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, 2011

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	x	No	o
PEF	Yes	x	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 4, 2011, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	295,005,362
PEC	Common Stock (Without Par Value)	159,608,055 (all of which were held directly by Progress Energy, Inc.)
PEF	Common Stock (Without Par Value)	100 (all of which were held indirectly by Progress Energy, Inc.)

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

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

TABLE OF CONTENTS
GLOSSARY OF TERMS		2
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS		5
PART I.  FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	7
	Unaudited Condensed Interim Financial Statements
	Progress Energy, Inc. (Progress Energy)
	Unaudited Condensed Consolidated Statements of Income	7
	Unaudited Condensed Consolidated Balance Sheets	8
	Unaudited Condensed Consolidated Statements of Cash Flows	9
	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
	Unaudited Condensed Consolidated Statements of Income	10
	Unaudited Condensed Consolidated Balance Sheets	11
	Unaudited Condensed Consolidated Statements of Cash Flows	12
	Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
	Unaudited Condensed Statements of Income	13
	Unaudited Condensed Balance Sheets	14
	Unaudited Condensed Statements of Cash Flows	15
	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.	16
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	72
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	110
ITEM 4.	CONTROLS AND PROCEDURES	113
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	114
ITEM 1A.	RISK FACTORS	114
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	115
ITEM 6.	EXHIBITS	116
SIGNATURES		118

1

GLOSSARY OF TERMS

We use the words “Progress Energy,” “we,” “us” or “our” to indicate that certain 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, acronyms or initialisms are used by the Progress Registrants:

TERM	DEFINITION
2010 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2010
401(k)	Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASLB	Atomic Safety and Licensing Board
the Asset Purchase Agreement	Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
ASU	Accounting Standards Update
Audit Committee	Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART	Best Available Retrofit Technology
Base Revenues	Non-GAAP measure defined as operating revenues excluding clause recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CCRC	Capacity Cost-Recovery Clause
CERCLA or Superfund	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Smokestacks Act	North Carolina Clean Smokestacks Act
the Code	Internal Revenue Code
CO2	Carbon dioxide
COL	Combined license
Corporate and Other	Corporate and Other segment primarily includes the Parent, PESC and miscellaneous other nonregulated businesses
CR1 and CR2	PEF’s Crystal River Units No. 1 and No. 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 No. 5 coal-fired steam turbines
CSAPR	Cross-State Air Pollution Rule
CVO	Contingent value obligation
D.C. Court of Appeals	U.S. Court of Appeals for the District of Columbia Circuit
DOE	U.S. Department of Energy
DOJ	U.S. Department of Justice
DSM	Demand-side management
Duke Energy	Duke Energy Corporation
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
EE	Energy efficiency

2

EGU MACT	MACT standards for coal-fired and oil-fired electric steam generating units
EIP	Equity Incentive Plan
EPA	U.S. Environmental Protection Agency
EPC	Engineering, procurement and construction
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
Fitch	Fitch Ratings
the Florida Global Case	U.S. Global, LLC v. Progress Energy, Inc. et al.
Florida Progress	Florida Progress Corporation
FPSC	Florida Public Service Commission
Funding Corp.	Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
Global	U.S. Global, LLC
GWh	Gigawatt-hours
Harris	PEC’s Shearon Harris Nuclear Plant
IPP	Progress Energy Investor Plus Plan
kV	Kilovolt
kVA	Kilovolt-ampere
kWh	Kilowatt-hours
Levy	PEF’s proposed Levy Units No. 1 and No. 2 Nuclear Plants
LIBOR	London Inter Bank Offered 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
the Merger	Proposed merger between Progress Energy and Duke Energy
the Merger Agreement	Agreement and Plan of Merger, dated as of January 8, 2011, by and among Progress Energy and Duke Energy
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
NO2	Nitrogen dioxide
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
NOx	Nitrogen oxides
NRC	Nuclear Regulatory Commission
O&M	Operation and maintenance expense
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income
Ongoing Earnings	Non-GAAP financial measure defined as GAAP net income attributable to controlling interests less discontinued operations and the effects of certain identified gains and charges
OPEB	Postretirement benefits other than pensions

3

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
PPACA	Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act
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
PRP	Potentially responsible party, as defined in CERCLA
PSSP	Performance Share Sub-Plan
QF	Qualifying facility
RCA	Revolving credit agreement
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
REPS	Renewable energy portfolio standard
the Registration Statement	The registration statement filed on Form S-4 by Duke Energy related to the Merger
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity
RSU	Restricted stock unit
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 45K	Section 45K of the Code
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 Financial Statements contained in PART I, Item 1 of this Form 10-Q
SERC	SERC Reliability Corporation
S&P	Standard & Poor’s Rating Services
SO2	Sulfur dioxide
SOx	Sulfur oxides
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
the Trust	FPC Capital I
the Utilities	Collectively, PEC and PEF
VSP	Voluntary severance plan
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

4

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 following headings: “Pending Merger” about the proposed merger between Progress Energy and Duke Energy Corporation (Duke Energy) (the Merger) and the impact of the Merger on our strategy and liquidity; “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 the effects of new environmental regulations, changes in the regulatory environment, meeting anticipated demand in our regulated service territories, potential nuclear construction and our synthetic fuels tax credits.

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:

·   our ability to obtain the approvals required to complete the Merger and the impact of compliance with material restrictions or conditions potentially imposed by our regulators;

·   the risk that the Merger is terminated prior to completion and results in significant transaction costs to us;

·   our ability to achieve the anticipated results and benefits of the Merger;

·   the impact of business uncertainties and contractual restrictions while the Merger is pending;

·   the scope of necessary repairs of the delamination of PEF’s Crystal River Unit No. 3 Nuclear Plant (CR3) could prove more extensive than is currently identified, such repairs could prove not to be feasible, the costs of repair and/or replacement power could exceed our estimates and insurance coverage or may not be recoverable through the regulatory process;

·   the impact of fluid and complex laws and regulations, including those relating to the environment and energy policy;

·   our ability to recover eligible costs and earn an adequate return on investment through the regulatory process;

·   the ability to successfully operate electric generating facilities and deliver electricity to customers;

·   the impact on our facilities and businesses from a terrorist attack, cyber security threats and other catastrophic events;

·   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;

·   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, safety, regulatory and financial risks;

·   the financial resources and capital needed to comply with environmental laws and regulations;

·   risks associated with climate change;

·   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;

·   fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process;

5

·   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);

·   current economic conditions;

·   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 or reductions in cash flow may have on each of the Progress Registrants;

·   the Progress Registrants’ ability to maintain their current credit ratings and the impacts in the event their credit ratings are downgraded;

·   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;

·   our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code (the Code) Section 29/45K (Section 29/45K); and

·   the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements.

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 Item 1A, “Risk Factors,” in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2010 (2010 Form 10-K), which was filed with the SEC on February 28, 2011, and is updated for material changes, if any, in this Form 10-Q and in our other SEC filings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on the Progress Registrants.

6

PART I.  FINANCIAL INFORMATION

ITEM 1.   FINANCIAL STATEMENTS

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2011
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended September 30						Nine months ended September 30
(in millions except per share data)	2011			2010			2011			2010
Operating revenues	$	2,747		$	2,962		$	7,170		$	7,869
Operating expenses
Fuel used in electric generation		844			935			2,236			2,574
Purchased power		349			418			898			996
Operation and maintenance		487			474			1,491			1,459
Depreciation, amortization and accretion		175			201			508			680
Taxes other than on income		163			161			437			448
Other		39			20			31			25
Total operating expenses		2,057			2,209			5,601			6,182
Operating income		690			753			1,569			1,687
Other income (expense)
Interest income		1			3			2			6
Allowance for equity funds used during construction		22			22			77			68
Other, net		(70	)		(5	)		(60	)		(5	)
Total other (expense) income, net		(47	)		20			19			69
Interest charges
Interest charges		180			197			568			587
Allowance for borrowed funds used during construction		(8	)		(8	)		(26	)		(24	)
Total interest charges, net		172			189			542			563
Income from continuing operations before income tax		471			584			1,046			1,193
Income tax expense		178			219			386			456
Income from continuing operations before cumulative effect   of change in accounting principle		293			365			660			737
Discontinued operations, net of tax		-			(2	)		(4	)		(2	)
Cumulative effect of change in accounting principle, net of tax		-			2			-			-
Net income		293			365			656			735
Net income attributable to noncontrolling interests, net of tax		(2	)		(4	)		(5	)		(4	)
Net income attributable to controlling interests	$	291		$	361		$	651		$	731
Average common shares outstanding – basic		296			294			296			289
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling   interests, net of tax	$	0.98		$	1.23		$	2.22		$	2.53
Discontinued operations attributable to controlling interests,   net of tax		-			-			(0.02	)		-
Net income attributable to controlling interests	$	0.98		$	1.23		$	2.20		$	2.53
Dividends declared per common share	$	0.620		$	0.620		$	1.860		$	1.860
Amounts attributable to controlling interests
Income from continuing operations, net of tax	$	291		$	363		$	655		$	733
Discontinued operations, net of tax		-			(2	)		(4	)		(2	)
Net income attributable to controlling interests	$	291		$	361		$	651		$	731
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

7

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	30,729		$	29,708
Accumulated depreciation		(11,905	)		(11,567	)
Utility plant in service, net		18,824			18,141
Other utility plant, net		222			220
Construction work in progress		2,233			2,205
Nuclear fuel, net of amortization		736			674
Total utility plant, net		22,015			21,240
Current assets
Cash and cash equivalents		103			611
Receivables, net		1,207			1,033
Inventory		1,376			1,226
Regulatory assets		180			176
Derivative collateral posted		112			164
Deferred tax assets		285			156
Prepayments and other current assets		162			110
Total current assets		3,425			3,476
Deferred debits and other assets
Regulatory assets		2,333			2,374
Nuclear decommissioning trust funds		1,512			1,571
Miscellaneous other property and investments		410			413
Goodwill		3,655			3,655
Other assets and deferred debits		327			325
Total deferred debits and other assets		8,237			8,338
Total assets	$	33,677		$	33,054
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 295   million and 293 million shares issued and outstanding, respectively	$	7,414		$	7,343
Accumulated other comprehensive loss		(207	)		(125	)
Retained earnings		2,905			2,805
Total common stock equity		10,112			10,023
Noncontrolling interests		3			4
Total equity		10,115			10,027
Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		11,717			11,864
Total capitalization		22,198			22,257
Current liabilities
Current portion of long-term debt		950			505
Short-term debt		45			-
Accounts payable		895			994
Interest accrued		184			216
Dividends declared		185			184
Customer deposits		339			324
Derivative liabilities		303			259
Accrued compensation and other benefits		140			175
Other current liabilities		507			298
Total current liabilities		3,548			2,955
Deferred credits and other liabilities
Noncurrent income tax liabilities		2,310			1,696
Accumulated deferred investment tax credits		104			110
Regulatory liabilities		2,326			2,635
Asset retirement obligations		1,253			1,200
Accrued pension and other benefits		1,226			1,514
Derivative liabilities		255			278
Other liabilities and deferred credits		457			409
Total deferred credits and other liabilities		7,931			7,842
Commitments and contingencies (Notes 14 and 15)
Total capitalization and liabilities	$	33,677		$	33,054
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

8

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2011			2010
Operating activities
Net income	$	656		$	735
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		632			804
Deferred income taxes and investment tax credits, net		430			263
Deferred fuel credit		(11	)		(37	)
Allowance for equity funds used during construction		(77	)		(68	)
Other adjustments to net income		202			197
Cash (used) provided by changes in operating assets and liabilities
Receivables		(93	)		(252	)
Inventory		(152	)		111
Derivative collateral posted		52			(83	)
Other assets		(19	)		(25	)
Income taxes, net		20			213
Accounts payable		(40	)		45
Accrued pension and other benefits		(359	)		(162	)
Other liabilities		63			163
Net cash provided by operating activities		1,304			1,904
Investing activities
Gross property additions		(1,535	)		(1,643	)
Nuclear fuel additions		(134	)		(164	)
Purchases of available-for-sale securities and other investments		(4,536	)		(5,927	)
Proceeds from available-for-sale securities and other investments		4,509			5,915
Insurance proceeds		78			18
Other investing activities		43			(3	)
Net cash used by investing activities		(1,575	)		(1,804	)
Financing activities
Issuance of common stock, net		42			419
Dividends paid on common stock		(550	)		(535	)
Net increase (decrease) in short-term debt		45			(140	)
Proceeds from issuance of long-term debt, net		1,286			591
Retirement of long-term debt		(1,000	)		(400	)
Other financing activities		(60	)		(69	)
Net cash used by financing activities		(237	)		(134	)
Net decrease in cash and cash equivalents		(508	)		(34	)
Cash and cash equivalents at beginning of period		611			725
Cash and cash equivalents at end of period	$	103		$	691
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	253		$	255
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

9

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2011
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
	Three months ended September 30						Nine months ended September 30
(in millions)	2011			2010			2011			2010
Operating revenues	$	1,332		$	1,414		$	3,525		$	3,794
Operating expenses
Fuel used in electric generation		388			464			1,077			1,322
Purchased power		117			109			257			235
Operation and maintenance		271			256			859			841
Depreciation, amortization and accretion		132			120			382			358
Taxes other than on income		57			58			163			169
Other		38			5			38			5
Total operating expenses		1,003			1,012			2,776			2,930
Operating income		329			402			749			864
Other income (expense)
Interest income		-			1			1			3
Allowance for equity funds used during construction		15			17			53			45
Other, net		(4	)		(2	)		(5	)		(5	)
Total other income, net		11			16			49			43
Interest charges
Interest charges		45			51			149			154
Allowance for borrowed funds used during construction		(4	)		(5	)		(15	)		(14	)
Total interest charges, net		41			46			134			140
Income before income tax		299			372			664			767
Income tax expense		100			138			227			284
Income before cumulative effect of change in accounting principle		199			234			437			483
Cumulative effect of change in accounting principle, net of tax		-			2			-			-
Net income		199			236			437			483
Net (income) loss attributable to noncontrolling interests, net of tax		-			(2	)		-			1
Net income attributable to controlling interests		199			234			437			484
Preferred stock dividend requirement		(1	)		(1	)		(2	)		(2	)
Net income available to parent	$	198		$	233		$	435		$	482
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

10

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	17,234		$	16,388
Accumulated depreciation		(7,505	)		(7,324	)
Utility plant in service, net		9,729			9,064
Other utility plant, net		186			184
Construction work in progress		1,141			1,233
Nuclear fuel, net of amortization		522			480
Total utility plant, net		11,578			10,961
Current assets
Cash and cash equivalents		67			230
Receivables, net		547			519
Receivables from affiliated companies		27			44
Inventory		734			590
Deferred fuel cost		52			71
Income taxes receivable		17			90
Deferred tax assets		112			65
Prepayments and other current assets		99			47
Total current assets		1,655			1,656
Deferred debits and other assets
Regulatory assets		1,029			987
Nuclear decommissioning trust funds		992			1,017
Miscellaneous other property and investments		185			183
Other assets and deferred debits		104			95
Total deferred debits and other assets		2,310			2,282
Total assets	$	15,543		$	14,899
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160   million shares issued and outstanding	$	2,144		$	2,130
Accumulated other comprehensive loss		(70	)		(33	)
Retained earnings		3,068			3,083
Total common stock equity		5,142			5,180
Preferred stock		59			59
Long-term debt, net		3,693			3,693
Total capitalization		8,894			8,932
Current liabilities
Current portion of long-term debt		500			-
Accounts payable		496			534
Payables to affiliated companies		88			109
Interest accrued		65			74
Customer deposits		114			106
Derivative liabilities		93			53
Accrued compensation and other benefits		81			99
Other current liabilities		147			81
Total current liabilities		1,584			1,056
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,902			1,608
Accumulated deferred investment tax credits		100			104
Regulatory liabilities		1,443			1,461
Asset retirement obligations		889			849
Accrued pension and other benefits		519			723
Other liabilities and deferred credits		212			166
Total deferred credits and other liabilities		5,065			4,911
Commitments and contingencies (Notes 14 and 15)
Total capitalization and liabilities	$	15,543		$	14,899
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 STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2011			2010
Operating activities
Net income	$	437		$	483
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		491			450
Deferred income taxes and investment tax credits, net		222			123
Deferred fuel cost		19			63
Allowance for equity funds used during construction		(53	)		(45	)
Other adjustments to net income		20			68
Cash provided (used) by changes in operating assets and liabilities
Receivables		56			(89	)
Receivables from affiliated companies		17			15
Inventory		(144	)		120
Other assets		(5	)		(41	)
Income taxes, net		79			59
Accounts payable		(41	)		(18	)
Payables to affiliated companies		(21	)		(1	)
Accrued pension and other benefits		(228	)		(103	)
Other liabilities		39			65
Net cash provided by operating activities		888			1,149
Investing activities
Gross property additions		(901	)		(867	)
Nuclear fuel additions		(121	)		(132	)
Purchases of available-for-sale securities and other investments		(430	)		(352	)
Proceeds from available-for-sale securities and other investments		401			323
Changes in advances to affiliated companies		(59	)		199
Other investing activities		16			-
Net cash used by investing activities		(1,094	)		(829	)
Financing activities
Dividends paid on preferred stock		(2	)		(2	)
Dividends paid to parent		(450	)		(75	)
Proceeds from issuance of long-term debt, net		496			-
Contributions from parent		-			14
Other financing activities		(1	)		-
Net cash provided (used) by financing activities		43			(63	)
Net (decrease) increase in cash and cash equivalents		(163	)		257
Cash and cash equivalents at beginning of period		230			35
Cash and cash equivalents at end of period	$	67		$	292
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	179		$	160
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

12

FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
September 30, 2011
UNAUDITED CONDENSED STATEMENTS of INCOME
	Three months ended September 30						Nine months ended September 30
(in millions)	2011			2010			2011			2010
Operating revenues	$	1,414		$	1,543		$	3,639		$	4,065
Operating expenses
Fuel used in electric generation		456			471			1,159			1,252
Purchased power		232			309			641			761
Operation and maintenance		221			234			655			647
Depreciation, amortization and accretion		39			77			112			311
Taxes other than on income		106			102			274			278
Other		(1	)		6			(13	)		6
Total operating expenses		1,053			1,199			2,828			3,255
Operating income		361			344			811			810
Other income (expense)
Interest income		1			-			1			1
Allowance for equity funds used during construction		7			5			24			23
Other, net		(1	)		(3	)		3			-
Total other income, net		7			2			28			24
Interest charges
Interest charges		50			68			187			202
Allowance for borrowed funds used during construction		(4	)		(3	)		(11	)		(10	)
Total interest charges, net		46			65			176			192
Income before income tax		322			281			663			642
Income tax expense		119			101			245			241
Net income		203			180			418			401
Preferred stock dividend requirement		-			-			(1	)		(1	)
Net income available to parent	$	203		$	180		$	417		$	400
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

13

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	September 30, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	13,331		$	13,155
Accumulated depreciation		(4,322	)		(4,168	)
Utility plant in service, net		9,009			8,987
Held for future use		36			36
Construction work in progress		1,092			972
Nuclear fuel, net of amortization		214			194
Total utility plant, net		10,351			10,189
Current assets
Cash and cash equivalents		18			249
Receivables, net		629			496
Receivables from affiliated companies		21			11
Inventory		643			636
Regulatory assets		128			105
Derivative collateral posted		98			140
Deferred tax assets		83			77
Prepayments and other current assets		58			29
Total current assets		1,678			1,743
Deferred debits and other assets
Regulatory assets		1,305			1,387
Nuclear decommissioning trust funds		520			554
Miscellaneous other property and investments		43			43
Other assets and deferred debits		117			140
Total deferred debits and other assets		1,985			2,124
Total assets	$	14,014		$	14,056
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized,   100 shares issued and outstanding	$	1,755		$	1,750
Accumulated other comprehensive loss		(26	)		(4	)
Retained earnings		3,084			3,144
Total common stock equity		4,813			4,890
Preferred stock		34			34
Long-term debt, net		4,482			4,182
Total capitalization		9,329			9,106
Current liabilities
Current portion of long-term debt		-			300
Notes payable to affiliated companies		69			9
Accounts payable		377			439
Payables to affiliated companies		67			60
Interest accrued		60			83
Customer deposits		225			218
Derivative liabilities		175			188
Accrued compensation and other benefits		34			47
Other current liabilities		237			121
Total current liabilities		1,244			1,465
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,411			1,065
Regulatory liabilities		796			1,084
Asset retirement obligations		364			351
Accrued pension and other benefits		414			522
Capital lease obligations		190			199
Derivative liabilities		168			190
Other liabilities and deferred credits		98			74
Total deferred credits and other liabilities		3,441			3,485
Commitments and contingencies (Notes 14 and 15)
Total capitalization and liabilities	$	14,014		$	14,056
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

14

FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2011			2010
Operating activities
Net income	$	418		$	401
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		113			328
Deferred income taxes and investment tax credits, net		291			211
Deferred fuel credit		(30	)		(100	)
Allowance for equity funds used during construction		(24	)		(23	)
Other adjustments to net income		70			89
Cash (used) provided by changes in operating assets and liabilities
Receivables		(134	)		(155	)
Receivables from affiliated companies		(10	)		(5	)
Inventory		(10	)		(11	)
Derivative collateral posted		43			(59	)
Other assets		(1	)		(20	)
Income taxes, net		51			117
Accounts payable		(2	)		70
Payables to affiliated companies		7			(18	)
Accrued pension and other benefits		(123	)		(51	)
Other liabilities		61			121
Net cash provided by operating activities		720			895
Investing activities
Gross property additions		(624	)		(774	)
Nuclear fuel additions		(13	)		(32	)
Purchases of available-for-sale securities and other investments		(4,097	)		(5,456	)
Proceeds from available-for-sale securities and other investments		4,098			5,460
Insurance proceeds		74			18
Other investing activities		39			(2	)
Net cash used by investing activities		(523	)		(786	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		(475	)		(50	)
Proceeds from issuance of long-term debt, net		296			591
Retirement of long-term debt		(300	)		(300	)
Changes in advances from affiliated companies		60			(213	)
Other financing activities		(8	)		(8	)
Net cash (used) provided by financing activities		(428	)		19
Net (decrease) increase in cash and cash equivalents		(231	)		128
Cash and cash equivalents at beginning of period		249			17
Cash and cash equivalents at end of period	$	18		$	145
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	72		$	92
Nuclear repairs insurance recovery		48			75
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

15

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED 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 through 9, 11, 12, 14 and 15
PEF	1 through 9, 11, 12, 14 and 15

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

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 Applicable Combined Notes to Unaudited Condensed Interim Financial Statements by Registrant. 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., subject to regulation by the Federal Energy Regulatory Commission (FERC).

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 (Corporate and Other) 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 jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.

PEF

PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction 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, 2010 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, 2010 (2010 Form 10-K).

17

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 2010 have been reclassified to conform to the 2011 presentation.

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)	2011		2010		2011		2010
Progress Energy	$	96	$	101	$	245	$	265
PEC		33		34		86		91
PEF		63		67		159		174

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. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our 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.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary during 2010 or for the nine months ended September 30, 2011. No financial or other support has been provided to the VIE during the periods presented.

18

The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:

(in millions)	September 30, 2011		December 31, 2010
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		-
Prepayments and other current assets		-		1
Accounts payable		-		5

The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses.

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million and $2 million for each of the three and nine months ended September 30, 2011 and 2010, respectively. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

See discussion of PEC’s variable interests within the Progress Energy section.

PEF

PEF has no significant variable interests in VIEs.

2. MERGER AGREEMENT

On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction (the Merger) and continue as a wholly owned subsidiary of Duke Energy.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the Merger. Accordingly, the adjusted exchange ratio is expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.

Consummation of the Merger is subject to customary conditions, including, among others things, approval of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission and the SCPSC. Although there are no merger-specific regulatory approvals required in Indiana, Ohio or Florida, the companies will continue to update the public service commissions in those states on the Merger, as applicable and as required. The status of these matters is as follows, and we cannot predict the outcome of pending approvals:

19

Shareholder Approval

·   On August 23, 2011, the Merger was approved by the shareholders of Progress Energy and Duke Energy.

Federal Regulatory Approvals

·   On March 28, 2011, Progress Energy and Duke Energy submitted their Hart-Scott-Rodino filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.

·   On July 27, 2011, the Federal Communications Commission approved the Assignment of Authorization filings to transfer control of certain licenses. The approval is effective for 180 days.

·   On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC’s acceptance of market power mitigation measures to address the FERC’s finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina power markets. Progress Energy and Duke Energy filed a market power mitigation plan with FERC on October 17, 2011. In the October 17, 2011 filing with the FERC, Progress Energy and Duke Energy proposed a “virtual divestiture” under which power up to a certain amount will be offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. In the proposal, after native loads have been met, power will be offered to entities serving load in the relevant areas at a price determined by the average incremental cost plus 10 percent. On a day-ahead order confirmation basis, PEC plans to offer 500 megawatt-hours (MWh) during each summer hour, which is less than 4 percent of PEC’s summer net capability. Duke Energy Carolinas plans to offer 300 MWh during each summer hour and 225 MWh during each winter hour. On October 31, 2011, Progress Energy and Duke Energy filed a request for a rehearing of the Merger order without withdrawing the previously submitted market power mitigation plan. In the request for rehearing, Progress Energy and Duke Energy asserted that the FERC had departed from its established merger rules in applying a more stringent analysis to assess whether the Merger will result in market power conditions in the Carolinas. We have requested that the FERC address the mitigation plan no later than December 15, 2011. If the FERC accepts the mitigation proposal, we will withdraw the request for a rehearing.

·   On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a Joint Dispatch Agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the Merger. The second filing is a joint open access transmission tariff pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate.

·   On March 30, 2011, Progress Energy and Duke Energy made filings with the NRC for approval for indirect transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses. The period to request a hearing or intervene expired in September 2011, and no such requests were received.

State Regulatory Approvals

·   On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed the settlement with the South Carolina Office of Regulatory Staff, a party to the proceedings. If the settlement agreement is approved, Progress Energy and Duke Energy will guarantee $650 million in fuel cost savings for customers in North Carolina and South Carolina between 2012 and 2016, maintain their current level of community support for the next four years, and provide $15 million for low-income energy assistance and workforce development. The parties also agreed that direct merger-related expenses would not be recovered from customers. Recovery of merger-related employee severance costs can be requested separately. The NCUC held hearings regarding these applications on September 20-22, 2011, and proposed orders and/or briefs must be filed by November 14, 2011.

20

·   On April 25, 2011, Progress Energy and Duke Energy filed a merger-related filing and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the merger-related filing, as the merger of these entities is not likely to occur for several years after the close of the Merger. Hearings before the SCPSC to approve the Joint Dispatch Agreement have been rescheduled for the week of December 12, 2011. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.

·   On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy’s and Duke Energy’s merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky.

Certain Progress Energy shareholders have filed class action lawsuits in the state and federal courts in North Carolina against Progress Energy and each of the members of Progress Energy’s board of directors (See Note 15C).

In connection with the Merger, we established an employee retention plan for certain eligible employees. Payments under the plan are contingent upon the consummation of the Merger and the employees’ continued employment through a specified time period following the Merger. These payments will be recorded as compensation expense following consummation of the Merger. We estimate the costs of the retention plan to be $14 million.

In connection with the Merger, we announced plans to offer a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the Merger. The window for eligible employees to request a voluntary end to their employment under the VSP opened on November 7, 2011, and will close on November 30, 2011. If the employee is not required to work for a significant period after the consummation of the Merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the Merger. If a significant retention period exists, the costs of any benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the Merger and formulated an exit plan to vacate one of our corporate headquarters buildings. Under the plan, we will gradually vacate the premises beginning in the fourth quarter of 2011 through January 1, 2013. The estimated exit cost liability associated with this exit plan is $16 million and will be recognized proportionately as we vacate the premises. No exit cost liabilities were recorded at September 30, 2011.

In connection with the Merger, we incurred merger and integration-related costs of $15 million and $36 million, net of tax, for the three and nine months ended September 30, 2011, respectively. These costs are included in operation and maintenance (O&M) expense in our Consolidated Statements of Income.

See Note 25 in the 2010 Form 10-K for additional information regarding the Merger.

3. NEW ACCOUNTING STANDARDS

FAIR VALUE MEASUREMENT AND DISCLOSURES

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” which amends Accounting Standards Codification (ASC) 820 to clarify certain existing disclosure requirements and to require a number of additional disclosures, including amounts and reasons for significant transfers between the three levels of the fair value hierarchy, and presentation of certain information in the reconciliation of recurring Level 3 measurements on a gross basis. ASU 2010-06 was effective for us on January 1, 2010, with certain disclosures effective January 1, 2011. The adoption of ASU 2010-06 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities’ financial position, results of operations, or cash flows.

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends ASC

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820 to develop a single, converged fair value framework between U.S. GAAP and IFRS. ASU 2011-04 is effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 will result in changes in certain fair value measurement principles, as well as additional disclosure in the notes to the financial statements. However, the impact of adoption is not expected to be significant to our or the Utilities’ financial position, results of operations, or cash flows.

GOODWILL IMPAIRMENT TESTING

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it is determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 is effective for us on January 1, 2012. The adoption of ASU 2011-08 will give us the option, at our normal goodwill testing date, to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The impact of the adoption is not expected to be significant to our or the Utilities’ financial position, results of operations, or cash flows.

4. REGULATORY MATTERS

On January 8, 2011, Progress Energy and Duke Energy entered into the Merger Agreement. See Note 2 for regulatory information related to the Merger with Duke Energy.

A. PEC RETAIL RATE MATTERS

COST RECOVERY FILINGS

On June 3, 2011, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina retail ratepayers, driven by rising fuel prices. On September 15, 2011, PEC filed a settlement agreement for an increase of approximately $85 million in the fuel rate. The settlement agreement updated certain costs from PEC’s original filing and included the impact of a $24 million disallowance of replacement power costs resulting from prior-year performance of PEC’s nuclear plants. If approved, the increase will be effective December 1, 2011, and will increase residential electric bills by $2.75 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. On June 3, 2011, and as subsequently amended on August 23, 2011, PEC also filed for a $24 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate charged to its North Carolina ratepayers which, if approved, will be effective December 1, 2011, and will increase the residential electric bills by $1.08 per 1,000 kWh for DSM and EE cost recovery. On June 3, 2011, and as subsequently amended on September 8, 2011, PEC also requested a $9 million increase for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), which if approved, will be effective December 1, 2011, and will decrease the residential electric bills by $0.02 per 1,000 kWh. The residential NC REPS rate decreased while the total amount to be recovered increased due to the allocation of the NC REPS recovery between customer classes. The net impact of the settlement agreement and filings results in an average increase in residential electric bills of 3.7 percent. We cannot predict the outcome of these matters.

On June 29, 2011, the SCPSC approved a $22 million increase in the fuel rate charged to PEC’s South Carolina ratepayers, driven by rising fuel prices. The increase was effective July 1, 2011, and increased residential electric bills by $3.45 per 1,000 kWh. Also on June 20, 2011, the SCPSC provisionally approved a $4 million increase in the DSM and EE rate. The increase was effective July 1, 2011, and increased residential electric bills by $1.25 per 1,000 kWh. The net impact of the two filings resulted in an average increase in residential electric bills of 4.7 percent. We cannot predict the outcome of this matter.

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OTHER MATTERS

Construction of Generating Facilities

The NCUC has granted PEC permission to construct two new generating facilities: an approximately 950-MW combined cycle natural gas-fueled facility at its Lee generation facility and an approximately 620-MW natural gas-fueled facility at its Sutton generation facility. The facilities are expected to be placed in service in January 2013 and December 2013, respectively.

Planned Retirements of Generating Facilities

PEC filed a plan with the NCUC and the SCPSC to retire all of its coal-fired generating facilities in North Carolina that do not have scrubbers. These facilities total approximately 1,500 MW at four sites. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units. PEC expects to retire the remaining coal-fired facilities by the end of 2013.

The net carrying value of the four facilities at September 30, 2011, of $171 million is included in other utility plant, net on the Consolidated Balance Sheets. Consistent with ratemaking treatment, PEC will continue to depreciate each plant using the current depreciation lives and rates on file with the NCUC and the SCPSC until the earlier of the plant’s retirement or PEC’s completion and filing of a new depreciation study on or before March 31, 2013. The final recovery periods may change in connection with the regulators’ determination of the recovery of the remaining net carrying value.

B. PEF RETAIL RATE MATTERS

CR3 OUTAGE

In September 2009, PEF’s Crystal River Unit No. 3 Nuclear Plant (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit’s steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes in the partially tensioned containment building and additional cracking or delaminations may have occurred or could occur during the repair process.

PEF analyzed multiple repair options as well as early decommissioning and believes, based on the information and analyses conducted to date, that repairing the unit is the best option. PEF engaged outside engineering consultants to perform the analysis of possible repair options for the second delamination. The consultants analyzed 22 potential repair options and ultimately narrowed those to four. PEF, along with other independent consultants, reviewed the four options for technical issues, constructability, and licensing feasibility as well as cost.

Based on that initial analysis, PEF selected the best repair option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the final repair is underway. PEF will update the current estimate as this work is completed.

PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any final repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return

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to service in 2014. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments.

CR3’s current operating license expires in December 2016, and PEF applied for a 20-year renewal of the license in 2008. PEF understands that the NRC has completed the license extension process with the exception of the containment structure repair. Once the repair design has been completed and evaluated, the NRC can proceed with the review of the containment structure. Assuming the repair is successful, management is not aware of any reasons why CR3 will not satisfy the requirements for the license extension.

PEF maintains insurance for property damage and incremental costs of replacement power resulting from prolonged accidental outages through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accident but has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through September 30, 2011. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. As discussed below, PEF considers replacement power costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause. PEF also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs.

The following table summarizes the CR3 replacement power and repair costs and recovery through September 30, 2011:

(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	457		$	229
NEIL proceeds received to date		(162	)		(136	)
Insurance receivable at September 30, 2011		(162	)		(48	)
Balance for recovery	$	133	(a)	$	45

(a) As approved by the FPSC on January 1, 2011, PEF began collecting, subject to refund, replacement power costs related to CR3 within the fuel clause (See Note 7C in the 2010 Form 10-K). The replacement power costs to be recovered through the fuel clause during 2011 allow for full recovery of all of 2010’s and 2011’s replacement power costs. The 2011 fuel cost-recovery filing, discussed in “Fuel Cost Recovery,” anticipates full recovery of estimated 2012 replacement power costs.

PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. PEF has recorded $324 million of NEIL replacement power cost reimbursements subsequent to the deductible period, of which $162 million has been received to date. PEF has received $45 million of replacement power reimbursements from NEIL for the nine months ended September 30, 2011. No replacement power reimbursements have been received from NEIL for the three months ended September 30, 2011. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. We cannot predict with certainty the future recoverability of these costs. Failure to recover some or all of these costs could have a material adverse effect on our and PEF’s financial results. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

On October 25, 2010, the FPSC approved PEF’s motion to establish a separate spin-off docket to review the prudence and costs related to the outage and replacement fuel and power costs associated with the CR3 extended outage. This docket will allow the FPSC to evaluate PEF’s actions concerning the concrete delamination and review PEF’s resulting costs associated with the extended outage. On June 27, 2011, PEF filed an updated status report with

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the NRC and FPSC regarding the CR3 outage. The FPSC held subsequent status conferences regarding the CR3 outage on July 14, 2011, and August 8, 2011.

On August 23, 2011, the FPSC issued an order dividing the docket into three phases. The first phase will include a prudence review of the events and decisions of PEF leading up to the October 2, 2009 delamination event. A hearing has been scheduled for June 11-15, 2012. The second phase will be a consideration of the prudence of PEF’s decision to repair rather than decommission CR3. The third phase of this docket will include the decisions and events subsequent to the October 2, 2009 delamination leading up to the March 14, 2011 delamination event and the subsequent repair of the containment building. The hearing dates and schedules for the second and third phases will be set in subsequent orders. PEF will file status reports regarding its analysis of the engineering reports, costs, schedule for completion of the repair, along with updated information regarding the decision to repair rather than decommission CR3, and updates regarding the repair of the containment building in accordance with the controlling dates set forth by the FPSC. The first status report is due January 9, 2012.

We cannot predict the outcome of these matters.

COST OF REMOVAL RESERVE

The base rate settlement agreement in effect through the last billing cycle of 2012 provides PEF the discretion to reduce amortization expense (cost of removal component) by up to $150 million in 2010, up to $250 million in 2011, and up to any remaining balance in the cost of removal reserve in 2012 until the earlier of (a) PEF’s applicable cost of removal reserve reaches zero, or (b) the expiration of the settlement agreement at the end of 2012. In the event PEF reduces amortization expense by less than the annual amounts for 2010 or 2011, PEF may carry forward (i.e., increase the annual cap by) any unused cost of removal reserve amounts in subsequent years during the term of the agreement. Pursuant to the settlement agreement, PEF carried an unused balance of $90 million forward from 2010, which is available to reduce future amortization expense. For the nine months ended September 30, 2011, PEF recognized a $205 million reduction in amortization expense. Under the base rate settlement agreement, PEF had eligible cost of removal reserves of $294 million remaining as of September 30, 2011. The balance of the cost of removal reserve is impacted by accruals in accordance with PEF’s latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreement.

FUEL COST RECOVERY

On September 1, 2011, and as subsequently adjusted by the FPSC (see “Nuclear Cost Recovery”), PEF filed its annual fuel-cost recovery filing, requesting to increase the total fuel-cost recovery by $162 million, increasing the residential rate by $3.32 per 1,000 kWh, or 2.78 percent, which will be effective January 1, 2012 if approved. This increase is due to an increase of $3.99 per 1,000 kWh for the projected recovery of fuel costs offset by a decrease of $0.67 per 1,000 kWh for the projected recovery through the Capacity Cost-Recovery Clause (CCRC). The increase in the projected recovery of fuel costs is due to an under-recovery from the prior year. The decrease in the CCRC is primarily due to lower anticipated costs associated with PEF’s proposed Levy Units No. 1 and No. 2 Nuclear Power Plants (Levy), and the deferral of 2011 and 2012 estimated costs associated with PEF’s CR3 uprate project until 2012 (see “Nuclear Cost Recovery”), partially offset by increased capacity costs and a reduction of the refund related to an over-recovery from the prior year. A hearing was held on November 1-2, 2011. An agenda conference has been scheduled for November 22, 2011. We cannot predict the outcome of this matter.

NUCLEAR COST RECOVERY

Levy Nuclear

Major construction activities on Levy have been postponed until after the NRC issues the combined license (COL) for the plants, which is expected in 2013 if the current licensing schedule remains on track. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of

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capital financing. Taking into account these criteria, we consider Levy to be PEF’s preferred baseload generation option.

CR3 Uprate

In 2007, the FPSC issued an order approving PEF’s Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3’s gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011.

Cost Recovery

On October 24, 2011, the FPSC approved a $78 million decrease in the amount charged to PEF’s ratepayers for nuclear cost recovery, which is a component of, and is included in, the fuel cost recovery (See “Fuel Cost Recovery”), including recovery of pre-construction and carrying costs and CCRC recoverable O&M expense anticipated to be incurred during 2012, recovery of $60 million of prior years’ deferrals in 2012, as well as the estimated actual true-up of 2011 costs associated with the Levy and CR3 uprate projects. Also included is the stipulation of PEF’s filed motion with the FPSC to defer until 2012 the approval of the long-term feasibility analysis of completing the CR3 uprate, and the determination of reasonableness on, and recovery of, 2011 and 2012 estimated costs. This results in an estimated decrease in the nuclear cost-recovery charge of $2.67 per 1,000 kWh for residential customers, beginning with the first January 2012 billing cycle. The approved rate did not include PEF’s request to apply the 2011 over-recovery against the prior-years’ deferrals, but rather provides for the refund of $55 million for those prior period over collections. Under the FPSC’s ruling, the prior-years’ deferral will be recovered consistent with the 2009 rate mitigation plan as approved by the FPSC in 2009, which presented the recovery of costs over a five-year period.

DEMAND-SIDE MANAGEMENT

On July 26, 2011, the FPSC voted to set PEF’s DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener timely filed a protest to the FPSC’s Proposed Agency Action order, asserting legal challenges to the order. The FPSC has approved a briefing schedule for the parties to make legal arguments to the FPSC. We cannot predict the outcome of this matter.

On November 1, 2011, the FPSC approved PEF’s request to decrease the Energy Conservation Cost Recovery Clause (ECCR) residential rate by $0.11 per 1,000 kWh, or 0.1 percent of the total residential rate, effective January 1, 2012. The decrease in the ECCR is primarily due to an increased refund of a prior period over-recovery, partially offset by an increase in conservation program costs.

OTHER MATTERS

On August 26, 2011, and as subsequently revised on October 14, 2011, PEF filed its annual Environmental Cost Recovery Clause (ECRC) filing, requesting to increase the ECRC by $24 million, increasing the residential rate by $0.54 per 1,000 kWh, or 0.5 percent, which would be effective January 1, 2012 if approved. The increase in the ECRC is primarily due to the 2011 return of a prior period over-recovery, partially offset by a decrease in the related O&M expense. A hearing was held on November 1-2, 2011. A subsequent agenda conference has been scheduled for November 22, 2011. We cannot predict the outcome of this matter.

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5. EQUITY AND COMPREHENSIVE INCOME

A. EARNINGS PER COMMON SHARE

There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2011 and 2010. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial.

B. RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of a subsidiary and a VIE (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, 2010	$	10,023		$	4		$	10,027
Net income(a)		651			2			653
Other comprehensive loss		(82	)		-			(82	)
Issuance of shares through offerings and stock-   based compensation plans (See Note 5D)		70			-			70
Dividends declared		(550	)		-			(550	)
Distributions to noncontrolling interests		-			(3	)		(3	)
Balance, September 30, 2011	$	10,112		$	3		$	10,115
Balance, December 31, 2009	$	9,449		$	6		$	9,455
Cumulative effect of change in accounting   principle		-			(2	)		(2	)
Net income(a)		731			1			732
Other comprehensive loss		(77	)		-			(77	)
Issuance of shares through offerings and stock-   based compensation plans (See Note 5D)		461			-			461
Dividends declared		(543	)		-			(543	)
Distributions to noncontrolling interests		-			(2	)		(2	)
Balance, September 30, 2010	$	10,021		$	3		$	10,024

(a) For the nine months ended September 30, 2011, consolidated net income of $656 million includes $3 million attributable to preferred shareholders of subsidiaries. For the nine months ended September 30, 2010, consolidated net income of $735 million includes $3 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

PEC

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

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)		2011			2010
Net income		$	293		$	365
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $1)			2			1
Change in unrecognized items for pension and other postretirement benefits   (net of tax expense of $1 and $-)			2			1
Net unrealized losses on cash flow hedges (net of tax benefit of $44 and $19)			(69	)		(30	)
Net unrecognized items on pension and other postretirement benefits (net of   tax benefit of $2)			-			(4	)
Other (net of tax expense of $-)			-			(1	)
Other comprehensive loss			(65	)		(33	)
Comprehensive income			228			332
Comprehensive income attributable to noncontrolling interests			(2	)		(4	)
Comprehensive income attributable to controlling interests		$	226		$	328
	Nine months ended September 30
(in millions)			2011			2010
Net income		$	656		$	735
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $3 and $3)			5			4
Change in unrecognized items for pension and other postretirement benefits   (net of tax expense of $3 and $1)			4			3
Net unrealized losses on cash flow hedges (net of tax benefit of $53 and $51)			(83	)		(80	)
Net unrecognized items on pension and other postretirement benefits (net of   tax benefit of $5 and $2)			(8	)		(4	)
Other comprehensive loss			(82	)		(77	)
Comprehensive income			574			658
Comprehensive income attributable to noncontrolling interests			(5	)		(4	)
Comprehensive income attributable to controlling interests		$	569		$	654

PEC
	Three months ended September 30
(in millions)	2011			2010
Net income	$	199		$	236
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $1)		1			1
Net unrealized losses on cash flow hedges (net of tax benefit of $23 and $7)		(35	)		(10	)
Other comprehensive loss		(34	)		(9	)
Comprehensive income		165			227
Comprehensive income attributable to noncontrolling interests		-			(2	)
Comprehensive income attributable to controlling interests	$	165		$	225

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	Nine months ended September 30
(in millions)	2011			2010
Net income	$	437		$	483
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $2 and $2)		3			3
Net unrealized losses on cash flow hedges (net of tax benefit of $26 and $17)		(40	)		(26	)
Other comprehensive loss		(37	)		(23	)
Comprehensive income		400			460
Comprehensive loss attributable to noncontrolling interests		-			1
Comprehensive income attributable to controlling interests	$	400		$	461

PEF
	Three months ended September 30
(in millions)		2011			2010
Net income		$	203		$	180
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $11 and $3)			(17	)		(6	)
Other comprehensive loss			(17	)		(6	)
Comprehensive income		$	186		$	174
	Nine months ended September 30
(in millions)			2011			2010
Net income		$	418		$	401
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $14 and $10)			(22	)		(16	)
Other comprehensive loss			(22	)		(16	)
Comprehensive income		$	396		$	385

D. COMMON STOCK

At September 30, 2011 and December 31, 2010, we had 500 million shares of common stock authorized under our charter, of which 295 million and 293 million shares were outstanding, respectively. We periodically issue shares of common stock through the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)), the Progress Energy Investor Plus Plan (IPP) and other benefit plans.

The following table presents information for our common stock issuances:

	2011				2010
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Three months ended September 30
Total issuances		0.3	$	16		0.3	$	14
Issuances through 401(k) and/or IPP		-		-		0.3		13
Nine months ended September 30
Total issuances		1.7	$	42		11.8	$	419
Issuances through 401(k) and/or IPP		-		1		11.0		418

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6. PREFERRED STOCK OF SUBSIDIARIES

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 dividends payable on PEC or PEF preferred stock are in default for an amount equivalent to or exceeding four quarterly dividend payments, the holders of the preferred stock are entitled to elect a majority of PEC’s 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. The holders of PEF’s preferred stock have no right to vote except for certain circumstances involving dividends payable on preferred stock that are in default or certain matters affecting the rights and preferences of the preferred stock.

7. 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, 2010, are as follows.

On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due January 15, 2021. The net proceeds, along with available cash on hand, were used to retire the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011.

On May 3, 2011, $22 million of the Parent’s $500 million revolving credit agreement (RCA) expired, leaving the Parent with total credit commitments of $478 million supported by 14 financial institutions. After the $22 million expiration, our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions.

On July 15, 2011, PEF paid at maturity $300 million of its 6.65% First Mortgage Bonds with proceeds from commercial paper borrowings.

On August 18, 2011, PEF issued $300 million 3.10% First Mortgage Bonds due August 15, 2021. The net proceeds were used to repay a portion of outstanding short-term debt, of which $300 million was issued to repay PEF’s July 15, 2011 maturity.

On September 15, 2011, PEC issued $500 million 3.00% First Mortgage Bonds due September 15, 2021. A portion of the net proceeds was used to repay outstanding short-term debt and the remainder was placed in temporary investments for general corporate use as needed, including construction expenditures.

On September 30, 2011, the current portion of our long-term debt was $950 million (including $500 million at PEC). We expect to fund the current portion of long-term debt with a combination of cash from operations, commercial paper borrowings and/or long-term debt.

8. FAIR VALUE DISCLOSURES

A. DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $12.940 billion and $12.642 billion at September 30, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $15.1 billion and $14.0 billion at September 30, 2011 and December 31, 2010, respectively.

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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 4C of the 2010Form 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 investments in certain benefit trusts 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, 2011 and December 31, 2010:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2011
Common stock equity	$	925	$	41	$	313
Preferred stock and other equity		50		1		8
Corporate debt		90		1		6
U.S. state and municipal debt		121		2		6
U.S. and foreign government debt		289		-		17
Money market funds and other		89		-		2
Total	$	1,564	$	45	$	352
December 31, 2010
Common stock equity	$	1,021	$	13	$	408
Preferred stock and other equity		28		-		11
Corporate debt		90		-		6
U.S. state and municipal debt		132		4		3
U.S. and foreign government debt		264		2		10
Money market funds and other		52		-		1
Total	$	1,587	$	19	$	439

The NDT funds and other available-for-sale debt 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 table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and unrealized gains for 2011 and 2010 relate to the NDT funds.

The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $266 million and $195 million, respectively.

At September 30, 2011, the fair value of our available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	35
Due after one through five years		212
Due after five through 10 years		127
Due after 10 years		140
Total	$	514

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The following table presents selected information about our sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.

	Three months ended September 30				Nine months ended September 30
(in millions)	2011		2010		2011		2010
Proceeds	$	1,062	$	2,051	$	4,254	$	5,743
Realized gains		9		7		24		17
Realized losses		11		5		20		20

Proceeds were primarily related to NDT funds. Some of our benefit investment trusts are managed by third-party investment managers who have the right to sell securities without our authorization. Losses for investments in those benefit investment trusts were not material. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, our other securities had no investments in a continuous loss position for greater than 12 months.

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $4.193 billion and $3.693 billion at September 30, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.7 billion and $4.0 billion at September 30, 2011 and December 31, 2010, 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 4C of the 2010Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes PEC’s available-for-sale securities at September 30, 2011 and December 31, 2010:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2011
Common stock equity	$	599	$	27	$	198
Preferred stock and other equity		15		1		5
Corporate debt		72		1		5
U.S. state and municipal debt		53		-		3
U.S. and foreign government debt		213		-		16
Money market funds and other		41		-		1
Total	$	993	$	29	$	228
December 31, 2010
Common stock equity	$	652	$	10	$	256
Preferred stock and other equity		14		-		6
Corporate debt		72		-		5
U.S. state and municipal debt		51		1		1
U.S. and foreign government debt		199		1		9
Money market funds and other		42		-		1
Total	$	1,030	$	12	$	278

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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 table includes 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 for 2011 and 2010 relate to the NDT funds.

The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $142 million and $104 million, respectively.

At September 30, 2011, the fair value of PEC’s available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	15
Due after one through five years		147
Due after five through 10 years		77
Due after 10 years		110
Total	$	349

The following table presents selected information about PEC’s sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.

	Three months ended September 30				Nine months ended September 30
(in millions)	2011		2010		2011		2010
Proceeds	$	136	$	88	$	386	$	310
Realized gains		4		3		10		9
Realized losses		4		3		9		15

PEC’s proceeds were primarily related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, PEC did not have any other securities.

PEF

DEBT

The carrying amount of PEF’s long-term debt, including current maturities, was $4.482 billion at September 30, 2011 and December 31, 2010. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $5.4 billion and $5.0 billion at September 30, 2011 and December 31, 2010, 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 4C of the 2010Form 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, 2011 and December 31, 2010:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2011
Common stock equity	$	326	$	14	$	115
Preferred stock and other equity		35		-		3
Corporate debt		18		-		1
U.S. state and municipal debt		68		2		3
U.S. and foreign government debt		76		-		1
Money market funds and other		41		-		1
Total	$	564	$	16	$	124
December 31, 2010
Common stock equity	$	369	$	3	$	152
Preferred stock and other equity		14		-		5
Corporate debt		14		-		1
U.S. state and municipal debt		81		3		2
U.S. and foreign government debt		62		1		1
Money market funds and other		10		-		-
Total	$	550	$	7	$	161

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 table includes unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds.

The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $124 million and $87 million, respectively.

At September 30, 2011, the fair value of PEF’s available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	20
Due after one through five years		65
Due after five through 10 years		50
Due after 10 years		30
Total	$	165

The following table presents selected information about PEF’s sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.

	Three months ended September 30				Nine months ended September 30
(in millions)	2011		2010		2011		2010
Proceeds	$	926	$	1,891	$	3,861	$	5,305
Realized gains		5		3		14		7
Realized losses		7		2		11		5

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PEF’s proceeds were related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, PEF did not have any other securities.

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 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 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 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 in which quoted prices or other observable inputs are not available.

Certain assets and liabilities, including long-lived assets, were measured at fair value on a nonrecurring basis. There were no significant fair value measurement losses recognized for such assets and liabilities in the periods reported. These fair value measurements fall within Level 3 of the hierarchy discussed above.

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 as of September 30, 2011 and December 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input 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.

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PROGRESS ENERGY
(in millions)	Level 1		Level 2		Level 3		Total
September 30, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	925	$	-	$	-	$	925
Preferred stock and other equity		23		27		-		50
Corporate debt		-		90		-		90
U.S. state and municipal debt		1		118		-		119
U.S. and foreign government debt		100		188		-		288
Money market funds and other		-		40		-		40
Total nuclear decommissioning trust funds		1,049		463		-		1,512
Derivatives
Commodity forward contracts		-		7		-		7
Other marketable securities
Money market and other		18		7		-		25
Total assets	$	1,067	$	477	$	-	$	1,544
Liabilities
Derivatives
Commodity forward contracts	$	-	$	426	$	43	$	469
Interest rate contracts		-		86		-		86
Contingent value obligations		-		-		74		74
Total liabilities	$	-	$	512	$	117	$	629

(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,021	$	-	$	-	$	1,021
Preferred stock and other equity		22		6		-		28
Corporate debt		-		86		-		86
U.S. state and municipal debt		-		132		-		132
U.S. and foreign government debt		79		182		-		261
Money market funds and other		1		42		-		43
Total nuclear decommissioning trust funds		1,123		448		-		1,571
Derivatives
Commodity forward contracts		-		15		-		15
Interest rate contracts		-		4		-		4
Other marketable securities
Corporate debt		-		4		-		4
U.S. and foreign government debt		-		3		-		3
Money market and other		18		-		-		18
Total assets	$	1,141	$	474	$	-	$	1,615
Liabilities
Derivatives
Commodity forward contracts	$	-	$	458	$	36	$	494
Interest rate contracts		-		39		-		39
Contingent value obligations		-		15		-		15
Total liabilities	$	-	$	512	$	36	$	548

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PEC
(in millions)	Level 1		Level 2		Level 3		Total
September 30, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	599	$	-	$	-	$	599
Preferred stock and other equity		15		-		-		15
Corporate debt		-		72		-		72
U.S. state and municipal debt		1		52		-		53
U.S. and foreign government debt		89		124		-		213
Money market funds and other		-		40		-		40
Total nuclear decommissioning trust funds		704		288		-		992
Other marketable securities		3		-		-		3
Total assets	$	707	$	288	$	-	$	995
Liabilities
Derivatives
Commodity forward contracts	$	-	$	92	$	42	$	134
Interest rate contracts		-		43		-		43
Total liabilities	$	-	$	135	$	42	$	177

(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	652	$	-	$	-	$	652
Preferred stock and other equity		14		-		-		14
Corporate debt		-		72		-		72
U.S. state and municipal debt		-		51		-		51
U.S. and foreign government debt		76		123		-		199
Money market funds and other		1		28		-		29
Total nuclear decommissioning trust funds		743		274		-		1,017
Derivatives
Commodity forward contracts		-		2		-		2
Interest rate contracts		-		3		-		3
Other marketable securities		4		-		-		4
Total assets	$	747	$	279	$	-	$	1,026
Liabilities
Derivatives
Commodity forward contracts	$	-	$	87	$	36	$	123
Interest rate contracts		-		11		-		11
Total liabilities	$	-	$	98	$	36	$	134

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PEF
(in millions)	Level 1		Level 2		Level 3		Total
September 30, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	326	$	-	$	-	$	326
Preferred stock and other equity		8		27		-		35
Corporate debt		-		18		-		18
U.S. state and municipal debt		-		66		-		66
U.S. and foreign government debt		11		64		-		75
Total nuclear decommissioning trust funds		345		175		-		520
Derivatives
Commodity forward contracts		-		7		-		7
Other marketable securities		1		-		-		1
Total assets	$	346	$	182	$	-	$	528
Liabilities
Derivatives
Commodity forward contracts	$	-	$	334	$	1	$	335
Interest rate contracts		-		8		-		8
Total liabilities	$	-	$	342	$	1	$	343

(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	369	$	-	$	-	$	369
Preferred stock and other equity		8		6		-		14
Corporate debt		-		14		-		14
U.S. state and municipal debt		-		81		-		81
U.S. and foreign government debt		3		59		-		62
Money market funds and other		-		14		-		14
Total nuclear decommissioning trust funds		380		174		-		554
Derivatives
Commodity forward contracts		-		13		-		13
Other marketable securities		1		-		-		1
Total assets	$	381	$	187	$	-	$	568
Liabilities
Derivatives
Commodity forward contracts	$	-	$	371	$	-	$	371
Interest rate contracts		-		7		-		7
Total liabilities	$	-	$	378	$	-	$	378

The determination of the fair values in the preceding tables 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 forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract 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

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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. 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 primarily represent available-for-sale debt securities used to fund certain employee benefit costs.

Contingent Value Obligations (CVOs), which are derivatives, are discussed further in Note 10. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and we have classified CVOs as Level 3. The CVOs were previously recorded at fair value based on quoted prices from a less-than-active market and classified as Level 2.

Transfers in (out) of Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher Level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. There were no significant transfers in (out) of Levels 1, 2 and 3 during the period other than the CVO transfer previously discussed. Transfers into and out of each Level are measured at the end of the period.

A reconciliation of changes in the fair value of our and the Utilities’ derivative liabilities for CVOs and commodities, as  applicable, classified as Level 3 in the fair value hierarchy for the periods ended September 30 follows:

PROGRESS ENERGY
	Three months ended September 30					Nine months ended September 30
(in millions)		2011		2010			2011		2010
Derivatives, net at beginning of period		$	37	$	62		$	36	$	39
Total losses, realized and unrealized - commodities
deferred as regulatory assets and liabilities, net			6		23			7		46
Transfers in (out) of Level 3, net - CVOs			74		-			74		-
Derivatives, net at end of period		$	117	$	85		$	117	$	85

PEC
	Three months ended September 30					Nine months ended September 30
(in millions)			2011		2010			2011		2010
Derivatives, net at beginning of period		$	37	$	42		$	36	$	27
Total losses, realized and unrealized - commodities
deferred as regulatory assets and liabilities, net			5		13			6		28
Derivatives, net at end of period		$	42	$	55		$	42	$	55

PEF
	Three months ended September 30					Nine months ended September 30
(in millions)			2011		2010			2011		2010
Derivatives, net at beginning of period		$	-	$	20		$	-	$	12
Total losses, realized and unrealized - commodities
deferred as regulatory assets and liabilities, net			1		10			1		18
Derivatives, net at end of period		$	1	$	30		$	1	$	30

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Substantially all unrealized gains and losses on the Utilities’ derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Unrealized losses on the change in fair value of our CVOs are discussed in Note 12. There were no Level 3 purchases, sales, issuances or settlements during the period.

9. INCOME TAXES

PROGRESS ENERGY

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Our federal tax years are open for examination from 2007 forward, and our open state tax years in our major jurisdictions are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns.

At September 30, 2011 and December 31, 2010, our liability for unrecognized tax benefits was $176 million. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $6 million at September 30, 2011.

At September 30, 2011 and December 31, 2010, we had accrued $19 million and $45 million, respectively, for interest and penalties, which were included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets. The decrease in interest and penalties was due to the completion of the examination of the 2004 and 2005 tax returns previously discussed.

PEC

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 federal tax years are open for examination from 2007 forward, and PEC’s open state tax years in our major jurisdictions are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns.

At September 30, 2011 and December 31, 2010, PEC’s liability for unrecognized tax benefits was $79 million and $74 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $4 million at September 30, 2011.

At September 30, 2011 and December 31, 2010, PEC had accrued $8 million and $14 million, respectively, for interest and penalties, which were included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets. The decrease in interest and penalties was due to the completion of the examination of the 2004 and 2005 tax returns previously discussed.

PEF

We file consolidated federal and state income tax returns that include PEF. PEF’s federal tax years are open for examination from 2007 forward and PEF’s open state tax years are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns.

At September 30, 2011 and December 31, 2010, PEF’s liability for unrecognized tax benefits was $87 million and $99 million, respectively. 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, 2011.

At September 30, 2011, PEF had accrued $7 million for interest and penalties, which were included in other current assets and other liabilities and deferred credits on the Balance Sheets. At December 31, 2010, PEF had accrued $29 million for interest and penalties, which were included in interest accrued and other assets and deferred debits on the Balance Sheets. The decrease in interest and penalties was due to the completion of the examination of the 2004 and 2005 tax returns previously discussed.

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10.  CONTINGENT VALUE OBLIGATIONS

In connection with the acquisition of Florida Progress Corporation (Florida Progress) during 2000, the Parent issued 98.6 million CVOs. Each CVO represents the right of the holder to receive contingent payments based on the performance of four coal-based solid synthetic fuels limited liability companies purchased by subsidiaries of Florida Progress in October 1999. All of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007 (See Note 15 of the 2010 Form 10-K).

On June 10, 2011, Davidson Kempner Partners, M.H. Davidson & Co., Davidson Kempner Institutional Partners, L.P., and Davidson Kempner International, Ltd. (jointly, Davidson Kempner) filed a lawsuit against us (see Note 15C) related to their ownership of CVOs. On October 3, 2011, we entered a settlement agreement and release with Davidson Kempner under which the parties mutually released all claims related to the CVOs and we purchased all of Davidson Kempner’s CVOs at a negotiated purchase price of $0.75 per CVO. The settlement agreement also contemplated a tender offer to remaining CVO holders at the same purchase price. Accordingly, we determined the purchase price included in the settlement agreement represented the fair value of the CVOs at September 30, 2011 (see Note 8). We commenced the tender offer in early November. The unrealized loss due to the change in fair value is recorded in other, net on the Consolidated Statements of Income. At September 30, 2011, the CVO liability included in other current liabilities on our Consolidated Balance Sheets was $74 million, and at December 31, 2010, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $15 million.

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 months ended September 30 were:

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	13		$	12		$	3	$	3
Interest cost		35			35			10		13
Expected return on plan assets		(45	)		(40	)		-		(1	)
Amortization of actuarial loss(a)		16			13			3		6
Other amortization, net (a)		2			2			1		1
Net periodic cost	$	21		$	22		$	17	$	22

(a) Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2010 Form 10-K.

PEC
	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	5		$	5		$	2	$	1
Interest cost		16			16			5		6
Expected return on plan assets		(23	)		(20	)		-		-
Amortization of actuarial loss		7			4			1		3
Other amortization, net		1			1			-		-
Net periodic cost	$	6		$	6		$	8	$	10

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PEF
	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	6		$	6		$	1	$	1
Interest cost		15			15			4		6
Expected return on plan assets		(19	)		(17	)		-		-
Amortization of actuarial loss		8			8			2		3
Other amortization, net		-			-			1		1
Net periodic cost	$	10		$	12		$	8	$	11

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

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Service cost	$	40		$	36		$	8		$	7
Interest cost		105			105			30			29
Expected return on plan assets		(136	)		(119	)		(1	)		(3	)
Amortization of actuarial loss(a)		49			38			9			6
Other amortization, net (a)		5			5			4			4
Net periodic cost	$	63		$	65		$	50		$	43

(a) Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2010 Form 10-K.

PEC
	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	16		$	14		$	3	$	4
Interest cost		47			48			15		14
Expected return on plan assets		(68	)		(58	)		-		(1	)
Amortization of actuarial loss		19			12			4		3
Other amortization, net		4			4			1		1
Net periodic cost	$	18		$	20		$	23	$	21

PEF
	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Service cost	$	18		$	16		$	3		$	2
Interest cost		45			44			13			12
Expected return on plan assets		(59	)		(51	)		(1	)		(1	)
Amortization of actuarial loss		25			23			6			3
Other amortization, net		-			-			3			3
Net periodic cost	$	29		$	32		$	24		$	19

In 2011, we expect to make contributions directly to pension plan assets of approximately $325 million to $350 million for us, including $215 million to $225 million for PEC and $110 million to $125 million for PEF. We contributed $313 million during the nine months ended September 30, 2011, including $207 million for PEC and $105 million for PEF.

As a result of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act, which were enacted in March 2010, we recognized an additional tax expense of $22 million, including $12 million for PEC and $10 million for PEF, during the nine months ended September 30, 2010. See Note 16A in the 2010 Form 10-K.

42

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 financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2011 and 2012. 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. Progress Energy had a cash collateral asset included in derivative collateral posted of $112 million and $164 million on the Progress Energy Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, Progress Energy had 339.4 million MMBtu notional of natural gas and 12.3 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $14 million and $24 million on the PEC Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEC had 98.4 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases.

PEF’s cash collateral asset included in derivative collateral posted was $98 million and $140 million on the PEF Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEF had 241.0 million MMBtu notional of natural gas and 12.3 million gallons notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases.

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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. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. 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, 2011, all open interest rate hedges will reach their mandatory termination dates in approximately two years. At September 30, 2011, including amounts related to terminated hedges, we had $140 million of after-tax losses, including $70 million and $26 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $12 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities and changes in market value of currently open forward starting swaps.

At December 31, 2010, including amounts related to terminated hedges, we had $63 million of after-tax losses, including $33 million and $4 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps.

At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. At September 30, 2011, Progress Energy had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

FAIR VALUE HEDGES

For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At September 30, 2011, and December 31, 2010, neither we nor the Utilities had any outstanding positions in such contracts.

C. CONTINGENT FEATURES

Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company’s credit rating with Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions.

In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody’s, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions.

The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $377 million at September 30, 2011, for which Progress Energy has posted collateral of $112 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, Progress Energy would have been required to post an additional $265 million of collateral with its counterparties.

44

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $116 million at September 30, 2011, for which PEC has posted collateral of $14 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, PEC would have been required to post an additional $102 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $261 million at September 30, 2011, for which PEF has posted collateral of $98 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on September 30, 2011, PEF would have been required to post an additional $163 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, 2011 and December 31, 2010:

Instrument / Balance sheet location	September 30, 2011					December 31, 2010
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current				$	1				$	-
Interest rate derivatives
Prepayments and other current assets	$	-				$	1
Other assets and deferred debits		-					3
Derivative liabilities, current					70					32
Derivative liabilities, long-term					16					7
Total derivatives designated as hedging instruments		-			87		4			39
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		6					11
Other assets and deferred debits		1					4
Derivative liabilities, current					231					226
Derivative liabilities, long-term					237					268
CVOs(b)
Other current liabilities					74					-
Other liabilities and deferred credits					-					15
Fair value of derivatives not designated as hedging instruments		7			542		15			509
Fair value loss transition adjustment(c)
Derivative liabilities, current					1					1
Derivative liabilities, long-term					2					3
Total derivatives not designated as hedging instruments		7			545		15			513
Total derivatives	$	7		$	632	$	19		$	552

(a)	Substantially all of these contracts receive regulatory treatment.
(b)	As discussed in Note 10, 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 contracts.

45

The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the three months ended September 30, 2011 and 2010:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2011			2010			2011			2010			2011			2010
Commodity cash flow derivatives(d)	$	(1	)	$	-		$	-		$	-		$	-		$	-
Interest rate derivatives(c) (e)		(68	)		(30	)		(2	)		(1	)		(1	)		-
Total	$	(69	)	$	(30	)	$	(2	)	$	(1	)	$	(1	)	$	-

(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI 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.
(d)	Amounts recorded in the Consolidated Statements of Income are classified in fuel used in electric generation.
(e)	Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2011			2010				2011			2010
Commodity derivatives		$	(91	)	$	(114	)		$	(157	)	$	(181	)

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2011			2010
Fair value loss transition adjustment(a)	$	1		$	1
CVOs(a)		(63	)		-
Total	$	(62	)	$	1

(a) Amounts recorded in the Consolidated Statements of Income are classified in other, net.

46

The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the nine months ended September 30, 2011 and 2010:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)						Amount of Pre-tax Gain or (Loss) Recognized in ncome on Derivatives(b)
(in millions)	2011			2010			2011			2010			2011			2010
Commodity cash flow derivatives(d)	$	(1	)	$	-		$	-		$	-		$	-		$	-
Interest rate derivatives(c) (e)		(82	)		(80	)		(5	)		(4	)		(3	)		-
Total	$	(83	)	$	(80	)	$	(5	)	$	(4	)	$	(3	)	$	-

(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI 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.
(d)	Amounts recorded in the Consolidated Statements of Income are classified in fuel used in electric generation.
(e)	Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2011			2010				2011			2010
Commodity derivatives		$	(219	)	$	(264	)		$	(201	)	$	(417	)

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2011			2010
Commodity derivatives(a)	$	1		$	-
Fair value loss transition adjustment(a)		1			1
CVOs(a)		(59	)		-
Total	$	(57	)	$	1

(a) Amounts recorded in the Consolidated Statements of Income are classified in other, net.

47

PEC

The following table presents the fair value of derivative instruments at September 30, 2011 and December 31, 2010:

Instrument / Balance sheet location	September 30, 2011						December 31, 2010
(in millions)		Asset		Liability				Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Other assets and deferred debits		$	-					$	3
Derivative liabilities, current					$	35					$	7
Other liabilities and deferred credits						8						4
Total derivatives designated as hedging instruments			-			43			3			11
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets			-						1
Other assets and deferred debits			-						1
Derivative liabilities, current						57						45
Other liabilities and deferred credits						77						78
Fair value of derivatives not designated as hedging instruments			-			134			2			123
Fair value loss transition adjustment(b)
Derivative liabilities, current						1						1
Other liabilities and deferred credits						2						3
Total derivatives not designated as hedging instruments			-			137			2			127
Total derivatives		$	-		$	180		$	5		$	138

(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 contracts.

The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the three months ended September 30, 2011 and 2010:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)							Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)							Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)		2011			2010				2011			2010				2011			2010
Interest rate derivatives(c) (d)		$	(35	)	$	(10	)		$	(1	)	$	(1	)		$	(1	)	$	-

(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI 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.
(d)	Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

48

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2011			2010				2011			2010
Commodity derivatives		$	(20	)	$	(17	)		$	(42	)	$	(38	)

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2011		2010
Fair value loss transition adjustment(a)	$	1	$	1

(a) Amounts recorded in the Consolidated Statements of Income are classified in other, net.

The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the nine months ended September 30, 2011 and 2010:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)						Amount of Pre-tax  Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2011			2010			2011			2010			2011			2010
Interest rate derivatives(c) (d)	$	(40	)	$	(26	)	$	(3	)	$	(3	)	$	(1	)	$	-

(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI 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.
(d)	Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2011			2010				2011			2010
Commodity derivatives		$	(42	)	$	(36	)		$	(55	)	$	(82	)

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

49

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2011		2010
Commodity derivatives(a)	$	1	$	-
Fair value loss transition adjustment(a)		1		1
Total	$	2	$	1

(a) Amounts recorded in the Consolidated Statements of Income are classified in other, net.

PEF

The following table presents the fair value of derivative instruments at September 30, 2011 and December 31, 2010:

Instrument / Balance sheet location	September 30, 2011						December 31, 2010
(in millions)		Asset		Liability				Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current					$	1					$	-
Interest rate derivatives
Derivative liabilities, current						-						7
Derivative liabilities, long-term						8						-
Total derivatives designated as hedging instruments						9						7
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		$	6					$	10
Other assets and deferred debits			1						3
Derivative liabilities, current						174						181
Derivative liabilities, long-term						160						190
Total derivatives not designated as hedging instruments			7			334			13			371
Total derivatives		$	7		$	343		$	13		$	378

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

50

The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Statements of Income for the three months ended September 30, 2011 and 2010:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2011			2010			2011		2010		2011		2010
Commodity cash flow derivatives(d)	$	(1	)	$	-		$	-	$	-	$	-	$	-
Interest rate derivatives(c) (e)		(16	)		(6	)		-		-		-		-
Total	$	(17	)	$	(6	)	$	-	$	-	$	-	$	-

(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI 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.
(d)	Amounts recorded in the Statements of Income are classified in fuel used in electric generation.
(e)	Amounts recorded in the Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2011			2010				2011			2010
Commodity derivatives		$	(71	)	$	(97	)		$	(115	)	$	(143	)

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.

The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Statements of Income for the nine months ended September 30, 2011 and 2010:

Derivatives Designated as Hedging Instruments
Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)	2011			2010			2011		2010		2011		2010
Commodity cash flow derivatives(d)	$	(1	)	$	-		$	-	$	-	$	-	$	-
Interest rate derivatives(c) (e)		(21	)		(16	)		-		-		-		-
Total	$	(22	)	$	(16	)	$	-	$	-	$	-	$	-

(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI 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.
(d)	Amounts recorded in the Consolidated Statements of Income are classified in fuel used in electric generation.
(e)	Amounts recorded in the Consolidated Statements of Income are classified in interest charges.

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Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2011			2010				2011			2010
Commodity derivatives		$	(177	)	$	(228	)		$	(146	)	$	(335	)

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.

13.  FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

Products and services are sold between the various reportable segments. All intersegment transactions are at cost.

(in millions)	PEC		PEF		Corporate and Other				Eliminations			Totals
At and for the three months ended September 30, 2011
Revenues
Unaffiliated	$	1,332	$	1,413		$	2		$	-		$	2,747
Intersegment		-		1			69			(70	)		-
Total revenues		1,332		1,414			71			(70	)		2,747
Ongoing Earnings		202		202			(60	)		-			344
Total Assets		15,543		14,014			20,954			(16,834	)		33,677
For the three months ended September 30, 2010
Revenues
Unaffiliated	$	1,414	$	1,543		$	5		$	-		$	2,962
Intersegment		-		-			66			(66	)		-
Total revenues		1,414		1,543			71			(66	)		2,962
Ongoing Earnings		233		177			(49	)		-			361
For the nine months ended September 30, 2011
Revenues
Unaffiliated	$	3,525	$	3,637		$	8		$	-		$	7,170
Intersegment		-		2			203			(205	)		-
Total revenues		3,525		3,639			211			(205	)		7,170
Ongoing Earnings		453		454			(150	)		-			757
For the nine months ended September 30, 2010
Revenues
Unaffiliated	$	3,794	$	4,064		$	11		$	-		$	7,869
Intersegment		-		1			179			(180	)		-
Total revenues		3,794		4,065			190			(180	)		7,869
Ongoing Earnings		493		409			(146	)		-			756

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Management uses the non-GAAP financial measure “Ongoing Earnings” as a performance measure to evaluate the results of our segments and operations. Ongoing Earnings is computed as GAAP net income attributable to controlling interests less discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Management has identified the following Ongoing Earnings adjustments: tax levelization, which increases or decreases the tax expense recorded in the reporting period to reflect the annual projected tax rate, because it has no impact on annual earnings; CVO mark-to-market adjustments because we are unable to predict changes in their fair value; CR3 indemnification charge (and subsequent adjustments, if any) for estimated future years’ joint owner replacement power costs (through the expiration of the indemnification provisions of the joint owner agreement) because GAAP requires that the charge be accounted for in the period in which it becomes probable and estimable rather than the periods to which it relates; and the impact from changes in the tax treatment of the Medicare Part D subsidy because GAAP requires that the impact of the tax law change be accounted for in the period of enactment rather than the affected tax year. Additionally, management does not consider impairments, charges (and subsequent adjustments, if any) recognized for the retirement of generating units prior to the end of their estimated useful lives, merger and integration costs, and operating results of discontinued operations to be representative of our ongoing operations and excluded these items in computing Ongoing Earnings.

Reconciliations of consolidated Ongoing Earnings to net income attributable to controlling interests follow:

	For the three months ended September 30
(in millions)		2011			2010
Ongoing Earnings		$	344		$	361
Tax levelization			8			4
CVO mark-to-market, net of tax benefit of $13 (Note 10)			(50	)		-
Impairment, net of tax benefit of $1			-			(2	)
Merger and integration costs, net of tax benefit of $7 (Note 2)			(15	)		-
CR3 indemnification adjustment, net of tax expense of $2 (Note 15B)			4			-
Continuing income attributable to noncontrolling interests, net of tax			2			2
Income from continuing operations before cumulative effect of change in   accounting principle			293			365
Discontinued operations, net of tax			-			(2	)
Cumulative effect of change in accounting principle, net of tax			-			2
Net income attributable to noncontrolling interests, net of tax			(2	)		(4	)
Net income attributable to controlling interests		$	291		$	361
	For the nine months ended September 30
(in millions)			2011			2010
Ongoing Earnings		$	757		$	756
Tax levelization			2			3
CVO mark-to-market, net of tax benefit of $13 (Note 10)			(46	)		-
Impairment, net of tax benefit of $3			-			(5	)
Plant retirement adjustment, net of tax expense of $1			-			1
Change in tax treatment of the Medicare Part D subsidy (Note 11)			-			(22	)
Merger and integration costs, net of tax benefit of $11 (Note 2)			(36	)		-
CR3 indemnification charge, net of tax benefit of $16 (Note 15B)			(22	)		-
Continuing income attributable to noncontrolling interests, net of tax			5			4
Income from continuing operations			660			737
Discontinued operations, net of tax			(4	)		(2	)
Net income attributable to noncontrolling interests, net of tax			(5	)		(4	)
Net income attributable to controlling interests		$	651		$	731

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14. ENVIRONMENTAL MATTERS

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

A.  HAZARDOUS AND SOLID WASTE

The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, 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. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

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 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.

We measure our liability for environmental 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 in O&M expense on the Income Statements 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.

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The following tables contain 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:

PROGRESS ENERGY
(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2010	$	20		$	15		$	35
Amount accrued for environmental loss contingencies(a)		1			6			7
Expenditures for environmental loss contingencies(b)		(4	)		(13	)		(17	)
Balance, September 30, 2011(c)	$	17		$	8		$	25
Balance, December 31, 2009	$	22		$	20		$	42
Amount accrued for environmental loss contingencies(a)		7			11			18
Expenditures for environmental loss contingencies(b)		(8	)		(14	)		(22	)
Balance, September 30, 2010(c)	$	21		$	17		$	38

(a)	Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, our accruals for environmental loss contingencies were not material.
(b)	Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011, our expenditures for environmental loss contingencies were not material. For the three months ended September 30, 2010, our expenditures were not material for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
(c)	Expected to be paid out over one to 15 years.

PEC
(in millions)	MGP and Other Sites
Balance, December 31, 2010	$	12
Amount accrued for environmental loss contingencies(a)		-
Expenditures for environmental loss contingencies(b)		(1	)
Balance, September 30, 2011(c)	$	11
Balance, December 31, 2009	$	13
Amount accrued for environmental loss contingencies(a)		3
Expenditures for environmental loss contingencies(b)		(4	)
Balance, September 30, 2010(c)	$	12

(a)	Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEC's accruals for the remediation of MGP and other sites were not material.
(b)	Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEC's expenditures for the remediation of MGP and other sites were not material.
(c)	Expected to be paid out over one to five years.

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PEF
(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2010	$	8		$	15		$	23
Amount accrued for environmental loss contingencies(a)		1			6			7
Expenditures for environmental loss contingencies(b)		(3	)		(13	)		(16	)
Balance, September 30, 2011(c)	$	6		$	8		$	14
Balance, December 31, 2009	$	9		$	20		$	29
Amount accrued for environmental loss contingencies(a)		4			11			15
Expenditures for environmental loss contingencies(b)		(4	)		(14	)		(18	)
Balance, September 30, 2010(c)	$	9		$	17		$	26

(a)	Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEF's accruals for environmental loss contingencies were not material.
(b)	Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011, PEF's expenditures were not material for the remediation of MGP and other sites and were $4 million for the remediation of distribution and substation transformers. For the three months ended September 30, 2010, PEF's expenditures were not material for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
(c)	Expected to be paid out over one to 15 years.

PROGRESS ENERGY

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

PEC

PEC has recorded a minimum estimated total remediation cost for its remaining MGP sites based upon its historical experience with remediation of its MGP sites remediated to date. The maximum amount of the range for all the sites cannot be determined at this time. 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 Transformer site in Raleigh, N.C. (Ward). 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, 2011 and December 31, 2010, PEC’s recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against 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. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. In June 2010, the court entered a case management order and discovery is proceeding. The court also set a trial date for May 7, 2012. The outcome of these matters cannot be predicted.

In 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

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past expenditures in addressing conditions at the site. On September 29, 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. 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

The accruals for PEF’s MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of a population of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed these distribution transformer sites and substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC.

B. AIR AND WATER QUALITY

We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations include 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 air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the CAIR.

In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court’s prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for NOx and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of NOx and SO2 emissions in addition to particulate matter emissions for PEF’s BART-eligible units, because Florida will no longer be subject to the annual emissions provisions. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. We are currently evaluating the impacts of the CSAPR.

In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it would develop a maximum achievable control technology (MACT) standard. The

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U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On October 21, 2011, the EPA requested the U.S. District Court for the District of Columbia to extend the deadline for the final rule to December 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following the conclusion of the 90-day public comment period, the EPA has requested to issue a final rule in December 2011. In addition, North Carolina adopted a state-specific mercury requirement. 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 the EPA’s proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment 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 originally anticipated to be around 2020. As discussed in Note 4B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

We account for emission allowances as inventory using the average cost method. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs effective January 1, 2012. SO2 emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. NOx allowances cannot be utilized to comply with other requirements. Therefore, NOx allowances that are not expected to be used in 2011 have been classified as obsolete inventory. PEC had an immaterial amount of NOx emission allowances. During the three and nine months ended September 30, 2011, PEF reduced the value of its NOx allowance inventory by $23 million, which is the remaining amount of NOx allowances that are not expected to be used in 2011. PEF believes the purchases of NOx emission allowances to meet the requirements of the CAIR were prudent and expects to recover the retail portion of the costs of these allowances through its ECRC. Accordingly, PEF recorded a $22 million regulatory asset for the retail portion of its NOx allowances. Therefore, there was no material impact to PEF’s results of operations for the reduction in value of its NOx allowance inventory.

15.  COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2010 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 2010 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs. At September 30, 2011, our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2010 Form 10-K other than as follows:

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PEC

As described in Note 22A in the 2010 Form 10-K, PEC entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs. As the transactions are subject to several conditions precedent, the estimated costs associated with these agreements were not included in PEC’s fuel commitments at December 31, 2010. The estimated total cost to PEC associated with these agreements at December 31, 2010,was approximately $2.042 billion, which pertain to the period from May 2011 through May 2033. During the nine months ended September 30, 2011, the conditions precedent for one of the agreements were satisfied. The agreement is for the period May 2011 through April 2031 and has an estimated total cost of approximately $487 million, including $16 million, $49 million, $49 million and $373 million, respectively, for less than one year, one to three years, three to five years and more than five years from December 31, 2010.

PEF

As described in Note 22A in the 2010 Form 10-K, PEF entered into conditional agreements for firm pipeline transportation capacity to support PEF’s gas supply needs. As the transactions were subject to several conditions precedent, the estimated costs associated with these agreements were not included in PEF’s fuel commitments at December 31, 2010. During the nine months ended September 30, 2011, the conditions precedent for these agreements were satisfied. These agreements are for the period April 2011 through April 2036 and have an estimated total cost of approximately $1.171 billion, including $36 million, $95 million, $95 million and $945 million, respectively, for less than one year, one to three years, three to five years and more than five years from December 31, 2010.

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, 2011, 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, 2011, 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. At September 30, 2011, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $351 million, including $75 million at PEF. 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. As part of settlement agreements entered into in 2002, PEF is responsible for providing the joint owners of CR3 a specified amount of generating capacity through the expiration of the indemnification provisions of the joint owner agreement in 2013. Due to the CR3 outage (See Note 4B), PEF has been unable to meet the required generating capacity and has provided replacement power from other generation sources or purchased power. During the nine months ended September 30, 2011, we and PEF recorded indemnification charges totaling $56 million for estimated joint owner replacement power costs for 2011 and future years, and provided replacement power totaling $17 million. At September 30, 2011 and December 31, 2010, we had recorded liabilities related to guarantees and indemnifications to third parties of $77 million and $31 million, respectively. These amounts included $50 million and $6 million for PEF at September 30, 2011 and December 31, 2010, respectively. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 16).

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C. OTHER COMMITMENTS AND CONTINGENCIES

MERGER

During January and February 2011, Progress Energy and its directors were named as defendants in eleven purported class action lawsuits with ten lawsuits brought in the Superior Court, Wake County, N.C. and one lawsuit filed in the United States District Court for the Eastern District of North Carolina, each in connection with the Merger (we refer to these lawsuits as the “actions”). The complaints in the actions allege, among other things, that the Merger Agreement was the product of breaches of fiduciary duty by the individual defendants, in that it allegedly does not provide for full and fair value for Progress Energy’s shareholders; that the Merger Agreement contains coercive deal protection measures; and that the Merger Agreement and the Merger were approved as a result, allegedly, of improper self-dealing by certain defendants who would receive certain alleged employment compensation benefits and continued employment pursuant to the Merger Agreement. The complaints in the actions also allege that Progress Energy aided and abetted the individual defendants’ alleged breaches of fiduciary duty. As relief, the plaintiffs in the actions seek, among other things, to enjoin completion of the Merger. The defendants believe that the allegations of the complaints in the actions are without merit and that they have substantial meritorious defenses to the claims made in the actions.

Additionally, the complaint in the federal action was amended in early April 2011 to include allegations that the defendants violated federal securities laws in connection with statements contained in the Registration Statement. Given the new allegations invoking federal securities laws, the defendants intend to move, plead, or otherwise respond to the amended federal complaint consistent with the provisions of the Private Securities Litigation Reform Act, which now governs the federal action.

On March 31, 2011, counsel for the federal action plaintiff sent a derivative demand letter to Mr. William D. Johnson, Chairman, President and CEO of Progress Energy, demanding that the Progress Energy board of directors desist from moving forward with the Merger, make certain disclosures, and engage in an auction of the company. Also on March 31, 2011, the same counsel sent Mr. Johnson a substantially identical derivative demand letter on behalf of two other purported Progress Energy shareholders.

On April 13, 2011, counsel for the federal action plaintiff sent another derivative demand letter to Mr. Johnson further demanding that the Progress Energy board of directors desist from moving forward with the Merger unless certain changes are made to the Merger Agreement and additional disclosures are made. Also on April 13, 2011, the same counsel sent Mr. Johnson a substantially identical derivative demand letter on behalf of two other purported Progress Energy shareholders.

On April 25, 2011, the Progress Energy board of directors established a special committee of disinterested directors to conduct a review and evaluation of the allegations and legal claims set forth in the derivative demand letters. The special committee investigated the allegations and legal claims and determined there was no basis to pursue the claims.

By order dated June 17, 2011, the court consolidated the state court cases. On June 21, 2011, the plaintiffs in the state court actions filed a verified consolidated amended complaint in the consolidated state court actions alleging breach of fiduciary duty by the individual defendants, and that Progress Energy aided and abetted the individual defendants’ alleged breaches of fiduciary duty. The verified consolidated amended complaint further alleges that the Registration Statement and amendments filed on April 8, April 25, and May 13, 2011, failed to disclose material facts, giving rise to plaintiffs’ claims.

On July 11, 2011, solely to avoid the costs, risks and uncertainties inherent in litigation and to allow its shareholders to vote on the proposals required in connection with the Merger at its special meeting of its shareholders, Progress Energy entered into a memorandum of understanding with plaintiffs in the consolidated state court actions and other named defendants to settle the consolidated action and all related claims that were or could have been asserted in other actions, subject to court approval. If the court approves the settlement contemplated in the memorandum of understanding, the claims will be released and the consolidated amended complaint will be dismissed with prejudice. Pursuant to the terms of the memorandum of understanding, Progress Energy agreed to make available additional information to its shareholders in advance of the special meeting of shareholders of Progress Energy held on

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August 23, 2011, in Raleigh, N.C. to vote upon the proposal to approve the plan of merger contained in the Merger Agreement. The additional information was contained in a Current Report on Form 8-K dated July 11, 2011 and filed by Progress Energy with the SEC on July 15, 2011. In addition, Progress Energy has agreed to pay the legal fees and expenses of plaintiffs’ counsel not to exceed $550,000 and ultimately determined by the court. At a hearing on July 29, 2011, the court indicated that it would provide preliminary approval of the settlement so that the special meeting of the shareholders to vote on the merger could proceed as scheduled on August 23, 2011.

On October 27, 2011, a final hearing was held to consider the settlement and plaintiffs’ application to the court for attorneys’ fees and expenses. A court order is expected by the end of November. The details of the settlement were set forth in a notice sent to Progress Energy’s shareholders of record that were members of the class as of July 5, 2011. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into such stipulation. In such event, the proposed settlement as contemplated by the memorandum of understanding may be terminated. The settlement will not affect the merger consideration to be paid to shareholders of Progress Energy in connection with the proposed Merger.

We cannot predict the outcome of these matters.

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 14).

Hurricane Katrina

In May 2011, PEC and PEF were named in a complaint of a class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claim that PEC and PEF, along with numerous other utility, oil, coal and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that defendants’ greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. We believe the plaintiffs’ claim is without merit; however, we cannot predict the outcome of this matter.

Water Discharge Permit

On October 5, 2011, Earthjustice, on behalf of the Sierra Club and Florida Wildlife Federation, filed a petition seeking review of the water discharge permit issued to CR1, CR2 and CR3. The petition raises a number of technical and legal issues with respect to the permit, all of which PEF disputes. The FDEP advised PEF that it intends to accept the petition for hearing. If the petitioners are successful in their challenge, additional controls could be required, the cost of which could be material. We cannot predict the outcome of this matter.

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts with the U.S. 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 U.S. 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. The Utilities have asserted over $90 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 may file subsequent damage claims as they incur additional costs.

In 2008, the Utilities received a ruling from the United States Court of Federal Claims awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. A request for reconsideration filed by the DOJ resulted in an immaterial reduction of the award. Substantially all of the award relates to costs incurred by PEC. On August 15, 2008, the DOJ appealed the U.S. Court of Federal Claims ruling to the D.C. Court of Appeals. 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

61

and other indirect expenses. The DOJ requested a rehearing en banc but the D.C. Court of Appeals denied the motion on November 3, 2009. The U.S. Court of Federal Claims held the remand hearing on the calculation of damages on February 16, 2011. On June 14, 2011, the judge issued a ruling to award the Utilities substantially all their asserted damages. In September 2011, after the government dismissed its notice of appeal, the judgment became final. As a result, during the three months ended September 30, 2011, PEC recorded the $92 million award as an offset for past spent fuel storage costs incurred, of which $27 million was O&M expense.

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), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global 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 Internal Revenue Code 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.

The jury awarded Global $78 million. On October 23, 2009, Global filed a motion to assess prejudgment interest on the award. On November 20, 2009, the court granted the motion and assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. On December 18, 2009, we appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we made a $154 million payment, which represents payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument was held on September 27, 2011. We cannot predict the outcome of this matter.

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 verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

FLORIDA NUCLEAR COST RECOVERY

On February 8, 2010, a lawsuit was filed against PEF in state circuit court in Sumter County, Fla., alleging that the Florida nuclear cost-recovery statute (Section 366.93, Florida Statutes) violates the Florida Constitution, and seeking a refund of all monies with interest collected by PEF pursuant to that statute. The complaint also requests that the court grant class action status to the plaintiffs. On April 6, 2010, PEF filed a motion to dismiss the complaint. The trial judge issued an order on May 3, 2010, dismissing the complaint. The plaintiffs filed an amended complaint on June 1, 2010. PEF believes the lawsuit is without merit and filed a motion to dismiss the amended complaint on July 12, 2010. On October 1, 2010, the plaintiffs filed an appeal of the trial court’s order dismissing the complaint. The court issued a per curiam affirmed opinion on May 17, 2011, which affirmed the trial court’s dismissal of the

62

lawsuit. The appellants filed a motion for written opinion on May 20, 2011, which was denied by the appellate court on June 20, 2011. With this final ruling from the appellate court, the plaintiffs have no further appellate rights; therefore this ruling ends this class action litigation against PEF.

CLAIM OF HOLDER OF CONTINGENT VALUE OBLIGATIONS

On June 10, 2011, Davidson Kempner Partners, M.H. Davidson & Co., Davidson Kempner Institutional Partners, L.P., and Davidson Kempner International, Ltd. (jointly, Davidson Kempner) filed a lawsuit against us in the Supreme Court of the State of New York, County of New York. Davidson Kempner is a holder of CVOs (See Note 10) and alleged that we improperly deducted escrow deposits in 2005 in determining net after-tax cash flow under the agreement governing the CVOs and that by taking this position, we breached our obligation under the agreement to exercise good faith and fair dealing. The plaintiffs alleged that this breach caused injury to the holders of CVOs in the approximate amount of $42 million. The plaintiffs requested declaratory judgment to require that we deduct the escrowed payments in 2006.

On August 2, 2011, the parties filed a Stipulation of Discontinuance without Prejudice to dismiss the state lawsuit so that certain of the plaintiffs could file a federal lawsuit against us. On August 9, 2011, M.H. Davidson & Co. and Davidson Kempner International, Ltd. filed a lawsuit against us in the United States District Court for the Southern District of New York with the same allegations and seeking the same relief as the prior state lawsuit. On October 3, 2011, we entered a settlement agreement and release with Davidson Kempner under which the parties mutually released all claims related to the CVOs and we purchased all of Davidson Kempner’s CVOs at a negotiated purchase price of $0.75 per CVO. The parties to the federal lawsuit filed a Stipulation of Discontinuance with Prejudice dismissing the lawsuit on October 12, 2011.

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. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

16. CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2010 Form 10-K, we have guaranteed certain payments of two 100 percent owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees 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 2010 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a VIE of 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 Subsidiaries column includes the consolidated financial results of all non-guarantor subsidiaries, which is primarily comprised of our wholly owned subsidiary PEC. The Other column includes elimination entries for all intercompany transactions and other consolidation adjustments. 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.

63

Condensed Consolidating Statement of Income
Three months ended September 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	1,415		$	1,332		$	-		$	2,747
Affiliate revenues		-			-			69			(69	)		-
Total operating revenues		-			1,415			1,401			(69	)		2,747
Operating expenses
Fuel used in electric generation		-			456			388			-			844
Purchased power		-			232			117			-			349
Operation and maintenance		2			221			332			(68	)		487
Depreciation, amortization and accretion		-			39			136			-			175
Taxes other than on income		-			106			58			(1	)		163
Other		-			1			38			-			39
Total operating expenses		2			1,055			1,069			(69	)		2,057
Operating (loss) income		(2	)		360			332			-			690
Other income (expense)
Interest income		-			-			1			-			1
Allowance for equity funds used during construction		-			7			15			-			22
Other, net		(63	)		(1	)		(5	)		(1	)		(70	)
Total other (expense) income, net		(63	)		6			11			(1	)		(47	)
Interest charges
Interest charges		80			56			45			(1	)		180
Allowance for borrowed funds used during construction		-			(4	)		(4	)		-			(8	)
Total interest charges, net		80			52			41			(1	)		172
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(145	)		314			302			-			471
Income tax (benefit) expense		(45	)		116			103			4			178
Equity in earnings of consolidated subsidiaries		391			-			-			(391	)		-
Income from continuing operations		291			198			199			(395	)		293
Discontinued operations, net of tax		-			1			(1	)		-			-
Net income		291			199			198			(395	)		293
Net income attributable to noncontrolling   interests, net of tax		-			(1	)		-			(1	)		(2	)
Net income attributable to controlling interests	$	291		$	198		$	198		$	(396	)	$	291

64

Condensed Consolidating Statement of Income
Three months ended September 30, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	1,548		$	1,414		$	-		$	2,962
Affiliate revenues		-			-			66			(66	)		-
Total operating revenues		-			1,548			1,480			(66	)		2,962
Operating expenses
Fuel used in electric generation		-			471			464			-			935
Purchased power		-			309			109			-			418
Operation and maintenance		2			234			301			(63	)		474
Depreciation, amortization and accretion		-			77			124			-			201
Taxes other than on income		-			102			60			(1	)		161
Other		-			10			10			-			20
Total operating expenses		2			1,203			1,068			(64	)		2,209
Operating (loss) income		(2	)		345			412			(2	)		753
Other income (expense)
Interest income		2			1			2			(2	)		3
Allowance for equity funds used during construction		-			5			17			-			22
Other, net		-			(3	)		(3	)		1			(5	)
Total other income, net		2			3			16			(1	)		20
Interest charges
Interest charges		71			74			53			(1	)		197
Allowance for borrowed funds used during construction		-			(3	)		(5	)		-			(8	)
Total interest charges, net		71			71			48			(1	)		189
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(71	)		277			380			(2	)		584
Income tax (benefit) expense		(25	)		99			147			(2	)		219
Equity in earnings of consolidated subsidiaries		406			-			-			(406	)		-
Income from continuing operations before    cumulative effect of change in accounting principle		360			178			233			(406	)		365
Discontinued operations, net of tax		1			(1	)		(2	)		-			(2	)
Cumulative effect of change in accounting principle,   net of tax		-			-			2			-			2
Net income		361			177			233			(406	)		365
Net income attributable to noncontrolling   interests, net of tax		-			(1	)		(2	)		(1	)		(4	)
Net income attributable to controlling interests	$	361		$	176		$	231		$	(407	)	$	361

65

Condensed Consolidating Statement of Income
Nine months ended September 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	3,645		$	3,525		$	-		$	7,170
Affiliate revenues		-			-			204			(204	)		-
Total operating revenues		-			3,645			3,729			(204	)		7,170
Operating expenses
Fuel used in electric generation		-			1,159			1,077			-			2,236
Purchased power		-			641			257			-			898
Operation and maintenance		6			655			1,026			(196	)		1,491
Depreciation, amortization and accretion		-			112			396			-			508
Taxes other than on income		-			274			168			(5	)		437
Other		-			(7	)		38			-			31
Total operating expenses		6			2,834			2,962			(201	)		5,601
Operating (loss) income		(6	)		811			767			(3	)		1,569
Other income (expense)
Interest income		-			1			1			-			2
Allowance for equity funds used during construction		-			24			53			-			77
Other, net		(59	)		5			(7	)		1			(60	)
Total other (expense) income, net		(59	)		30			47			1			19
Interest charges
Interest charges		216			204			149			(1	)		568
Allowance for borrowed funds used during construction		-			(11	)		(15	)		-			(26	)
Total interest charges, net		216			193			134			(1	)		542
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(281	)		648			680			(1	)		1,046
Income tax (benefit) expense		(100	)		240			243			3			386
Equity in earnings of consolidated subsidiaries		832			-			-			(832	)		-
Income from continuing operations		651			408			437			(836	)		660
Discontinued operations, net of tax		-			(2	)		(2	)		-			(4	)
Net income		651			406			435			(836	)		656
Net income attributable to noncontrolling   interests, net of tax		-			(3	)		-			(2	)		(5	)
Net income attributable to controlling interests	$	651		$	403		$	435		$	(838	)	$	651

66

Condensed Consolidating Statement of Income
Nine months ended September 30, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	4,075		$	3,794		$	-		$	7,869
Affiliate revenues		-			-			179			(179	)		-
Total operating revenues		-			4,075			3,973			(179	)		7,869
Operating expenses
Fuel used in electric generation		-			1,252			1,322			-			2,574
Purchased power		-			761			235			-			996
Operation and maintenance		5			647			977			(170	)		1,459
Depreciation, amortization and accretion		-			311			369			-			680
Taxes other than on income		-			278			175			(5	)		448
Other		-			15			10			-			25
Total operating expenses		5			3,264			3,088			(175	)		6,182
Operating (loss) income		(5	)		811			885			(4	)		1,687
Other income (expense)
Interest income		6			1			5			(6	)		6
Allowance for equity funds used during construction		-			23			45			-			68
Other, net		(1	)		-			(7	)		3			(5	)
Total other income, net		5			24			43			(3	)		69
Interest charges
Interest charges		214			219			159			(5	)		587
Allowance for borrowed funds used during construction		-			(10	)		(14	)		-			(24	)
Total interest charges, net		214			209			145			(5	)		563
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(214	)		626			783			(2	)		1,193
Income tax (benefit) expense		(83	)		235			301			3			456
Equity in earnings of consolidated subsidiaries		861			-			-			(861	)		-
Income from continuing operations		730			391			482			(866	)		737
Discontinued operations, net of tax		1			-			(3	)		-			(2	)
Net income		731			391			479			(866	)		735
Net (income) loss attributable to noncontrolling   interests, net of tax		-			(3	)		1			(2	)		(4	)
Net income attributable to controlling interests	$	731		$	388		$	480		$	(868	)	$	731

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Condensed Consolidating Balance Sheet
September 30, 2011
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	10,351	$	11,578	$	86		$	22,015
Current assets
Cash and cash equivalents		-		34		69		-			103
Receivables, net		-		630		577		-			1,207
Notes receivable from affiliated companies		97		27		138		(262	)		-
Regulatory assets		-		128		52		-			180
Derivative collateral posted		-		98		14		-			112
Prepayments and other current assets		131		816		1,062		(186	)		1,823
Total current assets		228		1,733		1,912		(448	)		3,425
Deferred debits and other assets
Investment in consolidated subsidiaries		14,196		-		-		(14,196	)		-
Regulatory assets		-		1,305		1,029		(1	)		2,333
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		520		992		-			1,512
Other assets and deferred debits		94		215		907		(479	)		737
Total deferred debits and other assets		14,290		2,040		2,928		(11,021	)		8,237
Total assets	$	14,518	$	14,124	$	16,418	$	(11,383	)	$	33,677
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,112	$	4,874	$	5,650	$	(10,524	)	$	10,112
Noncontrolling interests		-		3		-		-			3
Total equity		10,112		4,877		5,650		(10,524	)		10,115
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		-		(36	)		273
Long-term debt, net		3,542		4,482		3,693		-			11,717
Total capitalization		13,654		9,702		9,402		(10,560	)		22,198
Current liabilities
Current portion of long-term debt		450		-		500		-			950
Short-term debt		45		-		-		-			45
Notes payable to affiliated companies		-		259		3		(262	)		-
Derivative liabilities		35		175		93		-			303
Other current liabilities		318		1,015		1,104		(187	)		2,250
Total current liabilities		848		1,449		1,700		(449	)		3,548
Deferred credits and other liabilities
Noncurrent income tax liabilities		-		863		1,902		(455	)		2,310
Regulatory liabilities		-		796		1,443		87			2,326
Other liabilities and deferred credits		16		1,314		1,971		(6	)		3,295
Total deferred credits and other liabilities		16		2,973		5,316		(374	)		7,931
Total capitalization and liabilities	$	14,518	$	14,124	$	16,418	$	(11,383	)	$	33,677

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Condensed Consolidating Balance Sheet
December 31, 2010
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	10,189	$	10,961	$	90		$	21,240
Current assets
Cash and cash equivalents		110		270		231		-			611
Receivables, net		-		497		536		-			1,033
Notes receivable from affiliated companies		14		48		115		(177	)		-
Regulatory assets		-		105		71		-			176
Derivative collateral posted		-		140		24		-			164
Prepayments and other current assets		30		751		984		(273	)		1,492
Total current assets		154		1,811		1,961		(450	)		3,476
Deferred debits and other assets
Investment in consolidated subsidiaries		14,316		-		-		(14,316	)		-
Regulatory assets		-		1,387		987		-			2,374
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		554		1,017		-			1,571
Other assets and deferred debits		75		238		894		(469	)		738
Total deferred debits and other assets		14,391		2,179		2,898		(11,130	)		8,338
Total assets	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,023	$	4,957	$	5,686	$	(10,643	)	$	10,023
Noncontrolling interests		-		4		-		-			4
Total equity		10,023		4,961		5,686		(10,643	)		10,027
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		-		(36	)		273
Long-term debt, net		3,989		4,182		3,693		-			11,864
Total capitalization		14,012		9,486		9,438		(10,679	)		22,257
Current liabilities
Current portion of long-term debt		205		300		-		-			505
Notes payable to affiliated companies		-		175		3		(178	)		-
Derivative liabilities		18		188		53		-			259
Other current liabilities		278		1,002		1,184		(273	)		2,191
Total current liabilities		501		1,665		1,240		(451	)		2,955
Deferred credits and other liabilities
Noncurrent income tax liabilities		3		528		1,608		(443	)		1,696
Regulatory liabilities		-		1,084		1,461		90			2,635
Other liabilities and deferred credits		29		1,416		2,073		(7	)		3,511
Total deferred credits and other liabilities		32		3,028		5,142		(360	)		7,842
Total capitalization and liabilities	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054

69

Condensed Consolidating Statement of Cash Flows
Nine months ended September 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	659		$	664		$	909		$	(928	)	$	1,304
Investing activities
Gross property additions		-			(624	)		(911	)		-			(1,535	)
Nuclear fuel additions		-			(13	)		(121	)		-			(134	)
Purchases of available-for-sale securities and other   investments		-			(4,099	)		(437	)		-			(4,536	)
Proceeds from available-for-sale securities and other   investments		-			4,101			408			-			4,509
Changes in advances to affiliated companies		(83	)		22			(23	)		84			-
Contributions to consolidated subsidiaries		(11	)		-			-			11			-
Other investing activities		(6	)		113			14			-			121
Net cash used by investing activities		(100	)		(500	)		(1,070	)		95			(1,575	)
Financing activities
Issuance of common stock, net		42			-			-			-			42
Dividends paid on common stock		(550	)		-			-			-			(550	)
Dividends paid to parent		-			(478	)		(450	)		928			-
Net increase in short-term debt		45			-			-			-			45
Proceeds from issuance of long-term debt, net		494			296			496			-			1,286
Retirement of long-term debt		(700	)		(300	)		-			-			(1,000	)
Changes in advances from affiliated companies		-			84			-			(84	)		-
Contributions from parent		-			10			1			(11	)		-
Other financing activities		-			(12	)		(48	)		-			(60	)
Net cash used by financing activities		(669	)		(400	)		(1	)		833			(237	)
Net decrease in cash and cash equivalents		(110	)		(236	)		(162	)		-			(508	)
Cash and cash equivalents at beginning of period		110			270			231			-			611
Cash and cash equivalents at end of period	$	-		$	34		$	69		$	-		$	103

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Condensed Consolidating Statement of Cash Flows
Nine months ended September 30, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	23		$	872		$	1,205		$	(196	)	$	1,904
Investing activities
Gross property additions		-			(775	)		(893	)		25			(1,643	)
Nuclear fuel additions		-			(32	)		(132	)		-			(164	)
Purchases of available-for-sale securities and other   investments		-			(5,461	)		(466	)		-			(5,927	)
Proceeds from available-for-sale securities and other   investments		-			5,464			451			-			5,915
Changes in advances to affiliated companies		(24	)		(13	)		242			(205	)		-
Return of investment in consolidated subsidiaries		54			-			-			(54	)		-
Contributions to consolidated subsidiaries		(56	)		-			-			56			-
Other investing activities		-			16			-			(1	)		15
Net cash used by investing activities		(26	)		(801	)		(798	)		(179	)		(1,804	)
Financing activities
Issuance of common stock, net		419			-			-			-			419
Dividends paid on common stock		(535	)		-			-			-			(535	)
Dividends paid to parent		-			(102	)		(75	)		177			-
Dividends paid to parent in excess of retained earnings		-			-			(54	)		54			-
Net decrease in short-term debt		(140	)		-			-			-			(140	)
Proceeds from issuance of long-term debt, net		-			591			-			-			591
Retirement of long-term debt		(100	)		(300	)		-			-			(400	)
Changes in advances from affiliated companies		-			(205	)		-			205			-
Contributions from parent		-			33			37			(70	)		-
Other financing activities		-			(9	)		(69	)		9			(69	)
Net cash (used) provided by financing activities		(356	)		8			(161	)		375			(134	)
Net (decrease) increase in cash and cash equivalents		(359	)		79			246			-			(34	)
Cash and cash equivalents at beginning of period		606			72			47			-			725
Cash and cash equivalents at end of period	$	247		$	151		$	293		$	-		$	691

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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 Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2010 (2010 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, the impact of regulatory orders received and the timing of outages of electric generating units, especially nuclear-fueled units, among other factors.

MD&A includes financial information prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), as well as certain non-GAAP financial measures, “Ongoing Earnings” and “Base Revenues,” discussed below. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.

MD&A should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2010 Form 10-K.

PENDING MERGER

On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction (the Merger) and continue as a wholly owned subsidiary of Duke Energy.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the Merger. Accordingly, the adjusted exchange ratio is expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.

The combined company, to be called Duke Energy, will have an 18-member board of directors. The board will be comprised of, subject to their ability and willingness to serve, all 11 current directors of Duke Energy and seven current directors of Progress Energy. At the time of the Merger, William D. Johnson, Chairman, President and CEO of Progress Energy, will be President and CEO of Duke Energy and James E. Rogers, Chairman, President and CEO

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of Duke Energy, will be the Executive Chairman of the board of directors of Duke Energy, subject to their ability and willingness to serve.

Consummation of the Merger is subject to customary conditions, including, among others things, approval of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission, the Nuclear Regulatory Commission (NRC), the North Carolina Utilities Commission (NCUC), the Kentucky Public Service Commission, and the Public Service Commission of South Carolina (SCPSC). Although there are no merger-specific regulatory approvals required in Indiana, Ohio or Florida, the companies will continue to update the public service commissions in those states on the Merger, as applicable and as required. The status of these matters is as follows, and we cannot predict the outcome of pending approvals:

Shareholder Approval

·   On August 23, 2011, the Merger was approved by the shareholders of Progress Energy and Duke Energy.

Federal Regulatory Approvals

·   On March 28, 2011, Progress Energy and Duke Energy submitted their Hart-Scott-Rodino filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.

·   On July 27, 2011, the Federal Communications Commission approved the Assignment of Authorization filings to transfer control of certain licenses. The approval is effective for 180 days.

·   On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC’s acceptance of market power mitigation measures to address the FERC’s finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina power markets. Progress Energy and Duke Energy filed a market power mitigation plan with FERC on October 17, 2011. In the October 17, 2011 filing with the FERC, Progress Energy and Duke Energy proposed a “virtual divestiture” under which power up to a certain amount will be offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. In the proposal, after native loads have been met, power will be offered to entities serving load in the relevant areas at a price determined by the average incremental cost plus 10 percent. On a day-ahead order confirmation basis, PEC plans to offer 500 megawatt-hours (MWh) during each summer hour, which is less than 4 percent of PEC’s summer net capability. Duke Energy Carolinas plans to offer 300 MWh during each summer hour and 225 MWh during each winter hour. On October 31, 2011, Progress Energy and Duke Energy filed a request for a rehearing of the Merger order without withdrawing the previously submitted market power mitigation plan. In the request for rehearing, Progress Energy and Duke Energy asserted that the FERC had departed from its established merger rules in applying a more stringent analysis to assess whether the Merger will result in market power conditions in the Carolinas. We have requested that the FERC address the mitigation plan no later than December 15, 2011. If the FERC accepts the mitigation proposal, we will withdraw the request for a rehearing.

·   On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a Joint Dispatch Agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the Merger. The second filing is a joint open access transmission tariff pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate.

·   On March 30, 2011, Progress Energy and Duke Energy made filings with the NRC for approval for indirect transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses. The period to request a hearing or intervene expired in September 2011, and no such requests were received.

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State Regulatory Approvals

·   On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed the settlement with the South Carolina Office of Regulatory Staff, a party to the proceedings. If the settlement agreement is approved, Progress Energy and Duke Energy will guarantee $650 million in fuel cost savings for customers in North Carolina and South Carolina between 2012 and 2016, maintain their current level of community support for the next four years, and provide $15 million for low-income energy assistance and workforce development. The parties also agreed that direct merger-related expenses would not be recovered from customers. Recovery of merger-related employee severance costs can be requested separately. The NCUC held hearings regarding these applications on September 20-22, 2011, and proposed orders and/or briefs must be filed by November 14, 2011.

·   On April 25, 2011, Progress Energy and Duke Energy filed a merger-related filing and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the merger-related filing as the merger of these entities is not likely to occur for several years after the close of the Merger. Hearings before the SCPSC to approve the joint dispatch agreement have been rescheduled for the week of December 12, 2011. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.

·   On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy’s and Duke Energy’s merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky. 

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the Merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share.

Certain substantial changes in ownership of Progress Energy, including the Merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 14 in the 2010 Form 10-K).

The Merger Agreement contains certain termination rights for both companies and under specified circumstances we may be required to pay Duke Energy $400 million and Duke Energy may be required to pay us $675 million. In addition, under specified circumstances each party may be required to reimburse the other party for up to $30 million of merger-related expenses.

Certain Progress Energy shareholders have filed class action lawsuits in the state and federal courts in North Carolina against Progress Energy and each of the members of Progress Energy’s board of directors (See Note 15C).

In connection with the Merger, we established an employee retention plan for certain eligible employees. Payments under the plan are contingent upon the consummation of the Merger and the employees’ continued employment through a specified time period following the Merger. These payments will be recorded as compensation expense following consummation of the Merger. We estimate the costs of the retention plan to be $14 million.

In connection with the Merger, we announced plans to offer a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the Merger. The window for eligible employees to request a voluntary end to their employment under the VSP opened on November 7, 2011, and will close on November 30, 2011. If the employee is not required to work for a significant period after the consummation of the Merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the Merger. If a significant retention period exists, the costs of any benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the Merger and formulated an exit plan to vacate one of our corporate headquarters buildings. Under the plan, we will gradually vacate the premises beginning in the

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fourth quarter of 2011 through January 1, 2013. The estimated exit cost liability associated with this exit plan is $16 million and will be recognized proportionately as we vacate the premises. No exit cost liabilities were recorded at September 30, 2011.

In connection with the Merger, we incurred merger and integration-related costs of $15 million and $36 million, net of tax, for the three and nine months ended September 30, 2011, respectively. These costs are included in operation and maintenance (O&M) expense in our Consolidated Statements of Income.

PROGRESS ENERGY

RESULTS OF OPERATIONS

In this section, we provide analysis and discussion of earnings and the factors affecting earnings on both a GAAP and non-GAAP basis. We introduce our results of operations in an overview section followed by a more detailed analysis and discussion by business segment.

We compute our non-GAAP financial measurement “Ongoing Earnings” as GAAP net income attributable to controlling interests less discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Ongoing Earnings is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to, and not a substitute for, our results of operations presented in accordance with GAAP.

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A reconciliation of Ongoing Earnings to GAAP net income attributable to controlling interests follows:

(in millions except per share data)	PEC			PEF			Corporate and Other			Total			Per Share
Three months ended September 30, 2011
Ongoing Earnings	$	202		$	202		$	(60	)	$	344		$	1.16
Tax levelization		4			4			-			8			0.03
CVO mark-to-market, net of tax(a)		-			-			(50	)		(50	)		(0.17	)
Merger and integration costs, net of tax(a)		(8	)		(7	)		-			(15	)		(0.05	)
CR3 indemnification adjustment, net of tax(a)		-			4			-			4			0.01
Net income (loss) attributable to controlling interests(b)	$	198		$	203		$	(110	)	$	291		$	0.98
Three months ended September 30, 2010
Ongoing Earnings	$	233		$	177		$	(49	)	$	361		$	1.23
Tax levelization		1			4			(1	)		4			0.01
Impairment, net of tax(a)		(1	)		(1	)		-			(2	)		(0.01	)
Discontinued operations attributable to controlling   interests, net of tax		-			-			(2	)		(2	)		-
Net income (loss) attributable to controlling interests(b)	$	233		$	180		$	(52	)	$	361		$	1.23
Nine months ended September 30, 2011
Ongoing Earnings	$	453		$	454		$	(150	)	$	757		$	2.56
Tax levelization		1			2			(1	)		2			0.01
CVO mark-to-market, net of tax(a)		-			-			(46	)		(46	)		(0.15	)
Merger and integration costs, net of tax(a)		(19	)		(17	)		-			(36	)		(0.12	)
CR3 indemnification charge, net of tax(a)		-			(22	)		-			(22	)		(0.08	)
Discontinued operations attributable to controlling   interests, net of tax		-			-			(4	)		(4	)		(0.02	)
Net income (loss) attributable to controlling interests(b)	$	435		$	417		$	(201	)	$	651		$	2.20
Nine months ended September 30, 2010
Ongoing Earnings	$	493		$	409		$	(146	)	$	756		$	2.61
Tax levelization		4			2			(3	)		3			0.01
Impairment, net of tax(a)		(4	)		(1	)		-			(5	)		(0.01	)
Plant retirement adjustment, net of tax(a)		1			-			-			1			-
Change in the tax treatment of the Medicare Part D subsidy		(12	)		(10	)		-			(22	)		(0.08	)
Discontinued operations attributable to controlling   interests, net of tax		-			-			(2	)		(2	)		-
Net income (loss) attributable to controlling interests(b)	$	482		$	400		$	(151	)	$	731		$	2.53

(a)

Calculated using assumed tax rate of 40 percent to the extent items are tax deductible.

(b)

Net income attributable to controlling interests is shown net of preferred stock dividend requirement of $(1) million at PEC for the three months ended September 30, 2011 and 2010 and $(2) million for the nine months ended September 30, 2011 and 2010. Net income attributable to controlling interests is shown net of preferred stock dividend requirement of $(1) million at PEF for the nine months ended September 30, 2011 and 2010.

Management uses the non-GAAP financial measure Ongoing Earnings (i) as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; (iii) as a measure for determining levels of incentive compensation; and (iv) in communications with our board of directors, employees, shareholders, analysts and investors concerning our financial performance. Management believes this non-GAAP measure is appropriate for understanding the business and assessing our potential future performance, because excluded items are limited to those that management believes are not representative of our fundamental core earnings (See Note 13).

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OVERVIEW

For the three months ended September 30, 2011, our net income attributable to controlling interests was $291 million, or $0.98 per share, compared to net income attributable to controlling interests of $361 million, or $1.23 per share, for the same period in 2010. The decrease as compared to prior year was primarily due to:

·   unrealized loss recorded due to mark-to-market change in fair value of contingent value obligations (CVOs) (Ongoing Earnings adjustment) and

·   retail disallowance of replacement power costs in 2011 resulting from the prior-year performance of nuclear plants at PEC.

For the nine months ended September 30, 2011, our net income attributable to controlling interests was $651 million, or $2.20 per share, compared to net income attributable to controlling interests of $731 million, or $2.53 per share, for the same period in 2010. The decrease as compared to prior year was primarily due to:

·   less favorable impact of weather at the Utilities;

·   unrealized loss recorded due to mark-to-market change in fair value on CVOs (Ongoing Earnings adjustment); and

·   merger and integration costs related to the Merger (Ongoing Earnings adjustment).

 

Offsetting these items was:

·   lower depreciation and amortization expense at PEF.

PROGRESS ENERGY CAROLINAS

PEC contributed net income available to parent totaling $198 million and $233 million for the three months ended September 30, 2011 and 2010, respectively. The decrease in net income available to parent was primarily due to the retail disallowance of replacement power costs resulting from the prior-year performance of nuclear plants and the less favorable impact of weather. PEC contributed Ongoing Earnings of $202 million and $233 million for the three months ended September 30, 2011 and 2010. The 2011 Ongoing Earnings adjustments to net income available to parent were a $4 million tax levelization benefit and an $8 million charge, net of tax, for merger and integration costs. The 2010 Ongoing Earnings adjustments to net income available to parent were a $1 million charge, net of tax, for the impairment of other assets and a $1 million tax levelization benefit. Management does not consider these items to be representative of PEC’s fundamental core earnings and excluded these items in computing PEC’s Ongoing Earnings.

PEC contributed net income available to parent totaling $435 million and $482 million for the nine months ended September 30, 2011 and 2010, respectively. The decrease in net income available to parent was primarily due to the less favorable impact of weather. PEC contributed Ongoing Earnings of $453 million and $493 million for the nine months ended September 30, 2011 and 2010, respectively. The 2011 Ongoing Earnings adjustments to net income available to parent were a $19 million charge, net of tax, for merger and integration costs and a $1 million tax levelization benefit. The 2010 Ongoing Earnings adjustments to net income available to parent were a $12 million charge for the change in the tax treatment of the Medicare Part D subsidy, a $4 million impairment, net of tax, of certain miscellaneous investments and other assets, a $4 million tax levelization benefit and a $1 million adjustment, net of tax, for plant retirements. Management does not consider these items to be representative of PEC’s fundamental core earnings and excluded these items in computing PEC’s Ongoing Earnings.

Three Months Ended September 30, 2011, Compared to Three Months Ended September 30, 2010

REVENUES

The revenue tables that follow present the total amount and percentage change of total operating revenues and its components. “Base Revenues" is a non-GAAP measure and is defined as operating revenues excluding clause recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues. We and PEC consider Base Revenues a useful measure to evaluate PEC’s electric operations because fuel and other pass-through

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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. PEC’s clause-recoverable regulatory returns include renewable energy clause revenues and the return on asset component of demand-side management (DSM) and energy-efficiency (EE). The reconciliation and analysis that follows is a complement to the financial information provided in accordance with GAAP.

A reconciliation of PEC’s Base Revenues to GAAP operating revenues, including the percentage change by customer class, for the three months ended September 30 follows:

(in millions)
Customer Class	2011		Change			% Change			2010
Residential	$	360	$	(25	)		(6.5	)	$	385
Commercial		205		(9	)		(4.2	)		214
Industrial		108		(1	)		(0.9	)		109
Governmental		20		(2	)		(9.1	)		22
Unbilled		2		25		NM				(23	)
Total retail base revenues		695		(12	)		(1.7	)		707
Wholesale base revenues		74		(10	)		(11.9	)		84
Total Base Revenues		769		(22	)		(2.8	)		791
Clause-recoverable regulatory returns		8		4			100.0			4
Miscellaneous		37		-			-			37
Fuel and other pass-through revenues		518		(64	)	NM				582
Total operating revenues	$	1,332	$	(82	)		(5.8	)	$	1,414
NM - not meaningful

PEC’s total Base Revenues were $769 million and $791 million for the three months ended September 30, 2011 and 2010, respectively. The $22 million decrease in Base Revenues was due primarily to the $16 million unfavorable impact of weather. The unfavorable impact of weather was driven by 5 percent lower cooling-degree days than 2010. Cooling-degree days were 17 percent higher than normal in 2011 and 28 percent higher than normal in 2010. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2010 Form 10-K for a summary of degree days and weather estimation.

PEC’s electric energy sales in kilowatt-hours (kWh) and the percentage change by customer class for the three months ended September 30 were as follows:

(in millions of kWh)
Customer Class	2011			Change			% Change			2010
Residential		5,134			(366	)		(6.7	)		5,500
Commercial		3,917			(247	)		(5.9	)		4,164
Industrial		2,870			(69	)		(2.3	)		2,939
Governmental		476			16			3.5			460
Unbilled		(31	)		480		NM				(511	)
Total retail kWh sales		12,366			(186	)		(1.5	)		12,552
Wholesale		3,662			(135	)		(3.6	)		3,797
Total kWh sales		16,028			(321	)		(2.0	)		16,349

The decrease in retail kWh sales in 2011 was primarily due to less favorable weather compared to 2010, as previously discussed.

Wholesale kWh sales decreased primarily due to a contract that expired in early 2011.

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EXPENSES

Fuel and Purchased Power

Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation and 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 and is recorded as deferred fuel expense, which is included in fuel used in electric generation on the Consolidated Statements of Income.

Fuel and purchased power expenses were $505 million for the three months ended September 30, 2011, which represents a $68 million decrease compared to the same period in 2010. This decrease was primarily due to lower deferred fuel expense resulting from the impact of lower rates.

Operation and Maintenance

O&M expense was $271 million for the three months ended September 30, 2011, which represents a $15 million increase compared to the same period in 2010. This increase was primarily due to $24 million of higher storm costs, $13 million of merger and integration costs, $13 million higher nuclear plant maintenance costs and $3 million higher employee benefits expense, partially offset by the $27 million non-capital portion of a judgment from spent fuel litigation (See Note 15C), $12 million lower nuclear plant outage costs and $2 million prior-year impairment of other assets. The higher nuclear plant maintenance costs are primarily due to increased spending to improve the performance of PEC’s Robinson Nuclear Plant (Robinson) and higher dry storage costs in 2011 as compared to 2010. The lower nuclear plant outage costs are primarily due to a decrease in the number of outages in 2011 as compared to 2010. Management does not consider impairments and merger and integration costs to be representative of PEC’s fundamental core earnings. Therefore, the impacts of these items are excluded in computing PEC’s Ongoing Earnings. Certain O&M expenses are recoverable through cost-recovery clauses and therefore have no material impact on earnings. In aggregate, O&M expense primarily recoverable through base rates increased $13 million compared to the same period in 2010.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $132 million for the three months ended September 30, 2011, which represents a $12 million increase compared to the same period in 2010. This increase was primarily due to higher depreciable asset base.

Other

Other operating expense was $38 million for the three months ended September 30, 2011, which represents a $33 million increase compared to the same period in 2010. This increase was primarily due to the $28 million retail disallowance of replacement power costs resulting from the prior-year performance of nuclear plants (See Note 4A).

Total Other Income, Net

Total other income, net was $11 million for the three months ended September 30, 2011, which represents a $5 million decrease compared to the same period in 2010. This decrease was primarily due to unfavorable AFUDC equity resulting from decreased construction project costs.

Total Interest Charges, Net

Total interest charges, net was $41 million for the three months ended September 30, 2011, which represents a $5 million decrease compared to the same period in 2010. This decrease primarily resulted from the 2011 settlement of 2004 and 2005 income tax audits.

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Income Tax Expense

Income tax expense decreased $38 million for the three months ended September 30, 2011, as compared to the same period in 2010, primarily due to the $29 million tax impact of lower pre-tax income and the $3 million impact of tax levelization. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax 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. Because this adjustment will vary each quarter, but will have no effect on net income for the year, management does not consider this adjustment to be representative of PEC’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEC’s Ongoing Earnings.

Nine Months Ended September 30, 2011, Compared to Nine Months Ended September 30, 2010

REVENUES

A reconciliation of PEC’s Base Revenues to GAAP operating revenues, including the percentage change by customer class, for the nine months ended September 30 follows:

(in millions)
Customer Class	2011			Change			% Change			2010
Residential	$	940		$	(38	)		(3.9	)	$	978
Commercial		546			(10	)		(1.8	)		556
Industrial		279			1			0.4			278
Governmental		50			-			-			50
Unbilled		(26	)		(12	)	NM				(14	)
Total retail base revenues		1,789			(59	)		(3.2	)		1,848
Wholesale base revenues		218			(10	)		(4.4	)		228
Total Base Revenues		2,007			(69	)		(3.3	)		2,076
Clause-recoverable regulatory returns		22			14			175.0			8
Miscellaneous		100			(2	)		(2.0	)		102
Fuel and other pass-through revenues		1,396			(212	)	NM				1,608
Total operating revenues	$	3,525		$	(269	)		(7.1	)	$	3,794

PEC’s total Base Revenues were $2.007 billion and $2.076 billion for the nine months ended September 30, 2011 and 2010, respectively. The $69 million decrease in Base Revenues was due primarily to the $59 million unfavorable impact of weather and $5 million impact of a wholesale contract that expired in early 2011. The unfavorable impact of weather was driven by 13 percent lower heating-degree days and 4 percent lower cooling-degree days than 2010. Furthermore, in 2011, cooling-degree days were 22 percent higher than normal and heating-degree days were 5 percent lower than normal whereas in 2010, cooling-degree days were 32 percent higher than normal and heating-degree days were 11 percent higher than normal. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2010 Form 10-K for a summary of degree days and weather estimation.

Clause-recoverable regulatory returns were $22 million and $8 million for the nine months ended September 30, 2011 and 2010, respectively. The $14 million increase in clause-recoverable returns was due primarily to increased spending on DSM programs.

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PEC’s electric energy sales in kWh and the percentage change by customer class for the nine months ended September 30 were as follows:

(in millions of kWh)
Customer Class	2011			Change			% Change			2010
Residential		14,480			(615	)		(4.1	)		15,095
Commercial		10,644			(277	)		(2.5	)		10,921
Industrial		8,040			(19	)		(0.2	)		8,059
Governmental		1,236			32			2.7			1,204
Unbilled		(626	)		(198	)	NM				(428	)
Total retail kWh sales		33,774			(1,077	)		(3.1	)		34,851
Wholesale		9,840			(926	)		(8.6	)		10,766
Total kWh sales		43,614			(2,003	)		(4.4	)		45,617

The decrease in retail kWh sales in 2011 was primarily due to the less favorable impact of weather, as previously discussed.

Wholesale kWh sales decreased primarily due to lower excess generation sales driven by favorable market dynamics in the prior year and a contract that expired in early 2011.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.334 billion for the nine months ended September 30, 2011, which represents a $223 million decrease compared to the same period in 2010. This decrease was primarily due to lower deferred fuel expense, the $51 million impact of lower system requirements resulting from unfavorable weather compared to 2010 and the $42 million impact of generation mix, which was driven by nuclear plant outages in 2010. The lower deferred fuel expense is primarily due to the $139 million impact of lower rates.

Operation and Maintenance

O&M expense was $859 million for the nine months ended September 30, 2011, which represents an $18 million increase compared to the same period in 2010. This increase was primarily due to $31 million higher nuclear maintenance costs, $31 million of merger and integration costs, $21 million higher storm costs, $12 million higher employee benefits expense, $4 million higher vegetation management expense and a $2 million prior-year plant retirement adjustment, partially offset by $60 million lower nuclear plant outage costs, the $27 million non-capital portion of a judgment from spent fuel litigation (See Note 15C) and the $2 million prior-year impairment of other assets. The higher nuclear plant maintenance costs are primarily due to increased spending to improve the performance of Robinson and higher dry storage costs in 2011 as compared to 2010. The lower nuclear plant outage costs are primarily due to a decrease in the number of outages in 2011 as compared to 2010. Management does not consider impairments, merger and integration costs and adjustments recognized for the retirement of generating units prior to the end of their estimated useful lives to be representative of PEC’s fundamental core earnings. Therefore, the impacts of these items are excluded in computing PEC’s Ongoing Earnings. Certain O&M expenses are recoverable through cost-recovery clauses and therefore have no material impact on earnings. In aggregate, O&M expense primarily recoverable through base rates increased $12 million compared to the same period in 2010.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion was $382 million for the nine months ended September 30, 2011, which represents a $24 million increase compared to the same period in 2010. This increase was primarily due to higher depreciable asset base.

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Other

Other operating expense was $38 million for the nine months ended September 30, 2011, which represents a $33 million increase compared to the same period in 2010. This increase was primarily due to the $28 million previously discussed retail disallowance for replacement power costs and a $4 million prior-year impairment of certain miscellaneous investments. Management does not consider impairments to be representative of PEC’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEC’s Ongoing Earnings.

Total Other Income, Net

Total other income, net was $49 million for the nine months ended September 30, 2011, which represents a $6 million increase compared to the same period in 2010. This increase was primarily due to favorable AFUDC equity resulting from increased construction project costs.

Income Tax Expense

Income tax expense decreased $57 million for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily due to the $41 million tax impact of lower pre-tax income and the $12 million impact of the change in the tax treatment of the Medicare Part D subsidy resulting from federal health care reform enacted in 2010 (See Note 11), partially offset by the $3 million impact of tax levelization. As previously discussed, management does not consider this adjustment to be representative of PEC’s fundamental core earnings. Additionally, management does not consider the change in the tax treatment of the Medicare Part D subsidy to be representative of PEC’s fundamental core earnings. Accordingly, the impacts of these items are excluded in computing PEC’s Ongoing Earnings.

PROGRESS ENERGY FLORIDA

PEF contributed net income available to parent totaling $203 million and $180 million for the three months ended September 30, 2011 and 2010, respectively. The increase in net income available to parent was primarily due to lower depreciation and amortization expense and lower interest charges. PEF contributed Ongoing Earnings of $202 million and $177 million for the three months ended September 30, 2011 and 2010, respectively. The 2011 Ongoing Earnings adjustments to net income available to parent were a $4 million tax levelization benefit; a $4 million adjustment, net of tax, for indemnification for the estimated future years’ joint owner replacement power costs for Crystal River Unit No. 3 Nuclear Plant (CR3); and a $7 million charge, net of tax, for merger and integration costs. The 2010 Ongoing Earnings adjustments to net income available to parent were a $4 million tax levelization benefit and a $1 million charge, net of tax, for the impairment of other assets. Management does not consider these items to be representative of PEF’s fundamental core earnings and excluded these items in computing PEF’s Ongoing Earnings.

PEF contributed net income available to parent totaling $417 million and $400 million for the nine months ended September 30, 2011 and 2010, respectively. The increase in net income available to parent was primarily due to lower depreciation and amortization expense, lower interest charges, lower income tax expense due to the change in the tax treatment of the Medicare Part D subsidy in 2010 and a favorable litigation judgment, partially offset by the less favorable impact of weather, CR3 indemnification charge for the estimated future years’ joint owner replacement power costs, lower wholesale base revenues and merger and integration costs. PEF contributed Ongoing Earnings of $454 million and $409 million for the nine months ended September 30, 2011 and 2010, respectively. The 2011 Ongoing Earnings adjustments to net income available to parent were a $22 million charge, net of tax, for indemnification for the estimated future years’ joint owner replacement power costs for CR3; a $17 million charge, net of tax, for merger and integration costs; and a $2 million tax levelization benefit. The 2010 Ongoing Earnings adjustments to net income available to parent were a $10 million charge for the change in the tax treatment of the Medicare Part D subsidy, a $1 million charge, net of tax for the impairment of other assets and a $2 million tax levelization benefit. Management does not consider these items to be representative of PEF’s fundamental core earnings and excluded these items in computing PEF’s Ongoing Earnings.

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Three Months Ended September 30, 2011, Compared to Three Months Ended September 30, 2010

REVENUES

The revenue tables that follow present the total amount and percentage change of total operating revenues and its components. “Base Revenues” is a non-GAAP measure and is defined as operating revenues excluding clause recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues. We and PEF consider Base Revenues a useful measure to evaluate PEF’s electric operations because fuel and other pass-through revenues primarily represent the recovery of fuel, applicable portions of purchased power and other pass-through expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. PEF’s clause-recoverable regulatory returns include the revenues associated with the return on asset component of nuclear cost-recovery and environmental cost recovery clause (ECRC) revenues. The reconciliation and analysis that follows is a complement to the financial information we provide in accordance with GAAP.

A reconciliation of PEF’s Base Revenues to GAAP operating revenues, including the percentage change by customer class, for the three months ended September 30 follows:

(in millions)
Customer Class	2011			Change			% Change			2010
Residential	$	312		$	1			0.3		$	311
Commercial		102			-			-			102
Industrial		19			(1	)		(5.0	)		20
Governmental		24			(1	)		(4.0	)		25
Unbilled		(6	)		(2	)	NM				(4	)
Total retail base revenues		451			(3	)		(0.7	)		454
Wholesale base revenues		30			(11	)		(26.8	)		41
Total Base Revenues		481			(14	)		(2.8	)		495
Clause-recoverable regulatory returns		46			-			-			46
Miscellaneous		55			(5	)		(8.3	)		60
Fuel and other pass-through revenues		832			(110	)	NM				942
Total operating revenues	$	1,414		$	(129	)		(8.4	)	$	1,543

PEF’s total Base Revenues were $481 million and $495 million for the three months ended September 30, 2011 and 2010, respectively. The $14 million decrease in Base Revenues was due primarily to the $11 million lower wholesale base revenues and the $8 million unfavorable impact of weather, partially offset by the $5 million favorable impact of retail customer growth and usage. The $11 million decrease in wholesale base revenues was due primarily to decreased revenues from contracts that expired in 2010. The unfavorable impact of weather was driven by 3 percent lower cooling-degree days than 2010. Cooling-degree days were 5 percent higher than normal in 2011 and were 9 percent higher than normal in 2010. The favorable impact of retail customer growth and usage was driven by an increase in the average usage per customer and a net 8,000 increase in the average number of customers for 2011 compared to 2010.

PEF’s electric energy sales in kWh and the percentage change by customer class for the three months ended September 30 were as follows:

(in millions of kWh)
Customer Class	2011			Change			% Change			2010
Residential		6,181			(1	)		-			6,182
Commercial		3,459			4			0.1			3,455
Industrial		838			2			0.2			836
Governmental		869			(24	)		(2.7	)		893
Unbilled		(193	)		(70	)	NM				(123	)
Total retail kWh sales		11,154			(89	)		(0.8	)		11,243
Wholesale		846			(336	)		(28.4	)		1,182
Total kWh sales		12,000			(425	)		(3.4	)		12,425

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Wholesale kWh sales have decreased primarily due to decreased sales from contracts that expired in 2010, as previously discussed.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation and energy purchased in the market to meet customer load. Fuel and the majority 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 and is recorded as deferred fuel expense, which is included in fuel used in electric generation on the Consolidated Statements of Income.

Fuel and purchased power expenses were $688 million for the three months ended September 30, 2011, which represents a $92 million decrease compared to the same period in 2010. This decrease was primarily due to a $54 million decrease in fuel costs and a $49 million decrease in the recovery of deferred capacity costs. These decreases were partially offset by a $6 million reduction of the CR3 indemnification charge for the estimated joint owner replacement power costs for future years (through the expiration of the indemnification provisions of the joint owner agreement) that was recorded during the second quarter of 2011 (See Note 4B for a discussion of the CR3 outage and Note 15B for a discussion of the related indemnification). The decrease in fuel costs was due to lower coal and natural gas prices. The decrease in the recovery of deferred capacity costs was due to decreased current year rates. Management does not consider the CR3 indemnification of future years’ joint owner replacement power costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

Operation and Maintenance

O&M expense was $221 million for the three months ended September 30, 2011, which represents a $13 million decrease compared to the same period in 2010. This decrease was primarily due to a $15 million reduction driven by lower ECRC costs, lower environmental remediation expense, lower employee benefits expense, lower workers’ compensation expense and the $2 million prior-year impairment of other assets, partially offset by $11 million of merger and integration costs. Management does not consider impairments and merger and integration costs to be representative of PEF’s fundamental core earnings. Therefore, the impacts of these items are excluded in computing PEF’s Ongoing Earnings. The ECRC costs and certain other O&M expenses are recoverable through cost-recovery clauses and therefore have no material impact on earnings. In aggregate, O&M expenses primarily recoverable through base rates decreased $11 million compared to the same period in 2010.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $39 million for the three months ended September 30, 2011, which represents a $38 million decrease compared to the same period in 2010. This decrease was primarily due to the $21 million increase in the reduction in the cost of removal component of amortization expense in accordance with the 2010 base rate settlement agreement (See Note 4B) and $12 million lower nuclear cost-recovery amortization. The decrease in nuclear cost-recovery amortization is due to lower nuclear revenues in 2011. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and therefore, has no material impact on earnings. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates or the ECRC decreased $21 million compared to the same period in 2010.

Total Other Income, Net

Total other income, net was $7 million for the three months ended September 30, 2011, which represents a $5 million increase compared to the same period in 2010. This increase was primarily due to a $5 million prior-year donation.

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Total Interest Charges, Net

Total interest charges, net was $46 million for the three months ended September 30, 2011, which represents a $19 million decrease compared to the same period in 2010. This decrease primarily resulted from the 2011 settlement of 2004 and 2005 income tax audits.

Income Tax Expense

Income tax expense increased $18 million for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to the $16 million tax impact of higher pre-tax income. PEF’s income tax expense decreased by $4 million related to the impact of tax levelization for the three months ended September 30, 2011 and 2010. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax 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. Because this adjustment will vary each quarter, but will have no effect on net income for the year, management does not consider this adjustment to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

Nine Months Ended September 30, 2011, Compared to Nine Months Ended September 30, 2010

REVENUES

A reconciliation of PEF’s Base Revenues to GAAP operating revenues, including the percentage change by customer class, for the nine months ended September 30 follows:

(in millions)
Customer Class	2011		Change			% Change			2010
Residential	$	771	$	(37	)		(4.6	)	$	808
Commercial		270		-			-			270
Industrial		56		(2	)		(3.4	)		58
Governmental		68		(1	)		(1.4	)		69
Unbilled		6		(18	)	NM				24
Total retail base revenues		1,171		(58	)		(4.7	)		1,229
Wholesale base revenues		85		(36	)		(29.8	)		121
Total Base Revenues		1,256		(94	)		(7.0	)		1,350
Clause-recoverable regulatory returns		137		11			8.7			126
Miscellaneous		162		(5	)		(3.0	)		167
Fuel and other pass-through revenues		2,084		(338	)	NM				2,422
Total operating revenues	$	3,639	$	(426	)		(10.5	)	$	4,065

PEF’s total Base Revenues were $1.256 billion and $1.350 billion for the nine months ended September 30, 2011 and 2010, respectively. The $94 million decrease in Base Revenues was due primarily to the $56 million unfavorable impact of weather and $36 million lower wholesale base revenues. The unfavorable impact of weather was driven by 55 percent lower heating degree days than 2010. Heating-degree days were 2 percent higher than normal in 2011 and were 127 percent higher than normal in 2010. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2010 Form 10-K for a summary of degree days and weather estimation. The $36 million decrease in wholesale base revenues was due primarily to decreased revenues from contracts that expired in 2010.

PEF’s clause-recoverable regulatory returns were $137 million and $126 million for the nine months ended September 30, 2011 and 2010, respectively. The $11 million higher revenues primarily relate to higher returns on ECRC assets due to placing approximately $230 million of Clean Air Interstate Rule (CAIR) projects into service in the second quarter of 2010.

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PEF’s electric energy sales in kWh and the percentage change by customer class for the nine months ended September 30 were as follows:

(in millions of kWh)
Customer Class	2011		Change			% Change			2010
Residential		15,144		(762	)		(4.8	)		15,906
Commercial		9,037		46			0.5			8,991
Industrial		2,459		(12	)		(0.5	)		2,471
Governmental		2,418		(32	)		(1.3	)		2,450
Unbilled		116		(492	)	NM				608
Total retail kWh sales		29,174		(1,252	)		(4.1	)		30,426
Wholesale		2,132		(1,085	)		(33.7	)		3,217
Total kWh sales		31,306		(2,337	)		(6.9	)		33,643

The decrease in retail kWh sales in 2011 was primarily due to the unfavorable impact of weather, as previously discussed.

The decrease in wholesale kWh sales in 2011 was primarily due to decreased sales from contracts that expired in 2010, as previously discussed.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.800 billion for the nine months ended September 30, 2011, which represents a $213 million decrease compared to the same period in 2010. This decrease was primarily due to lower current year fuel and purchased power costs of $242 million and a decrease in the recovery of deferred capacity costs of $117 million, partially offset by an increase in deferred fuel expense of $147 million. The lower fuel and purchased power costs were driven by the $286 million impact of lower system requirements in 2011 as a result of the unfavorable impact of weather as previously discussed and lower natural gas and coal prices in 2011, partially offset by the previously discussed $38 million CR3 indemnification charge. The decrease in the recovery of deferred capacity costs was due to decreased current year rates. Deferred fuel expense increased due to the higher under-recovered fuel costs in 2010 as a result of higher system requirements due to extreme weather. Management does not consider the CR3 indemnification of future years’ joint owner replacement power costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

Operation and Maintenance

O&M expense was $655 million for the nine months ended September 30, 2011, which represents an $8 million increase compared to the same period in 2010. This increase was primarily due to $28 million of merger and integration costs and $14 million higher plant outage costs resulting from the increased number and scope of maintenance outages, partially offset by $15 million lower ECRC costs resulting from a refund of the 2010 over-recovery, $6 million lower workers’ compensation expense, $6 million lower uncollectible account expense, $4 million lower environmental remediation expense and the $2 million prior-year impairment of other assets. Management does not consider impairments and merger and integration costs to be representative of PEF’s fundamental core earnings. Therefore, the impacts of these items are excluded in computing PEF’s Ongoing Earnings. The ECRC costs and certain other O&M expenses are recoverable through cost-recovery clauses and therefore, have no material impact on earnings. In aggregate, O&M expenses primarily recoverable through base rates increased $19 million compared to the same period in 2010.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $112 million for the nine months ended September 30, 2011, which represents a $199 million decrease compared to the same period in 2010. This decrease was primarily due to the $145 million increase in the reduction of the cost of removal component of amortization expense in accordance

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with the 2010 base rate settlement agreement (See Note 4B) and $34 million lower nuclear cost-recovery amortization. The decrease in nuclear cost-recovery amortization is due to lower nuclear revenues in 2011. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and therefore, has no material impact on earnings. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates or the ECRC decreased $138 million compared to the same period in 2010.

Other

Other operating expense was a gain of $13 million for the nine months ended September 30, 2011, primarily due to a favorable litigation judgment.

Total Interest Charges, Net

Total interest charges, net was $176 million for the nine months ended September 30, 2011, which represents a $16 million decrease compared to the same period in 2010. This decrease primarily resulted from the 2011 settlement of 2004 and 2005 income tax audits.

Income Tax Expense

Income tax expense increased $4 million for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to the $8 million tax impact of higher pre-tax income and the $3 million impact of the prior-year deduction for domestic production activities, partially offset by the $10 million prior-year impact of the change in the tax treatment of the Medicare Part D subsidy resulting from enacted federal health care reform (See Note 11). PEF’s income tax expense was decreased by $2 million for the nine months ended September 30, 2011 and 2010, related to the impact of tax levelization. As previously discussed, management does not consider this adjustment to be representative of PEF’s fundamental core earnings. Additionally, management does not consider the change in the tax treatment of the Medicare Part D subsidy to be representative of PEF’s fundamental core earnings. Accordingly, the impacts of these items are excluded in computing PEF’s Ongoing Earnings.

CORPORATE AND OTHER

The Corporate and Other segment primarily includes the operations of the Parent, Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. A discussion of the items excluded from Corporate and Other’s Ongoing Earnings is included in the detailed discussion and analysis below. Management believes the excluded items are not representative of our fundamental core earnings. The following table reconciles Corporate and Other’s Ongoing Earnings to GAAP net income attributable to controlling interests:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2011			2010			2011			2010
Other interest expense	$	(86	)	$	(75	)	$	(232	)	$	(225	)
Other income tax benefit		30			30			89			88
Other expense		(4	)		(4	)		(7	)		(9	)
Ongoing Earnings		(60	)		(49	)		(150	)		(146	)
Tax levelization		-			(1	)		(1	)		(3	)
CVO mark-to-market, net of tax		(50	)		-			(46	)		-
Discontinued operations attributable to   controlling interests, net of tax		-			(2	)		(4	)		(2	)
Net loss attributable to controlling interests	$	(110	)	$	(52	)	$	(201	)	$	(151	)

OTHER INTEREST EXPENSE

Other interest expense increased $11 million for the three months ended September 30, 2011 compared to the same period in 2010, primarily due to the corporate impact of the 2011 settlement of 2004 and 2005 income tax audits.

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ONGOING EARNINGS ADJUSTMENTS

Tax Levelization

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 not impacted for the three months ended September 30, 2011, compared to an increase of $1 million for the same period in 2010, and was increased by $1 million and $3 million for the nine months ended September 30, 2011 and 2010, 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. Because this adjustment will vary each quarter, but will have no effect on net income for the year, management does not consider this adjustment to be representative of our fundamental core earnings.

CVO Mark-to-Market

At September 30, 2011 and 2010, the CVOs had fair values of approximately $74 million and $15 million, respectively. The unrealized gain/loss recognized due to changes in fair value is recorded in other, net on the Consolidated Statements of Income. There was no change in the fair value of the CVOs for the three months ended September 30, 2010. Progress Energy recorded a pre-tax unrealized loss of $63 million for the three months ended September 30, 2011 to record the change in fair value of the CVOs, which had average unit prices of $0.75 and $0.16 at September 30, 2011 and 2010, respectively. There was no change in the fair value of the CVOs for the nine months ended September 30, 2010. Progress Energy recorded a pre-tax unrealized loss of $59 million for the nine months ended September 30, 2011 to record the change in fair value of the CVOs. See Notes 8B and 10 herein and Note 15 in the 2010 Form 10-K for further information. Because Progress Energy is unable to predict the changes in the fair value of the CVOs, management does not consider this adjustment to be representative of our fundamental core earnings.

Discontinued Operations Attributable to Controlling Interests, Net of Tax

We completed our business strategy of divesting of nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. We recognized $2 million of loss from discontinued operations attributable to controlling interests, net of tax, for the three months ended September 30, 2010 and $4 million and $2 million of loss for the nine months ended September 30, 2011 and 2010, respectively. Management does not consider operating results of discontinued operations to be representative of our fundamental core earnings.

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 typically rely upon our operating cash flow, substantially all of which is generated by the Utilities, commercial paper and credit 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 will 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 and plant performance can lead to over- or under-recovery of fuel costs, as changes in fuel expense are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility and plant performance 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 and/or how our plants are performing. Changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows, but not materially affect net income. In addition, as discussed in “Future Liquidity and Capital Resources” below, the timing of applicable CR3 repair and the associated replacement power cost recovery from NEIL could impact short-term borrowing needs.

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As a registered holding company, our establishment of intercompany extensions of credit is subject to regulation by the FERC. 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. A non-utility money pool allows our nonregulated operations to lend to and borrow from each other. The Parent can lend money to the utility and non-utility money pools but cannot borrow funds.

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 $4.0 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; the Parent’s credit facility; and/or the Parent’s ability to access the short-term and long-term debt and equity capital markets. During the nine months ended September 30, 2011, PEC paid dividends of $450 million and PEF paid dividends of $475 million to 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. The Parent could change its existing common stock dividend policy based upon these and other business factors.

Cash from operations, commercial paper issuance, borrowings under our credit facilities and/or long-term debt financings are expected to fund capital expenditures, long-term debt maturities and common stock dividends for 2011. Through the nine months ended September 30, 2011 we have realized approximately $42 million in equity proceeds primarily through our equity incentive plans, but do not expect to realize a material amount of proceeds from the sale of equity during the remainder of 2011 (See “Financing Activities”).

We have 23 financial institutions supporting our combined $1.978 billion revolving credit agreements (RCAs) for the Parent, PEC and PEF. The credit facilities serve as back-ups to our commercial paper programs. To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At September 30, 2011, the Parent had no outstanding borrowings under its credit facility, $45 million of outstanding commercial paper and had issued $31 million of letters of credit, which were supported by the revolving credit facility. At September 30, 2011, PEC and PEF had no outstanding borrowings under their respective credit facilities and no outstanding commercial paper balances. Based on these outstanding amounts at September 30, 2011, there was a combined $1.902 billion available for additional borrowings.

At September 30, 2011, 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, 2011, 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, 2011, 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 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, 2011, the sums of the Parent’s, PEC’s and PEF’s open pay-fixed forward starting swaps were each in a net mark-to-market liability position. See Note 12B for additional information with regard to our interest rate derivatives.

In 2010, the Wall Street Reform and Consumer Protection Act was signed into law. Among other things, the law includes provisions related to the swaps and over-the-counter derivatives markets. Under the law, we expect to be exempt from mandatory clearing and exchange trading requirements for our commodity and interest rate hedges because we are an end user of these products. Capital and margin requirements for these hedges are currently in the process of being determined as detailed rules and regulations are published. At this time, we do not expect the law to have a material impact on our financial condition. However, we cannot determine the impact until the final regulations are issued.

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

We believe our internal and external liquidity resources will be sufficient to fund our current business plans. We will continue to monitor the credit markets to maintain an appropriate level of liquidity. Our ability to access the capital markets on favorable terms may be negatively impacted by credit rating actions. Risk factors associated with the capital markets and credit ratings are discussed below and in Item 1A, “Risk Factors” to the 2010 Form 10-K.

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

HISTORICAL FOR 2011 AS COMPARED TO 2010

CASH FLOWS FROM OPERATIONS

Net cash provided by operating activities decreased $600 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The decrease was primarily due to $263 million higher cash used for inventory, a $194 million increase in pension plan funding, the $115 million less favorable impact of weather at the Utilities as previously discussed and $86 million paid for interest rate locks terminated in conjunction with the issuance of long-term debt in 2011, partially offset by $52 million of net cash refunds of collateral to counterparties on derivative contracts in 2011 compared to $83 million of net cash payments of collateral in 2010. The increase in cash used for inventory was primarily due to the impact of changes in coal inventory in 2011 compared to 2010 due to higher purchases reflecting anticipated winter consumption and higher prices in 2011 combined with higher 2010 consumption of existing inventory levels to meet system requirements resulting from favorable weather.

INVESTING ACTIVITIES

Net cash used by investing activities decreased by $229 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. This decrease was primarily due to a $108 million decrease in gross property additions, primarily due to lower spending for environmental compliance and nuclear projects at PEF; the $54 million increase in receipt of NEIL insurance proceeds for repairs at CR3 (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”); and $27 million of litigation judgment proceeds.

FINANCING ACTIVITIES

Net cash used by financing activities increased by $103 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The increase was primarily due to a $377 million net decrease in issuances of common stock, primarily related to the Parent’s 2010 common stock sales under the Progress Energy Investor Plus Plan (IPP), partially offset by the $280 million increase in proceeds from short-term and long-term debt, net of retirements.

A discussion of our 2011 financing activities follows:

On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due January 15, 2021. The net proceeds, along with available cash on hand, were used to retire the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011.

On May 3, 2011, $22 million of the Parent’s $500 million RCA expired, leaving the Parent with total credit commitments of $478 million supported by 14 financial institutions. After the $22 million expiration, our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions.

On July 15, 2011, PEF paid at maturity $300 million of its 6.65% First Mortgage Bonds with proceeds from commercial paper borrowings.

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On August 18, 2011, PEF issued $300 million 3.10% First Mortgage Bonds due August 15, 2021. The net proceeds were used to repay a portion of outstanding short-term debt, of which $300 million was borrowed to repay PEF’s July 15, 2011 maturity.

On September 15, 2011, PEC issued $500 million 3.00% First Mortgage Bonds due September 15, 2021. A portion of the net proceeds was used to repay outstanding short-term debt and the remainder was placed in temporary investments for general corporate use as needed, including construction expenditures.

At December 31, 2010, we had 500 million shares of common stock authorized under our charter, of which 293 million shares were outstanding. For the three and nine months ended September 30, 2011, respectively, we issued approximately 0.3 million and 1.7 million shares of common stock through the IPP and equity incentive plans resulting in approximately $16 million and $42 million in net proceeds. For the three and nine months ended September 30, 2010, respectively, we issued approximately 0.3 million and 11.8 million shares of common stock resulting in approximately $14 million and $419 million in net proceeds.

SHORT-TERM DEBT

At September 30, 2011, Progress Energy had outstanding short-term debt consisting of commercial paper borrowings totaling $45 million at a weighted average interest rate of 0.34%. At the end of each month during the three months ended September 30, 2011, Progress Energy had a maximum short-term debt balance of $603 million and an average short-term debt balance of $415 million at a weighted average interest rate of 0.37%. Short-term debt balances were lower at September 30, 2011 compared to the maximum and average balances due to the repayment of commercial paper borrowings following the issuance of $500 million and $300 million of long-term debt at PEC and PEF, respectively. See “Financing Activities” above for more information on the long-term debt issuances at PEC and PEF during the three months ended September 30, 2011.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2011, there were no material changes in our discussion under “Liquidity and Capital Resources” in Item 7 to the 2010 Form 10-K, other than as described below and in “Historical for 2011 as Compared to 2010 – Financing Activities.”

The Utilities produce substantially all of our consolidated cash from operations. We anticipate that the Utilities will continue to produce substantially all of the consolidated cash flows from operations over the next several years. Our discontinued synthetic fuels operations historically produced significant net earnings from the generation of tax credits (See “Other Matters – Synthetic Fuels Tax Credits”). A portion of these tax credits has yet to be realized in cash due to the difference in timing of when tax credits are recognized for financial reporting purposes and realized for tax purposes. At September 30, 2011, we have carried forward $850 million of deferred tax credits that do not expire. 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, availability under our credit facilities and issuances of commercial paper and long-term debt, which are dependent on our ability to successfully access capital markets.

Credit rating downgrades could negatively impact our ability to access the capital markets and respond to major events such as hurricanes. Our cost of capital could also be higher, which could ultimately increase prices for our customers. It is important for us to maintain our credit ratings and have access to the capital markets in order to reliably serve customers, invest in capital improvements and prepare for our customers’ future energy needs (See Item 1A, “Risk Factors” to 2010 Form 10-K).

We typically issue commercial paper to meet short-term liquidity needs. 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 borrowing under our RCAs, issuing short-term notes, and/or issuing long-term debt.

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The Parent’s RCA will expire in May 2012. We are currently evaluating options to address this expiration. In the event we enter into a new RCA for the Parent, we cannot predict the terms, prices, durations or participants in such facility.

Progress Energy and its subsidiaries have approximately $12.940 billion in outstanding long-term debt, including the $950 million current portion. Currently, approximately $860 million of the Utilities’ debt obligations, approximately $620 million at PEC and approximately $240 million at PEF, are tax-exempt auction rate securities insured by bond insurance. These tax-exempt bonds have experienced 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 lower our tax-exempt bond ratings. In the event of a one notch downgrade of PEC’s and/or PEF’s senior secured debt rating by Standard and Poor’s Rating Services (S&P), the ratings of such utility’s tax-exempt bonds would be below A-, most likely resulting in higher future interest rate resets. In the event of a one notch downgrade by Moody’s Investor Services, Inc. (Moody’s), PEC’s and PEF’s tax-exempt bonds will continue to be rated at or above A3. We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations under our defined benefit pension plans. Although a number of factors impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the obligations under our defined benefit pension plans. During the nine months ended September 30, 2011, we contributed $313 million directly to pension plan assets and expect to make total contributions of $325 million to $350 million in 2011 (See Note 11).

As discussed in “Liquidity and Capital Resources” and 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. 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 in “Other Matters – Nuclear – Potential New Construction,” PEF will postpone major capital expenditures for the proposed nuclear plant in Levy County, Fla. (Levy) until after the NRC issues the combined license (COL), which is expected to be in 2013 if the current licensing schedule remains on track.

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 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, 2010, have impacted the amount of collateral posted with counterparties. At September 30, 2011, we had posted approximately $112 million of cash collateral compared to $164 million of cash collateral posted at December 31, 2010. The majority of our financial hedge agreements will settle in 2011 and 2012. 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. Credit rating downgrades could also require us to post additional cash collateral for commodity hedges in a liability position as certain derivative instruments require us to post collateral on liability positions based on our credit ratings.

The amount and timing of future sales of debt will depend on market conditions, operating cash flow and our specific liquidity needs. We may from time to time sell securities beyond the amount immediately needed to meet our capital or liquidity requirements in order to prefund our expected maturity schedule, 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.

At September 30, 2011, the current portion of our long-term debt was $950 million (including $500 million at PEC). We expect to fund the current portion of long-term debt with a combination of cash from operations, commercial paper borrowings and/or long-term debt.

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REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, including the CR3 outage and nuclear cost recovery, as discussed in Note 4 and “Other Matters – Nuclear,” and recovery of environmental costs, as discussed in Note 14 and in “Other Matters – Environmental Matters,” may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Energy legislation enacted in recent years may impact our liquidity over the long term, including among others, provisions regarding cost recovery, mandated renewable portfolio standards, DSM and EE.

Regulatory developments expected to have a material impact on our liquidity are discussed below.

PEC Cost Recovery Filings

On June 3, 2011, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina retail ratepayers, driven by rising fuel prices. On September 15, 2011, PEC filed a settlement agreement for an increase of approximately $85 million in the fuel rate. The settlement agreement updated certain costs from PEC’s original filing and included the impact of a $24 million disallowance of replacement power costs resulting from prior-year performance of PEC’s nuclear plants. If approved, the increase will be effective December 1, 2011. On June 3, 2011, and as subsequently amended on August 23, 2011, PEC also filed for a $24 million increase in the DSM and EE rate charged to its North Carolina ratepayers which, if approved, will be effective December 1, 2011. On June 3, 2011, and as subsequently amended on September 8, 2011, PEC also requested a $9 million increase for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), which if approved, will be effective December 1, 2011. We cannot predict the outcome of these matters.

On June 29, 2011, the SCPSC approved a $22 million increase in the fuel rate charged to PEC’s South Carolina ratepayers, driven by rising fuel prices. The increase was effective July 1, 2011.

PEC Construction of Generating Facilities

The NCUC has granted PEC permission to construct two new generating facilities: an approximately 950-MW combined cycle natural gas-fueled facility at its Lee generation facility and an approximately 620-MW natural gas-fueled facility at its Sutton generation facility. The facilities are expected to be placed in service in January 2013 and December 2013, respectively.

CR3 Outage

The preliminary cost estimate as filed with the FPSC on June 27, 2011, for the selected repair option to return CR3 to service is between $900 million and $1.3 billion. Engineering design of the final repair is underway. PEF will update the current estimate as this work is completed.

PEF maintains insurance for property damage and incremental costs of replacement power resulting from prolonged accidental outages through NEIL. NEIL has confirmed that the CR3 initial delamination is a covered accident but has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through September 30, 2011. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. As discussed below, PEF considers replacement power costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause. PEF also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs, the timing of which could impact its short-term borrowing needs.

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The following table summarizes the CR3 replacement power and repair costs and recovery through September 30, 2011:

(in millions)	Replacement Power Costs				Repair Costs
Spent to date	$	457			$	229
NEIL proceeds received		(162	)			(136	)
Insurance receivable at September 30, 2011		(162	)			(48	)
Balance for recovery	$	133		(a)	$	45

(a) As approved by the FPSC on January 1, 2011, PEF began collecting, subject to refund, replacement power costs related to CR3 within the fuel clause (See Note 7C in the 2010 Form 10-K). The replacement power costs to be recovered through the fuel clause during 2011 allow for full recovery of all of 2010’s and 2011’s replacement power costs. The 2011 fuel cost-recovery filing, discussed in “Fuel Cost Recovery,” anticipates full recovery of estimated 2012 replacement power costs.

PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. PEF has recorded $324 million of NEIL replacement power cost reimbursements subsequent to the deductible period, of which $162 million has been received to date. PEF has received $45 million of replacement power reimbursements from NEIL for the nine months ended September 30, 2011. No replacement power reimbursements have been received from NEIL for the three months ended September 30, 2011. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. We cannot predict with certainty the future recoverability of these costs. Failure to recover some or all of these costs could have a material adverse effect on our and PEF’s financial results. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

PEF Cost Recovery Filings

On September 1, 2011, and as subsequently adjusted by the FPSC, PEF filed its annual fuel-cost recovery filing, requesting to increase the total fuel-cost recovery by $162 million, which will be effective January 1, 2012 if approved. We cannot predict the outcome of this matter.

On October 24, 2011, the FPSC approved a $78 million decrease in the amount charged to PEF’s ratepayers for nuclear cost recovery, beginning with the first January 2012 billing cycle.

On August 26, 2011, and as subsequently revised on October 14, 2011, PEF filed its annual Environmental Cost Recovery Clause (ECRC) filing, requesting to increase the ECRC by $24 million, which would be effective January 1, 2012 if approved. We cannot predict the outcome of this matter.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

At September 30, 2011, our guarantees have not changed materially from what was reported in the 2010 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.

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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 2010 Form 10-K can result from new contracts, changes in existing contracts, and the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs. At September 30, 2011,our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2010 Form 10-K except as discussed below.

PEC

As described in Note 22A in the 2010 Form 10-K, PEC entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs. As the transactions are subject to several conditions precedent, the estimated costs associated with these agreements were not included in PEC’s fuel commitments at December 31, 2010. The estimated total cost to PEC associated with these agreements at December 31, 2010, was approximately $2.042 billion, which pertain to the period from May 2011 through May 2033. During the nine months ended September 30, 2011, the conditions precedent for one of the agreements were satisfied. The agreement is for the period May 2011 through April 2031 and has an estimated total cost of approximately $487 million, including $16 million, $49 million, $49 million and $373 million, respectively, for less than one year, one to three years, three to five years and more than five years from December 31, 2010.

PEF

As described in Note 22A in the 2010 Form 10-K, PEF entered into conditional agreements for firm pipeline transportation capacity to support PEF’s gas supply needs. As the transactions were subject to several conditions precedent, the estimated costs associated with these agreements were not included in PEF’s fuel commitments at December 31, 2010. During the nine months ended September 30, 2011, the conditions precedent for these agreements were satisfied. These agreements are for the period April 2011 through April 2036 and have an estimated total cost of approximately $1.171 billion, including $36 million, $95 million, $95 million and $945 million, respectively, for less than one year, one to three years, three to five years and more than five years from December 31, 2010.

OTHER MATTERS

ENVIRONMENTAL MATTERS

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

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the U.S. Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida or potentially responsible 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

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(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 14). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. Hazardous and solid waste management matters are discussed in detail in Note 14A.

We accrue costs 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 could change and additional losses, which could be material, may be incurred in the future.

In 2009, the EPA evaluated information about ash impoundment dams nationwide and developed a listing of 44 utility ash impoundment dams considered to have “high hazard potential,” including two of PEC’s ash impoundment dams. A “high hazard potential” rating is not related to the stability of those ash ponds but to the potential for harm should the impoundment dam fail. All of the dams at PEC’s coal ash ponds have been subject to periodic third-party inspection for many years in accordance with prior applicable requirements. The EPA rated the 44 “high hazard potential” impoundments, as well as other impoundments, from “unsatisfactory” to “satisfactory” based on their structural integrity and associated documentation.

Only dams rated as “unsatisfactory” would be considered to pose an immediate safety threat. None of the facilities received an “unsatisfactory” rating from the EPA. In total, six of PEC’s ash pond dams, including one “high hazard potential” impoundment, were rated as “poor” based on the contract inspector’s desire to see additional documentation and evaluations of 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 addressed several of the EPA’s recommendations for the active ponds. Following evaluations and inspections, engineers have determined that one ash pond dam requires modifications to comply with current standards for an extra margin of safety for slope stability. Design and permitting efforts for that work have been initiated. PEC is working with the North Carolina Dam Safety program to evaluate any remaining recommendations. We do not expect mitigation of these issues to have a material impact on our results of operations.

As of January 1, 2010, dams at utility fossil-fired power plants in North Carolina, including dams for ash ponds, are subject to the North Carolina Dam Safety Act’s applicable provisions, including state inspection. The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, 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. In 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residue management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residuals that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

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 expense.

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Control equipment installed pursuant to the provisions of the CAIR, Cross-State Air Pollution Rule (CSAPR), Clean Air Visibility Rule (CAVR) and mercury regulations, which are discussed below, may address some of the issues outlined previously. 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 Clean Air Mercury Rule (CAMR) below). The CAVR requires the installation of

best available retrofit technology (BART) on certain units. However, the outcome of these matters cannot be predicted.

Clean Smokestacks Act

The 2002 enactment of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act) requires the state's electric utilities to reduce the emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,000 MW of coal-fired generation capacity in North Carolina affected by the Clean Smokestacks Act. PEC’s environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions have been placed in service. PEC plans to retire, by the end of 2014, its remaining coal-fired generating facilities in North Carolina totaling 1,500 MW that do not have scrubbers and replace the generation capacity with new natural gas-fueled generating facilities, which should enable the utility to comply with the final Clean Smokestacks Act SO2 emissions target that begins in 2013. We are continuing to evaluate various design, technology, generation and fuel options that could change expenditures required to maintain compliance with the Clean Smokestacks Act limits subsequent to 2013.

O&M expense increases with the operation of pollution control equipment due to the cost of 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; the North Carolina retail portion of all other O&M expense is currently recoverable through base rates. In 2009, the SCPSC issued an order allowing PEC to begin deferring as a regulatory asset the depreciation expense that PEC incurs on its environmental compliance control facilities as well as the incremental O&M expense that PEC incurs in connection with its environmental compliance control facilities.

Clean Air Interstate Rule/Cross-State Air Pollution Rule

The CAIR, issued by the EPA, 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 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court’s prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the CSAPR as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina is classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina is classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, implementation of the CAIR fulfilled BART for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of the CSAPR, CAVR compliance eventually will require additional consideration of NOx and SO2 emissions in addition to particulate matter emissions for PEF’s BART-eligible units because Florida will no longer be subject to the annual emissions provisions. We are currently evaluating the impacts of the CSAPR. A number of parties

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 including groups which PEC and PEF are members of, have filed petitions for reconsideration and stay of, as well as legal challenges to, the CSAPR. We cannot predict the outcome of this matter.

The air quality controls installed to comply with NOx and SO2 requirements under certain sections of the Clean Air Act (CAA) and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR and CSAPR requirements for NOx and SO2 for our North Carolina units at PEC. NOx and SO2 emission control equipment are in service at PEF’s Crystal River Unit No. 4 and Crystal River Unit No. 5 (CR4 and CR5), and we plan to continue compliance with the CAIR in 2011 through a combination of emission controls, continued use of natural gas at applicable facilities, and use of emission allowances.

Under an agreement with the Florida Department of Environmental Protection (FDEP), PEF will retire Crystal River Units No. 1 and No. 2 coal-fired steam units (CR1 and CR2) and operate emission control equipment 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 originally anticipated to be around 2020. As discussed in Note 4B and “Other Matters – Nuclear – Potential New Construction,” major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

Clean Air Mercury Rule

In 2008, the D.C. Court of Appeals vacated the CAMR. As a result, the EPA subsequently announced that it will develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On October 21, 2011, the EPA requested the U.S. District Court for the District of Columbia to extend the deadline for the final rule to December 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT) and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following the conclusion of the 90-day public comment period, the EPA has requested to issue a final rule in December 2011. In addition, North Carolina adopted a state-specific requirement. 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 the EPA’s proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted.

Clean Air Visibility Rule

The EPA’s CAVR 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 certain 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 in Note 4A, Sutton Unit No. 3 is one of the coal-fired generating units that PEC plans to replace with combined cycle natural gas-fueled electric generation. As discussed previously, 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’ decision remanding the CAIR maintained its implementation such that CAIR satisfies BART for NOx and SO2. Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of NOx and SO2 emissions in addition to particulate matter emissions for PEF’s BART-eligible units, because Florida will no longer be subject to the annual emissions provisions. We are assessing the potential impact of BART and its

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implications with respect to our plans and estimated costs to comply with the CAVR. 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, in the spring of 2010 the EPA indicated that the Reasonable Further Progress portion of the Regional Haze implementation rule is not approvable. The FDEP is in the process of amending the rule by removing the Reasonable Further Progress provision, including the December 31, 2017 deadline for installation of additional controls, and instead will rely on current federal programs to achieve improvement in visibility. 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 CSAPR, the CAVR, mercury regulation and related air quality regulations. The air quality controls installed to comply with NOx and SO2 requirements under certain sections of the CAA and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, resulted in a reduction of the costs to meet PEC’s CAIR requirements and the CSAPR requirements that take effect beginning in 2012.

PEC’s environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions and PEF’s environmental compliance projects under the first phase of CAIR are in service.

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 previously regarding the vacating of the CAMR and remanding of the CAIR and its potential impact on CAVR). PEF’s April 1, 2011 filing with the FPSC for true-up of final 2010 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 $1.1 billion to be spent through 2016, to plan, design, build and install pollution control equipment at CR4 and CR5. PEF no longer plans to install pollution controls at the Anclote Plant as a part of its approved Integrated Clean Air Compliance Plan. The majority of the $1.1 billion estimated total project cost is related to CR4 and CR5 projects, which have been placed in service. Additional costs may be incurred if pollution controls are required in order to comply with the requirements of the CAVR, as discussed previously, or to meet compliance requirements of the CSAPR. 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

Risk factors regarding environmental compliance cost estimates are discussed in Item 1A, “Risk Factors,” of the 2010 Form 10-K. 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. 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. Additional compliance plans for PEC and PEF to meet the requirements of the CSAPR have not been completed. Compliance plans and costs to meet the requirements of the CAVR are being reassessed, and we cannot predict the impact that the EPA’s further proceedings will have on our compliance with the CAVR requirements. Compliance plans to meet the requirements of the EGU MACT will be determined upon finalization of the rule. Compliance plans to meet the requirements of a revised or new implementing rule under Section 316(b) of the Clean Water Act (Section 316(b)), as discussed below, will be determined upon finalization of the rule. The timing and extent of the costs for future projects will depend upon final compliance strategies. However, we believe that future costs to comply with new or subsequent rule interpretations could be significant.

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

In 2004, the North Carolina attorney general filed a petition with the EPA, under Section 126 of the CAA, asking the federal government to force fossil fuel-fired power plants in 13 other states, including South Carolina, to reduce

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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

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. In 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.

In 2008, the EPA revised the 8-hour primary and secondary standards for the NAAQS for ground-level ozone. Additional nonattainment areas may be designated in PEC’s and PEF’s service territories as a result of these revised standards. 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 2009, the EPA announced that it was reconsidering the level of the ozone NAAQS and it will stay plans to designate nonattainment areas until after the reconsideration has been completed.

In 2010, the EPA announced a proposed revision to the primary ozone NAAQS. In addition, the EPA proposed a cumulative seasonal secondary standard. On September 2, 2011, President Obama announced that the EPA would withdraw the proposed revision. As a result, the ozone NAAQS promulgated in 2008 will be implemented, and the review of the standard has been deferred until 2013. With respect to the 2008 standard, all areas in our service territories are in compliance.

In 2010, the EPA announced a revision to the primary NAAQS for nitrogen dioxide (NO2). The EPA plans to designate nonattainment areas for the primary NAAQS for NO2 by January 2012. Currently, there are no monitors reporting violation of this new standard in our service territories, but the expanded monitoring network will provide additional data, which could result in additional nonattainment areas. Should additional nonattainment areas for the new NO2 NAAQS be designated in our service territories, we may be required to install additional controls at some of our facilities. Additionally, the EPA revised the 1-hour NAAQS for SO2 in 2010. Implementation of the new 1-hour NAAQS for SO2 uses air quality modeling along with monitoring data in determining whether areas are attaining the new standard, which is likely to expand the number of nonattainment areas. Should additional nonattainment areas for the 1-hour NAAQS for SO2 be designated in our service territories, we may be required to install additional emission controls at some of our facilities. The outcome of these matters cannot be predicted.

On July 13, 2011, the EPA made available its proposed action on the combined review of the secondary NAAQS for NOx and sulfur oxides (SOx) and expects to issue a final rule by March 2012. In this rulemaking, the EPA is proposing to retain the existing secondary standards for NO2 and SO2 and is also proposing a new set of secondary standards identical to the health-based primary standards it set in 2010. For NOx, the new standard would be 100 parts per billion averaged over one hour, measured as NO2. For SOx, the new standard would be 75 parts per billion averaged over one hour, measured as SO2. Should nonattainment areas for secondary NAAQS for NOx and SOx be designated in our service territories, we may be required to install additional emission controls at some of our facilities. The outcome of these matters cannot be predicted.

Water Quality

1. General

As a result of the operation of certain pollution control equipment required to comply with the air quality issues outlined previously, 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

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future costs of complying with these requirements could be material to our or the Utilities’ results of operations or financial position.

In 2009, the EPA concluded after a multi-year study of power plant wastewater discharges that regulations have not kept pace with changes 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.

More stringent effluent limitations contained in the current water discharge permit for the Mayo Steam Electric Plant became effective in June 2011. PEC is currently negotiating the issuance of a special order by consent with the North Carolina Division of Water Quality, which would defer the agency’s enforcement of the more stringent effluent limitations due to the plant’s inability to achieve compliance with the more stringent limitations. The special order by consent, if issued, is expected to include the required development and installation of enhanced water pollution control technology and application of less stringent interim effluent limitations until PEC’s planned project to bring the plant into compliance with the more stringent effluent limitations is completed. However, since the special order by consent has not yet been issued in final form, it is not possible to determine the extent of the planned project. Moreover, the special order by consent does not prevent actions by the EPA or third parties. Thus, the outcome of these matters cannot be determined.

2. 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 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. Following appeal, in 2009, the U.S. Supreme Court issued an 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. 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 after 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. In December 2010, consent decrees were entered in two pending federal actions brought by environmental groups against the EPA requiring the EPA to issue proposed Section 316(b) rules by March 28, 2011, and to issue a final decision by July 27, 2012.

On April 20, 2011, the EPA published its proposed regulations for cooling water intake structures at existing power generating facilities and existing manufacturing and industrial facilities that withdraw more than two million gallons of water per day from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. The proposed regulations would establish nationwide, uniform standards for impingement mortality (immobilization of aquatic organisms against an intake screen) and case-by-case, site-specific standards for entrainment mortality (lethal effects due to passage of aquatic organisms into a cooling system). Comments on the proposed rule have been timely submitted by affected parties including PEC and PEF. The outcome of this matter cannot be predicted.

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OTHER ENVIRONMENTAL MATTERS

Global Climate Change

Growing state, federal and international attention to global climate change may result in the regulation of carbon dioxide (CO2) and other greenhouse gases (GHGs). In addition, the Obama administration has begun the process of regulating GHG emissions through use of the CAA. In 2007, the U.S. Supreme Court ruled that the EPA has the authority under the CAA to regulate CO2 emissions from new automobiles. In 2009, the EPA announced that six GHGs (CO2, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) pose a threat to public health and welfare under the CAA. A number of parties have filed petitions for review of this finding in the D.C. Court of Appeals. In 2010, the EPA announced a schedule for development of a new source performance standard for new and existing fossil fuel-fired electric utility units. Under the schedule, the EPA was to propose the standard by September 30, 2011, and issue the final rule by May 2012. The EPA has deferred, but not announced, the date by which it will propose the standard. The full impact of regulation under GHG initiatives and any final legislation, if enacted, cannot be determined at this time; however, we anticipate that it could result in significant cost increases over time for which the Utilities would seek corresponding rate recovery. We are preparing for a carbon-constrained future and are actively engaged in helping shape effective policies to address the issue.

While state-level study groups have been active in all three of our jurisdictions, we continue to believe that this issue 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 our service territories and provides a solid basis for slowing and reducing CO2 emissions by focusing on energy efficiency, alternative energy and a state-of-the-art power system.

There are ongoing efforts to reach a new international climate change treaty to succeed the Kyoto Protocol. The Kyoto Protocol was originally adopted by the United Nations to address global climate change by reducing emissions of CO2 and other GHGs. Although the treaty went into effect in 2005, the United States has not ratified it. In 2009, the United Nations Framework Convention on Climate Change convened the 15th Conference of the Parties to conduct further negotiations on GHG emissions reductions. At the conclusion of the conference, a number of the parties, including the United States, entered into a nonbinding accord calling upon the parties to submit emission reduction targets for 2020 to the United Nations Framework Convention on Climate Change Secretariat by the end of January 2010. In 2010, President Obama submitted a proposal to Congress to reduce the U.S. GHG emissions in the range of 17 percent below 2005 levels by 2020, subject to future congressional action. To date, Congress has not enacted legislation implementing the President’s proposal.

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.

In 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. The EPA extended the first annual reporting deadline to September 30, 2011. Because the rule builds on current emission-reporting requirements, compliance with the requirements is not expected to have a material impact on the Utilities.

The EPA is regulating mobile source GHG emissions under Section 202 of the CAA, which according to the EPA also results in stationary sources, such as coal-fired power plants, being subject to regulation of GHG emissions under the CAA. The EPA issued the final “tailoring rule,” which establishes the thresholds for applicability of the Prevention of Significant Deterioration program permitting requirements for GHG emissions from stationary sources such as power plants and manufacturing facilities. Prevention of Significant Deterioration is a construction air pollution permitting program designed to ensure air quality does not degrade beyond the NAAQS levels or beyond specified incremental amounts above a prescribed baseline level. The tailoring rule initially raises the permitting applicability threshold for GHG emissions to 75,000 tons per year. These developments require PEC and PEF to address GHG emissions in new air quality permits. The permitting requirements for GHG emissions from

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stationary sources began on January 2, 2011. A number of parties have filed petitions for review of the tailoring rule in the D.C. Court of Appeals. The impact of these developments cannot be predicted.

In May 2011, PEC and PEF were named, along with numerous other defendants, in a complaint of a class action lawsuit. Plaintiffs claim that defendants’ GHG emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. We cannot predict the outcome of this matter (See Note 15C).

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 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 the opportunity 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 if any of these states will move to increase retail competition in the electric industry.

Current retail rate matters affected by state regulatory authorities are discussed in Note 4, including specific retail rate matters, the status of the issues and the associated effects on our consolidated financial statements.

On April 28, 2010, we accepted a grant from the U.S. Department of Energy (DOE) for $200 million in federal matching infrastructure funds. In addition to providing the Utilities real-time information about the state of their electric grids, the smart grid transition will enable customers to better understand and manage their energy use, and will provide for more efficient integration of renewable energy resources. Supplementing the DOE grant, the Utilities will invest more than $300 million in smart grid projects, which include enhancements to distribution equipment, installation of 160,000 additional smart meters and additional public infrastructure for plug-in electric vehicles. Projects funded by the grant must be completed by April 2013.

Through September 30, 2011, we have incurred $186 million of allowable, 50 percent reimbursable, smart grid project costs, and have submitted to the DOE requests for reimbursement of $93 million, of which we have received $64 million of reimbursement.

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 DSM and EE programs; (2) investing in the development of alternative energy resources for the future; and (3) operating a state-of-the-art power system that demonstrates our commitment to environmental responsibility. These and other items are discussed in Item 7, “MD&A – Other Matters,” to the 2010 Form 10-K.

We are continuing the expansion and enhancement of our DSM and EE programs because 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.

As discussed in Note 4A, PEC announced a coal-to-gas modernization strategy whereby the 11 remaining coal-fired generating facilities in North Carolina that do not have scrubbers would be retired prior to the end of their useful lives and their approximately 1,500 MW of generating capacity replaced with new natural gas-fueled facilities. On October 1, 2011, we retired the Weatherspoon coal units.

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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.

In light of the events at the Fukushima Daiichi nuclear power station in Japan, the NRC formed a Task Force to conduct a comprehensive review of processes and regulations to determine whether the agency should make additional improvements to the nuclear regulatory system. On July 13, 2011, the Task Force proposed a set of improvements designed to ensure protection, enhance accident mitigation, strengthen emergency preparedness and improve efficiency of NRC programs. The NRC is also expected to issue a longer-term report with recommendations for the Commission’s consideration by early 2012. With the ongoing investigations into the nature and extent of damages in Japan, the underlying causes of the situation and the lack of clarity around regulatory and political responses, we cannot predict whether the NRC will impose additional licensing and safety-related requirements. See Item 1A, “Risk Factors”, in the 2010 Form 10-K for further discussion of applicable risk factors.

CR3 OUTAGE

In September 2009, CR3 began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete of the outer wall of the containment building, which resulted in an extension of the outage. In March 2011, engineers investigated and subsequently determined that a new delamination had occurred in another area of the structure after initial repair work was completed and during the late stages of retensioning the containment building. Subsequent to March 2011, monitoring equipment has detected additional changes in the partially tensioned containment building and additional cracking or delaminations may have occurred or could occur during the repair process.

PEF analyzed multiple repair options, as well as early decommissioning, and selected the best repair option, which entails systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair, as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the final repair is underway. PEF will update the current estimate as this work is completed. Under this repair plan, we estimate CR3 will return to service in 2014. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments (See Note 4B).

POTENTIAL NEW CONSTRUCTION

During 2008, PEC and PEF filed COL applications to potentially construct new nuclear plants in North Carolina and Florida. We anticipate that the NRC will issue the COLs no earlier than 2013 if the current licensing schedule remains on track.

We have focused on Levy given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce GHG emissions, as well as existing state legislative policy that is supportive of nuclear projects. PEF has entered into an engineering, procurement and construction (EPC) agreement and received two of the four key regulatory approvals needed for the proposed Levy units (with the issuance of the COL and federal environmental permits remaining). In light of a regulatory schedule shift and other factors, we have amended the EPC agreement and are deferring major construction activities on Levy until after the receipt of the COL. This decision will reduce the near-term price impact on customers and allows time for economic recovery and greater clarity on federal and state policies. Once we have received the COL, we will assess the project and determine the schedule.

In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time

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equipment. Work has been suspended on the remaining long lead time equipment items and PEF entered into suspension negotiations with the selected equipment vendors, all of which were concluded in July 2011.

In its May 2, 2011 nuclear cost-recovery filing, PEF included for rate-making purposes a point estimate of potential Levy purchase order disposition costs of $25 million, a reduction from the $50 million point estimate in the prior-year filing, subject to true-up. Final negotiations of all long lead-time equipment resulted in lower actual disposition costs compared to the $25 million point estimate.

SPENT NUCLEAR FUEL MATTERS

See Note 15C for discussion of the status of the Utilities’ contracts with the DOE for spent nuclear fuel storage.

SYNTHETIC FUELS TAX CREDITS

Historically, we had substantial operations associated with the production and sale of coal-based solid synthetic fuels, which qualified for federal income tax credits so long as certain requirements were satisfied. Tax credits generated under the synthetic fuels tax credit program (including those generated by Florida Progress Corporation prior to our acquisition) were $1.891 billion, of which $1.041 billion has been used through September 30, 2011, to offset regular federal income tax liability and $850 million is being carried forward as deferred tax credits that do not expire.

See Note 15C and Item 1A, “Risk Factors,” and “MD&A – Other Matters – Synthetic Fuels Tax Credits” to the 2010 Form 10-K for additional discussion related to our previous synthetic fuels operations and the associated tax credits generated under the synthetic fuels tax credit program.

LEGAL

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

NEW ACCOUNTING STANDARDS

See Note 3 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” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors,” to the 2010 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities decreased $261 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The decrease was primarily due to $264 million higher cash used for inventory, a $119 million increase in pension plan funding, the $59 million less favorable impact of weather as previously discussed and $33 million paid for interest rate locks terminated in conjunction with the issuance of long-term debt in 2011, partially offset by $173 million in lower net cash for taxes and $10 million of net cash refunds of collateral to counterparties on derivative contracts in 2011 compared to $24 million of net cash payments of collateral in 2010. The increase in cash used for inventory was primarily due to the impact of changes in coal inventory in 2011 compared to 2010 due to higher purchases reflecting anticipated winter consumption and higher prices in 2011 combined with higher 2010 consumption of existing inventory levels to meet system requirements resulting from favorable weather.

Net cash used by investing activities increased $265 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The increase was primarily due to a $258 million change in advances to affiliated companies.

Net cash provided by financing activities increased $106 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The increase was primarily due to the $500 million issuance of first mortgage bonds in 2011, partially offset by the $450 million payment of dividends to the Parent in 2011 compared to $75 million in 2010.

SHORT-TERM DEBT

At September 30, 2011, PEC had no outstanding short-term debt. At the end of each month during the three months ended September 30, 2011, PEC had a maximum short-term debt balance of $211 million and an average short-term debt balance of $129 million at a weighted average interest rate of 0.36%. Short-term debt balances were lower at September 30, 2011 compared to the maximum and average balances due to the repayment of short-term debt following the issuance of $500 million of long-term debt in September. See “Liquidity and Capital Resources” in Progress Energy’s MD&A for more information on the long-term debt issuances at PEC during the three months ended September 30, 2011.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

As a part of normal business, PEC enters into various agreements providing future financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness

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otherwise attributed to PEC, thereby facilitating the extension of sufficient credit to accomplish PEC’s intended commercial purpose. PEC’s guarantees include letters of credit and surety bonds. At September 30, 2011, PEC had issued $23 million of guarantees for future financial or performance assurance. PEC does not believe conditions are likely for significant performance under the guarantees of performance issued.

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.

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” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors,” to the 2010 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)(a) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities decreased $175 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The decrease was primarily due to a $74 million increase in pension plan funding, $72 million decrease due to timing of payables primarily due to fuel and purchased power, the $56 million less favorable impact of weather as previously discussed, $33 million paid for interest rate locks terminated in conjunction with the issuance of long-term debt in 2011 and $27 million in higher net cash for taxes, partially offset by $43 million net cash refunds of collateral to counterparties on derivative contracts in 2011 compared to $59 million net cash payments of collateral in 2010.

Net cash used by investing activities decreased $263 million for the nine months ended September 30, 2011, when compared to the same period in the prior year, primarily due to a $150 million decrease in gross property additions, primarily due to lower spending for environmental compliance and nuclear projects; the $54 million increase in receipt of NEIL insurance proceeds for repairs at CR3 (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”); and $27 million of litigation judgment proceeds.

Net cash used by financing activities increased $447 million for the nine months ended September 30, 2011, when compared to the same period in the prior year. The increase was primarily due to the combined $600 million issuance of first mortgage bonds in March 2010 and the $475 million payment of dividends to the Parent in 2011 compared to $50 million in 2010, partially offset by a $300 million issuance of first mortgage bonds in August 2011 and the $273 million change in advances from affiliated companies.

SHORT-TERM DEBT

At September 30, 2011, PEF had outstanding short-term debt consisting of money pool borrowings totaling $69 million at a weighted average interest rate of 0.31%. At the end of each month during the three months ended September 30, 2011, PEF had a maximum short-term debt balance of $350 million and an average short-term debt balance of $192 million at a weighted average interest rate of 0.37%. Short-term debt balances were lower at September 30, 2011 compared to the maximum and average balances due to the partial repayment of short-term debt following the issuance of $300 million of long-term debt in August. See “Liquidity and Capital Resources” in Progress Energy’s MD&A for more information on the long-term debt issuances at PEF during the three months ended September 30, 2011.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

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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.

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 for 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 “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 2010 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

Certain market risks are inherent in our financial instruments, which arise from transactions entered into in the normal course of business. Our primary exposures are changes in interest rates with respect to our long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to our nuclear decommissioning trust (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, 2010.

INTEREST RATE RISK

Our debt portfolio and our exposure to changes in interest rates at September 30, 2011, have changed from December 31, 2010. The total notional amount of fixed rate long-term debt at September 30, 2011, was $11.829 billion, with an average interest rate of 5.76% and fair market value of $14.0 billion. The total notional amount of fixed rate long-term debt at December 31, 2010, was $11.529 billion, with an average interest rate of 6.11% and fair market value of $12.8 billion. At both September 30, 2011 and December 31, 2010, the total notional amount and fair market value of our variable rate long-term debt was $861 million. At September 30, 2011 the average interest rate of our variable rate long-term debt was 0.35% and at December 31, 2010, the average interest rate of our variable rate long-term debt was 0.53%.

In addition to our variable rate long-term debt, we typically have commercial paper and/or loans outstanding under our credit facilities, which are also exposed to floating interest rates. At September 30, 2011, we had approximately $45 million of outstanding commercial paper and no loans outstanding under our credit facilities. At December 31, 2010, we had no outstanding commercial paper or loans under our credit facilities. At both September 30, 2011, and December 31, 2010, approximately 7 percent of consolidated debt was in floating rate mode.

Based on our variable rate debt balances at September 30, 2011,a 100 basis point change in interest rates would result in an annual pre-tax interest expense change of approximately $9 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.

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		Mandatory Settlement		Pay			Receive (a)	Fair Value			Exposure (b)
Parent
Risk hedged at September 30, 2011
Anticipated 10-year debt issue	$	200		2012		4.20	%	3-month LIBOR	$	(35	)	$	(5	)
Risk hedged at December 31, 2010
Anticipated 10-year debt issue	$	300		2011		4.15	%	3-month LIBOR	$	(18	)	$	(7	)
Anticipated 10-year debt issue	$	200		2012		4.20	%	3-month LIBOR	$	(3	)	$	(4	)
PEC
Risk hedged at September 30, 2011
Anticipated 10-year debt issue	$	200		2012		4.27	%	3-month LIBOR	$	(35	)	$	(5	)
Anticipated 10-year debt issue	$	50		2013		4.43	%	3-month LIBOR	$	(8	)	$	(1	)
Risk hedged at December 31, 2010
Anticipated 10-year debt issue	$	100		2011		4.31	%	3-month LIBOR	$	(7	)	$	(2	)
Anticipated 10-year debt issue	$	200		2012		4.27	%	3-month LIBOR	$	(2	)	$	(4	)
Anticipated 10-year debt issue	$	50		2013		4.43	%	3-month LIBOR	$	-		$	(1	)
PEF
Risk hedged at September 30, 2011
Anticipated 10-year debt issue	$	50		2013		4.30	%	3-month LIBOR	$	(8	)	$	(1	)
Risk hedged at December 31, 2010
Anticipated 10-year debt issue	$	150		2011		4.18	%	3-month LIBOR	$	(6	)	$	(3	)
Anticipated 10-year debt issue	$	50		2013		4.30	%	3-month LIBOR	$	-		$	(1	)

(a) 3-month London Inter Bank Offered Rate (LIBOR) was 0.37% at September 30, 2011and 0.30% at December 31, 2010.

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

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MARKETABLE SECURITIES PRICE RISK

The Utilities maintain trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning their nuclear plants. These funds are primarily invested in stocks, bonds and cash equivalents, which are exposed to price fluctuations in equity markets and to changes in interest rates. At September 30, 2011 and December 31, 2010, the fair value of these funds was $1.512 billion and $1.571 billion, respectively, including $992 million and $1.017 billion, respectively, for PEC and $520 million and $554 million, respectively, for PEF. We actively monitor our portfolio by benchmarking the performance of our investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At September 30, 2011 and December 31, 2010, the fair value of CVOs was $74 million and $15 million, respectively. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. A hypothetical 10 percent increase in the September 30, 2011 market price would result in a $7 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 physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. At September 30, 2011, 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 economic and cash flow derivative financial instruments.

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, 2010.

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, PEC and PEF 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 respective Chief Executive Officers 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 Officers and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our, PEC’s and PEF’s internal control over financial reporting during the quarter ended September 30, 2011, that has materially affected, or is reasonably likely to materially affect, our, PEC’s or PEF’s internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

In addition to the risk factor disclosed below and the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A, “Risk Factors,” to the 2010 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in the 2010 Form 10-K are not the only risks facing us.

The scope of necessary repairs of the delamination of CR3 could prove more extensive than is currently identified, such repairs could prove not to be feasible, the costs of repair and/or replacement power could exceed our estimates and insurance coverage or may not be recoverable through the regulatory process; the occurrence of any of which could adversely affect our results of operations or financial condition.

In September 2009, CR3 began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit’s steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. Subsequent to March 2011, monitoring equipment has detected additional changes in the partially tensioned containment building and additional cracking or delaminations may have occurred or could occur during the repair process. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options.

In June 2011, PEF notified the NRC and the FPSC that it plans to repair the CR3 containment structure and estimates it will return CR3 to service in 2014. The repair option selected entails systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include replacing concrete in the area where concrete was replaced during the initial repair. PEF’s preliminary cost estimate for this repair, as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion, although a number of factors will affect the repair schedule, return-to-service date and costs of repair, including regulatory reviews, final engineering designs, contract negotiations, ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments. PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, believe that replacement power and repair costs not recoverable through insurance to be recoverable through PEF’s fuel cost-recovery clause or base rates.

While the foregoing reflects PEF’s current intentions and estimates with respect to CR3, the costs, timing and feasibility of additional repairs to CR3, the cost of replacement power, and the degree of recoverability of these costs, are all subject to significant uncertainties. Additional developments with respect to the condition of the CR3 structures, costs that are greater than anticipated, recoverability that is less than anticipated, and/or the inability to return CR3 to service all could adversely affect our financial results.

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

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a)   Securities Delivered.  On July 25, 2011, and August 19, 2011, 3,300 shares and 6,700 shares, respectively, of our common stock were delivered to certain employees pursuant to the terms of the Progress Energy 2007 Equity Incentive Plan (the EIP) which has been approved by Progress Energy’s shareholders. Additionally, on July 26, 2011, 268 shares of our common stock were delivered to a former employee pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

(c)   Consideration. The restricted stock unit awards were granted to provide an incentive to the employees and the former employee 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.

ISSUER PURCHASES OF EQUITY SECURITIES FOR THIRD QUARTER OF 2011

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		263,903	$	47.7372		N/A		N/A
August 1 – August 31		725,507		46.1625		N/A		N/A
September 1 – September 30		127,327		48.6933		N/A		N/A
Total		1,116,737		46.8232		N/A		N/A

(1) At September 30, 2011, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) The plan administrator purchased 557,400 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy 401(k) Savings & Stock Ownership Plan.

(3) The plan administrator purchased 311,679 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 244,305 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 3,353 shares of our common stock during the third quarter of 2011 to pay taxes due upon the payout of certain Restricted Stock Unit awards pursuant to the terms of the 2007 EIP.

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ITEM 6. EXHIBITS

(a)   Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
*4(a)	Seventy-eighth Supplemental Indenture, dated as of September 1, 2011, to the Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, between Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and The Bank of New York Mellon (formerly Irving Trust Company) and Frederick G. Herbst (Ming Ryan, successor), as trustees (filed as Exhibit 4 to the Current Report on Form 8-K, dated September 12, 2011, File No. 1-3382).		X
*4(b)	Fiftieth Supplemental Indenture, dated as of August 1, 2011, to the Indenture, dated January 1, 1944, as supplemented, between Florida Power Corporation d/b/a Progress Energy Florida, Inc. and The Bank of New York Mellon, as successor Trustee (filed as Exhibit 4 to the Current Report on Form 8-K, dated August 15, 2011, File No. 1-3274).			X
10(a)	Deferred Compensation Plan for Key Management Employees of Progress Energy, Inc., amended and restated effective July 13, 2011.	X	X	X
10(b)	Executive and Key Manager 2009 Performance Share Sub-Plan, Exhibit A to 2007 Equity Incentive Plan, amended and restated effective July 12, 2011.	X	X	X
10(c)	Amended Management Incentive Compensation Plan of Progress Energy, Inc., amended and restated effective July 12, 2011.	X	X	X
10(d)	Progress Energy, Inc. Management Change-in-Control Plan, amended and restated effective July 13, 2011.	X	X	X
10(e)	Progress Energy, Inc. Amended and Restated Management Deferred Compensation Plan, revised and restated effective July 12, 2011.	X	X	X
10(f)	Progress Energy, Inc. Non-Employee Director Deferred Compensation Plan, amended and restated effective July 13, 2011.	X	X	X
10(g)	Progress Energy, Inc. Non-Employee Director Stock Unit Plan, amended and restated effective July 13, 2011.	X	X	X
10(h)	Amended and Restated Progress Energy, Inc. Restoration Retirement Plan, amended and restated effective July 13, 2011.	X	X	X

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10(i)	Amended and Restated Supplemental Senior Executive Retirement Plan of Progress Energy, Inc., amended and restated effective July 13, 2011.	X	X	X
31(a)	302 Certifications of Chief Executive Officer	X
31(b)	302 Certifications of Chief Financial Officer	X
31(c)	302 Certifications of Chief Executive Officer		X
31(d)	302 Certifications of Chief Financial Officer		X
31(e)	302 Certifications of Chief Executive Officer			X
31(f)	302 Certifications of Chief Financial Officer			X
32(a)	906 Certifications of Chief Executive Officer	X
32(b)	906 Certifications of Chief Financial Officer	X
32(c)	906 Certifications of Chief Executive Officer		X
32(d)	906 Certifications of Chief Financial Officer		X
32(e)	906 Certifications of Chief Executive Officer			X
32(f)	906 Certifications of Chief Financial Officer			X
101.INS	XBRL Instance Document**	X	X	X
101.SCH	XBRL Taxonomy Extension Schema Document	X	X	X
101.CAL	XBRL Taxonomy Calculation Linkbase Document	X	X	X
101.LAB	XBRL Taxonomy Label Linkbase Document	X	X	X
101.PRE	XBRL Taxonomy Presentation Linkbase Document	X	X	X

*    Incorporated herein by reference as indicated.

** Attached as Exhibit 101 are the following financial statements and notes thereto for Progress Energy, PEC and PEF from the Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, 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 Interim Financial Statements, which are tagged as blocks of text in respect to PEC and PEF’s disclosures.

In accordance with Rule 406T of Regulation S-T, the XBRL-related information for PEC and PEF 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 8, 2011	(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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