedule and filing requirements for DSM and energy-efficiency cost recovery and financial incentives. Rates for the DSM and energy-efficiency clause and the NC REPS clause will be set based on projected costs with true-up provisions. In 2008, PEC filed for NCUC approval of multiple DSM and energy-efficiency programs. The majority of the programs has been approved by the NCUC or is pending further review. We cannot predict the outcome of the DSM and energy-efficiency filings pending further approval by the NCUC or whether the programs will produce the expected operational and economic results.

LEGAL

We are subject to federal, state and local legislation and court orders. The specific issues, the status of the issues, accruals associated with issue resolutions and our associated exposures are discussed in detail in Note 15C.

INCREASING ENERGY DEMAND

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

We are actively pursuing expansion of our DSM, energy-efficiency and conservation programs as energy efficiency is one of the most effective ways to reduce energy costs, offset the need for new power plants and protect the environment. DSM programs include, but are not limited to, any program or initiative that shifts the timing of electricity use from peak to nonpeak periods and includes load management, electricity system and operating controls, direct load control, interruptible load, and electric system equipment and operating controls. Our energy-efficiency program provides simple, low-cost options for residential customers to reduce energy use, promotes home energy checks, provides tools and programs for large and small businesses to minimize their energy use and provides an interactive Internet Web site with online calculators, programs and efficiency tips.

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

In the coming years, we will continue to invest in existing plants and consider plans for building new generating plants. Due to the anticipated long-term growth in our service territories, we estimate that we will require new generation facilities in both Florida and the Carolinas toward the end of the next decade, and we are evaluating the best available options for this generation, including advanced design nuclear and gas technologies. At this time, no definitive decisions have been made to construct new nuclear plants. In 2007, PEC announced a two-year moratorium on constructing new coal-fired plants while pursuing expansion of energy-efficiency and conservation programs. If PEC proceeds with construction of a new nuclear plant, the new plant would not be online until at least 2019 (See “Nuclear” below).

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

In 2008, Congress authorized $38.5 billion in loan guarantee authority for innovative energy projects. Of the total provided, $18.5 billion is set aside for nuclear power facilities, $2 billion for advanced nuclear facilities for the "front-end" of the nuclear fuel cycle, $10 billion for renewable and/or energy-efficient systems and manufacturing and distributed energy generation/transmission and distribution, $6 billion for coal-based power generation and industrial gasification at retrofitted and new facilities that incorporate carbon capture and sequestration or other beneficial uses of carbon, and $2 billion for advanced coal gasification. In June 2008, the DOE announced solicitations for a total of up to $30.5 billion of the amount authorized by Congress in federal loan guarantees for projects that employ advanced energy technologies that avoid, reduce or sequester air pollutants or greenhouse gas emissions and advanced nuclear facilities for the “front-end” of the nuclear fuel cycle.

PEF submitted Part I of the Application for Federal Loan Guarantees for Nuclear Power Facilities on September 29, 2008, for Levy. PEF was one of 19 applicants that submitted Part I of the application. The program requires that the guarantee be in a first lien position on all assets of the project, which conflicts with PEF’s current mortgage. Obtaining the required approval to amend the current mortgage from 100 percent of PEF’s current bondholders would be unlikely, and current secured debt of $4.0 billion would need to be refinanced with unsecured debt to meet the requirements of the guarantee. In addition, the costs associated with obtaining the loan guarantee are unclear. PEF decided not to pursue the loan guarantee program and did not submit Part II of the application, which was due

on December 19, 2008. However, this decision does not preclude PEF from revisiting the program at a later date if there are changes to the program. We cannot predict if PEF will pursue this program further.

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

NUCLEAR

Nuclear generating units are regulated by the NRC. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. Our nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.

The NRC operating licenses for PEC’s nuclear units expire between 2030 and 2046. The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016. On March 9, 2009, the NRC docketed, or accepted for review, PEF’s application for a 20-year extension on the operating license for CR3, which would extend the operating license through 2036, if approved. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will renew the license. The license renewal application for CR3 is currently under review by the NRC with a decision expected in 2010 or 2011.

POTENTIAL NEW CONSTRUCTION

While we have not made a final determination on nuclear construction, we have taken steps to keep open the option of building a plant or plants. During 2008, PEC and PEF filed combined license (COL) applications to potentially construct new nuclear plants in North Carolina and Florida. The NRC estimates that it will take approximately three to four years to review and process the COL applications.

On January 23, 2006, we announced that PEC selected a site at the Shearon Harris Nuclear Plant (Harris) to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. On February 19, 2008, PEC filed its COL application with the NRC for two additional reactors at Harris. On April 17, 2008, the NRC docketed, or accepted for review, the Harris application. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will issue the license. One petition to intervene in the licensing proceeding was filed with the NRC within the 60-day notice period. We cannot predict the outcome of this matter. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, a new plant would not be online until at least 2019 (See “Increasing Energy Demand” above).

On December 12, 2006, we announced that PEF selected a greenfield site at Levy to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application submission. In 2007, PEF completed the purchase of approximately 5,000 acres for Levy and associated transmission needs. In 2007, both the Levy County Planning Commission and the Board of Commissioners voted unanimously in favor of PEF’s requests to change the comprehensive land use plan. On May 29, 2008, the Florida Department of Community Affairs (FDCA) issued its final determination that the amendments to the Levy County Comprehensive Plan are in compliance with land use regulations.

In 2008, PEF submitted filings for two key state approvals. First, on March 11, 2008, PEF filed a Petition for a Determination of Need for Levy with the FPSC. The FPSC issued a final order granting PEF’s petition for Levy on August 12, 2008. Second, on June 2, 2008, PEF filed its application for Site Certification with the FDEP. On

January 12, 2009, the FDEP filed a favorable staff analysis report in advance of site certification hearings. On March 12, 2009, the technical proceedings concluded, and an order from the administrative law judge is expected by the end of May 2009.

On July 30, 2008, PEF filed its COL application with the NRC for two reactors. PEF also completed and submitted a Limited Work Authorization request for Levy concurrent with the COL application. On October 6, 2008, the NRC docketed, or accepted for review, the Levy application. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will issue the license. On February 24, 2009, PEF received the NRC’s schedule for review and approval of the COL. One petition to intervene in the licensing proceeding was filed with the NRC within the 60-day notice period. On April 20-21, 2009, the Atomic Safety and Licensing Board heard oral arguments on whether any of the intervener’s proposed contentions will be admitted in the Levy COL proceeding. We cannot predict the outcome of this matter.

Based on the NRC’s treatment of certain work prior to the issuance of the Levy COL, PEF now expects a schedule shift for the commercial operation dates of the Levy nuclear units. Specifically, PEF’s initial schedule anticipated the ability to perform certain site work pursuant to a Limited Work Authorization from the NRC prior to COL receipt. The NRC Staff has recently determined, however, that certain schedule-critical work that PEF had proposed to perform within the Limited Work Authorization scope will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work will be shifted until after COL issuance. Although the overall schedule impact is not certain at this time, PEF expects the schedule to shift from the 2016 to 2018 timeframe by a minimum of 20 months. We anticipate amending the EPC agreement discussed below due to the schedule shift but cannot predict the impact such amendment might have on the project’s cost, if any.

As discussed below, the schedule shift will reduce the near-term capital expenditures for the project and also reduce the near-term impact on customer rates. The schedule shift will also allow more time for certainty around federal climate change policy, which is currently being debated, and could result in more favorable financing than currently available. We believe that continuing, although at a slower pace than initially anticipated, is a reasonable and prudent course at this early stage of the project. We still consider Levy as PEF’s preferred baseload generation option, taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including public, regulatory and political support; adequate financial cost-recovery mechanisms; and availability and terms of capital financing.

PEF signed the EPC agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two Westinghouse AP1000 nuclear units to be constructed at Levy. More than half of the approximate $7.650 billion contract price is fixed or firm with agreed upon escalation factors. The total cost for the two generating units is estimated to be approximately $14 billion. This total cost estimate includes land, plant components, financing costs, construction, labor, regulatory fees and the initial core for the two units. An additional $3 billion is estimated for the necessary transmission equipment and approximately 200 miles of transmission lines associated with the project. As noted above, the final cost of the project will depend on the completion dates, which will be determined in large part by the NRC review schedule. The EPC agreement includes various incentives, warranties, performance guarantees, liquidated damage provisions and parent guarantees designed to incent the contractor to perform efficiently. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances.

Florida regulations allow investor-owned utilities such as PEF to recover prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balance of a nuclear power plant prior to commercial operation. The costs are recovered on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in a utility’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule will require the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility.

In 2008, PEF sought and received approval from the FPSC to recover Levy preconstruction and carrying charges of $357 million as well as site selection costs of $38 million through the 2009 capacity cost-recovery clause. In 2009,

PEF received approval to defer until 2010 the recovery of $198 million of these costs (See Note 4B). PEF will be a participant in the annual nuclear cost-recovery proceeding, which was opened by the FPSC on January 5, 2009. The proceeding will occur throughout the year with an order expected by the end of 2009. On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 as well as the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to help mitigate the initial price impact on its customers, as part of its filing, PEF has proposed collecting certain costs over a five-year period, with associated carrying costs. The deferral would result in a nuclear cost-recovery charge of $6.69 per 1,000 kWh for residential customers, which is approximately half of the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery rule. If approved, the charges would begin with the first January 2010 billing cycle. The FPSC has scheduled hearings in this matter for September 8-11, 2009, with a decision expected in October 2009. We cannot predict the outcome of this matter.

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

SPENT NUCLEAR FUEL MATTERS

In July 2002, Congress passed an override resolution to Nevada’s veto of the DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.; and the city of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) for review of the Congressional override resolution. These same parties also challenged the EPA’s radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. On September 30, 2008, the EPA issued final rules for limiting radiation exposure at Yucca Mountain. The EPA retained the dose limit of 15 millirem per year for the first 10,000 years and established a dose limit of 100 millirem for annual exposure per year between 10,000 years and 1 million years. In February 2009, the NRC approved a final rule for the waste repository at Yucca Mountain incorporating these radiation protection standards. On October 10, 2008, the state of Nevada again filed suit with the D.C. Court of Appeals challenging the EPA standard.

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

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

On August 5, 2008, the DOE announced that its estimated cost to build and commence operations at the Yucca Mountain facility has increased from $57.5 billion to $96.2 billion due to an increase in material costs, an increase in the quantity of spent fuel to store and a refinement of the repository’s design. The 2010 federal budget proposed by the Obama administration largely eliminates funding for the Yucca Mountain facility while the administration devises a new strategy toward nuclear waste disposal. We cannot predict the outcome of this matter

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

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

See Note 15C for information about the complaint filed by the Utilities in the United States Court of Federal Claims against the DOE for its failure to fulfill its contractual obligation to receive spent fuel from nuclear plants. Failure to open the Yucca Mountain or other facility would leave the DOE open to further claims by utilities.

ENVIRONMENTAL MATTERS

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida or potentially responsible parties (PRP) groups. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 4 and 13). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. Hazardous and solid waste management matters are discussed in detail in Note 14A.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion products, primarily ash, from each of the Utilities’ coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. We are evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures. These issues are also under evaluation by state agencies. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when those new regulations are finalized.

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

AIR QUALITY AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which likely would result in increased capital expenditures and O&M expenses. Additionally, Congress is considering legislation that would require reductions in air emissions of NOx, SO2, 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 installed pursuant to the provisions of CAIR, CAVR and mercury regulation, which are discussed below, may address some of the issues outlined above.

PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, CAVR and mercury regulation (see discussion of the court decisions that impacted the CAIR, the delisting determination and the CAMR below). The CAVR requires the installation of best available retrofit technology (BART) on certain units. However, the outcome of these matters cannot be predicted.

Clean Smokestacks Act

In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,000 MW of coal-fired generation capacity in North Carolina that is affected by the Clean Smokestacks Act. On March 31, 2009, PEC filed its annual estimate with the NCUC of the total capital expenditures to meet emission targets under the Clean Smokestacks Act by the end of 2013, which were approximately $1.4 billion at the time of the filing. We are continuing to evaluate various design, technology and new generation options that could change expenditures required by the Clean Smokestacks Act. Changes in projected fuel sources may require us to incur costs, which are not currently estimable, to install additional controls subsequent to 2013 in order to remain compliant with the requirements of the Clean Smokestacks Act. O&M expenses increase with the operation of pollution control equipment due to the cost of commodities such as ammonia and limestone used in emissions control technologies (reagents), additional personnel and general maintenance associated with the pollution control equipment. Legislation in North Carolina and South Carolina expanded the traditional fuel clause to include the annual recovery of reagents and certain other costs; all other O&M expenses are currently recoverable through base rates.

Two of PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. In 2005, PEC entered into an agreement with the joint owner to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 14B).

Clean Air Interstate Rule

The CAIR issued by the EPA on March 10, 2005, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2. States were required to adopt rules implementing the CAIR and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR in 2007.

PEF participated in a coalition of Florida utilities that filed a challenge to the CAIR as it applied to Florida (PEF withdrew from the coalition during the fourth quarter of 2008). On July 11, 2008, the D.C. Court of Appeals issued its decision on multiple challenges to the CAIR, including the Florida challenge, which vacated the CAIR in its entirety. On December 23, 2008, the D.C. Court of Appeals remanded the CAIR, without vacating the rule, for the EPA to conduct further proceedings consistent with the D.C. Court of Appeals’ prior opinion. This decision leaves the CAIR in effect until such time that it is revised or replaced. The EPA informed the D.C. Court of Appeals that development and finalization of a replacement rule could take approximately two years. The outcome of this matter cannot be predicted.

PEF is continuing construction of its in-process emission control projects. On December 18, 2008, PEF and the FDEP announced an agreement under which PEF will retire CR1 and CR2 as coal-fired units and complete construction of its emission control projects at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was anticipated to be around 2020. As discussed under “Other Matters – Nuclear,” PEF expects the Levy schedule to shift by a minimum of 20 months from the 2016 to 2018 timeframe. PEF is required to advise the FDEP of any developements that will delay the retirement of CR1 and CR2 beyond the orginally anticipated completion date of the first fuel cycle for Levy Unit 2. Accordingly, PEF has advised the FDEP of the Levy schedule shift. We are currently evaluating the impacts of the Levy schedule shift. We cannot predict the outcome of this matter.

Clean Air Mercury Rule

On March 15, 2005, the EPA finalized two separate but related rules: the CAMR that set mercury emissions limits to be met in two phases beginning in 2010 and 2018, respectively, and encouraged a cap-and-trade approach to achieving those caps, and a delisting rule that eliminated any requirement to pursue a maximum achievable control technology approach for limiting mercury emissions from coal-fired power plants. On February 8, 2008, the D.C. Court of Appeals vacated the delisting determination and the CAMR. The U.S. Supreme Court declined to hear an appeal of the D.C. Court of Appeals decision in January 2009. As a result, the EPA subsequently announced that it will develop a maximum achievable control technology (MACT) standard consistent with the agency’s original listing determination. The three states in which the Utilities operate adopted mercury regulations implementing the CAMR and submitted their state implementation rules to the EPA. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. The outcome of this matter cannot be predicted.

Clean Air Visibility Rule

On June 15, 2005, the EPA issued the final CAVR. The EPA’s rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in 156 specially protected areas, including national parks and wilderness areas, designated as Class I areas. To help restore visibility in those areas, states must require the identified facilities to install BART to control their emissions. PEC’s BART-eligible units are Asheville Units No. 1 and No. 2, Roxboro Units No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Units No. 1 and No. 2, Bartow Unit No. 3 and CR1 and CR2. The reductions associated with BART begin in 2013. As discussed above, on December 18, 2008, PEF and the FDEP announced an agreement under which PEF will retire CR1 and CR2 as coal-fired units.

The CAVR included the EPA’s determination that compliance with the NOx and SO2 requirements of the CAIR could be used by states as a BART substitute to fulfill BART obligations, but the states could require the installation of additional air quality controls if they did not achieve reasonable progress in improving visibility. The D.C. Court of Appeals’ December 23, 2008 decision remanding the CAIR maintained its implementation such that CAIR satisfies BART for SO2 and NOx. Should this determination change as the CAIR is revised, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. On December 4, 2007, the FDEP finalized a Regional Haze implementation rule that goes beyond BART by requiring sources significantly impacting visibility in Class I areas to install additional controls by December 31, 2017. However, the FDEP has not determined the level of additional controls PEF may have to implement. The outcome of these matters cannot be predicted.

Compliance Strategy

Both PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, the CAVR, mercury regulation and related air quality regulations. The air quality controls installed to comply with the requirements of the NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) and Clean Smokestacks Act resulted in a reduction of the costs to meet the CAIR requirements for our North Carolina units at PEC.

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

The FPSC approved PEF’s petition to develop and implement an Integrated Clean Air Compliance Plan to comply with the CAIR, CAMR and CAVR and for recovery of prudently incurred costs necessary to achieve this strategy through the ECRC (see discussion above regarding the vacating of the CAMR and remanding of the CAIR). PEF’s most recent filing with the FPSC, filed on April 1, 2009, seeks approval for true-up of final 2008 environmental costs and included a review of the Integrated Clean Air Compliance Plan, which reconfirmed the efficacy of the recommended plan and included an estimated total project cost of approximately $1.2 billion to be spent through 2016, to plan, design, build and install pollution control equipment at the Anclote and Crystal River plants. Additional costs may be incurred if pollution controls are required in order to comply with the requirements of the CAVR, as discussed above, or to meet revised compliance requirements of a revised or new implementing rule for

the CAIR. Subsequent rule interpretations, increases in the underlying material, labor and equipment costs, equipment availability, or the unexpected acceleration of compliance dates, among other things, could result in significant increases in our estimated costs to comply and acceleration of some projects. The outcome of this matter cannot be predicted.

Environmental Compliance Cost Estimates

Environmental compliance cost estimates are dependent upon a variety of factors and, as such, are highly uncertain and subject to change. Factors impacting our environmental compliance cost estimates include new and frequently changing laws and regulations; the impact of legal decisions on environmental laws and regulations; changes in the demand for, supply of and costs of labor and materials; changes in the scope and timing of projects; various design, technology and new generation options; and projections of fuel sources, prices, availability and security. Costs to comply with environmental laws and regulations are eligible for regulatory recovery through either base rates or cost-recovery clauses. The outcome of future petitions for recovery cannot be predicted. Our estimates of capital expenditures to comply with environmental laws and regulations are subject to periodic review and revision and may vary significantly. We cannot predict the impact that the EPA’s further CAIR proceedings will have on our compliance with the CAVR requirements and will continue to reassess our plans and estimated costs to comply with the CAVR. The timing and extent of the costs for future projects will depend upon final compliance strategies.

The following tables contain information about our current estimates of capital expenditures to comply with environmental laws and regulations described above. Amounts presented in the tables exclude AFUDC.

Progress Energy

Air and Water Quality Estimated Required Environmental Expenditures (in millions)

Estimated Timetable

Total Estimated Expenditures

Cumulative Spent through March 31, 2009

Clean Smokestacks Act(a)

2002 – 2013

1,400

1,027

In-process CAIR projects(b)

2005 – 2010

1,200

923

CAVR(c)

– 2017

–

Mercury regulation(d)

2006 – 2017

–

Total air quality

2,600

1,955

Clean Water Act Section 316(b)(e)

–

Total air and water quality

2,600

1,955

PEC

Air and Water Quality Estimated Required Environmental Expenditures (in millions)

Estimated Timetable

Total Estimated Expenditures

Cumulative Spent through March 31, 2009

Clean Smokestacks Act(a)

2002 – 2013

1,400

1,027

In-process CAIR projects(b)

2005 – 2008

–

CAVR(c)

– 2017

–

Mercury regulation(d)

2006 – 2017

–

Total air quality

1,400

1,032

Clean Water Act Section 316(b)(e)

–

Total air and water quality

1,400

1,032

PEF

Air and Water Quality Estimated Required Environmental Expenditures (in millions)

Estimated Timetable

Total Estimated Expenditures

Cumulative Spent through March 31, 2009

In-process CAIR projects(b)

2005 – 2010

1,200

923

CAVR(c)

– 2017

–

Mercury regulation(d)

–

Total air quality

1,200

923

Clean Water Act Section 316(b) (e)

–

Total air and water quality

1,200

923

(a)	PEC is continuing to evaluate various design, technology and new generation options that could change expenditures required by the Clean Smokestacks Act.

(b)	PEF is continuing construction of its in-process emission control projects. Additional compliance plans for PEC and PEF to meet the requirements of a revised rule will be determined upon finalization of the rule. See discussion under “Clean Air Interstate Rule.”

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

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

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

All environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions, which included projects at PEC’s Asheville, Lee, Mayo and Roxboro plants, have been placed in service. The remaining projects to comply with the second phase of emission reductions, which are smaller in scope, have not yet begun. These estimates are conceptual in nature and subject to change. Additional compliance projects requiring material environmental compliance costs may be implemented in the future.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects under construction at CR5 and CR4, which are expected to be placed in service in 2009 and 2010, respectively. As a result of changes in the scope of work related to estimation of costs for compliance with the CAIR and the uncertainty regarding the EPA’s further CAIR proceedings, the delisting determination and the CAMR discussed above, PEF is currently unable to estimate certain costs of compliance. However, PEF believes that future costs to comply with new or subsequent rule interpretations could be significant. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when those new regulations are finalized.

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

In March 2004, the North Carolina attorney general filed a petition with the EPA, under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina’s ability to meet national air quality standards for ozone and particulate matter. In 2006, the EPA issued a final response denying the petition and the North Carolina attorney general filed a petition in the D.C. Court of Appeals seeking a review of the agency’s denial. Briefing on the merits has been completed and oral arguments were heard in early 2009. The outcome of this matter cannot be predicted.

National Ambient Air Quality Standards

In 2006, the EPA announced changes to the National Ambient Air Quality Standards (NAAQS) for particulate matter. The changes in particulate matter standards did not result in designation of any additional nonattainment areas in PEC’s or PEF’s service territories. Environmental groups and 13 states filed a joint petition with the D.C. Court of Appeals arguing that the EPA's new particulate matter rule does not adequately restrict levels of particulate matter, especially with respect to the annual and secondary standards. On February 24, 2009, the D.C. Court of Appeals remanded the annual and secondary standards to the EPA for further review and consideration. The outcome of this matter cannot be predicted.

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

New Source Review

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether changes at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. We were asked to provide information to the EPA as part of this initiative and cooperated in supplying the requested information. The EPA has undertaken civil enforcement actions against unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements requiring expenditures by these unaffiliated utilities, several of which included reported expenditures in excess of $1.0 billion for retrofit of pollution control equipment. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related costs through rate adjustments or similar mechanisms.

Water Quality

1. General

As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams will be generated at certain affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes is currently ongoing and will result in permitting, construction and treatment requirements imposed on the Utilities now and into the future. The future costs of these requirements could be material to our or the Utilities’ results of operations or financial position.

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

Section 316(b) of the Clean Water Act (Section 316(b)) requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. The EPA promulgated a rule implementing Section 316(b) in respect to existing power plants in July 2004.

A number of states, environmental groups and others sought judicial review of the July 2004 rule. In 2007, the U.S. Court of Appeals for the Second Circuit issued an opinion and order remanding many provisions of the rule to the EPA and the EPA suspended the rule pending further rulemaking, with the exception of the requirement that permitted facilities must meet any requirements under Section 316(b) as determined by the permitting authorities on a case-by-case, best professional judgment basis. Several parties filed petitions for writ of certiorari to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court issued its opinion holding that the EPA, in selecting the “best technology” pursuant to Section 316(b), does have the authority to reject technology when its costs are “wholly disproportionate” to the benefits expected. Also, the U.S. Supreme Court held that EPA’s site-specific variance procedure (contained in the July 2004 rule) was permissible in that the procedure required testing to determine whether costs would be “significantly greater than” the benefits before a variance would be considered. The EPA is expected to publish proposed rules later in 2009 responding to both the remand by the U.S. Court of Appeals for the Second Circuit and the U.S. Supreme Court’s opinion. As a result of these developments, our plans and associated estimated costs to comply with Section 316(b) will need to be reassessed and determined in accordance with any revised or new implementing rule once it is established by the EPA. Costs of compliance with a revised or new implementing rule are expected to be higher, and could be significantly higher, than estimated costs under the July 2004 rule. Our most recent cost estimates to comply with the July 2004 rule were $60 million to $90 million, including $5 million to $10 million at PEC and $55 million to $80 million at PEF. The outcome of this matter cannot be predicted.

OTHER ENVIRONMENTAL MATTERS

Global Climate Change

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO2 and other greenhouse gases. The treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol. Growing state, federal and international attention to global climate change may result in the regulation of CO2 and other greenhouse gases. The Obama administration has agreed to review whether or not CO2 emissions from coal-fired power plants should be regulated. We are preparing for a carbon-constrained future and are actively engaged in helping shape effective policies to address the issue. While state-level study groups are active in all three of our jurisdictions, we continue to believe that this is an issue that requires a national policy framework – one that provides certainty and consistency. Our balanced solution as discussed in “Other Matters – Increasing Energy Demand” is a comprehensive plan to meet the anticipated demand in the Utilities’ service territories and provides a solid basis for slowing and reducing CO2 emissions by focusing on energy efficiency, alternative energy and state-of-the-art power generation. We issued our latest report on global climate change in the second quarter of 2008, which further evaluates and states our position on this dynamic issue.

There are ongoing efforts to reach a new international climate change treaty to succeed the Kyoto Protocol. Reductions in CO2 emissions to the levels specified by the Kyoto Protocol, potential new international treaties or federal or state proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from ratepayers. The cost impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time. As discussed under “Other Matters – Regulatory Environment,” in 2008 the state of Florida passed comprehensive energy legislation, which includes a directive that the FDEP develop rules to establish a cap-and-trade program to regulate greenhouse gas emissions that would be presented to the legislature no earlier than January 2010.

On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority under the Clean Air Act to regulate CO2 emissions from new automobiles. On April 2, 2008, 18 states and 11 environmental groups filed an action in the D.C. Court of Appeals against the EPA Administrator seeking an order requiring the EPA to make a determination within 60 days of whether greenhouse gas emissions endanger public health and welfare. The D.C. Court of Appeals denied the petition on June 26, 2008. On April 17, 2009, the EPA issued a proposed endangerment finding under the Clean Air Act, which identified six greenhouse gases (carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) that pose a potential threat to human health and welfare. The proposed finding now moves to a public comment period after which the EPA will make a final determination. The outcome of this matter cannot be predicted.

Prior to 2009, the EPA received waiver requests from a number of states to allow those states to set standards for CO2 emissions from new vehicles. The EPA denied those requests. On January 26, 2009, the Obama administration requested the EPA to review its earlier denials of waiver requests by states to regulate CO2 emissions from vehicles. The impact of this development cannot be predicted.

NEW ACCOUNTING STANDARDS

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

PEC

The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q and Item 1A, “Risk Factors” to the 2008 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities decreased $22 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to the $55 million decrease from accounts payable, primarily driven by the timing of purchases and payments to vendors; a $28 million increase in inventory purchases, primarily due to higher priced coal; and a $23 million increase in accounts receivable driven by higher revenues. These impacts were partially offset by changes in income taxes, primarily due to the receipt of a $70 million federal income tax refund, and a $19 million increase in the recovery of deferred fuel costs due to higher fuel rates.

Net cash used by investing activities decreased $24 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due a $20 million decrease in advances to affiliated companies and a $13 million decrease in nuclear fuel additions. The decrease in nuclear fuel additions was driven by higher purchases of nuclear fuel in 2008. These impacts were partially offset by an $8 million increase in gross property additions.

Net cash used by financing activities increased $271 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to 2009 activity, which included the $400 million payment at maturity of PEC’s 5.95% Senior Notes, the $200 million in dividends paid to the Parent and the $110 million repayment of commercial paper outstanding. These impacts were partially offset by an increase in the proceeds from the issuance of long-term debt and the $154 million repayment of advances from affiliates in 2008. PEC issued $600 million in long-term debt in 2009 compared to a $325 million issuance in 2008. PEC’s 2009 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources.”

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

MARKET RISK AND DERIVATIVES

Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

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

OTHER MATTERS

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

PEF

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

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities decreased $158 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to a $204 million decrease resulting from cash collateral posted with counterparties on derivative contracts discussed under Progress Energy’s MD&A, “Liquidity and Capital Resources;” an $83 million decrease from accounts payable and payables to affiliated companies driven by the timing of payments to vendors and higher payments for fuel purchases due to increased fuel costs; a $50 million increase in accounts receivable driven by higher revenues; and a $35 million increase in inventory purchases. These impacts were partially offset by an $85 million increase in the recovery of deferred fuel costs due to higher fuel rates, an $80 million increase in the recovery of nuclear construction costs under Florida’s nuclear cost-recovery rule, and a $34 million decrease in long-term emission allowance purchases.

Net cash used by investing activities increased $176 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The increase was primarily due a $149 million decrease in settlements of advances to affiliates, a $16 million increase in capital expenditures for utility property additions, and a $9 million increase in nuclear fuel additions. The increase in property additions was driven by a $138 million increase in nuclear projects, partially offset by an $85 million decrease in environmental compliance spending and a $50 million decrease in spending for repowering the Bartow plant to more efficient natural gas-burning technology.

Net cash provided by financing activities increased $342 million for the three months ended March 31, 2009, when compared to the corresponding period in the prior year. The increase was primarily due a $347 million change in advances from affiliates, a $155 million contribution from the Parent and the payment at maturity of $80 million of first mortgage bonds in 2008. These impacts were partially offset by the $241 million repayment of commercial paper outstanding. PEF’s 2009 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources.”

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

MARKET RISK AND DERIVATIVES

Under its risk management policy, PEF may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

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

OTHER MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various risks related to changes in market conditions. Market risk represents the potential loss arising from adverse changes in market rates and prices. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk to the extent that the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties (See Note 11). Both PEC and PEF also have limited counterparty exposure from commodity hedges (primarily gas and oil hedges) by spreading concentration risk over a number of counterparties.

The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review Item 1A, “Risk Factors” to the 2008 Form 10-K, and Item 1A, “Risk Factors” found within Part II and “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q for a discussion of the factors that may impact any such forward-looking statements made herein.

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

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

PROGRESS ENERGY

Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2008.

INTEREST RATE RISK

Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at March 31, 2009, has changed from December 31, 2008. The total notional amount of fixed rate long-term debt at March 31, 2009, was $10.295 billion, with an average interest rate of 6.16% and fair market value of $10.7 billion. The total notional amount of fixed rate long-term debt at December 31, 2008, was $9.346 billion, with an average interest rate of 6.17% and fair market value of $9.9 billion. The total notional amount of variable rate long-term debt at March 31, 2009, was $961 million, with an average interest rate of 1.22% and fair market value of $1.0 billion. The total notional amount of variable rate long-term debt at December 31, 2008, was $1.061 billion, with an average interest rate of 2.27% and fair market value of $1.1 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, 2009, and December 31, 2008, approximately 13 percent and 18 percent, respectively, of consolidated debt was in floating rate mode.

Based on our variable rate long-term debt balances at March 31, 2009, a 100 basis point change in interest rates would result in an annual interest expense change of approximately $10 million. Based on our variable rate short-term debt balances at March 31, 2009, a 100 basis point change in interest rates would result in an annual interest expense change of approximately $6 million.

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

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

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

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

The following table summarizes the terms, fair market values and exposures of our interest rate derivative instruments. All of the positions included in the table consist of forward starting swaps used to mitigate exposure to interest rate risk in anticipation of future debt issuances.


Cash Flow Hedges (dollars in millions)	Notional Amount		Pay			Receive (a)	Fair Value			Exposure (b)
Parent
Risk hedged at March 31, 2009
Anticipated 10-year debt issue (c)	$	50		3.36	%	3-month LIBOR	$	–		$	(1	)

Risk hedged at December 31, 2008
Anticipated 10-year debt issue (d)	$	200		4.36	%	3-month LIBOR	$	(30	)	$	(5	)

PEC
Risk hedged at March 31, 2009
Anticipated 10-year debt issue (e)	$	50		3.49	%	3-month LIBOR	$	1		$	(1	)

Risk hedged at December 31, 2008
Anticipated 10-year debt issue (f)	$	250		4.18	%	3-month LIBOR	$	(35	)	$	(6	)

PEF
Risk hedged at March 31, 2009
Anticipated 10-year debt issue (g)	$	50		3.16	%	3-month LIBOR	$	–		$	(1	)
Risk hedged at December 31, 2008:	None

(a)	3-month LIBOR rate was 1.19% at March 31, 2009, and 1.43% at December 31, 2008.

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

(c)	Anticipated 10-year debt issue hedge executed January 2009 matures on March 1, 2021, and requires mandatory cash settlement on March 1, 2011.

(d)	Anticipated 10-year debt issue hedges were terminated on March 16, 2009, in conjunction with the Parent’s issuance of $450 million of 7.05% Senior Notes due 2019.

(e)	Anticipated 10-year debt issue hedge executed January 2009 matures on July 16, 2022, and requires mandatory cash settlement on July 16, 2012.

(f)	Anticipated 10-year debt issue hedges were terminated on January 8, 2009, in conjunction with PEC’s issuance of $600 million 5.30% First Mortgage Bonds due 2019.

(g)	Anticipated 10-year debt issue hedge executed January 2009 matures on June 1, 2020, and requires mandatory cash settlement on June 1, 2010.

MARKETABLE SECURITIES PRICE RISK

At March 31, 2009, and December 31, 2008, the fair value of our nuclear decommissioning trust funds was $1.044 billion and $1.089 billion, respectively, including $651 million and $672 million, respectively, for PEC and $393 million and $417 million, respectively, for PEF. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At March 31, 2009, and December 31, 2008, the fair value of CVOs was $27 million and $34 million, respectively. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analysis performed on the CVOs uses quoted prices obtained from brokers or quote services to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. A hypothetical 10 percent increase in the March 31, 2009, market price would result in a $3 million increase in the fair value of the CVOs and a corresponding increase in the CVO liability.

COMMODITY PRICE RISK

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

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

We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments that are not eligible for recovery from ratepayers. At March 31, 2009, substantially all derivative commodity instrument positions were subject to retail regulatory treatment.

See Note 11 for additional information with regard to our commodity contracts and use of derivative financial instruments.

ECONOMIC DERIVATIVES

The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, realized gains or losses are passed through the fuel cost-recovery clause. During the quarter ended March 31, 2009, PEC recorded a net realized loss of $18 million. PEC’s net realized gain was not material during the quarter ended March 31, 2008. During the quarters ended March 31, 2009 and 2008, PEF recorded a net realized loss of $109 million and a net realized gain of $16 million, respectively.

Certain of our hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparty negatively impact our liquidity. We

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

At March 31, 2009, the fair value of PEC’s commodity derivative instruments was recorded as a $57 million short-term derivative liability position included in derivative liabilities and $72 million long-term derivative liability position included in other liabilities and deferred credits on the PEC Consolidated Balance Sheet. At December 31, 2008, the fair value of such instruments was recorded as a $45 million short-term derivative liability position included in derivative liabilities and a $54 million long-term derivative liability position included in other liabilities and deferred credits on the PEC Consolidated Balance Sheet. Certain counterparties have held cash collateral with PEC in support of these instruments. PEC had a cash collateral asset included in prepayments and other current assets of $28 million and $18 million on the PEC Consolidated Balance Sheet at March 31, 2009 and December 31, 2008, respectively.

At March 31, 2009, the fair value of PEF’s commodity derivative instruments was recorded as a $5 million short-term derivative asset position included in prepayments and other current assets, a $496 million short-term liability position included in current derivative liabilities, and a $275 million long-term derivative liability position included in derivative liabilities on the PEF Balance Sheet. At December 31, 2008, the fair value of such instruments was recorded as a $9 million short-term derivative asset position included in prepayments and other current assets, a $1 million long-term derivative asset position included in other assets and deferred debits, a $380 million short-term liability position included in current derivative liabilities, and a $209 million long-term derivative liability position included in derivative liabilities on the PEF Balance Sheet. Certain counterparties have held cash collateral in support of these instruments. Due to the significant decline in natural gas prices since December 31, 2008, PEF's cash collateral asset included in derivative collateral posted was $535 million and $335 million on the PEF Balance Sheet at March 31, 2009 and December 31, 2008, respectively.

CASH FLOW HEDGES

The Utilities designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. From time to time we hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. We also hedge exposure to market risk associated with fluctuations in the price of fuel for fleet vehicles. Realized gains and losses are recorded net as part of fleet vehicle costs. At March 31, 2009 and December 31, 2008, neither we nor the Utilities had material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for the three months ended March 31, 2009 and 2008.

At March 31, 2009 and December 31, 2008, the amount recorded in our or the Utilities accumulated other comprehensive income related to commodity cash flow hedges was not material.

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 discussed above, PEC’s exposure to these risks has not materially changed since December 31, 2008.

PEF

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

ITEM 4. CONTROLS AND PROCEDURES

PROGRESS ENERGY

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

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2009, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES

PEC

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

There has been no change in PEF’s internal control over financial reporting during the quarter ended March 31, 2009, 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, 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.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 15C).

ITEM 1A. RISK FACTORS

In addition to the risk factor disclosed below and the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors to the 2008 Form 10-K, which could materially affect our business, financial condition or future results. The risks described herein and in the 2008 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.

Impairment of goodwill could have a significant negative impact on our financial condition and results of operations.

We account for goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” , which requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility segments and goodwill impairment tests are performed at the utility segment level.

We calculate the fair value of our utility segments by considering various factors, including valuation studies based primarily on income and market approaches. These calculations are dependent on subjective factors such as management’s estimate of future cash flows and the selection of appropriate discount and growth rates from a marketplace participant’s perspective. These underlying assumptions and estimates are made as of a point in time; subsequent changes, particularly changes in management’s estimate of future cash flows and the discount rates, interest rates and growth rates, could result in a future impairment charge to goodwill. Impairment of our recorded goodwill could result in earnings volatility and an increase in our leverage, which could trigger a downgrade of our credit ratings leading to higher borrowing costs.

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

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a)

Securities Delivered. On March 2, 2009, March 16, 2009 and March 20, 2009, 14,708 shares, 505 shares and 62 shares, respectively, of our common stock were delivered to certain former employees pursuant to the terms of the Progress Energy 2002 and 2007 Equity Incentive Plans (individually and collectively, the “EIP,”) which have been approved by Progress Energy’s shareholders. Additionally, on March 18, 2009 and March 20, 2009, 135,487 shares and 194,234 shares respectively, of our common stock were delivered to certain current employees pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

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

(d)

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

PERFORMANCE SHARE SUB-PLAN AWARD PAYOUTS

(a)

Securities Delivered. On March 23, 2009, 239,954 shares of our common stock were delivered to employees pursuant to the terms of the EIP. Additionally, on March 31, 2009, 492 shares of our common stock were delivered to a former employee pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

(c)	Consideration. The performance share awards were granted to provide an incentive to the current and former employees to exert their utmost efforts on our behalf and thus enhance our performance while aligning the employees’ interests with those of our shareholders.

(d)

ISSUER PURCHASES OF EQUITY SECURITIES FOR FIRST QUARTER OF 2009

Period	(a) Total Number of Shares (or Units) Purchased(1)(2)(3)(4)	(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	177,073	$38.3467	N/A	N/A
February 1– February 28	580,400	37.6673	N/A	N/A
March 1– March 31	442,044	35.6940	N/A	N/A
Total	1,199,517	$37.0404	N/A	N/A

(1)	At March 31, 2009, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2)	The plan administrator purchased 654,773 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy 401(k) Savings and Stock Ownership Plan.

(3)	The plan administrator purchased 323,200 shares of our common stock in open-market transactions to meet share delivery obligations under the Savings Plan for Employees of Florida Progress Corporation.

(4)	The plan administrator purchased 16,892 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy Investor Plus Plan.

ITEM 6. EXHIBITS

(a)

Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF

10(a)	Amended and Restated Supplemental Senior Executive Retirement Plan of Progress Energy, Inc., effective January 1, 2009	X	X	X

31(a)	302 Certifications of Chief Executive Officer	X

31(b)	302 Certifications of Chief Financial Officer	X

31(c)	302 Certifications of Chief Executive Officer		X

31(d)	302 Certifications of Chief Financial Officer		X

31(e)	302 Certifications of Chief Executive Officer			X

31(f)	302 Certifications of Chief Financial Officer			X

32(a)	906 Certifications of Chief Executive Officer	X

32(b)	906 Certifications of Chief Financial Officer	X

32(c)	906 Certifications of Chief Executive Officer		X

32(d)	906 Certifications of Chief Financial Officer		X

32(e)	906 Certifications of Chief Executive Officer			X

32(f)	906 Certifications of Chief Financial Officer			X

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
	FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
Date: May 8, 2009	(Registrants)

	By: /s/ Mark F. Mulhern
	Mark F. Mulhern
	Senior Vice President and Chief Financial Officer

	By: /s/ Jeffrey M. Stone
	Jeffrey M. Stone
	Chief Accounting Officer and Controller
	Progress Energy, Inc.
	Chief Accounting Officer
	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
	Florida Power Corporation d/b/a Progress Energy Florida, Inc.

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Duke Energy Progress 10-Q2009 Q1 Quarterly report

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