UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

OR

o    TRANSITION REPORT PURSUANT TO SECTION 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                    .

Commission File Number	Exact name of registrants as specified in their charters, states of incorporation, addresses of principal executive offices, and telephone numbers	I.R.S. Employer Identification Number
1-15929	Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone:   (919) 546-6111 State of Incorporation: North Carolina	56-2155481
1-3382	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 410 South Wilmington Street Raleigh, North Carolina  27601-1748 Telephone:   (919) 546-6111 State of Incorporation: North Carolina	56-0165465
1-3274	Florida Power Corporation d/b/a Progress Energy Florida, Inc. 299 First Avenue North St. Petersburg, Florida  33701 Telephone:   (727) 820-5151 State of Incorporation: Florida	59-0247770

NONE

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

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

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

Indicate by check mark whether each registrant 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	x	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 November 2, 2009, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	279,626,073
PEC	Common Stock (Without Par Value)	159,608,055 (all of which were held directly by Progress Energy, Inc.)
PEF	Common Stock (Without Par Value)	100 (all of which were held indirectly by Progress Energy, Inc.)

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

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

2

TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
PART I.  FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS
	Unaudited Condensed Interim Financial Statements:
	Progress Energy, Inc. (Progress Energy)
	Unaudited Condensed Consolidated Statements of Income
	Unaudited Condensed Consolidated Balance Sheets
	Unaudited Condensed Consolidated Statements of Cash Flows
	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
	Unaudited Condensed Consolidated Statements of Income
	Unaudited Condensed Consolidated Balance Sheets
	Unaudited Condensed Consolidated Statements of Cash Flows
	Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
	Unaudited Condensed Statements of Income
	Unaudited Condensed Balance Sheets
	Unaudited Condensed Statements of Cash Flows
	Combined Notes to Unaudited Condensed Interim Financial Statements for Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a Progress Energy Florida, Inc.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4.	CONTROLS AND PROCEDURES
ITEM 4T.	CONTROLS AND PROCEDURES
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS
ITEM 1A.	RISK FACTORS
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ITEM 6.	EXHIBITS
SIGNATURES

3

GLOSSARY OF TERMS

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

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

TERM	DEFINITION
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
ASLB	Atomic Safety and Licensing Board
Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
ASC	FASB Accounting Standards Codification
ASU	Accounting Standards Update
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
CCRC	Capacity Cost-Recovery Clause
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, which were sold on March 7, 2008
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
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

4

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
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
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
GHG	Greenhouse gas
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, Fla.
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
NDT	Nuclear decommissioning trust
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 NOx State Implementation Plan Call 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

5

OPEB	Postretirement benefits other than pensions
ORS	South Carolina’s Office of Regulatory Staff
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
REPS	Renewable energy portfolio standard
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
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, which were sold on March 7, 2008
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

6

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 goodwill, 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 recession; 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 (NDT) funds; the investment performance of the assets of our pension and benefit plans and resulting impact on future funding requirements; the impact of potential 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 are 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.

7

PART I.  FINANCIAL INFORMATION

ITEM 1.                 FINANCIAL STATEMENTS

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2009

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended September 30,						Nine months ended September 30,
(in millions except per share data)	2009			2008			2009			2008
Operating revenues	$	2,824		$	2,696		$	7,578		$	7,006
Operating expenses
Fuel used in electric generation		1,075			869			2,855			2,262
Purchased power		125			450			599			1,012
Operation and maintenance		423			439			1,360			1,370
Depreciation, amortization and accretion		371			205			877			619
Taxes other than on income		152			141			425			387
Other		2			1			14			(6	)
Total operating expenses		2,148			2,105			6,130			5,644
Operating income		676			591			1,448			1,362
Other income (expense)
Interest income		2			8			8			20
Allowance for equity funds used during construction		20			34			95			84
Other, net		1			(7	)		13			(9	)
Total other income, net		23			35			116			95
Interest charges
Interest charges		174			178			534			493
Allowance for borrowed funds used during construction		(6	)		(11	)		(30	)		(27	)
Total interest charges, net		168			167			504			466
Income from continuing operations before income tax		531			459			1,060			991
Income tax expense		181			150			352			329
Income from continuing operations		350			309			708			662
Discontinued operations, net of tax		(102	)		1			(103	)		67
Net income		248			310			605			729
Net income attributable to noncontrolling interests, net of tax		(1	)		(1	)		(2	)		(6	)
Net income attributable to controlling interests	$	247		$	309		$	603		$	723
Average common shares outstanding – basic		280			262			279			261
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	1.24		$	1.18		$	2.53		$	2.52
Discontinued operations attributable to controlling interests, net of tax		(0.36	)		–			(0.37	)		0.25
Net income attributable to controlling interests	$	0.88		$	1.18		$	2.16		$	2.77
Dividends declared per common share	$	0.620		$	0.615		$	1.860		$	1.845
Amounts attributable to controlling interests
Income from continuing operations attributable to controlling interests, net of tax	$	349		$	308		$	706		$	657
Discontinued operations attributable to controlling interests, net of tax		(102	)		1			(103	)		66
Net income attributable to controlling interests	$	247		$	309		$	603		$	723
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

8

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2009			December 31, 2008
ASSETS
Utility plant
Utility plant in service	$	28,041		$	26,326
Accumulated depreciation		(11,539	)		(11,298	)
Utility plant in service, net		16,502			15,028
Held for future use		38			38
Construction work in progress		2,392			2,745
Nuclear fuel, net of amortization		502			482
Total utility plant, net		19,434			18,293
Current assets
Cash and cash equivalents		155			180
Receivables, net		939			867
Inventory		1,352			1,239
Regulatory assets		180			533
Derivative collateral posted		185			353
Income taxes receivable		8			194
Prepayments and other current assets		230			154
Total current assets		3,049			3,520
Deferred debits and other assets
Regulatory assets		2,463			2,567
Nuclear decommissioning trust funds		1,300			1,089
Miscellaneous other property and investments		446			446
Goodwill		3,655			3,655
Other assets and deferred debits		311			303
Total deferred debits and other assets		8,175			8,060
Total assets	$	30,658		$	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	$	6,797		$	6,206
Unearned ESOP shares (1 million shares)		(12	)		(25	)
Accumulated other comprehensive loss		(99	)		(116	)
Retained earnings		2,695			2,622
Total common stock equity		9,381			8,687
Noncontrolling interests		6			6
Total equity		9,387			8,693
Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		272			272
Long-term debt, net		10,834			10,387
Total capitalization		20,586			19,445
Current liabilities
Current portion of long-term debt		400			–
Short-term debt		250			1,050
Accounts payable		771			912
Interest accrued		151			167
Dividends declared		174			164
Customer deposits		294			282
Derivative liabilities		246			493
Other current liabilities		474			418
Total current liabilities		2,760			3,486
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,065			818
Accumulated deferred investment tax credits		119			127
Regulatory liabilities		2,420			2,181
Asset retirement obligations		1,540			1,471
Accrued pension and other benefits		1,393			1,594
Capital lease obligations		222			231
Derivative liabilities		207			269
Other liabilities and deferred credits		346			251
Total deferred credits and other liabilities		7,312			6,942
Commitments and contingencies (Notes 15 and 16)
Total capitalization and liabilities	$	30,658		$	29,873
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

9

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2009			2008
Operating activities
Net income	$	605		$	729
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		991			703
Deferred income taxes and investment tax credits, net		50			270
Deferred fuel cost (credit)		81			(330	)
Allowance for equity funds used during construction		(95	)		(84	)
Loss (gain) on sales of assets		1			(71	)
Litigation expense (Note 16C)		115			–
Other adjustments to net income		186			94
Cash (used) provided by changes in operating assets and liabilities
Receivables		(99	)		150
Inventory		(118	)		(124	)
Derivative collateral posted		155			(6	)
Prepayments and other current assets		9			32
Income taxes, net		190			(92	)
Accounts payable		(91	)		181
Other current liabilities		25			(24	)
Other assets and deferred debits		51			(62	)
Other liabilities and deferred credits		(286	)		(7	)
Net cash provided by operating activities		1,770			1,359
Investing activities
Gross property additions		(1,644	)		(1,760	)
Nuclear fuel additions		(148	)		(158	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			63
Purchases of available-for-sale securities and other investments		(1,271	)		(1,190	)
Proceeds from available-for-sale securities and other investments		1,245			1,154
Other investing activities		(5	)		(3	)
Net cash used by investing activities		(1,823	)		(1,894	)
Financing activities
Issuance of common stock		557			106
Dividends paid on common stock		(520	)		(481	)
Payments of short-term debt with original maturities greater than 90 days		(29	)		(176	)
Net (decrease) increase in short-term debt		(871	)		470
Proceeds from issuance of long-term debt, net		1,337			1,797
Retirement of long-term debt		(400	)		(877	)
Cash distributions to noncontrolling interests		(5	)		(85	)
Other financing activities		(41	)		(71	)
Net cash provided by financing activities		28			683
Net (decrease) increase in cash and cash equivalents		(25	)		148
Cash and cash equivalents at beginning of period		180			255
Cash and cash equivalents at end of period	$	155		$	403
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	265		$	266
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

10

CAROLINA POWER & LIGHT COMPANY

d/b/a PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2009

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended September 30,						Nine months ended September 30,
(in millions)	2009			2008			2009			2008
Operating revenues	$	1,307		$	1,266		$	3,561		$	3,382
Operating expenses
Fuel used in electric generation		457			348			1,282			1,027
Purchased power		82			145			196			266
Operation and maintenance		225			243			767			766
Depreciation, amortization and accretion		120			124			355			379
Taxes other than on income		56			53			161			152
Other		–			–			2			(6	)
Total operating expenses		940			913			2,763			2,584
Operating income		367			353			798			798
Other income (expense)
Interest income		1			2			4			9
Allowance for equity funds used during construction		7			9			23			19
Other, net		(2	)		(5	)		(5	)		–
Total other income, net		6			6			22			28
Interest charges
Interest charges		48			54			157			164
Allowance for borrowed funds used during construction		(3	)		(4	)		(9	)		(8	)
Total interest charges, net		45			50			148			156
Income before income tax		328			309			672			670
Income tax expense		120			108			242			242
Net income		208			201			430			428
Net loss attributable to noncontrolling interests, net of tax		–			–			1			–
Net income attributable to controlling interests		208			201			431			428
Preferred stock dividend requirement		1			1			2			2
Net income available to parent	$	207		$	200		$	429		$	426
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

11

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2009			December 31, 2008
ASSETS
Utility plant
Utility plant in service	$	16,298		$	15,698
Accumulated depreciation		(7,539	)		(7,352	)
Utility plant in service, net		8,759			8,346
Held for future use		3			3
Construction work in progress		598			660
Nuclear fuel, net of amortization		359			376
Total utility plant, net		9,719			9,385
Current assets
Cash and cash equivalents		89			18
Receivables, net		474			502
Receivables from affiliated companies		14			29
Notes receivable from affiliated companies		147			55
Inventory		693			633
Deferred fuel cost		122			207
Income taxes receivable		7			98
Prepayments and other current assets		32			28
Total current assets		1,578			1,570
Deferred debits and other assets
Regulatory assets		1,199			1,243
Nuclear decommissioning trust funds		817			672
Miscellaneous other property and investments		200			197
Other assets and deferred debits		102			98
Total deferred debits and other assets		2,318			2,210
Total assets	$	13,615		$	13,165
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160 million shares issued and outstanding	$	2,103		$	2,083
Unearned ESOP common stock		(12	)		(25	)
Accumulated other comprehensive loss		(31	)		(35	)
Retained earnings		2,504			2,278
Total common stock equity		4,564			4,301
Noncontrolling interests		3			4
Total equity		4,567			4,305
Preferred stock		59			59
Long-term debt, net		3,708			3,509
Total capitalization		8,334			7,873
Current liabilities
Short-term debt		–			110
Accounts payable		297			377
Payables to affiliated companies		65			82
Interest accrued		57			59
Customer deposits		93			82
Derivative liabilities		29			82
Other current liabilities		217			173
Total current liabilities		758			965
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,205			1,111
Accumulated deferred investment tax credits		111			115
Regulatory liabilities		1,188			987
Asset retirement obligations		1,175			1,122
Accrued pension and other benefits		702			856
Other liabilities and deferred credits		142			136
Total deferred credits and other liabilities		4,523			4,327
Commitments and contingencies (Notes 15 and 16)
Total capitalization and liabilities	$	13,615		$	13,165
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

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CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2009			2008
Operating activities
Net income	$	430		$	428
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		437			454
Deferred income taxes and investment tax credits, net		41			113
Deferred fuel cost (credit)		136			(30	)
Allowance for equity funds used during construction		(23	)		(19	)
Other adjustments to net income		76			42
Cash provided (used) by changes in operating assets and liabilities
Receivables		18			(48	)
Receivables from affiliated companies		15			23
Inventory		(64	)		(55	)
Prepayments and other current assets		12			23
Income taxes, net		122			(35	)
Accounts payable		(74	)		48
Payables to affiliated companies		(17	)		–
Other current liabilities		(11	)		47
Other assets and deferred debits		39			(7	)
Other liabilities and deferred credits		(184	)		(52	)
Net cash provided by operating activities		953			932
Investing activities
Gross property additions		(575	)		(518	)
Nuclear fuel additions		(82	)		(131	)
Purchases of available-for-sale securities and other investments		(614	)		(464	)
Proceeds from available-for-sale securities and other investments		585			433
Changes in advances to affiliated companies		(92	)		–
Other investing activities		(1	)		3
Net cash used by investing activities		(779	)		(677	)
Financing activities
Dividends paid on preferred stock		(2	)		(2	)
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	)		(300	)
Changes in advances from affiliated companies		–			(153	)
Other financing activities		14			(2	)
Net cash used by financing activities		(103	)		(135	)
Net increase in cash and cash equivalents		71			120
Cash and cash equivalents at beginning of period		18			25
Cash and cash equivalents at end of period	$	89		$	145
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	104		$	87
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

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FLORIDA POWER CORPORATION

d/b/a PROGRESS ENERGY FLORIDA, INC.

UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

September 30, 2009

UNAUDITED CONDENSED STATEMENTS of INCOME
	Three months ended September 30,						Nine months ended September 30,
(in millions)	2009			2008			2009			2008
Operating revenues	$	1,516		$	1,428		$	4,012		$	3,618
Operating expenses
Fuel used in electric generation		618			521			1,573			1,235
Purchased power		43			305			403			746
Operation and maintenance		198			201			604			621
Depreciation, amortization and accretion		247			77			512			229
Taxes other than on income		96			88			264			235
Other		–			–			7			(4	)
Total operating expenses		1,202			1,192			3,363			3,062
Operating income		314			236			649			556
Other income (expense)
Interest income		–			5			1			7
Allowance for equity funds used during construction		13			25			72			65
Other, net		1			–			8			(1	)
Total other income, net		14			30			81			71
Interest charges
Interest charges		63			68			194			163
Allowance for borrowed funds used during construction		(3	)		(7	)		(21	)		(19	)
Total interest charges, net		60			61			173			144
Income before income tax		268			205			557			483
Income tax expense		91			62			172			148
Net income		177			143			385			335
Preferred stock dividend requirement		–			–			1			1
Net income available to parent	$	177		$	143		$	384		$	334
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	September 30, 2009			December 31, 2008
ASSETS
Utility plant
Utility plant in service	$	11,560		$	10,449
Accumulated depreciation		(3,933	)		(3,885	)
Utility plant in service, net		7,627			6,564
Held for future use		35			35
Construction work in progress		1,794			2,085
Nuclear fuel, net of amortization		143			106
Total utility plant, net		9,599			8,790
Current assets
Cash and cash equivalents		19			19
Receivables, net		461			362
Receivables from affiliated companies		6			15
Inventory		659			606
Regulatory assets		58			326
Derivative collateral posted		182			335
Prepayments and other current assets		160			139
Total current assets		1,545			1,802
Deferred debits and other assets
Regulatory assets		1,264			1,324
Nuclear decommissioning trust funds		483			417
Miscellaneous other property and investments		42			37
Other assets and deferred debits		93			101
Total deferred debits and other assets		1,882			1,879
Total assets	$	13,026		$	12,471
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized, 100 shares issued and outstanding	$	1,587		$	1,116
Accumulated other comprehensive income (loss)		1			(1	)
Retained earnings		2,667			2,284
Total common stock equity		4,255			3,399
Preferred stock		34			34
Long-term debt, net		3,882			4,182
Total capitalization		8,171			7,615
Current liabilities
Current portion of long-term debt		300			–
Short-term debt		50			371
Notes payable to affiliated companies		155			72
Accounts payable		457			514
Payables to affiliated companies		48			55
Interest accrued		52			51
Customer deposits		201			200
Derivative liabilities		217			380
Other current liabilities		234			128
Total current liabilities		1,714			1,771
Deferred credits and other liabilities
Noncurrent income tax liabilities		772			634
Accumulated deferred investment tax credits		8			12
Regulatory liabilities		1,117			1,076
Asset retirement obligations		365			349
Accrued pension and other benefits		445			494
Capital lease obligations		208			216
Derivative liabilities		148			209
Other liabilities and deferred credits		78			95
Total deferred credits and other liabilities		3,141			3,085
Commitments and contingencies (Notes 15 and 16)
Total capitalization and liabilities	$	13,026		$	12,471
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

15

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2009			2008
Operating activities
Net income	$	385		$	335
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		538			234
Deferred income taxes and investment tax credits, net		(12	)		90
Deferred fuel credit		(55	)		(300	)
Allowance for equity funds used during construction		(72	)		(65	)
Other adjustments to net income		93			17
Cash (used) provided by changes in operating assets and liabilities
Receivables		(115	)		(120	)
Receivables from affiliated companies		9			(1	)
Inventory		(54	)		(73	)
Derivative collateral posted		141			(6	)
Prepayments and other current assets		9			(3	)
Income taxes, net		71			48
Accounts payable		(14	)		147
Payables to affiliated companies		(7	)		(38	)
Other current liabilities		77			74
Other assets and deferred debits		11			(21	)
Other liabilities and deferred credits		(90	)		37
Net cash provided by operating activities		915			355
Investing activities
Gross property additions		(1,069	)		(1,229	)
Nuclear fuel additions		(66	)		(27	)
Purchases of available-for-sale securities and other investments		(591	)		(616	)
Proceeds from available-for-sale securities and other investments		596			618
Changes in advances to affiliated companies		–			149
Proceeds from sales of assets to affiliated companies		–			12
Other investing activities		(5	)		(6	)
Net cash used by investing activities		(1,135	)		(1,099	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Net decrease in short-term debt		(321	)		–
Proceeds from issuance of long-term debt, net		–			1,475
Retirement of long-term debt		–			(532	)
Changes in advances from affiliated companies		83			2
Contributions from parent		465			–
Other financing activities		(6	)		–
Net cash provided by financing activities		220			944
Net increase in cash and cash equivalents		–			200
Cash and cash equivalents at beginning of period		19			23
Cash and cash equivalents at end of period	$	19		$	223
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	160		$	176
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

16

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 through 12, and 14 through 16
PEF	1, 2, 4, 6 through 12, and 14 through 16

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED INTERIM FINANCIAL STATEMENTS

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 13 for further information about our segments.

PEC

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

PEF

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

B.      BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 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). We have evaluated subsequent events through November 6, 2009, which is the date we issued our financial statements.

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2009		2008		2009		2008
Progress Energy	$	97	$	88	$	253	$	225
PEC		31		29		83		79
PEF		66		59		170		146

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 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. 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 Notes 1C and 3J in the 2008 Form 10-K for discussion of our variable interest in Ceredo and our disposal of Ceredo in 2007. There were no changes to our assessment of the primary beneficiary during 2008 or 2009. No financial or other support has been provided to Ceredo during the periods presented. At September 30, 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 on the Consolidated Balance Sheets. The ultimate resolution of the indemnifications could result in adjustments to the gain on disposal in future periods. The creditors of Ceredo do not have recourse to the general credit of Progress Energy. See Note 16B for a general discussion of guarantees. See Note 16C for discussion of recent developments related to legal indemnifications.

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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 2009. No financial or other support has been provided to the VIEs during the periods presented. At September 30, 2009, PEC had assets of $39 million, substantially all of which were reflected in miscellaneous other property and investments, $15 million in long-term debt, $3 million in other liabilities and deferred credits and $5 million in accounts payable on the 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 provided by GAAP 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 2009. No financial or other support has been provided to the VIE during the periods presented. At September 30, 2009, PEF had a $6 million prepayment included in other assets and deferred debits on the Balance Sheets. No liabilities associated with the prepayment clause were recorded. The aggregate maximum exposure to loss at September 30, 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

20

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 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 September 30, 2009, because the early termination clause was not exercised. The aggregate maximum exposure to loss at September 30, 2009, is $17 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

Effective July 1, 2009, changes to the source of authoritative U.S. GAAP, the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC), are communicated through an Accounting Standards Update (ASU). ASUs will be published for all authoritative U.S. GAAP promulgated by the FASB, regardless of the form in which such guidance may have been issued prior to release of the FASB Codification (e.g., FASB Statements, EITF Abstracts, FASB Staff Positions, etc.).

ASC 810-10-65 (SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51)

In December 2007, the FASB issued ASC 810-10-65, which was previously referred to as SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.” ASC 810-10-65 introduces significant changes in the accounting for noncontrolling interests in a partially owned consolidated subsidiary. ASC 810-10-65 was adopted on January 1, 2009. See Note 6B for information regarding our first quarter 2009 implementation of ASC 810-10-65. The adoption of ASC 810-10-65 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. 167, Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” which makes significant changes to the model for determining who should consolidate a VIE and addresses how often this assessment should be performed. SFAS No. 167 requires all existing arrangements with VIEs to be evaluated, and must be adopted through a cumulative-effect adjustment. The guidance is effective for us on January 1, 2010. We are currently evaluating the impact adoption may have on our or the Utilities’ financial position, results of operations and cash flows.

ASC 815-10-65 (SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133)

On January 1, 2009, we implemented ASC 815-10-65, which was previously referred to as SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” ASC 815-10-65 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 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 12 for information regarding our first quarter 2009 implementation of ASC 815-10-65. The adoption of ASC 815-10-65 did not have a material impact on our or the Utilities' financial position or results of operations.

ASC 260-10-45 (FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities)

On January 1, 2009, we implemented ASC 260-10-45, which was previously referred to as FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” ASC 260-10-45 requires that certain unvested share-based payment awards (e.g., restricted stock) that contain

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nonforfeitable rights to dividends or dividend equivalents be included in the computation of earnings per share using the two-class method. ASC 260-10-45 required a retrospective adjustment for all prior-period earnings per share data. The adoption of ASC 260-10-45 did not have a material impact on our or the Utilities' financial position, results of operations or earnings per share amounts.

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.

ASC 820 includes the FSP previously referred to as 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” and provides guidance on determining fair value when market activity has decreased for an asset or liability. ASC 825-10-65, previously referred to as FSP FAS 107-1 and APB 28-1, “Interim Disclosures About Fair Value of Financial Instruments,” increases the frequency of fair value disclosures required from annually to quarterly.

ASC 320 includes the FSPs previously referred to as FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” and 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 ASC 320, 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 new guidance in ASC 820, ASC 825 and ASC 320 were effective for us during the three months ended June 30, 2009. The adoption resulted in additional disclosures but did not have a material impact on our or the Utilities' financial position or results of operations. See Note 9 for the disclosures resulting from the implementation of this guidance in 2009.

ASC 855 (SFAS No. 165, Subsequent Events)

In May 2009, the FASB issued ASC 855, previously referred to as SFAS No. 165, “Subsequent Events,” which is applicable to the accounting for and disclosure of subsequent events not otherwise addressed in GAAP. ASC 855 defines subsequent events as “events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued.” For public entities, financial statements are considered “issued” when they are widely distributed to shareholders and other financial users for general use and reliance in a form and format that complies with GAAP. ASC 855 was effective for us on June 30, 2009. The adoption of ASC 855 requires the disclosure of the date through which subsequent events have been evaluated, as well as whether the date is the date the financial statements were issued or the date the financial statements were available to be issued. See Note 1 for the information regarding our implementation of ASC 855.

ASC 715-20-65 (FSP FAS 132R-1, Employers’ Disclosures about Post Retirement Benefit Plan Assets)

In December 2008, the FASB issued ASC 715-20-65 previously referred to as FSP FAS 132R-1, “Employers’ Disclosures about Post Retirement Benefit Plan Assets,” 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. ASC 715-20-65 is effective for us on December 31, 2009. The adoption of ASC 715-20-65 will change certain disclosures in the notes to the financial statements, but we do not expect the adoption of ASC 715-20-65 to have a material impact on our or the Utilities’ financial position or results of operations.

ASU 2009-12, “Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)”

In September 2009, the FASB issued ASU 2009-12, “Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent),” which provides additional guidance related to measuring the fair value of certain alternative investments, such as interests in hedge funds, private equity funds, real estate funds, venture capital funds, offshore fund vehicles, and funds of funds. ASU 2009-12 allows reporting entities to use net asset value per share to estimate the fair value of certain investments as a practical expedient and requires disclosures by

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major category of investment about the attributes of the investments. ASU 2009-12 is effective for us on December 31, 2009. We do not expect the adoption of ASU 2009-12 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 nine months ended September 30, 2008, we recorded an after-tax gain of $41 million on the sale of these assets. The accompanying consolidated financial statements 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.

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our Synthetic Fuels subsidiaries and affiliates. As a result, during the three months ended September 30, 2009, we recorded a charge of $101 million to discontinued operations, which was net of a previously recorded indemnification liability (See Note 1C) and estimated tax impacts. The ultimate resolution of these matters could result in further adjustments to Synthetic Fuels earnings from discontinued operations. See Note 16C for additional information. The accompanying consolidated statements of income reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

Results of Terminals and Synthetic Fuels discontinued operations for the three and nine months ended September 30 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Revenues	$	–		$	–		$	–		$	17
(Loss) earnings before income taxes and noncontrolling interest		(117	)		(1	)		(119	)		9
Income tax benefit, including tax credits and tax levelization		14			1			16			13
Earnings attributable to noncontrolling interests of Synthetic Fuels		–			–			–			(1	)
Net (loss) earnings from discontinued operations attributable to controlling interests		(103	)		–			(103	)		21
Gain on disposal of discontinued operations, including income tax expense of $7		–			–			–			41
(Loss) earnings from discontinued operations attributable to controlling interests	$	(103	)	$	–		$	(103	)	$	62

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 nine months ended September 30, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.

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

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

C.   OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations are amounts related to adjustments of our prior sales of other diversified businesses, primarily the Competitive Commercial Operations (CCO) in Georgia and Progress Rail Services Corporation. 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 16B). The ultimate resolution of these matters could result in additional adjustments in future periods. For the three months ended September 30, 2009 and 2008, we recorded additional gains of $1 million and $2 million, net of tax, respectively. For the nine months ended September 30, 2009, net gains and losses were not material. For the nine months ended September 30, 2008, we recorded additional gains of $2 million, net of tax.

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. On May 28, 2009, PEC jointly filed a settlement agreement with the South Carolina Office of Regulatory Staff (ORS) and Nucor Steel. Under the terms of the settlement agreement, the parties agreed to PEC’s proposed rate reduction of approximately $13 million. On June 19, 2009, the SCPSC approved the settlement agreement. The decrease was effective July 1, 2009, and decreased residential electric bills by $2.08 per 1,000 kilowatt-hours (kWh), or 2.0 percent, for fuel cost recovery.

On June 4, 2009, PEC filed with the NCUC for a decrease in the fuel rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $14 million decrease in the fuel rates driven by declining fuel prices. If approved, the decrease would take effect December 1, 2009, and would decrease residential electric bills by $0.45 per 1,000 kWh, or 0.4 percent, for fuel cost recovery. A hearing on the matter was held on September 15, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT AND ENERGY-EFFICIENCY COST RECOVERY

See Note 7B in the 2008 Form 10-K for discussion of North Carolina’s comprehensive energy legislation, which became law on August 20, 2007. As a result of the legislation, PEC has implemented a series of demand-side management (DSM) and energy-efficiency programs and will continue to pursue additional programs. These programs must be approved by the NCUC, and we cannot predict the outcome of the DSM and energy-efficiency filings currently pending approval by the NCUC or whether the implemented programs will produce the expected operational and economic results.

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On June 6, 2008, and as subsequently amended, PEC filed an application with the NCUC for approval of a DSM and energy-efficiency rider to recover all program costs, including the recovery of appropriate incentives for investing in such programs. 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, subject to true-up to the final order, were implemented on December 1, 2008, increasing residential electrical bills by $0.74 per 1,000 kWh, or 0.8 percent. 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. On June 15, 2009, the NCUC issued an order approving the Agreement and Stipulation of Partial Settlement, subject to certain modifications. PEC estimates the year-to-date impact of these modifications to be immaterial. On July 13, 2009, PEC filed a motion asking the NCUC to reconsider certain provisions of the June 15, 2009 order and stay the requirements for PEC to revise its cost-recovery filings in accordance with the decisions approved in the order. On July 20, 2009, the NCUC issued an order requesting comments on the motion and allowed the motion for stay, pending a ruling on the motion for reconsideration, on a portion of PEC’s request. A hearing on the matter was held on September 16, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter.

On June 4, 2009, PEC filed with the NCUC for an adjustment in the DSM and energy-efficiency rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $1 million increase in the DSM and energy-efficiency rates. However, because of changes in how the costs are allocated among customer classes, the request results in a decrease to the residential rate, while increasing rates for other customer classes. If approved, the rate changes would take effect December 1, 2009, and would decrease residential electric bills by $0.18 per 1,000 kWh, or 0.2 percent, for DSM and energy-efficiency cost recovery. A hearing on the matter was held on September 16, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter.

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 and issued a directive requiring PEC to file for approval of all proposed DSM and energy-efficiency programs. On May 11, 2009, in accordance with the SCPSC directive, PEC filed its programs for approval and an application for a cost-recovery rider for PEC’s DSM and energy-efficiency programs. On June 10, 2009, SCPSC approved the proposed DSM and energy-efficiency programs and the cost-recovery rider application, on a provisional basis pending a review of the cost-recovery rider by the ORS. The rate increase was effective July 1, 2009, and increased residential electric bills by $0.79 per 1,000 kWh, or 0.8 percent, for DSM and energy-efficiency cost recovery. We cannot predict the outcome of this matter.

RENEWABLE ENERGY AND ENERGY EFFICIENCY PORTFOLIO STANDARD COST RECOVERY

On June 4, 2009, PEC filed with the NCUC for an increase in the Renewable Energy and Energy Efficiency Portfolio standard (NC REPS) rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $7 million increase in the NC REPS rates. If approved, the increase would take effect December 1, 2009, and would increase residential electric bills by $0.29 per month, or 0.3 percent, for REPS cost recovery. A hearing on the matter was held on September 16, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter.

OTHER MATTERS

North Carolina enacted a law in July 2009 that abbreviates the certification process for a public utility to construct a new natural gas plant as long as the public utility permanently retires the existing coal units at that specific site. On August 18, 2009, PEC filed with the NCUC an application for a certificate of public convenience and necessity to construct a 950-MW combined cycle natural gas-fueled electric generating facility at a site in Wayne County, N.C. PEC projects that the generating facility would be in service by January 2013. PEC proposed that upon completion of the generating facility, it will permanently cease operation of the three coal-fired generating units, with a combined generating capacity of approximately 400 MW, that are currently in operation at the site. This will result in approximately 550 MW of incremental capacity. On September 21, 2009, the Public Staff recommended that the NCUC issue the certificate subject to additional conditions as follows: the facility be constructed and operated in

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accordance with all applicable laws and regulations, PEC file with the NCUC a progress report and any revisions in the cost estimates on an annual basis, PEC permanently cease operation of the three coal-fired units immediately upon completion and placement into service of the facility and that the NCUC clarify that the issuance of the certificate does not constitute approval of the final costs associated with construction of the facility. On October 1, 2009, the NCUC issued a notice of decision stating it found good cause to issue an order granting PEC the certificate of public convenience and necessity subject to the four conditions proposed by the Public Staff as well as adding a condition that PEC submit for NCUC approval a plan to retire additional coal-fired capacity reasonably proportionate to the 550 MW of incremental capacity. On October 22, 2009, the NCUC issued its order granting PEC a certificate of public convenience and necessity to construct the 950-MW facility. PEC is currently evaluating its options concerning the additional retirements.

B.   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.

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 Plant, which began commercial operations in June 2009. On May 19, 2009, the FPSC approved both the annualized interim base rate increase and the cost recovery for the repowered Bartow Plant subject to refund with interest effective July 1, 2009. The interim and limited base rate relief increased revenues by $47 million during the nine months ended September 30, 2009, and are expected to result in total increases to revenues of approximately $70 million for 2009. The changes increased residential bills by approximately $4.52 per 1,000 kWh, or 3.7 percent. On July 2, 2009, Florida’s Office of Public Counsel (OPC), the Florida Industrial Power Users Group, the Attorney General, the Florida Retail Federation and PCS Phosphate filed a petition protesting portions of the FPSC approval. On August 31, 2009, the FPSC issued an order to consolidate the interim and limited base rate relief increase and the base rate proposal. We cannot predict the outcome of this matter.

If PEF’s remaining rate request is approved by the FPSC as filed by PEF, the new base rates would increase residential bills by approximately $9.66 per 1,000 kWh, or 7.6 percent, effective January 1, 2010. A hearing was held on this matter September 21, 2009 – October 1, 2009. On October 27, 2009, the FPSC held a hearing to determine if the voting of pending rate cases should be delayed until new FPSC appointees take office in January 2010. During the hearing, the FPSC voted to delay the rulings on the appropriate level of revenue requirements until January 11, 2010, and on the appropriate customer rates until January 28, 2010. In response to this delay and in lieu of implementing PEF's proposed base rates subject to refund, PEF filed a motion with the FPSC on November 2, 2009, to establish a regulatory asset (or liability) for the incremental rate relief not recovered between January 1, 2010, and when new rates become effective, expected to be March 1, 2010.  If PEF's petition is approved, the regulatory asset (or liability) would be recovered, plus interest at the commercial paper rate, through a rate adjustment commencing March 1, 2010, through the remainder of the calendar year.  We cannot predict the outcome of this matter.

FUEL COST RECOVERY

On March 17, 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 reduced residential customers’ fuel charges by $6.90 per 1,000 kWh, or 5.0 percent, starting with the first billing cycle of April 2009, with similar reductions for commercial and industrial customers.

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See Note 7C in the 2008 Form 10-K for discussion of the OPC petition filed with the FPSC in 2006 requesting PEF to refund to ratepayers $135 million, plus interest, related to fuel recovery charges during the period 2003 to 2005 for Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5). On October 10, 2007, in response to the OPC petition, the FPSC ordered PEF to refund its ratepayers $14 million for disallowed fuel and sulfur dioxide (SO2) costs, inclusive of interest, over a 12-month period beginning January 1, 2008. In addition, 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, the OPC filed direct testimony alleging that during 2006 and 2007, PEF collected excessive fuel costs and SO2 allowance costs of $61 million before interest. During the hearing on the matter, the OPC reduced the alleged excessive fuel costs to $33 million before interest. On June 30, 2009, the FPSC approved a refund of $8 million to PEF’s ratepayers to be paid over a 12-month period beginning January 1, 2010, and ordered PEF to file a report by September 2009 regarding the prospective application of PEF’s coal procurement plan and the prudence of PEF’s coal procurement actions. In compliance with the FPSC order, PEF filed the coal procurement status report on September 14, 2009. For the nine months ended September 30, 2009, PEF recorded a pre-tax other operating expense of $8 million plus an immaterial amount of interest and an associated regulatory liability for the disallowed fuel costs and interest. PEF chose not to appeal the FPSC’s order.

On September 14, 2009, PEF filed a request with the FPSC to seek approval of a cost adjustment to reduce fuel costs, thereby decreasing residential electric bills by $3.34 per 1,000 kWh, or 2.6 percent, effective January 1, 2010. This decrease is due to a decrease of $9.89 per 1,000 kWh for the projected recovery of fuel costs, partially offset by an increase of $6.55 per 1,000 kWh for the projected recovery through the capacity cost-recovery clause (CCRC). The decrease in projected fuel costs is due primarily to a decrease in the price of natural gas and a change in the expected average fuel costs. An extended biennial nuclear outage at Crystal River Unit No. 3 Nuclear Plant (CR3) for an uprate project in 2009 contributed to higher projected fuel costs for 2009; however, anticipated changes in the generation mix for 2010 are expected to result in lower average fuel costs and contributed to the projected decrease in 2010 fuel costs. The increase in the CCRC is primarily the result of projected costs to be incurred in 2010 under the nuclear cost-recovery rule discussed below for the proposed nuclear plant in Levy County, Fla. (Levy) and an under-recovery of purchased power costs in 2009. On October 23, 2009, as a result of the October 16, 2009 FPSC vote in the nuclear cost recovery matter discussed more fully below, PEF filed a cost adjustment with the FPSC which reduced the CCRC rate by $0.08 per 1,000 kWh from the original September 14, 2009 cost-adjustment filing. The FPSC approved PEF's fuel and capacity clause filings on November 2, 2009.

On August 28, 2009, PEF filed a request to increase the Environmental Cost Recovery Clause (ECRC) residential rate and the filing was updated on October 27, 2009.  PEF is asking the FPSC to increase residential rates by $2.25 per 1,000 kWh, or 1.8 percent. This increase is primarily due to the return on assets expected to be placed in service at the end of 2009. On September 14, 2009, PEF filed a request to increase the Energy Conservation Cost Recovery Clause (ECCR) residential rate by $0.47 per 1,000 kWh, or 0.4 percent. This increase is due mainly to an increase in conservation program costs. If approved, the ECRC and ECCR changes would be effective January 1, 2010. The FPSC approved PEF’s ECRC and ECCR clause filings on November 2, 2009.

NUCLEAR COST RECOVERY

On March 17, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear pre-construction costs for Levy, which the FPSC had authorized to be collected in 2009. The approval reduced residential customers’ nuclear cost-recovery charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first billing cycle of April 2009, with similar reductions for commercial and industrial customers.

On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million through the CCRC, which primarily consists of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 and 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 proposed collecting certain costs over a five-year period, with associated carrying costs on the unrecovered balance. This alternate proposal reduced the 2010 revenue requirement to $236 million. On September 14, 2009, consistent with FPSC rules, PEF included both proposed revenue requirements in its CCRC filing, which would result in a nuclear cost-recovery charge of either $7.98 per 1,000 kWh for residential customers under PEF’s alternate proposal, or $15.07 per 1,000 kWh if the FPSC did not approve PEF’s alternate proposal. At a special agenda hearing by the FPSC on October 16, 2009, the FPSC approved the alternate proposal allowing PEF to recover $207 million of revenue requirements associated with the nuclear cost-recovery clause through the CCRC beginning with the first billing cycle of January 2010. The remainder, with minor adjustments, will also be recovered through the CCRC. This revenue level results in a nuclear

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cost-recovery charge of $6.99 per 1,000 kWh, which represents a $2.68 increase per 1,000 kWh for residential customer bills. In adopting PEF’s proposed rate plan for 2010, the FPSC permitted PEF to annually reconsider changes to the recovery of deferred amounts to afford greater flexibility to manage future rate impacts.

On October 16, 2009, the FPSC clarified certain implemenation policies related to the recognition of deferrals and the application of carrying charges under the nuclear cost-recovery rule. Specifically, the FPSC clarified that (1) nuclear costs are deemed to be recovered up to the amount of FPSC-approved projections and (2) the deferral of unrecovered nuclear costs would accrue a carrying charge at PEF’s approved allowance for funds used during construction (AFUDC) rate consistent with the requirements of FPSC’s nuclear cost-recovery rule, which is fixed at the pre-tax AFUDC rate in effect as of June 12, 2007. Accordingly, PEF retrospectively assigned capacity revenues to match the FPSC-approved projected level of nuclear cost recovery as of September 30, 2009. Nuclear costs incurred in excess of original projections earn a carrying charge equal to the AFUDC rate. Prior to the FPSC clarification, PEF assigned capacity revenues to nuclear cost recovery based on actual costs incurred; any over- or under-recoveries of actual costs were deferred and earned a carrying charge equal to a commercial paper rate.

See Note 7C in the 2008 Form 10-K for discussion of PEF’s filing with the FPSC for Determination of Need to uprate CR3 and bid rule exemption, and for recovery of the revenue requirements of the uprate. On August 28, 2009, PEF filed a petition with the FPSC to approve a $17 million base rate increase for the phase II costs associated with the uprate of CR3. PEF’s 2009 revenue requirements for recovery of the phase II costs were included in the CCRC. As permitted under the nuclear cost-recovery rule, PEF’s phase III costs associated with the CR3 uprate are currently being recovered through the CCRC discussed above.  On October 29, 2009, the FPSC Staff recommended that the FPSC approve PEF's request with minor modifications and that the new rates be implemented at the same time as PEF implements new base rates from its rate case proceeding.  On October 30, 2009, PEF filed an amended petition requesting this rate change be implemented effective January 1, 2010.   If approved, the base rates for residential customers will increase by $0.57 per 1,000 kWh, or 0.4 percent. A decision by the FPSC is expected on December 1, 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 expense and the authorization to charge $33 million in estimated 2009 storm hardening expenses to its 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. On June 16, 2009, the FPSC denied PEF’s request related to the storm hardening expenses, but approved the deferral of the retail portion of actual 2009 pension expense. As a result of the order, PEF deferred pension expense of $10 million and $26 million for the three months and nine months ended September 30, 2009, respectively. PEF will not earn a carrying charge on the deferred pension regulatory asset. The retail portion of subsequent pension expense will be deferred as incurred during the remainder of 2009. The deferral of pension expense will not result in a change in PEF’s 2009 retail rates or prices. In accordance with the order, subsequent to 2009 PEF will amortize the deferred pension regulatory asset to the extent that annual pension expense is less than the allowance provided for in the base rates established in the 2010 base rate proceeding. In the event such amortization is insufficient to fully amortize the regulatory asset, PEF can seek recovery of the remaining unamortized amount in a base rate proceeding no earlier than 2015.

C.   OTHER RATE MATTERS

On May 15, 2009 and May 29, 2009, PEC and PEF filed updates to their Open Access Transmission Tariffs (OATT) with the FERC. For PEC, the updates increased the transmission rate charged to wholesale customers by 18 percent effective June 1, 2009, and by an additional 1 percent effective August 1, 2009. The impact to PEC’s 2009 revenue is expected to be an increase of $4 million. For PEF, the updates increased the transmission rate charged to wholesale customers by 11 percent, effective June 1. The impact to PEF’s 2009 revenue is expected to be an increase of $2 million. On October 9, 2009, PEC and PEF reached settlement agreements with their respective wholesale customers regarding these rate increases. Both settlement agreements resulted in a small decrease to the filed rates, but have no material impact on the expected increase to 2009 revenue.

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5.   GOODWILL

Goodwill is required to 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 our goodwill impairment tests are performed at the utility segment level. The carrying amounts of goodwill at September 30, 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. We perform our annual impairment tests as of April 1 each year. During the second quarter of 2009, we completed the 2009 annual tests, which indicated the goodwill was not impaired.

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 September 30,				Nine Months Ended September 30,
(in millions)	2009		2008		2009		2008
Weighted-average common shares – basic		280		262		279		261
Net effect of dilutive stock-based compensation plans		–		–		–		–
Weighted-average shares – fully dilutive		280		262		279		261

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 (a)		603			–			603
Other comprehensive income		17			–			17
Comprehensive income								620
Issuance of shares through offerings and stock-based compensation plans (See Note 6D)		603			–			603
Dividends paid and declared		(529	)		–			(529	)
Distributions to noncontrolling interest		–			(1	)		(1	)
Other transactions		–			1			1
Balance, September 30, 2009	$	9,381		$	6		$	9,387

(a)   Consolidated net income of $605 million includes $2 million attributable to preferred shareholders of subsidiaries, which is not a component of total equity and is excluded from the table above.

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(in millions)	Total Common Stock Equity			Noncontrolling Interests			Total Equity
Balance, December 31, 2007	$	8,395		$	84		$	8,479
Net income		723			6			729
Other comprehensive income		8			–			8
Comprehensive income								737
Issuance of shares through offerings and stock-based compensation plans (See Note 6D)		156			–			156
Dividends paid and declared		(483	)		–			(483	)
Contributions from noncontrolling interest		–			2			2
Distributions to noncontrolling interest		–			(85	)		(85	)
Balance, September 30, 2008	$	8,799		$	7		$	8,806

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 (loss)		431			(1	)		430
Other comprehensive income		4			–			4
Comprehensive income								434
Issuance of parent company shares through stock-based compensation plans		33			–			33
Dividends paid to parent		(200	)		–			(200	)
Preferred stock dividends at stated rate		(2	)		–			(2	)
Tax benefit dividend		(3	)		–			(3	)
Balance, September 30, 2009	$	4,564		$	3		$	4,567

(in millions)	Total Common  Stock Equity			Noncontrolling  Interests		Total Equity
Balance, December 31, 2007	$	3,752		$	4	$	3,756
Net income		428			–		428
Other comprehensive loss		(3	)		–		(3	)
Comprehensive income							425
Issuance of parent company shares through stock-based compensation plans		37			–		37
Preferred stock dividends at stated rate		(2	)		–		(2	)
Tax benefit dividend		2			–		2
Balance, September 30, 2008	$	4,214		$	4	$	4,218

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.

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C.COMPREHENSIVE INCOME

Progress Energy
	Three Months Ended September 30,
(in millions)	2009			2008
Net income	$	248		$	310
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $-, respectively)		2			1
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $1)		1			–
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $4 and $(1), respectively)		(6	)		1
Other comprehensive (loss) income		(3	)		2
Comprehensive income		245			312
Comprehensive income attributable to noncontrolling interests, net of tax		(1	)		(1	)
Comprehensive income attributable to controlling interests	$	244		$	311

	Nine Months Ended September 30,
(in millions)	2009			2008
Net income	$	605		$	729
Other comprehensive income
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $3 and $1, respectively)		5			2
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $2 and $1, respectively)		3			1
Net unrealized gains on cash flow hedges (net of tax expense of $5 and $3, respectively)		8			5
Other (net of tax expense of $1)		1			–
Other comprehensive income		17			8
Comprehensive income		622			737
C Comprehensive income attributable to noncontrolling interests, net of tax		(2	)		(6	)
C Comprehensive income attributable to controlling interests	$	620		$	731

PEC
	Three Months Ended September 30,
(in millions)	2009			2008
Net income	$	208		$	201
Other comprehensive income
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $-, respectively)		1			1
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $1 and $-, respectively)		(1	)		1
Other comprehensive income		–			2
Comprehensive income		208			203
C Comprehensive loss attributable to noncontrolling interests, net of tax		–			–
C Comprehensive income attributable to controlling interests	$	208		$	203

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	Nine Months Ended September 30,
(in millions)	2009		2008
Net income	$	430	$	428
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $2 and $-, respectively)		3		1
Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of $(1) and $2, respectively)		1		(4	)
Other comprehensive income (loss)		4		(3	)
Comprehensive income		434		425
Comprehensive loss attributable to noncontrolling interests, net of tax		1		–
Comprehensive income attributable to controlling interests	$	435	$	425

PEF
	Three Months Ended September 30,
(in millions)	2009			2008
Net income	$	177		$	143
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $1)		(1	)		–
Other comprehensive loss		(1	)		–
Comprehensive income	$	176		$	143

	Nine Months Ended September 30,
(in millions)	2009		2008
Net income	$	385	$	335
Other comprehensive income
Net unrealized gains on cash flow hedges (net of tax expense of $1 and $5, respectively)		2		8
Other comprehensive income		2		8
Comprehensive income	$	387	$	343

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 and nine months ended September 30, 2009 and 2008, we issued shares of common stock, primarily under a public offering and to meet the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) and Investor Plus Stock Purchase Plan. In addition, we periodically issue shares for our other benefit plans. The following table presents information for our common stock issuances:

	Three Months Ended September 30,
	2009				2008
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		0.3	$	12		1.5	$	64
Issuances to meet requirements of 401(k) and Investor Plus Purchase Plan		0.3		12		1.5		63

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	Nine Months Ended September 30,
	2009				2008
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		15.8	$	557		3.0	$	106
Issuances under a public offering		14.4		523		–		–
Issuances to meet requirements of 401(k) and Investor Plus Purchase Plan		0.9		34		2.4		104

The shares issued under a public offering were issued on January 12, 2009, at a public offering price of $37.50. 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 its 14.4 million share common stock issuance discussed in Note 6D. During the third quarter of 2009, the Parent further reduced the outstanding RCA balance by $300 million with cash on hand, resulting in an outstanding balance of $200 million at September 30, 2009. Subsequent to September 30, 2009, the Parent repaid an additional $100 million of the outstanding balance with proceeds from commercial paper borrowings. At November 6, 2009, the outstanding balance of the RCA loan was $100 million. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining 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 with the remaining proceeds used for general corporate purposes.

On June 18, 2009, PEC entered into a Seventy-seventh Supplemental Indenture to its Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, in connection with certain amendments to the mortgage. The amendments are set forth in the Seventy-seventh Supplemental Indenture and include an amendment to extend the maturity date of the mortgage by 100 years. The maturity date of the mortgage is now May 1, 2140.

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9.   FAIR VALUE DISCLOSURES

A.   DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $11.506 billion and $10.659 billion at September 30, 2009 and December 31, 2008, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $12.8 billion and $11.3 billion at September 30, 2009 and December 31, 2008, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities’ nuclear plants as discussed in Note 4D of the 2008 Form 10-K. Nuclear decommissioning trust (NDT) funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, we hold other debt and equity investments classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.

The following table summarizes our available-for-sale securities at September 30, 2009 and December 31, 2008.

September 30, 2009 (in millions)	Unrealized Losses			Unrealized Gains		Fair  Value
Equity securities	$	(25	)	$	268	$	807
Debt securities		(2	)		21		426
Cash equivalents		–			–		112
Total	$	(27	)	$	289	$	1,345
December 31, 2008 (in millions)	Unrealized Losses			Unrealized Gains		Fair Value
Equity securities	$	(93	)	$	134	$	559
Debt securities		(27	)		15		466
Cash equivalents		–			–		114
Total	$	(120	)	$	149	$	1,139

The NDT funds and other available-for-sale debt and equity investments held in certain benefit trusts are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments; $27 million of the unrealized losses and $287 million of the unrealized gains at September 30, 2009, and $118 million of the unrealized losses and $148 million of the unrealized gains at December 31, 2008, relate to the NDT funds. There were no material unrealized losses for the other available-for-sale debt and equity securities held in benefit trusts at September 30, 2009 and December 31, 2008.

The aggregate fair value of investments with unrealized losses at September 30, 2009 and December 31, 2008 was $146 million and $374 million, respectively.

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At September 30, 2009, the fair value of available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	10
Due after one through five years		202
Due after five through 10 years		122
Due after 10 years		92
Total	$	426

The following table presents selected information about our sales of available-for-sale securities during the three and nine months ended September 30, 2009. Proceeds were primarily related to the NDT funds. Realized gains and losses were determined on a specific identification basis.

(in millions)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Proceeds	$	207		$	1,078
Realized gains		5			20
Realized losses		(8	)		(82	)

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $3.708 billion and $3.509 billion at September 30, 2009 and December 31, 2008, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.0 billion and $3.7 billion at September 30, 2009 and December 31, 2008, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC’s nuclear plants as discussed in Note 4D of the 2008 Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, PEC holds other debt and equity investments classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.

The following table summarizes PEC’s available-for-sale securities at September 30, 2009 and December 31, 2008.

September 30, 2009 (in millions)	Unrealized Losses			Unrealized Gains		Fair Value
Equity securities	$	(21	)	$	164	$	521
Debt securities		(1	)		15		288
Cash equivalents		–			–		8
Total	$	(22	)	$	179	$	817
December 31, 2008  (in millions)	Unrealized Losses			Unrealized Gains		Fair Value
Equity securities	$	(55	)	$	75	$	334
Debt securities		(10	)		11		250
Cash equivalents		–			–		105
Total	$	(65	)	$	86	$	689

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The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments; all of the unrealized losses and gains at September 30, 2009 and December 31, 2008, relate to the NDT funds.

The aggregate fair value of investments with unrealized losses at September 30, 2009 and December 31, 2008, was $100 million and $191 million, respectively.

At September 30, 2009, the fair value of available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	9
Due after one through five years		154
Due after five through 10 years		84
Due after 10 years		41
Total	$	288

The following table presents selected information about PEC’s sales of available-for-sale securities during the three and nine months ended September 30, 2009. Proceeds were primarily related to the NDT funds. Realized gains and losses were determined on a specific identification basis.

(in millions)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Proceeds	$	84		$	550
Realized gains		2			7
Realized losses		(4	)		(34	)

PEF

DEBT

The carrying amount of PEF’s long-term debt, including current maturities, was $4.182 billion at September 30, 2009 and December 31, 2008. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.7 billion and $4.5 billion at September 30, 2009 and December 31, 2008, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF’s nuclear plant as discussed in Note 4D of the 2008 Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.

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The following table summarizes PEF’s available-for-sale securities at September 30, 2009 and December 31, 2008.

September 30, 2009 (in millions)	Unrealized Losses			Unrealized Gains		Fair  Value
Equity securities	$	(4	)	$	104	$	286
Debt securities		(1	)		4		99
Cash equivalents		–			–		100
Total	$	(5	)	$	108	$	485
December 31, 2008  (in millions)	Unrealized Losses			Unrealized Gains		Fair Value
Equity securities	$	(38	)	$	59	$	225
Debt securities		(15	)		3		177
Cash equivalents		–			–		9
Total	$	(53	)	$	62	$	411

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments; all of the unrealized losses and gains at September 30, 2009 and December 31, 2008, relate to the NDT funds.

The aggregate fair value of investments with unrealized losses at September 30, 2009 and December 31, 2008 was $42 million and $165 million, respectively.

At September 30, 2009, the fair value of available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	1
Due after one through five years		43
Due after five through 10 years		27
Due after 10 years		28
Total	$	99

The following table presents selected information about PEF’s sales of available-for-sale securities during the three and nine months ended September 30, 2009. Proceeds from the sale of securities primarily related to the NDT funds. Realized gains and losses were determined on a specific identification basis.

(in millions)	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Proceeds	$	102		$	467
Realized gains		3			12
Realized losses		(3	)		(47	)

B.   FAIR VALUE MEASUREMENTS

GAAP 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). Fair value measurements require 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. Valuation techniques are

37

required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

GAAP also 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 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 September 30, 2009. 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
Nuclear decommissioning trust funds
Equity	$	800	$	7		$	–		$	807
Corporate debt		–		69			–			69
U.S. state and municipal debt		–		124			–			124
U.S. Treasury and other U.S. government agency debt		47		223			–			270
Money market funds and other		1		29			–			30
Total nuclear decommissioning trust funds		848		452			–			1,300
Commodity and interest rate derivatives		–		18			–			18
Other marketable securities		21		41			–			62
Total assets	$	869	$	511		$	–		$	1,380
Liabilities
Commodity and interest rate derivatives	$	–	$	(406	)	$	(42	)	$	(448	)
CVO derivatives		–		(23	)		–			(23	)
Total liabilities	$	–	$	(429	)	$	(42	)	$	(471	)

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PEC
(in millions)	Level 1		Level 2			Level 3			Total
Assets
Nuclear decommissioning trust funds
Equity	$	521	$	–		$	–		$	521
Corporate debt		–		64			–			64
U.S. state and municipal debt		–		37			–			37
U.S. Treasury and other U.S. government agency debt		47		130			–			177
Money market funds and other		1		17			–			18
Total nuclear decommissioning trust funds		569		248			–			817
Commodity and interest rate derivatives		–		3			–			3
Other marketable securities		3		–			–			3
Total assets	$	572	$	251		$	–		$	823
Liabilities
Commodity and interest rate derivatives	$	–	$	(56	)	$	(24	)	$	(80	)

PEF
(in millions)	Level 1		Level 2			Level 3			Total
Assets
Nuclear decommissioning trust funds
Equity	$	279	$	7		$	–		$	286
Corporate debt		–		5			–			5
U.S. state and municipal debt		–		87			–			87
U.S. Treasury and other U.S. government agency debt		–		93			–			93
Money market funds and other		–		12			–			12
Total nuclear decommissioning trust funds		279		204			–			483
Commodity and interest rate derivatives		–		13			–			13
Other marketable securities		2		–			–			2
Total assets	$	281	$	217		$	–		$	498
Liabilities
Commodity and interest rate derivatives	$	–	$	(346	)	$	(19	)	$	(365	)

The determination of the fair values above incorporates various factors, 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 12 for discussion of risk management activities and derivative transactions.

NDT 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.

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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 for the three and nine months ended September 30.

Progress Energy
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Derivatives, net at beginning of period	$	(31	)	$	163		$	(41	)	$	26
Total gains (losses), realized and unrealized
Included in earnings		–			–			–			–
Included in other comprehensive income		–			–			–			–
Deferred as regulatory assets and liabilities, net		(11	)		(145	)		(1	)		(8	)
Purchases, issuances and settlements, net		–			–			–			–
Transfers in (out) of Level 3, net		–			1			–			1
Derivatives, net at end of period	$	(42	)	$	19		$	(42	)	$	19

PEC
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Derivatives, net at beginning of period	$	(19	)	$	36		$	(23	)	$	6
Total gains (losses), realized and unrealized
Included in earnings		–			–			–			–
Included in other comprehensive income		–			–			–			–
Deferred as regulatory assets and liabilities, net		(5	)		(42	)		(1	)		(12	)
Purchases, issuances and settlements, net		–			–			–			–
Transfers in (out) of Level 3, net		–			2			–			2
Derivatives, net at end of period	$	(24	)	$	(4	)	$	(24	)	$	(4	)

PEF
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Derivatives, net at beginning of period	$	(12	)	$	127		$	(19	)	$	20
Total gains (losses), realized and unrealized
Included in earnings		–			–			–			–
Included in other comprehensive income		–			–			–			–
Deferred as regulatory assets and liabilities, net		(7	)		(103	)		–			4
Purchases, issuances and settlements, net		–			–			–			–
Transfers in (out) of Level 3, net		–			(1	)		–			(1	)
Derivatives, net at end of period	$	(19	)	$	23		$	(19	)	$	23

Substantially all unrealized gains and losses on commodity 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 September 30, 2009.

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10.   INCOME TAXES

Progress Energy

The accounting for income taxes prescribes a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. A two-step process is required; recognition of the tax benefit based on a “more-likely-than-not” threshold and measurement of the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with the taxing authority. Our liability for unrecognized tax benefits at January 1, 2009, was $104 million. Of the total amount of unrecognized tax benefits at January 1, 2009, $8 million would have affected the effective tax rate for income from continuing operations, if recognized. At September 30, 2009, our liability for unrecognized tax benefits increased to $159 million. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $8 million at September 30, 2009.

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Our open federal tax years are from 2004 forward, and our open state tax years in our major jurisdictions are generally from 2003 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. We cannot predict when those examinations will be completed. We are not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the 12-month period ending September 30, 2010.

We include interest expense related to unrecognized tax benefits in interest charges and we include penalties in other, net on the Consolidated Statements of Income. At January 1, 2009, we had accrued $27 million for interest and penalties. At September 30, 2009, we had accrued $32 million for interest and penalties.

During the three months ended September 30, 2009, we recorded a valuation allowance of $29 million against the deferred tax asset related to a loss on a legal judgment (see Note 16C). The tax expense related to the valuation allowance was recorded as part of loss from discontinued operations. Management continues to evaluate its options regarding this litigation, including grounds to appeal the judgment. Management’s decisions could have a significant impact on the realization of part or all of the $29 million deferred tax asset in a future period. We cannot predict the outcome of these matters.

PEC

PEC’s liability for unrecognized tax benefits at January 1, 2009, was $38 million. Of the total amount of unrecognized tax benefits at January 1, 2009, $5 million would have affected the effective tax rate, if recognized. At September 30, 2009, PEC’s liability for unrecognized tax benefits increased to $57 million. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $5 million at September 30, 2009.

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. PEC’s open federal tax years are from 2004 forward, and PEC’s open state tax years in our major jurisdictions are generally from 2003 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEC cannot predict when those examinations will be completed. PEC is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the 12-month period ending September 30, 2010.

PEC includes interest expense related to unrecognized tax benefits in interest charges and includes penalties in other, net on the Consolidated Statements of Income. At January 1, 2009, PEC had accrued $7 million for interest and penalties. At September 30, 2009, PEC had accrued $10 million for interest and penalties.

PEF

PEF’s liability for unrecognized tax benefits at January 1, 2009, was $62 million. Of the total amount of unrecognized tax benefits at January 1, 2009, $2 million would have affected the effective tax rate, if recognized. At September 30, 2009, PEF’s liability for unrecognized tax benefits increased to $100 million. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $2 million at September 30, 2009.

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We file consolidated federal and state income tax returns that include PEF. PEF’s open federal tax years are from 2004 forward and PEF’s open state tax years are generally from 2003 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEF cannot predict when those examinations will be completed. PEF is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the 12-month period ending September 30, 2010.

Pursuant to a regulatory order, PEF records interest expense related to unrecognized tax benefits as a regulatory asset, which is amortized over a three-year period or less, with the amortization included in interest charges on the Statements of Income. Penalties are included in other, net on the Statements of Income. At January 1, 2009, PEF had accrued $19 million for interest and penalties. At September 30, 2009, PEF had accrued $22 million for interest and penalties.

11.   BENEFIT PLANS

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

The components of the net periodic benefit cost for the respective Progress Registrants for the three and nine months ended September 30 were:

Progress Energy
	Pension Benefits						Other Postretirement  Benefits
	Three months ended September 30,
(in millions)	2009			2008			2009			2008
Service cost	$	11		$	11		$	1		$	2
Interest cost		36			33			6			9
Expected return on plan assets		(31	)		(45	)		–			(1	)
Amortization of actuarial loss (gain)(a)		16			–			(2	)		–
Other amortization, net(a)		2			1			1			1
Net periodic cost before deferral (see below)	$	34		$	–		$	6		$	11

	Pension Benefits						Other Postretirement Benefits
	Nine months ended September 30,
(in millions)	2009			2008			2009			2008
Service cost	$	31		$	35		$	5		$	6
Interest cost		104			95			23			25
Expected return on plan assets		(100	)		(127	)		(3	)		(4	)
Amortization of actuarial loss(a)		40			5			1			1
Other amortization, net(a)		5			2			4			3
Net periodic cost before deferral (see below)	$	80		$	10		$	30		$	31

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

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PEC
	Pension Benefits						Other Postretirement Benefits
	Three months ended September 30
(in millions)	2009			2008			2009			2008
Service cost	$	5		$	5		$	1		$	1
Interest cost		17			15			3			5
Expected return on plan assets		(15	)		(17	)		–			(1	)
Amortization of actuarial loss (gain)		4			–			(1	)		–
Other amortization, net		1			1			–			–
Net periodic cost	$	12		$	4		$	3		$	5

	Pension Benefits						Other Postretirement Benefits
	Nine months ended September 30
(in millions)	2009			2008			2009			2008
Service cost	$	13		$	17		$	3		$	3
Interest cost		48			43			12			13
Expected return on plan assets		(49	)		(49	)		(1	)		(3	)
Amortization of actuarial loss		8			4			–			–
Other amortization, net		4			2			1			1
Net periodic cost	$	24		$	17		$	15		$	14

PEF
	Pension Benefits						Other Postretirement Benefits
	Three months ended September 30
(in millions)	2009			2008			2009			2008
Service cost	$	5		$	4		$	–		$	1
Interest cost		14			14			2			4
Expected return on plan assets		(13	)		(24	)		–			–
Amortization of actuarial loss (gain)		10			–			(1	)		–
Other amortization, net		–			–			1			–
Net periodic cost (benefit) before deferral (see below)	$	16		$	(6	)	$	2		$	5

	Pension Benefits						Other Postretirement Benefits
	Nine months ended September 30
(in millions)	2009			2008			2009			2008
Service cost	$	14		$	13		$	1		$	2
Interest cost		42			40			10			11
Expected return on plan assets		(42	)		(68	)		(1	)		(1	)
Amortization of actuarial loss		29			–			–			1
Other amortization, net		–			–			3			2
Net periodic cost (benefit) before deferral (see below)	$	43		$	(15	)	$	13		$	15

On June 16, 2009, PEF received permission from the FPSC to defer the retail portion of pension expense incurred in 2009. The FPSC order does not change the total net periodic pension cost presented above, but defers a portion of those costs to be recovered in future periods. For the three and nine months ended September 30, 2009, PEF deferred $10 million and $26 million, respectively, of net periodic pension cost as a regulatory asset (See Note 4B).

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In 2009, contributions directly to our pension plan assets are expected to approximate $222 million, including $163 million for PEC and $58 million for PEF, substantially all of which were made in the third quarter of 2009.

12.   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. 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.

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, any realized gains or losses are passed through the fuel cost-recovery clause.

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

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 $3 million and $18 million on the PEC Consolidated Balance Sheet at September 30, 2009 and December 31, 2008, respectively. At September 30, 2009, PEC had 51.8 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases. Changes in natural gas prices and settlements of financial hedge agreements since December 31, 2008, have impacted PEF’s cash collateral asset included in derivative collateral posted on the PEF Balance Sheet, which was $182 million at September 30, 2009, compared to $335 million at December 31, 2008. At September 30, 2009, PEF had 199.5 million MMBtu notional of natural gas and 1.7 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. 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 September 30, 2009, we had 0.5 million gallons notional of

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gasoline and 0.6 million gallons notional of heating oil 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 September 30, 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 and nine months ended September 30, 2009 and 2008.

At September 30, 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 September 30, 2009, all open interest rate hedges will reach their mandatory termination dates within three years. It is expected that in the next 12 months $3 million and $4 million, net of tax, 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 the timing of debt issuances at the Parent and the Utilities and changes in the market value of currently open interest rate hedges.

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, June and July 2009, the Parent entered into forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. At September 30, 2009, the Parent had $150 million notional of interest rate cash flow hedges.  Subsequent to September 30, 2009, the Parent entered into $200 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

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 and June 2009, PEC entered into forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. At September 30, 2009, PEC had $100 million notional of interest rate cash flow hedges.

At December 31, 2008, PEF had no outstanding interest rate cash flow hedges. In January and June 2009, PEF entered into forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. At September 30, 2009, PEF had $75 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 September 30, 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, we 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 were in a liability position at September 30, 2009, was $79 million, for which PEC had posted collateral of $3 million in the

45

normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2009, PEC would have been required to post an additional $76 million of collateral with its counterparties.

The aggregate fair value of all derivative instruments at PEF with credit risk-related contingent features that were in a liability position at September 30, 2009, was $365 million, for which PEF had posted collateral of $182 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on September 30, 2009, PEF would have been required to post an additional $173 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 September 30, 2009 and December 31, 2008:

Instrument / Balance sheet location	September 30, 2009					December 31, 2008
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	–				$	(2	)
Interest rate derivatives
Prepayments and other current assets	$	2				$	–
Other assets and deferred debits		5					–
Derivative liabilities, current				–					(65	)
Derivative liabilities, long-term				(4	)				–
Total derivatives designated as hedging instruments		7		(4	)		–		(67	)
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		6					9
Other assets and deferred debits		5					1
Derivative liabilities, current				(245	)				(425	)
Derivative liabilities, long-term				(199	)				(263	)
CVOs(b)
Other liabilities and deferred credits				(23	)				(34	)
Fair value of derivatives not designated as hedging instruments		11		(467	)		10		(722	)
Fair value loss transition adjustment(c)
Derivative liabilities, current				(1	)				(1	)
Derivative liabilities, long-term				(4	)				(6	)
Total derivatives not designated as hedging instruments		11		(472	)		10		(729	)
Total derivatives	$	18	$	(476	)	$	10	$	(796	)

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

(b)   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.

(c)   In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the adoption of new accounting guidance for derivatives. The related liability is being amortized to earnings over the term of the related contract (See Note 14).

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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 September 30, 2009 and 2008:

Derivatives Designated as Hedging Instruments
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)	$	(6	)	$	1	Interest charges	$	(2	)	$	(1	)	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
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(236	)	$	124	$	(38	)	$	(1,085	)

(a)   After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause and are reflected in fuel used in electric generation on the Consolidated Statements of Income.

(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	$(5)
Fair value loss transition adjustment	Other, net	1	1
CVOs	Other, net	3	–
Total		$5	$(4)

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The following tables present the effect of derivative instruments on OCI (see Note 6C) and the Consolidated Statements of Income for the nine months ended September 30, 2009 and 2008:

Derivatives Designated as Hedging Instruments
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	$	1	$	(1	)		$	–		$	–			$	–		$	–
Interest rate derivatives(c)		7		6		Interest charges		(5	)		(2	)	Interest charges		(3	)		1
Total	$	8	$	5			$	(5	)	$	(2	)		$	(3	)	$	1

(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
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(548	)	$	249	$	(302	)	$	20

(a)   After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause and are reflected in fuel used in electric generation on the Consolidated Statements of Income.

(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	$	(1	)
Fair value loss transition adjustment	Other, net		2		2
CVOs	Other, net		11		(2	)
Total		$	14	$	(1	)

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PEC

The following table presents the fair value of derivative instruments at September 30, 2009 and December 31, 2008:

Instrument / Balance sheet location	September 30, 2009					December 31, 2008
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	–				$	(1	)
Interest rate derivatives
Other assets and deferred debits	$	3				$	–
Derivative liabilities, current				–					(35	)
Other liabilities and deferred credits				(1	)				–
Total derivatives designated as hedging instruments		3		(1	)		–		(36	)
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Derivative liabilities, current				(28	)				(45	)
Other liabilities and deferred credits				(51	)				(54	)
Fair value of derivatives not designated as hedging instruments		–		(79	)		–		(99	)
Fair value loss transition adjustment(b)
Derivative liabilities, current				(1	)				(1	)
Other liabilities and deferred credits				(4	)				(6	)
Total derivatives not designated as hedging instruments		–		(84	)		–		(106	)
Total derivatives	$	3	$	(85	)	$	–	$	(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 adoption of new accounting guidance for derivatives. The related liability is being amortized to earnings over the term of the related contract (See Note 14).

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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 September 30, 2009 and 2008:

Derivatives Designated as Hedging Instruments
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)	$	(1	)	$	1	Interest charges	$	(1	)	$	(1	)	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
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(29	)	$	6	$	(8	)	$	(165	)

(a)   After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause and are reflected in fuel used in electric generation on the Consolidated Statements of Income.

(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	$	(5	)
Fair value loss transition adjustment	Other, net		1		1
Total		$	2	$	(4	)

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The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Consolidated Statements of Income for the nine months ended September 30, 2009 and 2008:

Derivatives Designated as Hedging Instruments
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	$	–	$	(1	)		$	–		$	–			$	–		$	–
Interest rate derivatives(c)		1		(3	)	Interest charges		(3	)		(1	)	Interest charges		(2	)		–
Total	$	1	$	(4	)		$	(3	)	$	(1	)		$	(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
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(68	)	$	12	$	(49	)	$	(24	)

(a)   After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause and are reflected in fuel used in electric generation on the Consolidated Statements of Income.

(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	$	(1	)
Fair value loss transition adjustment	Other, net		2		2
Total		$	3	$	1

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PEF

The following table presents the fair value of derivative instruments at September 30, 2009 and December 31, 2008:

Instrument / Balance sheet location	September 30, 2009					December 31, 2008
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets	$	2				$	–
Total derivatives designated as hedging instruments		2					–
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		6					9
Other assets and deferred debits		5					1
Derivative liabilities, current			$	(217	)			$	(380	)
Derivative liabilities, long-term				(148	)				(209	)
Total derivatives not designated as hedging instruments		11		(365	)		10		(589	)
Total derivatives	$	13	$	(365	)	$	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 September 30, 2009 and 2008:

Derivatives Designated as Hedging Instruments
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)	$	(1	)	$	–	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.

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Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(207	)	$	118	$	(30	)	$	(920	)

(a)   After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause and are reflected in fuel used in electric generation on the Statements of Income.

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

The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Statements of Income for the nine months ended September 30, 2009 and 2008:

Derivatives Designated as Hedging Instruments
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)	$	2	$	8	Interest charges	$	–	$	–	Interest charges	$	–	$	1

(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
Instrument	Realized Gain or (Loss)(a)					Unrealized Gain or (Loss)(b)
(in millions)	2009			2008		2009			2008
Commodity derivatives	$	(480	)	$	237	$	(253	)	$	44

(a)   After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause and are reflected in fuel used in electric generation on the Statements of Income.

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

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13.   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 thresholds for disclosure as separate reportable business segments. 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 and nine months ended September 30:

									Income (Loss)
	Revenues								from Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
Three Months Ended September 30, 2009
PEC	$	1,307	$	–		$	1,307		$	207		$	13,615
PEF		1,516		–			1,516			177			13,026
Corporate and Other		1		51			52			(34	)		19,433
Eliminations		–		(51	)		(51	)		–			(15,416	)
Totals	$	2,824	$	–		$	2,824		$	350		$	30,658
Three Months Ended September 30, 2008
PEC	$	1,266	$	–		$	1,266		$	200
PEF		1,428		–			1,428			143
Corporate and Other		2		92			94			(34	)
Eliminations		–		(92	)		(92	)		–
Totals	$	2,696	$	–		$	2,696		$	309

									Income (Loss)
	Revenues								from Continuing
(in millions)	Unaffiliated		Intersegment			Total			Operations			Assets
Nine Months Ended September 30, 2009
PEC	$	3,561	$	–		$	3,561		$	429		$	13,615
PEF		4,012		–			4,012			384			13,026
Corporate and Other		5		171			176			(105	)		19,433
Eliminations		–		(171	)		(171	)		–			(15,416	)
Totals	$	7,578	$	–		$	7,578		$	708		$	30,658
Nine Months Ended September 30, 2008
PEC	$	3,382	$	–		$	3,382		$	426
PEF		3,618		–			3,618			334
Corporate and Other		6		268			274			(98	)
Eliminations		–		(268	)		(268	)		–
Totals	$	7,006	$	–		$	7,006		$	662

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14.   OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income; AFUDC equity, which represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets; and other, net. The components of other, net as shown on the accompanying Statements of Income are presented 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.

Progress Energy
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Nonregulated energy and delivery services (expense) income, net	$	(2	)	$	(3	)	$	7		$	10
Fair value loss transition adjustment amortization (see Note 12)		1			1			2			2
CVOs unrealized gain (loss), net		3			–			11			(2	)
Donations		(3	)		(3	)		(8	)		(14	)
Other, net		2			(2	)		1			(5	)
Other, net – Progress Energy	$	1		$	(7	)	$	13		$	(9	)

PEC
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Nonregulated energy and delivery services (expense) income, net	$	(5	)	$	(4	)	$	(1	)	$	5
Fair value loss transition adjustment amortization (see Note 12)		1			1			2			2
Donations		(1	)		(2	)		(4	)		(8	)
Other, net		3			–			(2	)		1
Other, net – PEC	$	(2	)	$	(5	)	$	(5	)	$	–

PEF
	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Nonregulated energy and delivery services income, net	$	2		$	2		$	8		$	6
Donations		(1	)		(1	)		(4	)		(6	)
Other, net		–			(1	)		4			(1	)
Other, net – PEF	$	1		$	–		$	8		$	(1	)

15.   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

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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 current liabilities and other liabilities and deferred credits on the Balance Sheets:

(in millions)	September 30, 2009		December 31, 2008
PEC
MGP and other sites(a)	$	13	$	16
PEF
Remediation of distribution and substation transformers		22		22
MGP and other sites		13		15
Total PEF environmental remediation accruals(b)		35		37
Total Progress Energy environmental remediation accruals	$	48	$	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 16B).

PEC

Including the Ward Transformer site located in Raleigh, N.C. (Ward), and MGP sites discussed below, for the three months ended September 30, 2009, PEC reduced its accrual by approximately $1 million and spent approximately $2 million. For the nine months ended September 30, 2009, PEC accrued approximately $3 million and spent approximately $6 million. For the three months ended September 30, 2008, PEC accrued approximately $2 million and spent approximately $2 million. For the nine months ended September 30, 2008, PEC accrued approximately $8 million and spent approximately $6 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

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have historical experience. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

In 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 September 30, 2009 and December 31, 2008, PEC’s recorded liability for the site was approximately $4 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 has settled with a number of the PRPs and is in active settlement negotiations with others. With respect to the defendants that do not settle, the federal district court in which this matter is pending requires that alternative dispute resolution be pursued early in civil litigation but it is unclear what process the court will require. 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 advised would be used to negotiate implementation of the required actions. The other PRPs’ good faith response was subsequently withdrawn. Discussions among representatives of certain PRPs, including PEC, and the EPA are ongoing. 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, if any, 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. For the three and nine months ended September 30, 2009, PEF accrued approximately $9 million and $11 million, respectively, due to the identification of additional transformer sites and an increase in estimated remediation costs, and spent approximately $4 million and $11 million, respectively, related to the remediation of transformers. For the three and nine months ended September 30, 2008, PEF accrued approximately $3 million and $15 million, respectively, due to the identification of additional transformer sites and an increase in estimated remediation costs, and spent approximately $6 million and $20 million, respectively, related to the remediation of transformers. At September 30, 2009, PEF had recorded a regulatory asset for the probable recovery of costs through the ECRC related to the sites included under the agreement with the FDEP.

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. For the three months ended September 30, 2009, PEF made no material accruals or expenditures. For the nine months ended September 30, 2009, PEF made no material accruals and spent approximately $2 million, which primarily related to its MGP sites. For the three and nine months ended September 30, 2008, PEF made no material accruals or expenditures.

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B.   AIR AND WATER QUALITY

At September 30, 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. Through September 30, 2009, cumulative environmental compliance capital expenditures since 2002 with regard to these environmental laws and regulations were $2.084 billion, including $1.051 billion at PEC and $1.033 billion at PEF. Through 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. Because the D.C. Court of Appeals’ December 23, 2008 decision remanded the CAIR, the current implementation of the CAIR continues to fulfill 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 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. On May, 1, 2009, PEF announced that it expects the construction schedule to shift later than the originally estimated 2016 to 2018 timeframe by a minimum of 20 months 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. At September 30, 2009 and December 31, 2008, PEC had approximately $15 million and $22 million, respectively, in SO2 emission allowances and an immaterial amount of NOx emission allowances. At September 30, 2009 and December 31, 2008, PEF had approximately $8 million and $11 million, respectively, in SO2 emission allowances and approximately $43 million and $65 million, respectively, in NOx emission allowances.

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

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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. The terms of the agreement place no limit on PEC’s maximum remaining liability; however, PEC estimates its remaining exposure to be $2 million at September 30, 2009. At September 30, 2009 and December 31, 2008, the amount of the liability was $2 million and $10 million, respectively, based upon the respective estimates for the remaining Clean Smokestacks Act compliance costs. During the three months ended September 30, 2009, PEC made no additional accruals and spent approximately $5 million that exceeded the joint owner limit. During the nine months ended September 30, 2009, PEC accrued approximately $2 million and spent approximately $10 million that exceeded the joint owner limit (See Note 16B). 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.

16.   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

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.

PEC

In October 2009, PEC entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs for the period from July 2012 through August 2032. The total cost to PEC associated with these agreements is estimated to be approximately $1.0 billion. These agreements are subject to several conditions precedent, including various federal regulatory approvals, the completion and commencement of operation of necessary related interstate and intrastate natural gas pipeline system expansions, and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEC’s fuel and purchased power commitments.

PEF

On May 1, 2009, PEF announced 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 for the commercial operation of Levy to shift later than 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 predict the impact, if any, such amendment might have on the project’s total cost. However, consistent with nuclear cost-recovery filings with the FPSC (See Note 4B), PEF anticipates that approximately $1 billion of the construction obligations disclosed in Note 22A in the 2008 Form 10-K for the three-year period following December 31, 2008, could be deferred to later periods as a result of the schedule shift.

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During the second quarter of 2009, PEF entered into conditional agreements for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with these agreements is estimated to be approximately $281 million. These agreements are subject to several conditions precedent, including various federal regulatory approvals, the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions, and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEF’s fuel and purchased power commitments.

B.   GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At September 30, 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 September 30, 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. 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. The terms of the agreement place no limit on PEC’s maximum remaining liability; however, PEC estimates its remaining exposure to be $2 million at September 30, 2009. Pursuant to a September 2008 NCUC order, PEC is including the indemnification costs as allowable costs to be included in rate base for ratemaking purposes (See Note 15B). At September 30, 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 September 30, 2009 and December 31, 2008, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $52 million and $61 million, respectively. These amounts include $2 million and $10 million, respectively, for PEC and $8 million for PEF at September 30, 2009 and December 31, 2008. During the three months ended September 30, 2009, PEC made no additional accruals and spent approximately $5 million that exceeded the joint owner limit. During the nine months ended September 30, 2009, PEC accrued approximately $2 million and spent approximately $10 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 17 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.

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A trial was held in November 2007 in the United States Court of Federal Claims, and closing arguments were presented on April 4, 2008. On May 19, 2008, the Utilities received a ruling from the Trial Court 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 Trial Court’s ruling to the D.C. Court of Appeals. Oral arguments were held on May 4, 2009. On July 21, 2009, the D.C. Court of Appeals vacated and remanded the calculation of damages back to the Trial Court but affirmed the portion of damages awarded that were directed to overhead costs and other indirect expenses. The Department of Justice requested a rehearing en banc but the D.C. Court of Appeals denied the motion on November 3, 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

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000, (the Asset Purchase Agreement) 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 (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates). In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global had requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was 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 and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the expiration of the Section 29 tax credit program on December 31, 2007, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations (See Note 3A).

The jury awarded Global $78 million. On October 23, 2009, Global filed a motion to assess prejudgment interest on the award, which totaled approximately $53 million through September 30, 2009. During the three months ended September 30, 2009, we recorded a charge of $101 million to discontinued operations, which was net of a previously recorded indemnification liability (See Note 1C) and estimated tax impacts. We intend to oppose the motion for assessment of interest. We have filed post-trial motions to set aside the verdict and for a new trial, which have been denied. We are evaluating grounds for appeal and will make a determination as to whether to appeal at a later date.

In a second suit filed in the Superior Court for Wake County, N.C., Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), the Progress Affiliates seek 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. Based upon the resolution of the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

In December 2006, we reached agreement with Global to settle an additional claim in the Florida Global Case 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.

61

NOTICE OF VIOLATION

On April 29, 2009, the EPA issued a notice of violation and opportunity to show cause with respect to a 16,000 gallon oil spill at one of PEC’s substations in 2007. The notice of violation did not include specified sanctions sought. Subsequently, the EPA notified PEC that the agency is seeking monetary sanctions that are de minimus to our and PEC’s results of operations or financial condition. Discussions between PEC and the EPA are ongoing. 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 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.

17.   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 variable-interest entity for which we are not the primary beneficiary. 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 Statements of 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.

62

Condensed Consolidating Statement of Income Three Months Ended September 30, 2009
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiary			Other			Progress Energy,  Inc.
Operating revenues	$	–		$	1,517		$	1,307		$	–		$	2,824
Operating expenses
Fuel used in electric generation		–			618			457			–			1,075
Purchased power		–			43			82			–			125
Operation and maintenance		2			198			225			(2	)		423
Depreciation, amortization and accretion		–			247			120			4			371
Taxes other than on income		–			96			56			–			152
Other		–			2			–			–			2
Total operating expenses		2			1,204			940			2			2,148
Operating (loss) income		(2	)		313			367			(2	)		676
Other income (expense)
Interest income		2			–			1			(1	)		2
Allowance for equity funds used during construction		–			13			7			–			20
Other, net		3			2			(2	)		(2	)		1
Total other income (expense), net		5			15			6			(3	)		23
Interest charges
Interest charges		59			68			48			(1	)		174
Allowance for borrowed funds used during construction		–			(3	)		(3	)		–			(6	)
Total interest charges, net		59			65			45			(1	)		168
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(56	)		263			328			(4	)		531
Income tax (benefit) expense		(25	)		89			120			(3	)		181
Equity in earnings of consolidated subsidiaries		278			–			–			(278	)		–
Income (loss) from continuing operations		247			174			208			(279	)		350
Discontinued operations, net of tax		–			(52	)		–			(50	)		(102	)
Net income (loss)		247			122			208			(329	)		248
Net income attributable to noncontrolling interests, net of tax		–			(1	)		–			–			(1	)
Net income (loss) attributable to controlling interests	$	247		$	121		$	208		$	(329	)	$	247

63

Condensed Consolidating Statement of Income Three Months Ended September 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiary			Other			Progress Energy, Inc.
Operating revenues	$	–		$	1,430		$	1,266		$	–		$	2,696
Operating expenses
Fuel used in electric generation		–			521			348			–			869
Purchased power		–			305			145			–			450
Operation and maintenance		1			201			243			(6	)		439
Depreciation, amortization and accretion		–			77			124			4			205
Taxes other than on income		–			88			53			–			141
Other		–			2			–			(1	)		1
Total operating expenses		1			1,194			913			(3	)		2,105
Operating (loss) income		(1	)		236			353			3			591
Other income (expense)
Interest income		3			5			2			(2	)		8
Allowance for equity funds used during construction		–			25			9			–			34
Other, net		–			(1	)		(5	)		(1	)		(7	)
Total other income (expense), net		3			29			6			(3	)		35
Interest charges
Interest charges		49			75			54			–			178
Allowance for borrowed funds used during construction		–			(7	)		(4	)		–			(11	)
Total interest charges, net		49			68			50			–			167
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(47	)		197			309			–			459
Income tax (benefit) expense		(20	)		59			108			3			150
Equity in earnings of consolidated subsidiaries		336			–			–			(336	)		–
Income (loss) from continuing operations		309			138			201			(339	)		309
Discontinued operations, net of tax		–			(1	)		–			2			1
Net income (loss)		309			137			201			(337	)		310
Net income attributable to noncontrolling interests, net of tax		–			(1	)		–			–			(1	)
Net income (loss) attributable to controlling interests	$	309		$	136		$	201		$	(337	)	$	309

64

Condensed Consolidating Statement of Income Nine Months Ended September 30, 2009
(in millions)	Parent			Subsidiary  Guarantor			Non- Guarantor Subsidiary			Other			Progress Energy, Inc.
Operating revenues	$	–		$	4,017		$	3,561		$	–		$	7,578
Operating expenses
Fuel used in electric generation		–			1,573			1,282			–			2,855
Purchased power		–			403			196			–			599
Operation and maintenance		5			604			767			(16	)		1,360
Depreciation, amortization and accretion		–			512			355			10			877
Taxes other than on income		–			264			161			–			425
Other		–			12			2			–			14
Total operating expenses		5			3,368			2,763			(6	)		6,130
Operating (loss) income		(5	)		649			798			6			1,448
Other income (expense)
Interest income		8			2			4			(6	)		8
Allowance for equity funds used during construction		–			72			23			–			95
Other, net		11			8			(5	)		(1	)		13
Total other income (expense), net		19			82			22			(7	)		116
Interest charges
Interest charges		169			211			157			(3	)		534
Allowance for borrowed funds used during construction		–			(21	)		(9	)		–			(30	)
Total interest charges, net		169			190			148			(3	)		504
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(155	)		541			672			2			1,060
Income tax (benefit) expense		(64	)		165			242			9			352
Equity in earnings of consolidated subsidiaries		693			–			–			(693	)		–
Income (loss) from continuing operations		602			376			430			(700	)		708
Discontinued operations, net of tax		1			(53	)		–			(51	)		(103	)
Net income (loss)		603			323			430			(751	)		605
Net (income) loss attributable to noncontrolling interests, net of tax		–			(2	)		1			(1	)		(2	)
Net income (loss) attributable to controlling interests	$	603		$	321		$	431		$	(752	)	$	603

65

Condensed Consolidating Statement of Income Nine Months Ended September 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiary			Other			Progress Energy, Inc.
Operating revenues	$	–		$	3,624		$	3,382		$	–		$	7,006
Operating expenses
Fuel used in electric generation		–			1,235			1,027			–			2,262
Purchased power		–			746			266			–			1,012
Operation and maintenance		3			621			766			(20	)		1,370
Depreciation, amortization and accretion		–			229			379			11			619
Taxes other than on income		–			235			152			–			387
Other		–			–			(6	)		–			(6	)
Total operating expenses		3			3,066			2,584			(9	)		5,644
Operating (loss) income		(3	)		558			798			9			1,362
Other income (expense)
Interest income		9			7			9			(5	)		20
Allowance for equity funds used during construction		–			65			19			–			84
Other, net		(2	)		(4	)		–			(3	)		(9	)
Total other income (expense), net		7			68			28			(8	)		95
Interest charges
Interest charges		147			184			164			(2	)		493
Allowance for borrowed funds used during construction		–			(19	)		(8	)		–			(27	)
Total interest charges, net		147			165			156			(2	)		466
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(143	)		461			670			3			991
Income tax (benefit) expense		(60	)		139			242			8			329
Equity in earnings of consolidated subsidiaries		806			–			–			(806	)		–
Income (loss) from continuing operations		723			322			428			(811	)		662
Discontinued operations, net of tax		–			63			–			4			67
Net income (loss)		723			385			428			(807	)		729
Net income attributable to noncontrolling interests, net of tax		–			(6	)		–			–			(6	)
Net income (loss) attributable to controlling interests	$	723		$	379		$	428		$	(807	)	$	723

66

Condensed Consolidating Balance Sheet September 30, 2009
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiary		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	–	$	9,599	$	9,719	$	116		$	19,434
Current assets
Cash and cash equivalents		–		64		89		2			155
Notes receivable from affiliated companies		18		98		147		(263	)		–
Regulatory assets		–		58		122		–			180
Derivative collateral posted		–		182		3		–			185
Income taxes receivable		36		–		7		(35	)		8
Prepayments and other current assets		6		1,292		1,210		13			2,521
Total current assets		60		1,694		1,578		(283	)		3,049
Deferred debits and other assets
Investment in consolidated subsidiaries		12,960		–		–		(12,960	)		–
Regulatory assets		–		1,264		1,199		–			2,463
Goodwill		–		–		–		3,655			3,655
Other assets and deferred debits		168		677		1,119		93			2,057
Total deferred debits and other assets		13,128		1,941		2,318		(9,212	)		8,175
Total assets	$	13,188	$	13,234	$	13,615	$	(9,379	)	$	30,658
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	9,381	$	4,344	$	4,564	$	(8,908	)	$	9,381
Noncontrolling interests		–		3		3		–			6
Total equity		9,381		4,347		4,567		(8,908	)		9,387
Preferred stock of subsidiaries		–		34		59		–			93
Long-term debt, affiliate		–		309		–		(37	)		272
Long-term debt, net		3,244		3,882		3,708		–			10,834
Total capitalization		12,625		8,572		8,334		(8,945	)		20,586
Current liabilities
Current portion of long-term debt		100		300		–		–			400
Short-term debt		200		50		–		–			250
Notes payable to affiliated companies		–		306		–		(306	)		–
Other current liabilities		227		1,207		758		(82	)		2,110
Total current liabilities		527		1,863		758		(388	)		2,760
Deferred credits and other liabilities
Noncurrent income tax liabilities		–		270		1,205		(410	)		1,065
Regulatory liabilities		–		1,117		1,188		115			2,420
Other liabilities and deferred credits		36		1,412		2,130		249			3,827
Total deferred credits and other liabilities		36		2,799		4,523		(46	)		7,312
Total capitalization and liabilities	$	13,188	$	13,234	$	13,615	$	(9,379	)	$	30,658

67

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
Income taxes receivable		34		56		98		6			194
Prepayments and other current assets		14		1,082		1,174		(10	)		2,260
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	)		–
Other current liabilities		251		1,344		855		(14	)		2,436
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

68

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2009
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiary			Other			Progress  Energy, Inc.
Net cash provided (used) by operating activities	$	76		$	913		$	953		$	(172	)	$	1,770
Investing activities
Gross property additions		–			(1,069	)		(575	)		–			(1,644	)
Nuclear fuel additions		–			(66	)		(82	)		–			(148	)
Purchases of available-for-sale securities and other investments		–			(597	)		(614	)		(60	)		(1,271	)
Proceeds from available-for-sale securities and other investments		–			600			585			60			1,245
Changes in advances to affiliated companies		16			(54	)		(92	)		130			–
Contributions to consolidated subsidiaries		(502	)		–			–			502			–
Return of investment in consolidated subsidiaries		12			–			–			(12	)		–
Other investing activities		–			(2	)		(1	)		(2	)		(5	)
Net cash (used) provided by investing activities		(474	)		(1,188	)		(779	)		618			(1,823	)
Financing activities
Issuance of common stock		557			–			–			–			557
Dividends paid on common stock		(520	)		–			–			–			(520	)
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		(440	)		(321	)		(110	)		–			(871	)
Proceeds from issuance of long-term debt, net		742			–			595			–			1,337
Retirement of long-term debt		–			–			(400	)		–			(400	)
Cash distributions to noncontrolling interests		–			(3	)		–			(2	)		(5	)
Changes in advances from affiliated companies		–			100			–			(100	)		–
Contributions from parent		–			498			15			(513	)		–
Other financing activities		–			(7	)		(3	)		(31	)		(41	)
Net cash provided (used) by financing activities		310			266			(103	)		(445	)		28
Net (decrease) increase in cash and cash equivalents		(88	)		(9	)		71			1			(25	)
Cash and cash equivalents at beginning of period		88			73			18			1			180
Cash and cash equivalents at end of period	$	–		$	64		$	89		$	2		$	155

69

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2008
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor  Subsidiary			Other			Progress  Energy, Inc.
Net cash (used) provided by operating activities	$	(138	)	$	502		$	932		$	63		$	1,359
Investing activities
Gross property additions		–			(1,230	)		(518	)		(12	)		(1,760	)
Nuclear fuel additions		–			(27	)		(131	)		–			(158	)
Proceeds from sales of discontinued operations and other assets, net of cash divested		–			60			3			–			63
Proceeds from sales of assets to affiliated companies		–			12			–			(12	)		–
Purchases of available-for-sale securities and other investments		(6	)		(618	)		(464	)		(102	)		(1,190	)
Proceeds from available-for-sale securities and other investments		–			622			433			99			1,154
Changes in advances to affiliated companies		140			83			–			(223	)		–
Contributions to consolidated subsidiaries		(99	)		–			–			99			–
Return of investment in consolidated subsidiaries		–			10			–			(10	)		–
Other investing activities		(1	)		(1	)		–			(1	)		(3	)
Net cash provided (used) by investing activities		34			(1,089	)		(677	)		(162	)		(1,894	)
Financing activities
Issuance of common stock		106			–			–			–			106
Dividends paid on common stock		(481	)		–			–			–			(481	)
Dividends paid to parent		–			(3	)		–			3			–
Payments of short-term debt with original maturities greater than 90 days		(176	)		–			–			–			(176	)
Net increase in short-term debt		470			–			–			–			470
Proceeds from issuance of long-term debt, net		–			1,475			322			–			1,797
Retirement of long-term debt		–			(577	)		(300	)		–			(877	)
Cash distributions to noncontrolling interests		–			(85	)		–			–			(85	)
Changes in advances from affiliated companies		–			(96	)		(153	)		249			–
Contributions from parent		–			85			15			(100	)		–
Other financing activities		–			2			(19	)		(54	)		(71	)
Net cash (used) provided by financing activities		(81	)		801			(135	)		98			683
Net (decrease) increase in cash and cash equivalents		(185	)		214			120			(1	)		148
Cash and cash equivalents at beginning of period		185			43			25			2			255
Cash and cash equivalents at end of period	$	–		$	257		$	145		$	1		$	403

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

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

The following MD&A contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors” found within Part II of this Form 10-Q and Item 1A, “Risk Factors” to the Progress Registrant’s annual report on Form 10-K for the fiscal year ended December 31, 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 and nine months ended September 30, 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 three months ended September 30, 2009, our net income attributable to controlling interests was $247 million, or $0.88 per share, compared to net income attributable to controlling interests of $309 million, or $1.18 per share, for the same period in 2008. The decrease in net income attributable to controlling interests as compared to prior year was primarily due to losses from discontinued operations, partially offset by an increase in income from continuing operations as discussed below. The current year losses from discontinued operations are primarily due to a legal judgment in a lawsuit related to certain of our now discontinued synthetic fuels facilities (See Note 16C).

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For the three months ended September 30, 2009, our income from continuing operations was $350 million compared to $309 million for the same period in 2008. The increase in income from continuing operations as compared to prior year was primarily due to:

·   favorable impact of interim and limited base rate relief at PEF;

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

·   net impact of returns earned on higher levels of nuclear and environmental cost recovery clause (ECRC) assets at PEF; and

·   lower depreciation expense associated with PEC’s accelerated cost-recovery program for nuclear generating assets recognized during 2008.

Offsetting these items was:

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

For the nine months ended September 30, 2009, our net income attributable to controlling interests was $603 million, or $2.16 per share, compared to net income attributable to controlling interests of $723 million, or $2.77 per share, for the same period in 2008. The decrease in net income attributable to controlling interests as compared to prior year was primarily due to losses from discontinued operations, partially offset by an increase in income from continuing operations as discussed below. The impact from discontinued operations is primarily due to a legal judgment in the current year, as previously mentioned (See Note 16C), partially offset by the prior year gain on sales of our coal terminals and docks.

For the nine months ended September 30, 2009, our income from continuing operations was $708 million compared to $662 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 impact of interim and limited base rate relief at PEF;

·   lower depreciation and amortization expense at PEC related to North Carolina Clean Smokestacks Act (Clean Smokestacks Act) amortization expense and depreciation expense associated with the accelerated cost-recovery program for nuclear generating assets recognized during 2008;

·   net impact of returns earned on higher levels of nuclear and ECRC assets at PEF; and

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

Offsetting these items were:

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

·   higher interest expense.

Our segments contributed the following profits or losses for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Business Segment
PEC	$	207		$	200		$	429		$	426
PEF		177			143			384			334
Total segment profit		384			343			813			760
Corporate and Other		(34	)		(34	)		(105	)		(98	)
Income from continuing operations		350			309			708			662
Discontinued operations, net of tax		(102	)		1			(103	)		67
Net income attributable to noncontrolling interests, net of tax		(1	)		(1	)		(2	)		(6	)
Net income attributable to controlling interests	$	247		$	309		$	603		$	723

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PROGRESS ENERGY CAROLINAS

PEC contributed segment profits of $207 million and $200 million for the three months ended September 30, 2009 and 2008, respectively. The increase in profits for the three months ended September 30, 2009, compared to the same period in 2008, was primarily due to lower O&M expenses, lower depreciation expense and higher wholesale revenues, partially offset by unfavorable net retail customer growth and usage.

PEC contributed segment profits of $429 million and $426 million for the nine months ended September 30, 2009 and 2008, respectively. The increase in profits for the nine months ended September 30, 2009, compared to the same period in 2008, was primarily due to lower depreciation and amortization expense and the favorable impact of weather, partially offset by unfavorable net retail customer growth and usage, primarily in the industrial customer class.

The revenue tables that follow present the total amount and percentage change of revenues excluding fuel and other pass-through revenues. Revenues excluding fuel and other pass-through revenues is defined as total electric revenues less fuel and other pass-through revenues. We and 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, applicable portions of purchased power expenses and other pass-through expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. Pass-through revenues do not include the revenues associated with the return on asset component of demand-side management (DSM), energy-efficiency and renewable energy clause revenues as these revenues will have an impact on reported 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.

Three Months Ended September 30, 2009, Compared to Three Months Ended September 30, 2008

REVENUES

PEC’s electric revenues for the three months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended September 30,
Customer Class	2009			Change			% Change			2008
Residential	$	525		$	30			6.1		$	495
Commercial		348			17			5.1			331
Industrial		197			(3	)		(1.5	)		200
Governmental		33			1			3.1			32
Unbilled		(11	)		5			–			(16	)
Total retail revenues		1,092			50			4.8			1,042
Wholesale		186			(10	)		(5.1	)		196
Miscellaneous		29			1			3.6			28
Total electric revenues		1,307			41			3.2			1,266
Less: Fuel and other pass-through revenues		(520	)		(54	)		–			(466	)
Revenues excluding fuel and other pass-through revenues	$	787		$	(13	)		(1.6	)	$	800

PEC’s revenues, excluding fuel and other pass-through revenues of $520 million and $466 million for the three months ended September 30, 2009 and 2008, respectively, decreased $13 million. The decrease was primarily due to $23 million unfavorable impact of net retail customer growth and usage, partially offset by $6 million higher wholesale revenues. 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 13,000 increase in the average number of customers for the three months ended September 30, 2009, compared to the same period in 2008. However, PEC’s rate of residential growth has declined as PEC’s average number of customers for the three months ended September 30, 2008, compared to the same period in 2007, increased a net 23,000 customers. Higher energy rates with a major customer drove the higher wholesale revenues, excluding fuel and other pass-through revenues.

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PEC’s electric energy sales for the three months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2009			Change			% Change			2008
Residential		4,824			(105	)		(2.1	)		4,929
Commercial		3,923			(156	)		(3.8	)		4,079
Industrial		2,789			(90	)		(3.1	)		2,879
Governmental		437			–			–			437
Unbilled		(397	)		(147	)		–			(250	)
Total retail kWh sales		11,576			(498	)		(4.1	)		12,074
Wholesale		3,607			(139	)		(3.7	)		3,746
Total kWh sales		15,183			(637	)		(4.0	)		15,820

Retail revenues increased for the three months ended September 30, 2009, despite a decrease in retail kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates. The decrease in retail kWh sales for the three months ended September 30, 2009, is primarily due to a decrease in average usage per retail customer.

Wholesale revenues and kWh sales decreased for the three months ended September 30, 2009, primarily due to a decline in usage for a major wholesale customer.

PEC has experienced a decline in its retail and wholesale kWh sales due to the current recession in the United States. 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 $539 million for the three months ended September 30, 2009, which represents a $46 million increase compared to the same period in 2008. Fuel used in electric generation increased $109 million to $457 million primarily due to 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 decreased $63 million compared to the same period in 2008, primarily due to lower market purchases resulting from lower system requirements and lower fuel prices.

Operation and Maintenance

O&M expense was $225 million for the three months ended September 30, 2009, which represents an $18 million decrease compared to the same period in 2008. This decrease is primarily due to $9 million in targeted cost reductions, $6 million lower net plant outage and maintenance costs, and the $3 million impact of changes to an environmental reserve (see Note 15).

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $120 million for the three months ended September 30, 2009, which represents a $4 million decrease compared to the same period in 2008. Depreciation, amortization and accretion expense decreased primarily due to the $10 million depreciation associated with the accelerated cost-recovery program for nuclear generating assets recognized during 2008, partially offset by the $5 million impact of depreciable asset base increases. The North Carolina jurisdictional aggregate minimum amount of accelerated cost

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recovery has been met and the South Carolina jurisdictional obligation was terminated by the Public Service Commission of South Carolina (SCPSC). PEC does not anticipate recording additional accelerated depreciation in the North Carolina jurisdiction, but will record depreciation over the remaining useful life of the assets.

Taxes other than on income

Taxes other than on income was $56 million for the three months ended September 30, 2009, which represents a $3 million increase compared to the same period in 2008. This increase is primarily due to an increase in gross receipts taxes due to higher operating 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 interest charges, net

Total interest charges, net was $45 million for the three months ended September 30, 2009, which represents a $5 million decrease compared to the same period in 2008. This decrease was primarily due to lower interest rates on variable rate debt, partially offset by higher interest as a result of higher average debt outstanding.

Income Tax Expense

Income tax expense increased $12 million for the three months ended September 30, 2009, as compared to the same period in 2008, primarily due to the $8 million impact of higher pre-tax income and the $5 million impact of changes in tax estimates.

Nine Months Ended September 30, 2009, Compared to Nine Months Ended September 30, 2008

REVENUES

PEC’s electric revenues for the nine months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions)	Nine Months Ended September 30,
Customer Class	2009			Change			% Change			2008
Residential	$	1,404		$	148			11.8		$	1,256
Commercial		926			64			7.4			862
Industrial		533			(22	)		(4.0	)		555
Governmental		85			7			9.0			78
Unbilled		(18	)		(8	)		–			(10	)
Total retail revenues		2,930			189			6.9			2,741
Wholesale		544			(22	)		(3.9	)		566
Miscellaneous		87			13			17.6			74
Total electric revenues		3,561			180			5.3			3,381
Less: Fuel and other pass-through revenues		(1,417	)		(188	)		–			(1,229	)
Revenues excluding fuel and other pass-through revenues	$	2,144		$	(8	)		(0.4	)	$	2,152

PEC’s revenues, excluding fuel and other pass-through revenues of $1.417 billion and $1.229 billion for the nine months ended September 30, 2009 and 2008, respectively, decreased $8 million. The decrease was primarily due to the $43 million unfavorable impact of net retail customer growth and usage, primarily in the industrial customer class, partially offset by the $23 million favorable impact of weather and $13 million higher miscellaneous revenues. 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 15,000 increase in the average number of customers for the nine months ended September 30, 2009, compared to the same period in 2008. However, PEC’s rate of residential growth has declined as PEC’s average number of customers for the nine months ended September 30, 2008, compared to the same period in 2007, increased a net 25,000 customers. The favorable impact of weather was driven by higher cooling and heating degree days than 2008. Additionally, cooling degree days were 8 percent higher than normal in 2009 compared to 2 percent higher than normal in 2008. Higher miscellaneous revenues were primarily due to higher point to point transmission sales.

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PEC’s electric energy sales for the nine months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2009			Change			% Change			2008
Residential		13,553			361			2.7			13,192
Commercial		10,528			(213	)		(2.0	)		10,741
Industrial		7,771			(1,002	)		(11.4	)		8,773
Governmental		1,137			32			2.9			1,105
Unbilled		(227	)		19			–			(246	)
Total retail kWh sales		32,762			(803	)		(2.4	)		33,565
Wholesale		10,542			(417	)		(3.8	)		10,959
Total kWh sales		43,304			(1,220	)		(2.7	)		44,524

Retail revenues increased for the nine months ended September 30, 2009, despite a decrease in retail kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates. The decrease in retail kWh sales for the nine months ended September 30, 2009, is primarily due to a decrease in average usage per retail customer. PEC’s industrial kWh sales have decreased 11.4 percent from 2008, primarily due to reductions in textile manufacturing in the Carolinas as a result of global competition and domestic consolidation as well as a downturn in the lumber and building materials segment as a result of declines in construction. However, sales to the chemical segment, now our largest industrial segment, have slightly increased. 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. While industrial kWh sales have decreased 11.4 percent from 2008, industrial revenues have only decreased 4.0 percent due in part to increased fuel revenues and the demand charges component of industrial revenues.

Wholesale kWh sales decreased for the nine months ended September 30, 2009, primarily due to decreased excess generation sales resulting from unfavorable market dynamics.

As previously discussed, PEC has been, and may continue to be, impacted by the current recession in the United States.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.478 billion for the nine months ended September 30, 2009, which represents a $185 million increase compared to the same period in 2008. Fuel used in electric generation increased $255 million to $1.282 billion primarily due to $156 million higher deferred fuel expense and the $99 million net impact of higher fuel costs. The increase in deferred fuel expense was primarily due to the implementation of new fuel rates in North Carolina. The higher fuel costs are primarily due to higher coal prices and the unfavorable impact of a change in generation mix, partially offset by lower system requirements. Purchased power expense decreased $70 million to $196 million compared to the same period in 2008 primarily due to lower co-generation of $42 million and lower market purchases of $36 million, primarily due to lower system requirements and fuel prices.

Operation and Maintenance

O&M expense was $767 million for the nine months ended September 30, 2009, which represents a $1 million increase compared to the same period in 2008. This increase is primarily due to $22 million higher net plant outage and maintenance costs, as a result of two nuclear refueling and maintenance outages in the current year compared to one in the prior year, offset by $16 million of targeted cost reductions and lower emission allowance expense of $12 million resulting from lower system requirements, generation mix and sales of nitrogen oxide (NOx) allowances.

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Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $355 million for the nine months ended September 30, 2009, which represents a $24 million decrease compared to the same period in 2008. Depreciation, amortization and accretion expense decreased primarily due to the $25 million of depreciation associated with the accelerated cost-recovery program for nuclear generating assets recognized during 2008 and the $15 million of Clean Smokestacks Act amortization recognized during 2008, partially offset by the $13 million impact of depreciable asset base increases. As previously discussed, PEC does not anticipate recording additional accelerated depreciation. 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 $161 million for the nine months ended September 30, 2009, which represents a $9 million increase compared to the same period in 2008. This increase is primarily due to an increase in gross receipts taxes due to higher operating 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.

Other

Other operating expenses consisted of losses of $2 million and gains of $6 million for the nine months ended September 30, 2009 and 2008, respectively. The prior year gain was primarily due to land sales.

Total Other Income, Net

Total other income, net was $22 million for the nine months ended September 30, 2009, which represents a $6 million decrease compared to the same period in 2008. This decrease is primarily due to lower interest income of $5 million, primarily due to lower balances on unrecovered deferred fuel, and losses on a balanced billing program of $5 million, partially offset by favorable AFUDC equity related to higher eligible construction project costs of $4 million.

Total interest charges, net

Total interest charges, net was $148 million for the nine months ended September 30, 2009, which represents an $8 million decrease compared to the same period in 2008. This decrease was primarily due to lower interest rates on variable rate debt, partially offset by higher interest as a result of higher average debt outstanding.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $177 million and $143 million for the three months ended September 30, 2009 and 2008, respectively. The increase in profits for the three months ended September 30, 2009, compared to the same period in 2008, was primarily due to the favorable impact of interim and limited base rate relief (See Note 4B), higher net impact of returns earned on higher levels of nuclear and ECRC assets to be recovered through respective cost-recovery clauses, and the favorable impact of weather, partially offset by the unfavorable impact of retail customer growth and usage.

PEF contributed segment profits of $384 million and $334 million for the nine months ended September 30, 2009 and 2008, respectively. The increase in profits for the nine months ended September 30, 2009, compared to the same period in 2008, was primarily due to the favorable impact of interim and limited base rate relief (See Note 4B), higher net impact of returns earned on higher levels of nuclear and ECRC assets to be recovered through respective cost-recovery clauses, the favorable impact of weather, favorable AFUDC equity, and the tax benefit resulting from the deduction related to nuclear decommissioning trust (NDT) funds, partially offset by the unfavorable impact of retail customer growth and usage and higher interest expense.

The revenue tables that follow present the total amount and percentage change of revenues excluding fuel and other pass-through revenues. Revenues excluding fuel and other pass-through revenues is defined as total electric revenues less fuel and other pass-through revenues. We and PEF consider revenues excluding fuel and other pass-through revenues a useful measure to evaluate PEF’s electric operations because fuel and other pass-through

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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. Pass-through revenues do not include the revenues associated with the return on asset component of nuclear cost-recovery and ECRC revenues, as these revenues will have an impact on reported earnings. We and PEF have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, revenues excluding fuel and other pass-through revenues is not defined under GAAP, and the presentation may not be comparable to other companies’ presentation or more useful than the GAAP information provided elsewhere in this report.

Three Months Ended September 30, 2009, Compared to Three Months Ended September 30, 2008

REVENUES

PEF’s electric revenues for the three months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions)	Three Months Ended September 30,
Customer Class	2009			Change			% Change			2008
Residential	$	806		$	83			11.5		$	723
Commercial		371			43			13.1			328
Industrial		85			3			3.7			82
Governmental		92			12			15.0			80
Unbilled		(2	)		4			–			(6	)
Total retail revenues		1,352			145			12.0			1,207
Wholesale		115			(60	)		(34.3	)		175
Miscellaneous		49			3			6.5			46
Total electric revenues		1,516			88			6.2			1,428
Less: Fuel and other pass-through revenues		(932	)		(15	)		–			(917	)
Revenues excluding fuel and other pass-through revenues	$	584		$	73			14.3		$	511

PEF’s revenues, excluding fuel and other pass-through revenues of $932 million and $917 million for the three months ended September 30, 2009 and 2008, respectively, increased $73 million. The increase was primarily due to the $40 million favorable impact of interim and limited base rate relief, the $37 million increased revenues related to nuclear cost recovery and ECRC assets, and the $7 million favorable impact of weather, partially offset by the $15 million unfavorable impact of retail customer growth and usage. The interim and limited base rate relief approved by the Florida Public Service Commission (FPSC) effective July 1, 2009, is expected to result in additional revenues of approximately $70 million in 2009 (See Note 4B). As a result of a FPSC regulatory order effective in January 2009, PEF is allowed to earn returns on certain costs related to nuclear construction, as discussed in Note 4B. In addition to lower average usage per customer, PEF’s average number of customers for the three months ended September 30, 2009, compared to the same period in 2008, decreased a net 8,000 customers. PEF’s net customer decline year over year was the same for the first three quarters of 2009.

PEF’s electric energy sales for the three months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Three Months Ended September 30,
Customer Class	2009		Change			% Change			2008
Residential		5,905		(188	)		(3.1	)		6,093
Commercial		3,405		(118	)		(3.3	)		3,523
Industrial		863		(118	)		(12.0	)		981
Governmental		872		(29	)		(3.2	)		901
Unbilled		52		256			–			(204	)
Total retail kWh sales		11,097		(197	)		(1.7	)		11,294
Wholesale		1,096		(848	)		(43.6	)		1,944
Total kWh sales		12,193		(1,045	)		(7.9	)		13,238

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The current recession and general housing downturn in the United States has continued to contribute to a slowdown in customer growth and usage in PEF’s service territory resulting in a 1.7 percent decrease in retail kWh sales for the three months ended September 30, 2009, compared to the same period in 2008. The impact of the general housing downturn was especially severe in several states, including Florida. Consequently, PEF’s residential kWh sales decreased 3.1 percent compared to the same period in 2008. We cannot predict how long the recession and housing downtown may last or the extent to which revenues may be impacted. In the future, PEF’s customer usage could be impacted by customer response to energy-efficiency programs and to increased rates.

Retail revenues increased for the three months ended September 30, 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, interim and limited base rate relief and the recovery of nuclear costs (see Note 4B).

Wholesale revenues decreased for the three months ended September 30, 2009, primarily due to decreased fuel revenues. Wholesale kWh sales decreased for the three months ended September 30, 2009, primarily due to market conditions under which wholesale customers fulfilled a portion of their system requirements from other sources.

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 $661 million for the three months ended September 30, 2009, which represents a $165 million decrease compared to the same period in 2008. Fuel used in electric generation increased $97 million to $618 million compared to the same period in 2008. This increase was primarily due to higher deferred fuel expense of $185 million driven by the implementation of new fuel rates, partially offset by decreased current year fuel costs of $87 million. The decrease in current year fuel costs was primarily due to lower natural gas prices. Purchased power expense decreased $262 million to $43 million compared to the same period in 2008 due to the $170 million impact of deferred capacity costs and a decrease in interchange purchases of $78 million resulting from lower system requirements. PEF’s deferred capacity costs were impacted by the reduction in capacity revenues due to PEF’s April 2009 election to defer the 2009 recovery of $198 million in nuclear pre-construction costs until 2010 (see Note 4B). In accordance with Florida’s nuclear cost-recovery rule, the variance in capacity revenues from projected revenues approved by the FPSC are deferred through deferred capacity costs within purchased power expense. Projected nuclear costs approved by the FPSC are recorded as nuclear cost amortization within depreciation, amortization and accretion expense. As a result of the FPSC’s clarification related to recognition of nuclear cost deferrals on October 16, 2009 (See Note 4B), during the three months ended September 30, 2009, PEF retrospectively assigned capacity revenues to match the FPSC-approved projected level of nuclear cost recovery. Accordingly, PEF recognized additional nuclear cost recovery for both amortization of and higher returns on unrecovered costs than had been previously recognized, partially offset by adjustments to previously recognized deferred capacity costs.

Operation and Maintenance

O&M expense was $198 million for the three months ended September 30, 2009, which represents a $3 million decrease when compared to the same period in 2008. O&M expense decreased $10 million due to the storm damage reserve replenishment surcharge that ended in July 2008, and the $9 million impact of a change in the vacation benefits policy, partially offset by the $13 million higher ECRC costs primarily due to the recovery of emission allowances. 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 decreased $7 million compared to the same period in 2008.

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Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $247 million for the three months ended September 30, 2009, which represents a $170 million increase compared to the same period in 2008. Depreciation, amortization and accretion expense increased primarily due to the $155 million higher nuclear cost-recovery amortization, which began in January 2009 in accordance with a 2008 regulatory order, as discussed above. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates increased $12 million compared to the same period in 2008, primarily due to depreciable asset base increases.

Taxes Other Than on Income

Taxes other than on income was $96 million for the three months ended September 30, 2009, which represents an $8 million increase compared to the same period in 2008. This increase is primarily due to an unfavorable increase in gross receipts and franchise taxes due to higher operating 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 $14 million for the three months ended September 30, 2009, which represents a $16 million decrease compared to the same period in 2008. This decrease was primarily due to lower AFUDC equity related to eligible construction project costs and increased clause recovery of certain nuclear financing costs.

Income tax expense

Income tax expense increased $29 million for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to the impact of higher pre-tax income.

Nine Months Ended September 30, 2009, Compared to Nine Months Ended September 30, 2008

REVENUES

PEF’s electric revenues for the nine months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions)	Nine Months Ended September 30,
Customer Class	2009			Change			% Change			2008
Residential	$	2,023		$	284			16.3		$	1,739
Commercial		990			138			16.2			852
Industrial		248			18			7.8			230
Governmental		258			41			18.9			217
Unbilled		28			8			–			20
Total retail revenues		3,547			489			16.0			3,058
Wholesale		327			(100	)		(23.4	)		427
Miscellaneous		138			5			3.8			133
Total electric revenues		4,012			394			10.9			3,618
Less: Fuel and other pass-through revenues		(2,542	)		(291	)		–			(2,251	)
Revenues excluding fuel and other pass-through revenues	$	1,470		$	103			7.5		$	1,367

PEF’s revenues, excluding fuel and other pass-through revenues of $2.542 billion and $2.251 billion for the nine months ended September 30, 2009 and 2008, respectively, increased $103 million. The increase was primarily due to the $52 million higher revenues related to nuclear cost recovery and ECRC assets discussed previously, the $47 million favorable impact of interim and limited base rate relief discussed previously, and the $26 million favorable impact of weather, partially offset by the $41 million unfavorable impact of retail customer growth and usage. The favorable impact of weather was primarily driven by 37 percent higher heating degree days than 2008. Heating degree days were 2 percent higher than normal in 2009 and 26 percent lower than normal in 2008.

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As discussed previously, PEF has experienced a slowdown in customer growth and usage in its service territory. In addition to lower average usage per customer, PEF’s average number of customers for the nine months ended September 30, 2009, compared to the same period in 2008, decreased a net 8,000 customers. In comparison, PEF’s average number of customers for the nine months ended September 30, 2008, compared to the same period in 2007, increased a net 2,000 customers.

PEF’s electric energy sales for the nine months ended September 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:

(in millions of kWh)	Nine Months Ended September 30,
Customer Class	2009		Change			% Change			2008
Residential		14,700		(154	)		(1.0	)		14,854
Commercial		8,907		(345	)		(3.7	)		9,252
Industrial		2,486		(369	)		(12.9	)		2,855
Governmental		2,409		(59	)		(2.4	)		2,468
Unbilled		740		248			–			492
Total retail kWh sales		29,242		(679	)		(2.3	)		29,921
Wholesale		3,108		(2,376	)		(43.3	)		5,484
Total kWh sales		32,350		(3,055	)		(8.6	)		35,405

Retail revenues increased for the nine months ended September 30, 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 nuclear cost-recovery revenues, as previously mentioned.

Wholesale revenues decreased for the nine months ended September 30, 2009, primarily due to decreased fuel revenues. Wholesale kWh sales decreased for the nine months ended September 30, 2009, primarily due to market conditions in which wholesale customers fulfilled a portion of their system requirements from other sources.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.976 billion for the nine months ended September 30, 2009, which represents a $5 million decrease compared to the same period in 2008. Fuel used in electric generation increased $338 million to $1.573 billion compared to the same period in 2008. This increase was primarily due to higher deferred fuel expense of $445 million driven by the implementation of new fuel rates, partially offset by decreased current year fuel costs of $107 million. The decrease in current year fuel costs is primarily due to lower system requirements. Purchased power expense decreased $343 million compared to the same period in 2008, primarily due to the $195 million current year impact of deferred capacity costs and a decrease in interchange purchases of $133 million primarily as a result of lower system requirements. PEF’s deferred capacity costs were impacted by the reduction in capacity revenues due to PEF’s previously discussed election to defer recovery of $198 million in nuclear pre-construction costs until 2010 (see Note 4B). In accordance with Florida’s nuclear cost-recovery rule, the variance in capacity revenues from projected revenues approved by the FPSC are deferred through deferred capacity costs within purchased power expense. Projected nuclear costs approved by the FPSC are recorded as nuclear cost amortization within depreciation, amortization and accretion expense.

Operation and Maintenance

O&M expense was $604 million for the nine months ended September 30, 2009, which represents a $17 million decrease when compared to the same period in 2008. O&M expense decreased $66 million due to the storm damage reserve replenishment surcharge that ended in July 2008 and $11 million lower expenses at distributions operations, primarily due to targeted cost reductions, partially offset by the $46 million higher ECRC costs primarily due to the recovery of emission allowances and higher pension costs of $18 million. The replenishment of storm damage reserves and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. Pension costs are higher due to a $15 million pension credit in the prior year. Substantially all of 2009’s pension expense has been deferred in accordance with an FPSC order (See Note 4B). In aggregate, O&M expenses recoverable through base rates decreased $4 million compared to the same period in 2008.

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Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $512 million for the nine months ended September 30, 2009, which represents a $283 million increase compared to the same period in 2008. Depreciation, amortization and accretion expense increased primarily due to higher nuclear cost-recovery amortization, as previously discussed. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates increased $17 million compared to the same period in 2008, primarily due to depreciable asset base increases.

Taxes Other Than on Income

Taxes other than on income was $264 million for the nine months ended September 30, 2009, which represents a $29 million increase compared to the same period in 2008. This increase is primarily due to an increase in gross receipts and franchise taxes due to higher operating 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.

Other

Other operating expenses of $7 million for the nine months ended September 30, 2009, compared to other operating income of $4 million for the same period in 2008, represents an $11 million change, primarily due to the $8 million regulatory disallowance of fuel costs (See Note 4B) and the $4 million prior year gain on land sales.

Total Other Income, Net

Total other income, net was $81 million for the nine months ended September 30, 2009, which represents a $10 million increase compared to the same period in 2008. This increase was primarily due to the $7 million of investment gains on certain employee benefit trusts resulting from improved financial market conditions and $7 million favorable AFUDC equity related to eligible construction project costs, partially offset by $5 million lower interest income resulting from lower short-term investment balances.

Total Interest Charges, net

Total interest charges, net was $173 million for the nine months ended September 30, 2009, which represents a $29 million increase compared to the same period in 2008. This increase was primarily due to higher interest as a result of higher average debt outstanding.

Income Tax Expense

Income tax expense increased $24 million for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the $29 million impact of higher pre-tax income and the $6 million impact of tax levelization, partially offset by the $11 million impact of the favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from the nonqualified NDT fund to the qualified NDT fund. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was decreased by $2 million and $8 million for the nine months ended September 30, 2009 and 2008, respectively, 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.

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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 business segment. Corporate and Other expense is summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2009			2008			2009			2008
Other interest expense	$	(64	)	$	(54	)	$	(183	)	$	(165	)
Contingent value obligations		3			–			11			(2	)
Tax levelization		2			1			(4	)		1
Other income tax benefit		28			18			66			59
Continuing income attributable to noncontrolling interests, net of tax		1			1			4			5
Other		(4	)		–			1			4
Corporate and Other after-tax expense	$	(34	)	$	(34	)	$	(105	)	$	(98	)

Other interest expense increased $10 million for the three months ended September 30, 2009, and $18 million for the nine months ended September 30, 2009, compared to the same periods in 2008. The increase for the three and nine months ended September 30, 2009, was primarily due to higher average debt outstanding at the Parent.

At September 30, 2009 and 2008, the contingent value obligations (CVOs) had fair values of approximately $23 million and $36 million, respectively, and average unit prices of $0.24 and $0.37 at September 30, 2009 and 2008, respectively. We recorded an unrealized gain of $3 million for the three months ended September 30, 2009, and no adjustment for the three months ended September 30, 2008, to record the changes in fair value of the CVOs. We recorded an unrealized gain of $11 million for the nine months ended September 30, 2009, and an unrealized loss of $2 million for the nine months ended September 30, 2008, to record the changes in fair value of the CVOs. See Note 15 in the 2008 Form 10-K for further information.

GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $2 million and $1 million for the three months ended September 30, 2009 and 2008, respectively, in order to maintain an effective rate consistent with the estimated annual rate. Income tax expense was increased by $4 million and decreased by $1 million for the nine months ended September 30, 2009 and 2008, respectively, in order to maintain an effective 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.

Other income tax benefit increased $10 million for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to the impact of changes in tax estimates and higher pre-tax expenses. Other income tax benefit increased $7 million for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to higher pre-tax expenses.

DISCONTINUED OPERATIONS

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our Synthetic Fuels subsidiaries and affiliates. As a result, during the three months ended September 30, 2009, we recorded a charge of $101 million to discontinued operations, which was net of a previously recorded indemnification liability (See Note 1C) and estimated tax impacts. The ultimate resolution of these matters could result in further adjustments to Synthetic Fuels earnings from discontinued operations. See Note 16C for additional information.

In 2008, we completed our business strategy of divesting of nonregulated businesses to reduce our business risk and focus on the core operations of the Utilities. During the nine months ended September 30, 2008, we recognized $67 million of income from discontinued operations, net of tax, which was comprised primarily of $48 million after-tax gains on sales of our coal terminals and docks in West Virginia and Kentucky (Terminals) and our remaining coal mining businesses (See Note 3).

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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. Our subsidiaries participate in internal money pools, administered by PESC, to more effectively utilize cash resources and reduce external 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 subsidiaries 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. During the nine months ended September 30, 2009, PEC paid dividends of $200 million to the Parent. During the nine months ended September 30, 2009, PEF received equity contributions of $465 million 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.

Cash from operations, commercial paper issuance, borrowings under our credit facilities, long-term debt financings, equity offerings, and/or 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, long-term debt maturities and common stock dividends for the remainder of 2009 and 2010. During the nine months ended September 30, 2009, net proceeds from our long-term debt issuances were $1.337 billion. For the fiscal year 2009, we expect to realize approximately $575 million in the aggregate from the sale of stock through marketed and ongoing equity sales of which $557 million was realized through September 30, 2009. These long-term debt and equity issuances helped provide additional liquidity support during the first half of 2009. (See discussion that follows under “Financing Activities.”)

We have 16 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. Due to conditions in the financial markets 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 revolving credit agreement (RCA) to reduce rollover

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risk in the commercial paper markets. We subsequently repaid $400 million of the borrowings, and at September 30, 2009, the Parent had $200 million of outstanding borrowings under its credit facility. In addition, at September 30, 2009, the Parent had issued $37 million of letters of credit and PEF had $50 million of outstanding commercial paper, which were supported by their respective RCAs. Based on these amounts outstanding at September 30, 2009, $1.743 billion was available for additional borrowings under our combined revolving credit facilities. Subsequent to September 30, 2009, the Parent repaid an additional $100 million of the outstanding balance under its revolving credit facility with proceeds from commercial paper borrowings. At November 6, 2009, the outstanding balance was $100 million.

Borrowings under our RCA during 2008, coupled with long-term debt and equity issuances in 2009, provided liquidity during a period of uncertain financial market conditions. We will continue to monitor the credit markets to maintain an appropriate level of liquidity.

At September 30, 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 September 30, 2009, the majority of the Utilities’ open financial commodity hedges were in net mark-to-market liability positions. See Note 12A for additional information with regard to our commodity derivatives.

At September 30, 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 September 30, 2009, the sum of the Parent’s open pay-fixed forward starting swaps were in a net mark-to-market liability position and the sum of PEC’s and PEF’s open pay-fixed forward starting swaps were both in net mark-to-market asset positions. See Note 12B for additional information with regard to our interest rate derivatives.

Our pension trust funds and NDT 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 increased $411 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $557 million increase in the recovery of deferred fuel costs due to higher fuel rates; a $161 million increase in the recovery of nuclear costs under Florida’s nuclear cost-recovery rule; $155 million receipt in 2009 of cash collateral previously posted with counterparties on derivative contracts; $118 million lower net income tax payments; and a $108 million payment made in 2008 to counterparties for collateral held associated with derivative contracts at our former synthetic fuels businesses. These impacts were partially offset by a $272 million decrease from accounts payable, largely driven by changes in fuel purchase costs and the timing of purchases and payments to vendors at the Utilities; a $249 million decrease from receivables; and $221 million in pension and other benefits contributions. 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.

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INVESTING ACTIVITIES

Net cash used by investing activities decreased by $71 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. This decrease was primarily due to a $116 million decrease in gross property additions, primarily due to lower spending for environmental compliance projects and completion of PEF’s Bartow Plant repowering project. The net decrease in gross property additions was partially offset by $63 million in proceeds received in 2008 from sales of discontinued operations and other assets, net of cash divested, which primarily included proceeds from the sale of Terminals and Coal Mining (See Notes 3A and 3B).

FINANCING ACTIVITIES

Net cash provided by financing activities decreased by $655 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to a $1.341 billion decrease in short-term indebtedness, primarily driven by commercial paper repayments and the Parent’s repayment of borrowings outstanding under its RCA; and a $460 million decrease in net proceeds from long-term debt issuances due to PEC’s $600 million issuance and the Parent’s $750 million issuance in 2009 compared to PEC’s $325 million issuance and PEF’s $1.500 billion issuance in 2008. These impacts were partially offset by a $477 million decrease in payments at maturity of long-term debt; and a $451 million increase in proceeds from the issuance of common stock, primarily related to the Parent’s January 2009 common stock offering. 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. Net proceeds from this offering were approximately $523 million. On February 3, 2009, the Parent used $100 million of the proceeds to reduce its $600 million RCA balance outstanding at December 31, 2008, and the remainder was used for general corporate purposes.

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 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 with the remaining proceeds used for general corporate purposes.

On June 18, 2009, PEC entered into a Seventy-seventh Supplemental Indenture to its Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, in connection with certain amendments to the mortgage. The amendments are set forth in the Seventy-seventh Supplemental Indenture and include an amendment to extend the maturity date of the mortgage by 100 years. The maturity date of the mortgage is now May 1, 2140.

During the third quarter of 2009, the Parent reduced its outstanding RCA balance by $300 million with cash on hand, resulting in an outstanding balance of $200 million at September 30, 2009. Subsequent to September 30, 2009, the Parent repaid an additional $100 million of the outstanding balance with proceeds from commercial paper borrowings. At Novemer 6, 2009, the outstanding balance of the RCA loan was $100 million. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining 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 approximately 264 million were outstanding. For the nine months ended September 30, 2009, we issued approximately 15.8 million shares of common stock resulting in approximately $557 million in net proceeds. Included in these amounts were the previously discussed 14.4 million shares issued in a public offering in January 2009 for net proceeds of approximately $523 million. For the nine months ended September 30, 2008, we issued approximately 3.0 million shares of common stock resulting in approximately $106 million in proceeds, primarily to meet the requirements of the Progress Energy 401(k) Savings & Stock Ownership Plan and the Investor Plus Stock Purchase Plan.

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FUTURE LIQUIDITY AND CAPITAL RESOURCES

At September 30, 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 “Regulatory Matters and Recovery of Costs” and “Financing Activities.”

The Utilities produce substantially all of our consolidated cash flows 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 September 30, 2009, we have carried forward $769 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 discussed above under “Overview,” the Parent borrowed $600 million under its RCA and repaid $400 million of the outstanding balance with proceeds from the January 2009 equity issuance and cash on hand. Subsequent to September 30, 2009, the Parent repaid an additional $100 million of the outstanding balance with proceeds from commercial paper borrowings. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining $100 million balance of the RCA loan, while maintaining an appropriate level of liquidity. If liquidity conditions deteriorate 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 additional borrowings under our RCAs, issuing short-term notes and/or issuing long-term debt.

Progress Energy and its subsidiaries have approximately $11.506 billion in outstanding long-term debt. Currently, approximately $860 million of the Utilities’ debt obligations, consisting of approximately $620 million at PEC and approximately $240 million at PEF, are tax-exempt auction rate securities. These tax-exempt bonds have and continue to experience failed auctions. 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-. The Utilities’ senior secured debt ratings are currently A1 by Moody’s Investors Service, Inc. (Moody’s) and A- by Standard and Poor’s Rating Services (S&P). We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

As discussed in Note 4B, on October 27, 2009, the FPSC held a hearing to determine if the voting of pending rate cases should be delayed until new FPSC appointees take office in January 2010. During the hearing, the FPSC voted to delay the rulings until January 2010. Both S&P and Moody’s have indicated that the FPSC’s decision to delay a decision on PEF’s pending base rate case into 2010 could harm the credit quality of the Parent, PEF, and, with respect to S&P, PEC. Both ratings agencies noted that the FPSC action implies that a reconstituted commission may accommodate the heightened political atmosphere that has developed around the regulatory process. S&P indicated that any rating or outlook revisions would be premature at this time and that it would analyze the final rate decisions and PEF's plans in response to the decision to determine the projected financial effects and how that may affect its consolidated business risk profile. Moody’s has not indicated if or when it may take any action, but noted that the political and regulatory environment surrounding PEF’s rate case increases the possibility of a rate case outcome that is negative to PEF’s credit quality. The ultimate action, if any, taken by S&P or Moody’s with respect to the credit ratings of the Parent, PEF or PEC cannot be determined. However, a downgrade in either outlook or rating would likely result in an increase in borrowing costs and more limited financial flexibility.

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

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obligations under our defined benefit pension plans. In 2009, contributions directly to our pension plan assets are expected to approximate $222 million, including $163 million for PEC and $58 million for PEF, substantially all of which were made in the third quarter of 2009 (See Note 11).

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 – 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/or 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 the commercial operation of its proposed nuclear plant in Levy County, Fla. (Levy), to shift later than the 2016 to 2018 timeframe by a minimum of 20 months, 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 consumption of the fuel, any realized gains or losses are passed through the fuel cost-recovery clause. Changes in natural gas prices and settlements of financial hedge agreements since December 31, 2008, have impacted the amount of collateral posted with counterparties. At September 30, 2009, we had posted approximately $185 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.

On August 3, 2009, Moody’s raised the senior secured debt rating of both PEC and PEF to A1 from A2 as a result of Moody’s reevaluating its notching criteria for investment-grade regulated utilities to reflect the historical lower default rates for regulated utilities than for non-financial, non-utility corporate issuers.

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 15 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, DSM and energy efficiency.

PEC Cost-Recovery Clause

On May 7, 2009, PEC filed with the SCPSC for a decrease in the fuel rate charged to its South Carolina ratepayers. On June 19, 2009, the SCPSC approved a settlement agreement filed jointly by PEC and the South Carolina Office of Regulatory Staff (ORS) and Nucor Steel. Under the terms of the settlement agreement, the parties agreed to PEC’s proposed rate reduction of approximately $13 million. The decrease was effective July 1, 2009, and decreased residential electric bills by $2.08 per 1,000 kWh, or 2.0 percent, for fuel cost recovery.

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On June 4, 2009, PEC filed with the North Carolina Utilities Commission (NCUC) for a decrease in the fuel rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $14 million decrease in the fuel rates driven by declining fuel prices. If approved, the decrease would take effect December 1, 2009, and would decrease residential electric bills by $0.45 per 1,000 kWh, or 0.4 percent, for fuel cost recovery. A hearing on the matter was held on September 15, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter.

PEC Other Matters

As discussed in Note 4 and in “Other Matters – Environmental Matters,” on October 22, 2009, the NCUC issued an order granting PEC a certificate of public convenience and necessity to construct a 950-MW combined cycle natural gas-fueled electric generating facility at a site in Wayne County, N.C., to replace three coal-fired generating units at the site that have a combined generating capacity of approximately 400 MW. We anticipate continuing to depreciate the three coal-fired units at their current depreciation rate until PEC’s next depreciation study. PEC projects that the generating facility would be in service by January 2013. We currently estimate that capital expenditures, net of AFUDC – borrowed funds for the new generating facility will be approximately $800 million. PEC modified its Clean Smokestacks Act compliance plan for the change in fuel source and removed retrofitting PEC’s Sutton Plant with emission-reduction technology from the plan. Accordingly, PEC filed a revised estimate with the NCUC, which decreased estimated capital expenditures to meet the Clean Smokestacks Act emission targets by 2013 to $1.1 billion from $1.4 billion. We are continuing to evaluate various design, technology, generation and fuel options, including retiring some coal-fired plants that could change expenditures required to maintain compliance with the Clean Smokestacks Act limits subsequent to 2013.

PEF Base Rates

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.

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 Plant, which began commercial operations in June 2009. On May 19, 2009, the FPSC approved both the annualized interim base rate increase and the cost recovery for the repowered Bartow Plant subject to refund with interest effective July 1, 2009. The interim and limited base rate relief increased revenues by $47 million during the nine months ended September 30, 2009, and are expected to result in total increases to revenues of approximately $70 million for 2009. The changes increased residential bills by approximately $4.52 per 1,000 kWh, or 3.7 percent. On July 2, 2009, Florida’s Office of Public Counsel (OPC), the Florida Industrial Power Users Group, the Attorney General, the Florida Retail Federation and PCS Phosphate filed a petition protesting portions of the FPSC approval. On August 31, 2009, the FPSC issued an order to consolidate the interim and limited base rate relief increase and base rate proposal. We cannot predict the outcome of this matter.

If PEF’s remaining rate request is approved by the FPSC as filed by PEF, the new base rates would increase residential bills by approximately $9.66 per 1,000 kWh, or 7.6 percent, effective January 1, 2010. A hearing was held on this matter September 21, 2009 – October 1, 2009. On October 27, 2009, the FPSC held a hearing to determine if the voting of pending rate cases should be delayed until new FPSC appointees take office in January 2010. During the hearing, the FPSC voted to delay the rulings until January 2010.  In response to this delay and in lieu of implementing PEF's proposed base rates subject to refund, PEF filed a motion with the FPSC on November 2, 2009, to establish a regulatory asset (or liability) for the incremental rate relief not recovered between January 1, 2010, and when new rates become effective, expected to be March 1, 2010.  If PEF's petition is approved, the regulatory asset (or liability) would be recovered, plus interest at the commercial paper rate, through a rate adjustment commencing March 1, 2010, through the remainder of the calendar year. We cannot predict the outcome of this matter.

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PEF Cost-Recovery Clauses

On March 17, 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 reduced residential customers’ fuel charges by $6.90 per 1,000 kWh, or 5.0 percent, starting with the first billing cycle of April 2009, with similar reductions for commercial and industrial customers.

In 2007, the FPSC ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for Crystal River Units No. 4 and 5 (CR4 and CR5). On June 30, 2009, the FPSC approved a refund of $8 million to PEF’s ratepayers to be paid over a 12-month period beginning January 1, 2010, and ordered PEF to file a report by September 2009 regarding the prospective application of PEF’s coal procurement plan and the prudence of PEF’s coal procurement actions. In compliance with the FPSC order, PEF filed the coal procurement status report on September 14, 2009. PEF chose not to appeal this decision.

On September 14, 2009, PEF filed a request with the FPSC to seek approval of a cost adjustment to reduce fuel costs, thereby decreasing residential electric bills by $3.34 per 1,000 kWh, or 2.6 percent, effective January 1, 2010. On October 23, 2009, PEF filed a cost adjustment with the FPSC, which reduced the capacity cost-recovery clause (CCRC) rate by $0.08 per 1,000 kWh from the original September 14, 2009 cost adjustment filing. The FPSC approved PEF's fuel and capacity clause filings on November 2, 2009.

In addition, on August 28, 2009 and as updated on October 27, 2009,  PEF filed a request to increase the Environmental Cost Recovery Clause (ECRC) residential rate by $2.25 per 1,000 kWh, or 1.8 percent. The FPSC approved PEF's ECRC clause filing on November 2, 2009.

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. 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 CCRC. 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. As discussed in Note 4, on October 16, 2009, the FPSC clarified certain implementation policies related to the recognition of deferrals and the application of carrying charges under the nuclear cost-recovery rule.

On March 17, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear pre-construction costs for Levy, which the FPSC had authorized to be collected in 2009. The approval reduced residential customers’ nuclear cost-recovery charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first billing cycle of April 2009, with similar reductions for commercial and industrial customers.

On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million through the CCRC, which primarily consists of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 and 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 proposed collecting certain costs over a five-year period, with associated carrying costs on the unrecovered balance. This alternate proposal reduced the 2010 revenue requirement to $236 million. On September 14, 2009, consistent with FPSC rules, PEF included both proposed revenue requirements in its CCRC filing, which would result in a nuclear cost-recovery charge of either $7.98 per 1,000 kWh for residential customers under PEF’s alternate proposal, or $15.07 per 1,000 kWh if the FPSC

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did not approve PEF’s alternate proposal. At a special agenda hearing by the FPSC on October 16, 2009, the FPSC approved the alternate proposal allowing PEF to recover $207 million through the nuclear cost-recovery clause of the CCRC beginning with the first billing cycle of January 2010. The remainder, with minor adjustments, will also be recovered through the CCRC. This revenue level results in a nuclear cost-recovery charge of $6.99 per 1,000 kWh, which represents a $2.68 increase per 1,000 kWh for residential customer bills. In adopting PEF’s proposed rate plan for 2010, the FPSC permitted PEF to annually reconsider changes to the recovery of deferred amounts to afford greater flexibility to manage future rate impacts.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

At September 30, 2009, our guarantees have not changed materially from the information 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 12 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. Contingencies and significant changes, if any, to our and the Utilities contractual cash obligations and other commercial commitments from what was reported in Note 22 in the 2008 Form 10-K are described below.

PEC

In October 2009, PEC entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs for the period from July 2012 through August 2032. The total cost to PEC associated with these agreements is estimated to be approximately $1.0 billion. These agreements are subject to several conditions precedent, including various federal regulatory approvals, the completion and commencement of operation of necessary related interstate and intrastate natural gas pipeline system expansions, and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEC’s fuel and purchased power commitments.

PEF

On May 1, 2009, PEF announced 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 for the commercial operation of Levy to shift later than 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, if any, such amendment might have on the project’s total cost. However, consistent with nuclear cost-recovery filings with the FPSC (See Note 4B), PEF anticipates that approximately $1 billion of the contractual cash obligations for the three-year period following December 31, 2008, disclosed in the 2008 Form 10-K, could be deferred to later periods as a result of the schedule shift. Refer to “Other Matters – Nuclear” below for further discussion of the Levy nuclear project.

During the second quarter of 2009, PEF entered into conditional agreements for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with these agreements is estimated to be approximately $281 million. These agreements are subject to

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several conditions precedent, including various federal regulatory approvals, the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions, and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEF’s fuel and purchased power commitments.

OTHER MATTERS

GOODWILL

Goodwill is required to 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 our goodwill impairment tests are performed at the utility segment level. The carrying amounts of goodwill at September 30, 2009 and December 31, 2008, for reportable segments PEC and PEF, were $1.922 billion and $1.733 billion, respectively. We perform our annual impairment tests as of April 1 each year. During the second quarter of 2009, we completed the 2009 annual tests, which indicated the goodwill was not impaired. If the fair value of PEC had been lower by 10 percent and the fair value of PEF had been lower by 7.5 percent, there still would be no impact on the reported value of their goodwill.

We calculate the fair value of our utility segments by considering various factors, including valuation studies based primarily on income and market approaches. More emphasis is applied to the income approach as substantially all of the utility segments’ cash flows are from rate-regulated operations. In such environments, revenue requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, the utility segments operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions.

The income approach uses discounted cash flow analyses to determine the fair value of the utility segments. The estimated future cash flows from operations are based on the utility segments’ business plans, which reflect management’s assumptions related to customer usage based on internal data and economic data obtained from third party sources. The business plans assume the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, the timing of anticipated significant future capital investments, the anticipated earnings and returns related to such capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also determines the appropriate discount rate for the utility segments based on the weighted average cost of capital for each utility, which takes into account both the cost of equity and pre-tax cost of debt. As each utility segment has a different risk profile based on the nature of its operations, the discount rate for each reporting unit may differ.

The market approach uses implied market multiples derived from comparable peer utilities and market transactions to estimate the fair value of the utility segments. Peer utilities are evaluated based on percentage of revenues generated by regulated utility operations; percentage of revenues generated by electric operations; generation mix, including coal, gas, nuclear and other resources; market capitalization as of the valuation date; and geographic location. Comparable market transactions are evaluated based on the availability of financial transaction data and the nature and geographic location of the businesses or assets acquired, including whether the target company had a significant electric component. The selection of comparable peer utilities and market transactions, as well as the appropriate multiples from within a reasonable range, is a matter of professional judgment.

The calculations in both the income and market approaches are highly dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates from a marketplace participant’s perspective, and the selection of peer utilities and marketplace transactions for comparative valuation purposes. These underlying assumptions and estimates are made as of a point in time. If these assumptions change or should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, the fair value of the utility segments could be significantly different in future periods, which could result in a future impairment charge to goodwill.

As an overall test of the reasonableness of the estimated fair values of the utility segments, we compared their combined fair value estimate to Progress Energy’s market capitalization as of April 1, 2009. The analysis confirmed that the fair values were reasonably representative of market views when applying a reasonable control premium to the market capitalization.

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We monitor for events or circumstances, including financial market conditions and economic factors, that may indicate an interim goodwill impairment test is necessary. We would perform an interim impairment test should any events occur or circumstances change that would more likely than not reduce the fair value of a utility segment below its carrying value.

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 Corporation (Florida Progress) prior to our acquisition) were $1.891 billion, of which $1.122 billion has been used through September 30, 2009, to offset regular federal income tax liability and $769 million is being carried forward as deferred tax credits.

See Note 16C 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 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 $3.4 billion in Smart Grid technology development grants, $615 million for Smart Grid storage, monitoring and technology viability, $6.3 billion for energy-efficiency and conservation grants and $2 billion in tax credits for the purchase of plug-in electric vehicles. In August 2009, we submitted our application to the United States Department of Energy (DOE) for $200 million in federal matching infrastructure funds in support of our investment in Smart Grid-related technologies in the Carolinas and Florida. On October 27, 2009, the DOE notified us of our selection for Smart Grid award negotiations. We are now awaiting further questions and comments from the DOE on our Smart Grid application. The submission of an application and the notification for award negotiations is not a commitment to accept federal funds but is a necessary step to keep the option open. We are currently evaluating the provisions of the law and assessing the conditions imposed by participation in the incentive programs. Also, the Obama administration has announced a goal of encouraging investment in transmission and promoting renewable resources while also pricing greenhouse gas (GHG) emissions and setting a federal requirement for renewable energy.

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On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009. This bill would establish a national cap-and-trade program to reduce GHG emissions as well as a national renewable energy portfolio standard (REPS). The bill also calls for investment in the electric grid, more production and utilization of electric vehicles and improvements in energy efficiency in buildings and appliances. The full impact of the legislation if enacted into law cannot be determined at this time and will depend upon changes made to its provisions during the legislative process and the manner in which key provisions are implemented, including the regulation of carbon. The U.S. Senate is considering similar proposals. The full impact of final legislation, if enacted, and additional regulation resulting from other federal GHG initiatives cannot be determined at this time; however, we anticipate that it could result in significant rate increases over 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.

On July 31, 2009, the governor of North Carolina signed into law a bill that includes three key provisions that may impact PEC. First, the legislation accelerates the certification process for a public utility to construct a new natural gas plant as long as the public utility permanently retires the existing coal unit at that specific site. Pursuant to the legislation, PEC requested and received approval from the NCUC to pursue construction of a new natural gas plant (see further discussion in Note 4A and “Other Matters – Environmental Matters”). Second, a recovery mechanism is provided for utilities if they invest in zero emissions renewable energy facilities within the next five years. Finally, the legislation changes the state’s Dam Safety Act such that dams at utility coal-fired power plants, including dams for ash ponds, will, as of January 1, 2010, be subject to the Act’s applicable provisions, including state inspection.

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 GHG 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 these agency actions are finalized, 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 GHG emissions. The executive orders call for the first southeastern state cap-and-trade program and include adoption of a maximum allowable emissions level of GHGs 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. To date, the FDEP has held three rulemaking workshops on the GHG cap-and-trade rulemaking. 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 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, but the legislature did not take action in the 2009 session. 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 “Energy Demand,” includes greater investment in energy efficiency, renewable energy and state-of-the-art generation and demonstrates our commitment to environmental responsibility.

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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. PEC has implemented a series of DSM and energy-efficiency programs and will continue to pursue additional programs. These programs must be approved by the NCUC, and we cannot predict the outcome of filings currently pending approval by the NCUC or whether the implemented 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 16C.

ENERGY DEMAND

Implementing state and federal energy policies, promoting environmental stewardship and providing reliable electricity to meet 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 programs and initiatives that shift the timing of electricity use from peak to nonpeak periods, such as load management, electricity system and operating controls, direct load control, interruptible load, and electric system equipment and operating controls. We provide our residential customers with home energy audits and offer energy-efficiency programs that provide incentives for customers to implement measures that reduce energy use. For business customers, we also provide energy audits and other tools, including an interactive Internet Web site with online calculators, programs and efficiency tips, to help them reduce their energy use.

We are actively engaged in a variety of alternative energy projects to pursue the generation of electricity from swine waste and other plant or animal sources, biomass, solar, hydrogen and landfill-gas technologies. Among our projects, we have executed contracts to purchase approximately 300 MW of electricity generated from biomass and 60 MW of electricity generated from municipal solid waste sources. The majority of these projects should be online within the next five years. In addition, we have executed purchased power agreements for 9 MW of electricity generated from solar photovoltaic generation. The majority of these projects are online and the remainder should be online by early 2010. We will continue to pursue solar projects and expect to add additional projects before year end. Additionally, in June 2009, we expanded our solar energy strategy to include a range of new residential and commercial solar incentives and programs, which are expected to increase our use of solar energy by more than 100 MW over the next decade.

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. 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 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.

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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 GHG 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.

CR3 is currently undergoing an extended outage for normal refueling and maintenance as well as a project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a gap within the concrete of the outer wall of the containment structure. Engineers are assessing the extent and cause of the gap to determine the repairs that would be required to return CR3 to service. Due to the early stage of the assessment process, PEF cannot currently predict to what extent the repair of the gap will impact its operations and financial condition. However, depending on the results of the assessment process, CR3’s current outage could be extended and the costs to repair the gap and associated costs of an outage extension, such as fuel, purchased power and maintenance, could be material.

The NRC operating licenses for PEC’s nuclear units expire between 2030 and 2046. The NRC operating license held by PEF for 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.

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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, which included 11 contentions, was filed with the NRC within the 60-day notice period by the North Carolina Waste Awareness and Reduction Network. The Atomic Safety and Licensing Board (ASLB) admitted one of the contentions and PEC appealed. Upon review by the NRC, the contention was remanded to the ASLB for reconsideration of admissibility on May 18, 2009. On remand, the ASLB ruled on June 30, 2009, that the contention was not admissible and denied the petition to intervene. On July 22, 2009, the petitioner requested that the NRC reconsider the ASLB’s decision on all 11 contentions. PEC filed its brief in response on August 3, 2009. 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 “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 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. Certification addresses permitting, land use and zoning, and property interests and replaces state and local permits. Certification grants approval for the location of the power plant and its associated facilities such as roadways and electrical transmission lines carrying power to the electrical grid, among others. Certification does not include licenses required by the federal government. On January 12, 2009, the FDEP filed a favorable staff analysis report in advance of certification hearings. The technical proceedings concluded on March 12, 2009, and the administrative law judge issued a recommended order on certification on May 15, 2009. The Power Plant Siting Board, comprised of the governor and the Cabinet, issued the Levy certification on August 11, 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 joint petition to intervene in the licensing proceeding was filed with the NRC within the 60-day notice period by the Green Party of Florida, the Nuclear Information and Resource Service and the Ecology Party of Florida. On April 20-21, 2009, the ASLB heard oral arguments on whether any of the joint interveners’ proposed contentions will be admitted in the Levy COL proceeding. On July 8, 2009, the ASLB issued a decision accepting three of the 12 contentions submitted. The admitted contentions involved questions about the storage of low-level radioactive waste, how construction would affect the aquifer in the area and Levy’s use and disposal of salt water. PEF filed an appeal of the ASLB’s decision on July 20, 2009. A hearing on the contentions will be conducted in the future. Other COL applicants have received similar petitions raising similar potential contentions. We cannot predict the outcome of this matter.

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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. However, earlier in 2009, the NRC Staff has determined 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 for the commercial operation of Levy to shift later than the 2016 to 2018 timeframe by a minimum of 20 months.

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. We anticipate amending the EPC agreement due to the schedule shift previously discussed but cannot predict the impact such amendment might have on the project’s cost, if any.

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 CCRC. 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 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.

In 2008, PEF sought and received approval from the FPSC to recover Levy pre-construction and carrying charges of $357 million as well as site selection costs of $38 million through the 2009 CCRC. In 2009, PEF received approval to defer until 2010 the recovery of $198 million of these costs (See Note 4B). On October 16, 2009, the FPSC approved the recovery of $201 million of pre-construction costs and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with Levy as part of the total $207 million FPSC-approved recovery of nuclear costs through the 2010 CCRC (See Note 4B).

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 inclusion of construction work in progress in rate base with corresponding rate adjustment in a general rate case while a baseload generating plant is under construction (See “Other Matters – Regulatory Environment”).

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SPENT NUCLEAR FUEL MATTERS

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. We have a contract with the DOE for the future storage and disposal of our spent nuclear fuel. Delays have occurred in the DOE’s proposed permanent repository to be located at Yucca Mountain, Nev. The DOE has stated that the earliest date the repository may be able to start accepting spent nuclear fuel is 2020. However, the 2010 federal budget largely eliminates funding for the Yucca Mountain facility while the administration devises a new strategy toward nuclear waste disposal. Debate surrounding any new strategy likely will address centralized interim storage, permanent storage at multiple sites and/or spent nuclear fuel reprocessing. We cannot predict the outcome of this matter.

The NRC has 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 permanent 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. We cannot predict the outcome of this matter.

On September 15, 2009, the NRC proposed licensing requirements for storage of spent nuclear fuel, which would clarify the term limits for specific licenses for independent spent fuel storage installations and for certificates of compliance for spent nuclear fuel storage casks. The agency proposal would formalize the site-by-site exemption the NRC has used for renewal applications requesting more than the current 20-year duration. The initial and renewal terms of a specific installation license would be effective for a period of up to 40 years. Similarly, the proposed rule would allow applicants for certificates of compliance to request initial and renewal terms of up to 40 years, provided they can demonstrate that all design requirements are satisfied for the requested term. We cannot predict the outcome of this matter.

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 (Robinson), Brunswick Nuclear Plant (Brunswick) 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 16C 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

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations.

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the 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 15). Both PEC and PEF evaluate potential claims

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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 15A.

As discussed in “Other Matters – Regulatory Environment,” on July 31, 2009, the governor of North Carolina signed into law a bill that changed the state’s Dam Safety Act such that dams at utility coal-fired power plants, including dams for ash ponds, will, as of January 1, 2010, be subject to the Act’s applicable provisions, including state inspection. Until the state agency responsible for dam safety inspects each of the affected dams, we cannot predict if additional safety-related measures will be required. However, these dams have been subject to periodic third-party inspection in accordance with prior applicable requirements.

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 any new regulations are finalized.

In June 2009, the EPA posted a listing of 44 utility ash ponds that are considered to have “high hazard potential,” including two of PEC’s ash ponds. A “high hazard potential” rating is not related to the stability of those ash ponds but to the potential for harm should the impoundment fail. As noted above, all of the dams at PEC’s coal ash ponds have been subject to periodic third-party inspection. In September 2009, the EPA rated the 44 “high hazard potential” impoundments, as well as other impoundments, from “unsatisfactory” to “satisfactory” based on their structural integrity.

Only impoundments rated as “unsatisfactory” would be considered to pose an immediate safety threat, but none of the facilities received an “unsatisfactory” rating. In total, six of PEC’s ash ponds, including one “high hazard potential” impoundment, were rated as “poor” based on the contract inspector’s desire to see additional documentation and several recommendations for vegetation management and minor erosion control. Inspectors applied the same criteria to both active and inactive ash ponds, despite the fact that most of the inactive ash impoundments no longer hold water and do not pose a risk of breaching and spilling. PEC has completed several of the recommendations for the active ponds and other recommendations are scheduled to be completed by the end of 2009. We are working with the Dam Safety Act program to evaluate the remaining recommendations. We do not expect mitigation of these issues to have a material impact on our results of operations.

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 nitrogen oxides (NOx), SO2, carbon dioxide (CO2) and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national 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 regulations, 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.

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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. As discussed in “Other Matters – Regulatory Environment,” North Carolina enacted a law in July 2009 that abbreviates the certification process for a public utility to construct a new natural gas plant as long as the public utility permanently retires the existing coal units at that specific site. The law gives PEC the option to seek certification, construct a new natural gas plant and retire existing coal units, with resulting reduced emissions, in time to comply with the Clean Smokestacks Act’s 2013 emission targets. As discussed in Note 4 on October 22, 2009, the NCUC issued an order granting PEC a certificate of public convenience and necessity to construct a 950-MW combined cycle natural gas-fueled electric generating facility at a site in Wayne County, N.C., to replace three coal-fired generating units at the site that have a combined generating capacity of approximately 400 MW. PEC projects that the generating facility would be in service by January 2013. The NCUC included a condition that PEC submit for NCUC approval a plan to retire additional coal-fired capacity reasonably proportionate to the amount of incremental capacity above 400 MW. PEC modified its Clean Smokestacks Act compliance plan for the change in fuel source and removed retrofitting PEC’s Sutton Plant with emission-reduction technology from the plan. Accordingly, PEC filed a revised estimate with the NCUC totaling $1.1 billion of capital expenditures to meet the Clean Smokestacks Act emission targets. We are continuing to evaluate various design, technology, generation and fuel options, including retiring some coal-fired plants that could change expenditures required to maintain compliance with the Clean Smokestacks Act limits subsequent to 2013.

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. PEC is allowed to recover the cost of reagents and certain other costs under its fuel clause; 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 15B).

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.

The air quality controls installed to comply with the requirements of the NOx State Implementation Plan Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) and Clean Smokestacks Act, as well as plans to replace a portion of PEC’s coal-fired generation with gas-fueled generation, largely address the CAIR requirements for our North Carolina units at PEC. PEF anticipates it will meet the 2009 phase requirements of CAIR for NOx with a combination of emission reductions generated by in-service emission control equipment and emission allowances.

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.

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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 schedule for the commercial operation of Levy to shift later than the 2016 to 2018 timeframe by a minimum of 20 months. PEF is required to advise the FDEP of any developments that will delay the retirement of CR1 and CR2 beyond the originally 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 (MACT) 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 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, 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 State Implementation Plan Call Rule under Section 110 of the Clean Air Act (NOx SIP Call) and Clean Smokestacks Act, as well as plans to replace a portion of PEC’s coal-fired generation with gas-fueled generation, resulted in a reduction of the costs to meet the CAIR requirements for our North Carolina units at PEC.

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PEC has completed installation of controls to meet the NOx SIP Call requirements. The NOx SIP Call is not applicable to 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 April 1, 2009 filing with the FPSC for true-up of final 2008 environmental costs 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. As discussed in Note 4, on August 28, 2009, PEF filed for recovery of costs through the ECRC, and the FPSC approved PEF’s filing on November 2, 2009. 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.

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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 September 30, 2009
Clean Smokestacks Act(a)		2002 – 2013	$	1,100	$	1,046
In-process CAIR projects(b)		2005 – 2010		1,200		1,033
CAVR(c)		– 2017		–		–
Mercury regulation(d)		2006 – 2017		–		5
Total air quality				2,300		2,084
Clean Water Act Section 316(b)(e)				–		–
Total air and water quality			$	2,300	$	2,084

PEC
Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2009
Clean Smokestacks Act(a)		2002 – 2013	$	1,100	$	1,046
In-process CAIR projects(b)		2005 – 2008		–		–
CAVR(c)		– 2017		–		–
Mercury regulation(d)		2006 – 2017		–		5
Total air quality				1,100		1,051
Clean Water Act Section 316(b)(e)				–		–
Total air and water quality			$	1,100	$	1,051

PEF
Air and Water Quality Estimated Required Environmental Expenditures (in millions)	Estimated Timetable		Total Estimated Expenditures		Cumulative Spent through September 30, 2009
In-process CAIR projects(b)		2005 – 2010	$	1,200	$	1,033
CAVR(c)		– 2017		–		–
Mercury regulation(d)				–		–
Total air quality				1,200		1,033
Clean Water Act Section 316(b) (e)				–		–
Total air and water quality			$	1,200	$	1,033

(a) PEC is continuing to evaluate various design, technology and new generation options that could change expenditures required to maintain compliance with the Clean Smokestacks Act limits subsequent to 2013.

(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.

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To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects under construction at CR5 and CR4, which are expected to be placed in service in 2009 and 2010, respectively. As a result of changes in the scope of work related to estimation of costs for compliance with the CAIR and the 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 fossil fuel-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 Ambient Air Quality Standards (NAAQS) 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. In 2009, the D.C. Court of Appeals remanded the EPA’s denial to the agency for reconsideration. The outcome of the remand proceeding cannot be predicted.

National Ambient Air Quality Standards

In 2006, the EPA announced changes to the 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 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. Additional nonattainment areas may be designated in PEC’s and PEF’s service territories as a result of these revised standards. 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 requested the D.C. Court of Appeals to suspend proceedings in the case while the EPA evaluates whether to maintain, modify or otherwise reconsider the revised NAAQS. In September 2009, the EPA announced that it is reconsidering the level of the ozone NAAQS. The EPA originally indicated plans to designate nonattainment areas for these standards by March 2010. However, the EPA announced that it will stay those designations until after its reconsideration has been completed. Designations are now scheduled to be completed by August 2011. Should additional nonattainment areas be designated in our service territories, we may be required to install additional emission controls at some of our facilities. The outcome of this matter cannot be predicted.

On June 29, 2009, the EPA announced a proposed revision to the primary NAAQS for nitrogen dioxide. Since 1971, when the first NAAQS were promulgated, the standard for nitrogen dioxide has been an annual average of 53 parts per billion. The EPA is proposing to retain the annual standard and add a new 1-hour NAAQS of between 80 and 100 parts per billion. In conjunction with proposing changes to the standard, the EPA is also proposing to increase the coverage of the monitoring network, particularly near roadways where the highest concentrations are expected to occur due to traffic emissions. The EPA plans to finalize the standard by January 2010 and to designate nonattainment areas by January 2012. 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

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expenditures to be made over extended time periods, and some of the unaffiliated utilities 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 pollution control equipment required to comply with the air quality issues outlined above, new sources of wastewater discharge will be generated at certain affected facilities. Integration of these new wastewater discharges 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 complying with these requirements could be material to our or the Utilities’ results of operations or financial position.

On September 15, 2009, the EPA announced that it had completed a multi-year study of power plant wastewater discharges and concluded that current regulations have not kept pace with changes that have occurred in the electric power industry since the regulations were issued in 1982, including addressing impacts to wastewater discharge from operation of air pollution control equipment. As a result, the EPA has announced that it plans to revise the regulations that govern wastewater discharge, which may result in operational changes and additional compliance costs in the future. The outcome of this matter cannot be predicted.

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

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

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. We currently anticipate that proposed rules will be published in late 2009 or in 2010 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

Growing state, federal and international attention to global climate change may result in the regulation of CO2 and other GHGs. As discussed under “Other Matters – Regulatory Environment,” on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009. This bill would establish a national cap-and-trade program to reduce GHG emissions as well as a national REPS. The U.S. Senate is considering similar proposals. Final legislation will depend upon changes made during the legislative process to the provisions and the manner in which key provisions are implemented, including for the regulation of carbon. In addition, the Obama administration has begun the process of regulating GHG emissions through use of the Clean Air Act. The full impact of final legislation, if enacted, and additional regulation resulting from other federal GHG initiatives cannot be determined at this time; however, we anticipate that it could result in significant rate increases over time. We are

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preparing for a carbon-constrained future and are actively engaged in helping shape effective policies to address the issue.

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 GHG emissions that would be presented to the legislature no earlier than January 2010. As discussed under “Clean Smokestacks Act,” on July 31, 2009, the governor of North Carolina signed into law a bill that may impact PEC’s Clean Smokestacks Act compliance plans. While state-level study groups have been 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 –  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. The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO2 and other GHGs. Although the treaty went into effect on February 16, 2005, the United States has not adopted it.

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.

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 GHG 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 GHGs (CO2, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) that pose a potential threat to human health and welfare. The EPA is expected to make a final determination later this year. 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 those denials of waiver requests. On June 30, 2009, the EPA granted California’s waiver request, enabling the state to enforce its GHG emissions standards for new motor vehicles, beginning with the current model year. Additional states may set similar standards as a result of the decision. The impact of this development cannot be predicted.

On September 22, 2009, the EPA issued the final GHG emissions reporting rule, which establishes a national protocol for the reporting of annual GHG emissions. Facilities that emit greater than 25,000 metric tons per year of GHGs must report emissions by March 31 of each year beginning in 2011 for year 2010 emissions. Because the rule builds on current emission reporting requirements, compliance with the requirements is not expected to have a material impact on the Utilities.

NEW ACCOUNTING STANDARDS

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

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PEC

The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q and Item 1A, “Risk Factors” to the 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 increased $21 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $166 million increase in the recovery of deferred fuel costs due to higher fuel rates in 2009; $107 million lower net income tax payments; and a $58 million decrease in accounts receivable and receivables from affiliated companies, largely driven by lower wholesale revenues and the timing of customer billings and receipts. These impacts were partially offset by a $139 million decrease from accounts payable and accounts payable to affiliated companies, primarily driven by the timing of purchases and payments to vendors, and $163 million in pension and other benefits contributions made in 2009.

Net cash used by investing activities increased $102 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $57 million increase in gross property additions and a $92 million increase in advances to affiliated companies, partially offset by a $49 million decrease in nuclear fuel additions. Property additions are primarily for normal construction activity and ongoing capital expenditures related to environmental compliance programs.

Net cash used by financing activities decreased $32 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to the $400 million payment at maturity of long-term debt, the $200 million in dividends paid to the Parent and the $110 million net repayment of commercial paper in 2009. These impacts were partially offset by a $273 million increase in the proceeds from the issuance of long-term debt in 2009 compared to 2008, as well as the $300 million payment at maturity of long-term debt and $153 million repayment of advances from affiliates 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 12 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.

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OTHER MATTERS

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

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PEF

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

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

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities increased $560 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $391 million increase in the recovery of deferred fuel costs due to higher fuel rates, a $161 million increase in the recovery of nuclear costs under Florida’s nuclear cost-recovery rule, and $141 million receipt in 2009 of cash collateral previously posted with counterparties on derivative contracts. These impacts were partially offset by a $130 million decrease from accounts payable and payables to affiliated companies, largely driven by changes in fuel purchase costs and the timing of payments to vendors.

Net cash used by investing activities increased $36 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $149 million decrease in settlements of advances to affiliates and a $39 million increase in nuclear fuel additions. These impacts were partially offset by a $160 million decrease in property additions. The decrease in property additions was driven by decreases in environmental compliance spending and completion of the Bartow Plant repowering project to more efficient natural gas-burning technology, partially offset by an increase in expenditures for nuclear projects.

Net cash provided by financing activities decreased $724 million for the nine months ended September 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to $1.475 billion in proceeds received from the issuance of long-term debt, net in 2008 and the $321 million net repayment of commercial paper outstanding in 2009. These impacts were partially offset by the payment at maturity of $532 million of long-term debt in 2008 and receipt of $465 million in contributions from the Parent in 2009. 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 12 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.

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OTHER MATTERS

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

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ITEM 3.                 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various risks related to changes in market conditions. Market risk represents the potential loss arising from adverse changes in market rates and prices. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk to the extent that the counterparty fails to perform under the contract. We 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 12). 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 NDT 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 September 30, 2009, has changed from December 31, 2008. The total notional amount of fixed rate long-term debt at September 30, 2009, was $10.295 billion, with an average interest rate of 6.16% and fair market value of $11.5 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 September 30, 2009, was $961 million, with an average interest rate of 0.64% 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. The total notional amount of debt to affiliated trust at September 30, 2009, and December 31, 2008, was $309 million, with an average interest rate of 7.10%. At September 30, 2009 and December 31, 2008, the fair market value of debt to affiliated trust was $309 million and $290 million, respectively.

In addition to our variable rate long-term debt, we typically have commercial paper and/or loans outstanding under our RCA facilities, which are also exposed to floating interest rates. At September 30, 2009 and December 31, 2008, approximately 10 percent and 18 percent, respectively, of consolidated debt was in floating rate mode.

Based on our variable rate long-term debt balances at September 30, 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 September 30, 2009, a 100 basis point change in interest rates would result in an annual interest expense change of approximately $3 million.

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

The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates.

We 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 GAAP, 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.

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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 September 30, 2009
Anticipated 10-year debt issue(c) (d)	$	150		4.03	%	3-month LIBOR	$	(1	)	$	(3	)
Risk hedged at December 31, 2008
Anticipated 10-year debt issue(e)	$	200		4.36	%	3-month LIBOR	$	(30	)	$	(5	)
PEC
Risk hedged at September 30, 2009
Anticipated 10-year debt issue(f)	$	100		4.07	%	3-month LIBOR	$	2		$	(2	)
Risk hedged at December 31, 2008
Anticipated 10-year debt issue(g)	$	250		4.18	%	3-month LIBOR	$	(35	)	$	(6	)
PEF
Risk hedged at September 30, 2009
Anticipated 10-year debt issue(h)	$	75		3.48	%	3-month LIBOR	$	2		$	(2	)
Risk hedged at December 31, 2008	None

(a) 3-month LIBOR rate was 0.287% at September 30, 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 hedges executed January 2009, June 2009 and July 2009 mature on March 1, 2021, and require mandatory cash settlement on March 1, 2011.

(d) Subsequent to September 30, 2009, the Parent entered into $200 million notional of forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances.

(e) 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.

(f) Anticipated 10-year debt issue hedges executed January 2009 and June 2009 mature on July 16, 2022, and require mandatory cash settlement on July 16, 2012.

(g) 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.

(h) Anticipated 10-year debt issue hedges executed January 2009 and June 2009 mature on June 1, 2020, and require mandatory cash settlement on June 1, 2010.

MARKETABLE SECURITIES PRICE RISK

At September 30, 2009 and December 31, 2008, the fair value of our NDT funds was $1.300 billion and $1.089 billion, respectively, including $817 million and $672 million, respectively, for PEC and $483 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.

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CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At September 30, 2009 and December 31, 2008, the fair value of CVOs was $23 million and $34 million, respectively. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analysis performed on the CVOs uses quoted prices obtained from brokers or quote services to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. A hypothetical 10 percent increase in the September 30, 2009 market price would result in a $2 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 and, therefore, 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 September 30, 2009, substantially all derivative commodity instrument positions were subject to retail regulatory treatment.

See Note 12 for additional information with regard to our commodity contracts and use of derivative financial instruments.

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.

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 three and nine months ended September 30, 2009, PEC recorded net realized losses of $29 million and $68 million, respectively. During the three and nine months ended September 30, 2008, PEC recorded net realized gains of $6 million and $12 million, respectively. During the three and nine months ended September 30, 2009, PEF recorded net realized losses of $207 million and $480 million, respectively. During the three and nine months ended September 30, 2008, PEF recorded net realized gains of $118 million and $237 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 September 30, 2009, the fair value of PEC’s commodity derivative instruments was recorded as a $28 million short-term derivative liability position included in derivative liabilities and a $51 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

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collateral with PEC in support of these instruments. PEC had a cash collateral asset included in prepayments and other current assets of $3 million and $18 million on the PEC Consolidated Balance Sheet at September 30, 2009 and December 31, 2008, respectively.

At September 30, 2009, the fair value of PEF’s commodity derivative instruments was recorded as a $6 million short-term derivative asset position included in prepayments and other current assets, a $5 million long-term derivative asset position included in other assets and deferred debits, a $217 million short-term derivative liability position included in current derivative liabilities, and a $148 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 derivative 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. Changes in natural gas prices and settlements of financial hedge agreements since December 31, 2008, have impacted the amount of collateral posted with counterparties.  PEF’s cash collateral asset included in derivative collateral posted on the PEF Balance Sheet was $182 million at September 30, 2009, compared to $335 million at December 31, 2008.

CASH FLOW HEDGES

The Utilities designate a portion of commodity derivative instruments as cash flow hedges. 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 September 30, 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 and nine months ended September 30, 2009 and 2008.

At September 30, 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 NDT 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).

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ITEM 4.                 CONTROLS AND PROCEDURES

PROGRESS ENERGY

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

There has been no change in our internal control over financial reporting during the quarter ended September 30, 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 PEC’s internal control over financial reporting during the quarter ended September 30, 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.

There has been no change in PEF’s internal control over financial reporting during the quarter ended September 30, 2009, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1.                      LEGAL PROCEEDINGS

Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 16C).

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.

Goodwill is required to 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 and/or dilution through additional issuances of common stock.

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

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a)   Securities Delivered. On July 1, 2009, July 27, 2009 and September 22, 2009, 609, 847 and 1,099 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. 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.

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ISSUER PURCHASES OF EQUITY SECURITIES FOR THIRD QUARTER OF 2009

Period	(a) Total Number of Shares (or Units) Purchased (1)(2)(3)(4)(5)		(b) Average Price Paid Per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs(1)		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs(1)
July 1 – July 31		483,417	$	37.5826		N/A		N/A
August 1 – August 31		88,004		39.0169		N/A		N/A
September 1– September 30		280,293		39.0436		N/A		N/A
Total		851,714	$	38.2116		N/A		N/A

(1) At September 30, 2009, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) The plan administrator purchased 585,213 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 265,608 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 186 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy Investor Plus Plan.

(5) Progress Energy withheld 707 shares of our common stock during the third quarter of 2009 to pay taxes due upon the payout of certain Restricted Stock Unit Awards pursuant to the terms of the Company’s 2002 and 2007 Equity Incentive Plans.

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ITEM 6.                 EXHIBITS

(a)   Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
31(a)	302 Certifications of Chief Executive Officer	X
31(b)	302 Certifications of Chief Financial Officer	X
31(c)	302 Certifications of Chief Executive Officer		X
31(d)	302 Certifications of Chief Financial Officer		X
31(e)	302 Certifications of Chief Executive Officer			X
31(f)	302 Certifications of Chief Financial Officer			X
32(a)	906 Certifications of Chief Executive Officer	X
32(b)	906 Certifications of Chief Financial Officer	X
32(c)	906 Certifications of Chief Executive Officer		X
32(d)	906 Certifications of Chief Financial Officer		X
32(e)	906 Certifications of Chief Executive Officer			X
32(f)	906 Certifications of Chief Financial Officer			X
101.INS	XBRL Instance Document*	X
101.SCH	XBRL Taxonomy Extension Schema Document	X
101.CAL	XBRL Taxonomy Calculation Linkbase Document	X
101.LAB	XBRL Taxonomy Label Linkbase Document	X
101.PRE	XBRL Taxonomy Presentation Linkbase Document	X

* Attached as Exhibit 101 are the following financial statements and notes thereto for Progress Energy from the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, formatted in Extensible Business Reporting Language (XBRL): (i) the Unaudited Condensed Consolidated Statements of Income, (ii) the Unaudited Condensed Consolidated Balance Sheets, (iii) the Unaudited Condensed Consolidated Statement of Cash Flows, and (iv) the Notes to Unaudited Condensed Consolidated Financial Statements, tagged as blocks of text.

In accordance with Rule 406T of Regulation S-T, the XBRL-related information in Exhibit 101 to this Quarterly Report on Form 10-Q is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections.

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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: November 6, 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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