Duke Energy Progress 10-Q 2011 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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	o	No	o
PEF	Yes	o	No	o

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

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

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

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

At May 5, 2011, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	294,351,281
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	59
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	88
ITEM 4.	CONTROLS AND PROCEDURES	92
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	93
ITEM 1A.	RISK FACTORS	93
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	93
ITEM 6.	EXHIBITS	95
SIGNATURES		97

1

GLOSSARY OF TERMS

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

The following abbreviations, 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, Progress Energy Service Company 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
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	Electric steam generating unit
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 Power 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
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 after excluding discontinued operations and the effects of certain identified gains and charges
OPEB	Postretirement benefits other than pensions
the Parent	Progress Energy, Inc. holding company on an unconsolidated basis

3

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
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
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
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 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;

·   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;

·   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;

5

·   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
March 31, 2011
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
(in millions except per share data)
Three months ended March 31	2011			2010
Operating revenues	$	2,167		$	2,535
Operating expenses
Fuel used in electric generation		718			896
Purchased power		220			263
Operation and maintenance		494			480
Depreciation, amortization and accretion		154			246
Taxes other than on income		140			154
Other		(10	)		2
Total operating expenses		1,716			2,041
Operating income		451			494
Other income (expense)
Interest income		1			2
Allowance for equity funds used during construction		29			21
Other, net		3			(5	)
Total other income, net		33			18
Interest charges
Interest charges		199			191
Allowance for borrowed funds used during construction		(9	)		(9	)
Total interest charges, net		190			182
Income from continuing operations before income tax		294			330
Income tax expense		107			139
Income from continuing operations before cumulative effect of   change in accounting principle		187			191
Discontinued operations, net of tax		(2	)		1
Cumulative effect of change in accounting principle, net of tax		-			(2	)
Net income		185			190
Net income attributable to noncontrolling interests, net of tax		(1	)		-
Net income attributable to controlling interests	$	184		$	190
Average common shares outstanding – basic		295			284
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	0.63		$	0.67
Discontinued operations attributable to controlling interests, net of tax		(0.01	)		-
Net income attributable to controlling interests	$	0.62		$	0.67
Dividends declared per common share	$	0.620		$	0.620
Amounts attributable to controlling interests
Income from continuing operations, net of tax	$	186		$	189
Discontinued operations, net of tax		(2	)		1
Net income attributable to controlling interests	$	184		$	190
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

7

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	March 31, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	29,782		$	29,708
Accumulated depreciation		(11,711	)		(11,567	)
Utility plant in service, net		18,071			18,141
Other utility plant, net		220			220
Construction work in progress		2,533			2,205
Nuclear fuel, net of amortization		658			674
Total utility plant, net		21,482			21,240
Current assets
Cash and cash equivalents		172			611
Receivables, net		880			1,033
Inventory		1,276			1,226
Regulatory assets		101			176
Derivative collateral posted		135			164
Income taxes receivable		36			52
Prepayments and other current assets		193			214
Total current assets		2,793			3,476
Deferred debits and other assets
Regulatory assets		2,306			2,374
Nuclear decommissioning trust funds		1,641			1,571
Miscellaneous other property and investments		413			413
Goodwill		3,655			3,655
Other assets and deferred debits		332			325
Total deferred debits and other assets		8,347			8,338
Total assets	$	32,622		$	33,054
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 294   million and 293 million shares issued and outstanding, respectively	$	7,362		$	7,343
Accumulated other comprehensive loss		(121	)		(125	)
Retained earnings		2,806			2,805
Total common stock equity		10,047			10,023
Noncontrolling interests		3			4
Total equity		10,050			10,027
Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		11,868			11,864
Total capitalization		22,284			22,257
Current liabilities
Current portion of long-term debt		300			505
Short-term debt		79			-
Accounts payable		849			994
Interest accrued		205			216
Dividends declared		184			184
Customer deposits		335			324
Derivative liabilities		220			259
Accrued compensation and other benefits		144			175
Other current liabilities		323			298
Total current liabilities		2,639			2,955
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,765			1,696
Accumulated deferred investment tax credits		108			110
Regulatory liabilities		2,625			2,635
Asset retirement obligations		1,218			1,200
Accrued pension and other benefits		1,311			1,514
Derivative liabilities		239			278
Other liabilities and deferred credits		433			409
Total deferred credits and other liabilities		7,699			7,842
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	32,622		$	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)
Three months ended March 31	2011			2010
Operating activities
Net income	$	185		$	190
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		199			285
Deferred income taxes and investment tax credits, net		101			51
Deferred fuel cost (credit)		70			(45	)
Allowance for equity funds used during construction		(29	)		(21	)
Other adjustments to net income		56			63
Cash provided (used) by changes in operating assets and liabilities
Receivables		163			(32	)
Inventory		(49	)		98
Derivative collateral posted		28			(157	)
Other assets		(21	)		(17	)
Income taxes, net		57			165
Accounts payable		(89	)		31
Accrued pension and other benefits		(224	)		(18	)
Other liabilities		(1	)		(7	)
Net cash provided by operating activities		446			586
Investing activities
Gross property additions		(501	)		(555	)
Nuclear fuel additions		(57	)		(54	)
Purchases of available-for-sale securities and other investments		(1,817	)		(1,986	)
Proceeds from available-for-sale securities and other investments		1,809			1,977
Other investing activities		46			(1	)
Net cash used by investing activities		(520	)		(619	)
Financing activities
Issuance of common stock, net		8			197
Dividends paid on common stock		(183	)		(175	)
Net increase (decrease) in short-term debt		79			(140	)
Proceeds from issuance of long-term debt, net		494			591
Retirement of long-term debt		(700	)		(100	)
Other financing activities		(63	)		(44	)
Net cash (used) provided by financing activities		(365	)		329
Net (decrease) increase in cash and cash equivalents		(439	)		296
Cash and cash equivalents at beginning of period		611			725
Cash and cash equivalents at end of period	$	172		$	1,021
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	178		$	235
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
March 31, 2011
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
(in millions)
Three months ended March 31	2011			2010
Operating revenues	$	1,133		$	1,263
Operating expenses
Fuel used in electric generation		363			483
Purchased power		67			50
Operation and maintenance		295			285
Depreciation, amortization and accretion		124			118
Taxes other than on income		56			60
Other		-			1
Total operating expenses		905			997
Operating income		228			266
Other income (expense)
Interest income		-			1
Allowance for equity funds used during construction		20			13
Other, net		(2	)		(7	)
Total other income, net		18			7
Interest charges
Interest charges		50			50
Allowance for borrowed funds used during construction		(5	)		(4	)
Total interest charges, net		45			46
Income before income tax		201			227
Income tax expense		70			89
Income before cumulative effect of change in accounting principle		131			138
Cumulative effect of change in accounting principle, net of tax		-			(2	)
Net income		131			136
Net loss attributable to noncontrolling interests, net of tax		-			2
Net income attributable to controlling interests		131			138
Preferred stock dividend requirement		(1	)		(1	)
Net income available to parent	$	130		$	137
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)	March 31, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	16,451		$	16,388
Accumulated depreciation		(7,388	)		(7,324	)
Utility plant in service, net		9,063			9,064
Other utility plant, net		184			184
Construction work in progress		1,462			1,233
Nuclear fuel, net of amortization		458			480
Total utility plant, net		11,167			10,961
Current assets
Cash and cash equivalents		113			230
Receivables, net		415			519
Receivables from affiliated companies		33			44
Notes receivable from affiliated companies		3			2
Inventory		636			590
Deferred fuel cost		42			71
Income taxes receivable		20			90
Prepayments and other current assets		123			110
Total current assets		1,385			1,656
Deferred debits and other assets
Regulatory assets		985			987
Nuclear decommissioning trust funds		1,066			1,017
Miscellaneous other property and investments		181			183
Other assets and deferred debits		96			95
Total deferred debits and other assets		2,328			2,282
Total assets	$	14,880		$	14,899
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160   million shares issued and outstanding	$	2,137		$	2,130
Accumulated other comprehensive loss		(31	)		(33	)
Retained earnings		3,113			3,083
Total equity		5,219			5,180
Preferred stock		59			59
Long-term debt, net		3,693			3,693
Total capitalization		8,971			8,932
Current liabilities
Accounts payable		462			534
Payables to affiliated companies		85			109
Interest accrued		65			74
Customer deposits		112			106
Derivative liabilities		49			53
Accrued compensation and other benefits		84			99
Other current liabilities		107			81
Total current liabilities		964			1,056
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,697			1,608
Accumulated deferred investment tax credits		103			104
Regulatory liabilities		1,517			1,461
Asset retirement obligations		863			849
Accrued pension and other benefits		583			723
Other liabilities and deferred credits		182			166
Total deferred credits and other liabilities		4,945			4,911
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	14,880		$	14,899
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

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CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Three months ended March 31	2011			2010
Operating activities
Net income	$	131		$	136
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		161			149
Deferred income taxes and investment tax credits, net		69			44
Deferred fuel cost		29			36
Allowance for equity funds used during construction		(20	)		(13	)
Other adjustments to net income		12			19
Cash provided (used) by changes in operating assets and liabilities
Receivables		102			(9	)
Receivables from affiliated companies		11			9
Inventory		(45	)		90
Other assets		(8	)		(28	)
Income taxes, net		81			68
Accounts payable		(48	)		8
Payables to affiliated companies		(24	)		13
Accrued pension and other benefits		(147	)		(3	)
Other liabilities		13			(12	)
Net cash provided by operating activities		317			507
Investing activities
Gross property additions		(279	)		(293	)
Nuclear fuel additions		(50	)		(46	)
Purchases of available-for-sale securities and other investments		(149	)		(122	)
Proceeds from available-for-sale securities and other investments		141			109
Changes in advances to affiliated companies		(1	)		204
Other investing activities		5			-
Net cash used by investing activities		(333	)		(148	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		(100	)		-
Changes in advances from affiliated companies		-			6
Contributions from parent		-			8
Other financing activities		-			1
Net cash (used) provided by financing activities		(101	)		14
Net (decrease) increase in cash and cash equivalents		(117	)		373
Cash and cash equivalents at beginning of period		230			35
Cash and cash equivalents at end of period	$	113		$	408
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	98		$	111
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

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FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
March 31, 2011
UNAUDITED CONDENSED STATEMENTS of INCOME
(in millions)
Three months ended March 31	2011			2010
Operating revenues	$	1,032		$	1,270
Operating expenses
Fuel used in electric generation		355			413
Purchased power		153			213
Operation and maintenance		210			205
Depreciation, amortization and accretion		25			124
Taxes other than on income		85			93
Other		(12	)		-
Total operating expenses		816			1,048
Operating income		216			222
Other income
Allowance for equity funds used during construction		9			8
Other, net		3			2
Total other income, net		12			10
Interest charges
Interest charges		69			64
Allowance for borrowed funds used during construction		(4	)		(5	)
Total interest charges, net		65			59
Income before income tax		163			173
Income tax expense		61			71
Net income		102			102
Preferred stock dividend requirement		(1	)		(1	)
Net income available to parent	$	101		$	101
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	March 31, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	13,166		$	13,155
Accumulated depreciation		(4,248	)		(4,168	)
Utility plant in service, net		8,918			8,987
Held for future use		36			36
Construction work in progress		1,071			972
Nuclear fuel, net of amortization		200			194
Total utility plant, net		10,225			10,189
Current assets
Cash and cash equivalents		39			249
Receivables, net		436			496
Receivables from affiliated companies		18			11
Inventory		641			636
Regulatory assets		59			105
Derivative collateral posted		117			140
Deferred tax assets		42			77
Prepayments and other current assets		38			29
Total current assets		1,390			1,743
Deferred debits and other assets
Regulatory assets		1,321			1,387
Nuclear decommissioning trust funds		575			554
Miscellaneous other property and investments		47			43
Other assets and deferred debits		140			140
Total deferred debits and other assets		2,083			2,124
Total assets	$	13,698		$	14,056
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized,   100 shares issued and outstanding	$	1,752		$	1,750
Accumulated other comprehensive loss		(4	)		(4	)
Retained earnings		2,920			3,144
Total common stock equity		4,668			4,890
Preferred stock		34			34
Long-term debt, net		4,182			4,182
Total capitalization		8,884			9,106
Current liabilities
Current portion of long-term debt		300			300
Notes payable to affiliated companies		7			9
Accounts payable		364			439
Payables to affiliated companies		54			60
Interest accrued		94			83
Customer deposits		223			218
Derivative liabilities		171			188
Accrued compensation and other benefits		38			47
Other current liabilities		205			121
Total current liabilities		1,456			1,465
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,097			1,065
Regulatory liabilities		1,018			1,084
Asset retirement obligations		355			351
Accrued pension and other benefits		455			522
Capital lease obligations		198			199
Derivative liabilities		163			190
Other liabilities and deferred credits		72			74
Total deferred credits and other liabilities		3,358			3,485
Commitments and contingencies (Notes 12 and 13)
Total capitalization and liabilities	$	13,698		$	14,056
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Three months ended March 31	2011			2010
Operating activities
Net income	$	102		$	102
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		29			128
Deferred income taxes and investment tax credits, net		60			65
Deferred fuel cost (credit)		41			(81	)
Allowance for equity funds used during construction		(9	)		(8	)
Other adjustments to net income		35			26
Cash provided (used) by changes in operating assets and liabilities
Receivables		72			(23	)
Receivables from affiliated companies		(7	)		-
Inventory		(5	)		8
Derivative collateral posted		22			(137	)
Other assets		(3	)		(11	)
Income taxes, net		63			96
Accounts payable		(45	)		26
Payables to affiliated companies		(6	)		10
Accrued pension and other benefits		(74	)		(11	)
Other liabilities		26			29
Net cash provided by operating activities		301			219
Investing activities
Gross property additions		(218	)		(275	)
Nuclear fuel additions		(7	)		(8	)
Purchases of available-for-sale securities and other investments		(1,659	)		(1,823	)
Proceeds from available-for-sale securities and other investments		1,659			1,827
Other investing activities		42			(1	)
Net cash used by investing activities		(183	)		(280	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		(325	)		-
Proceeds from issuance of long-term debt, net		-			591
Changes in advances from affiliated companies		(2	)		(214	)
Net cash (used) provided by financing activities		(328	)		376
Net (decrease) increase in cash and cash equivalents		(210	)		315
Cash and cash equivalents at beginning of period		249			17
Cash and cash equivalents at end of period	$	39		$	332
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	78		$	122
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO 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 10, 12 and 13
PEF	1 through 10, 12 and 13

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO 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 11 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).

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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 March 31
(in millions)	2011		2010
Progress Energy	$	73	$	83
PEC		28		30
PEF		45		53

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 managing member, and 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 for this VIE during 2010 or for the period ended March 31, 2011. No financial or other support has been provided to the VIE during the periods presented.

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

(in millions)	March 31, 2011			December 31, 2010
Miscellaneous other property and investments		$	12		$	12
Other assets and deferred debits			1			1
Accounts payable			5			5

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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 for each of the three months ended March 31, 2010 and 2011. 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, which will be subject to completion of the Merger and receipt of the requisite approval of the shareholders of Duke Energy. 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, the SCPSC, the FPSC, the Indiana Utility Regulatory Commission and the Ohio Public Utilities Commission. The status of these matters is as follows:

·   On March 17, 2011, Duke Energy filed a registration statement on Form S-4 with the SEC. This filing and its subsequent amendments contain a preliminary joint proxy statement for a special meeting of each company’s shareholders to vote on the Merger. Shareholder meetings for Duke Energy and Progress Energy for shareholders to vote on the Merger are expected in mid-summer.

·   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 March 30, 2011, Progress Energy and Duke Energy made filings with the NRC for approval for transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses. NRC approval is expected to take six to nine months.

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·   On April 4, 2011, Progress Energy and Duke Energy filed an application to approve the Merger with the Kentucky Public Service Commission. Procedural hearings have been scheduled for July 6, 2011.

·   On April 4, 2011, Progress Energy and Duke Energy made joint filings with the FERC, which assesses market power-related issues. 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. The FERC is expected to rule on the filings within 180 days.

·   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. Procedural hearings have been scheduled for September 20, 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. Procedural hearings have not been scheduled.

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 13C).

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 disclosure in the notes to the financial statements but did not have an impact on our or the Utilities’ financial position or results of operations.

4. REGULATORY MATTERS

A. PEC RETAIL RATE MATTERS

COST RECOVERY FILINGS

On May 5, 2011, PEC filed with the SCPSC an application for a $24 million increase in the fuel rate charged to its South Carolina ratepayers, driven by rising fuel prices. If approved, the increase will be effective July 1, 2011, and will increase residential electric bills by $3.71 per 1,000 kilowatt-hour (kWh). On May 2, 2011, PEC also filed with the SCPSC for a $4 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate, driven by the introduction of new and the expansion of existing DSM and EE programs. If approved, the increase will be effective July 1, 2011, and will increase residential electric bills by $1.25 per 1,000 kWh. The net impact of the two filings will result in an average increase in residential electric bills of 5 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 three new generating facilities: an approximately 600-MW combined cycle dual-fuel facility at its Richmond generation facility, 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 June 2011, 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. In March 2011, PEC advised the NCUC and the SCPSC that the coal-fired generating facilities at one of the four sites, the Weatherspoon site, is expected to be retired on October 1, 2011. PEC expects to retire the remaining facilities by the end of 2014.

The net carrying value of the four facilities at March 31, 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 rate recovery of the remaining net carrying value.

B. PEF RETAIL RATE MATTERS

CR3 OUTAGE

In September 2009, the 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 within the concrete of the outer wall of the containment building, which resulted in an extension of the outage. After comprehensive analysis, we determined that the concrete delamination at CR3 was caused by redistribution of stresses on the containment wall that occurred when we 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 after the repair work was completed and during the late stages of retensioning the containment building. CR3 will remain out of service while we conduct a thorough engineering analysis and review of the new delamination and evaluate repair options.

The potential repair options, which will be based on the engineering analysis, could range from repair of the impacted areas to replacement of a substantial portion of the concrete walls of the containment building. Repair options that alter the original licensing basis could require approval by the NRC. Once the repair options are known, there are many additional factors that will be considered in the decision about the unit’s operation, including, among other things, customer benefits; public, regulatory and political support; adequate financial cost-recovery mechanisms; the scope of insurance coverage for replacement power and repair costs (as discussed below); and NRC renewal of CR3’s operating license. CR3’s current operating license expires in December 2016, and PEF applied for a 20-year renewal of the license in 2008. Our current intention is to return CR3 to service as it is an important aspect of providing power to our customers from a diverse portfolio of baseload generation. We currently believe that retiring and decommissioning the unit without returning it to service is unlikely. However, we cannot estimate a return-to-service date or the cost of repair at this time.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accident. 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 is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. PEF also maintains insurance coverage through

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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 March 31, 2011:

(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	339		$	182
NEIL proceeds received to date		(144	)		(75	)
Insurance receivable at March 31, 2011		(85	)		(62	)
Balance for recovery	$	110		$	45

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. 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). PEF has recorded $229 million of NEIL replacement power cost reimbursements subsequent to the deductible period, which reduced the portion of the deferred fuel regulatory asset related to the extended CR3 outage to $110 million at March 31, 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.

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 April 26, 2011, the FPSC denied PEF’s motion to bifurcate the spin-off docket into two phases. The FPSC ordered PEF to file an updated status report with the FPSC on May 19, 2011, and scheduled a status conference for May 23, 2011.

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 that PEF will have 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. PEF carried an unused balance of $90 million forward from 2010, which is available to reduce future amortization expense. For the three months ended March 31, 2011, PEF recognized an $80 million reduction in amortization expense pursuant to the settlement agreement. PEF’s applicable cost of removal reserve of $369 million is recorded as a regulatory liability on its March 31, 2011 Balance Sheet. 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.

NUCLEAR COST RECOVERY

Levy Nuclear

In 2008, the FPSC granted PEF’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule for PEF’s proposed Levy Units No. 1 and No. 2 Nuclear Power Plants (Levy), together with the associated facilities, including transmission lines and substation facilities.

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Major construction activities on the Levy project are being postponed until after the NRC issues the combined license (COL), which is expected in 2013 if the current licensing schedule remains on track. Taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification, we consider Levy to be PEF’s preferred baseload generation option. 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, public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility, including comparison to other generation options; DSM and EE programs; and availability and terms of capital financing.

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 third and final stage of the uprate will require a license amendment to be filed with the NRC. PEF is in the process of finalizing that amendment request.

Cost Recovery

On May 2, 2011, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $158 million, which includes recovery of pre-construction and carrying costs and Capacity Cost-Recovery Clause (CCRC) recoverable operation and maintenance (O&M) expense incurred or anticipated to be incurred during 2012, recovery of $115 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. This results in a decrease in the nuclear cost-recovery charge of $0.33 per 1,000 kWh for residential customers, which if approved, would begin with the first January 2012 billing cycle. The FPSC has scheduled hearings in this matter for August 2011, with a decision expected in October 2011. We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT COST RECOVERY

On December 30, 2009, the FPSC ordered PEF and other Florida utilities to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. As subsequently revised by the FPSC, PEF’s aggregate conservation goals over the next 10 years were: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). On March 30, 2010, PEF filed a petition for approval of its proposed DSM plan and to authorize cost recovery through the Energy Conservation Cost Recovery Clause (ECCR). On September 14, 2010, the FPSC held an agenda conference to approve PEF’s petition for the DSM plan. The FPSC ruled that while PEF’s proposed DSM plan met the cumulative, 10-year DSM goals set by the FPSC, the plan did not meet the annual DSM goals. On October 4, 2010, the FPSC denied PEF’s petition for the DSM plan, approved PEF’s solar pilot programs, and required PEF to file a revised proposed DSM plan that meets the annual goals set by the FPSC. PEF filed a revised proposed DSM plan on November 29, 2010. An agenda conference has been scheduled by the FPSC for May 24, 2011. We cannot predict the outcome of this matter.

5. EQUITY AND COMPREHENSIVE INCOME

A. EARNINGS PER COMMON SHARE

There are no material differences between our basic and diluted earnings per share amounts for the three months ended March 31, 2011 and 2010.  The effects of restricted stock unit awards, 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).

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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)		184			(1	)		183
Other comprehensive income		4			-			4
Issuance of shares through offerings and stock-   based compensation plans (See Note 5D)		19			-			19
Dividends declared		(183	)		-			(183	)
Distributions to noncontrolling interests		-			(2	)		(2	)
Other		-			2			2
Balance,  March 31, 2011	$	10,047		$	3		$	10,050
Balance,  December 31, 2009	$	9,449		$	6		$	9,455
Net income(a)		190			(2	)		188
Other comprehensive loss		(4	)		-			(4	)
Issuance of shares through offerings and stock-   based compensation plans (See Note 5D)		220			-			220
Dividends declared		(179	)		-			(179	)
Other		-			1			1
Balance,  March 31, 2010	$	9,676		$	5		$	9,681

(a) For the three months ended March 31, 2011, consolidated net income of $185 million includes $2 million attributable to preferred shareholders of subsidiaries. For the three months ended March 31, 2010, consolidated net income of $190 million includes $2 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 March 31
(in millions)	2011			2010
Net income	$	185		$	190
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $1)		1			2
Change in unrecognized items for pension and other postretirement benefits   (net of tax expense of $1 and $1)		1			1
Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of $(1) and $4)		2			(6	)
Other (net of tax expense of $-)		-			(1	)
Other comprehensive income (loss)		4			(4	)
Comprehensive income		189			186
Comprehensive income attributable to noncontrolling interests		(1	)		-
Comprehensive income attributable to controlling interests	$	188		$	186

PEC
	Three months ended March 31
(in millions)	2011		2010
Net income	$	131	$	136
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 gains (losses) on cash flow hedges (net of tax (expense) benefit of $(1) and $1)		1		(1	)
Other comprehensive income		2		-
Comprehensive income		133		136
Comprehensive loss attributable to noncontrolling interests		-		2
Comprehensive income attributable to controlling interests	$	133	$	138

PEF
	Three months ended March 31
(in millions)	2011		2010
Net income	$	102	$	102
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $- and $2)		-		(3	)
Other comprehensive loss		-		(3	)
Comprehensive income	$	102	$	99

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D. COMMON STOCK

At March 31, 2011 and December 31, 2010, we had 500 million shares of common stock authorized under our charter, of which 294 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:

	Three months ended March 31
	2011				2010
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		1.0	$	8		6.1	$	197
Issuances through 401(k) and/or IPP		-		1		5.2		197

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 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 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.

8. FAIR VALUE DISCLOSURES

A. DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $12.441 billion and $12.642 billion at March 31, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted

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market prices for the same or similar issues, was $13.6 billion and $14.0 billion at March 31, 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. 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 in 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 March 31, 2011 and December 31, 2010:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2011
Common stock equity	$	1,089	$	12	$	461
Preferred stock and other equity		52		-		11
Corporate debt		88		-		5
U.S. state and municipal debt		104		4		2
U.S. and foreign government debt		232		1		9
Money market funds and other		89		-		1
Total	$	1,654	$	17	$	489
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. There were no material unrealized losses and unrealized gains for the other available-for-sale debt securities held in benefit trusts at March 31, 2011 and December 31, 2010.

The aggregate fair value of investments that related to the 2011 and 2010 unrealized losses was $188 million and $195 million, respectively.

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At March 31, 2011, the fair value of our available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	42
Due after one through five years		153
Due after five through 10 years		156
Due after 10 years		80
Total	$	431

The following table presents selected information about our sales of available-for-sale securities during the three months ended March 31, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.

(in millions)	2011		2010
Proceeds	$	1,744	$	1,937
Realized gains		9		5
Realized losses		4		6

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 these 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 March 31, 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 $3.693 billion at March 31, 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 $4.0 billion at March 31, 2011 and December 31, 2010.

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 in 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 March 31, 2011 and December 31, 2010:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2011
Common stock equity	$	699	$	10	$	291
Preferred stock and other equity		16		-		7
Corporate debt		75		-		4
U.S. state and municipal debt		48		1		1
U.S. and foreign government debt		200		1		8
Money market funds and other		35		-		1
Total	$	1,073	$	12	$	312

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(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
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

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 March 31, 2011 and December 31, 2010 unrealized losses was $122 million and $104 million, respectively.

At March 31, 2011, the fair value of PEC’s available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	14
Due after one through five years		139
Due after five through 10 years		118
Due after 10 years		59
Total	$	330

The following table presents selected information about PEC’s sales of available-for-sale securities during the three months ended March 31, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.

(in millions)	2011		2010
Proceeds	$	131	$	107
Realized gains		3		3
Realized losses		1		5

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 March 31, 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 March 31, 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 $4.9 billion and $5.0 billion at March 31, 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

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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 in the 2010Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.

The following table summarizes PEF’s available-for-sale securities at March 31, 2011 and December 31, 2010:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2011
Common stock equity	$	390	$	2	$	170
Preferred stock and other equity		36		-		4
Corporate debt		13		-		1
U.S. state and municipal debt		56		3		1
U.S. and foreign government debt		32		-		1
Money market funds and other		47		-		-
Total	$	574	$	5	$	177
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 March 31, 2011 and December 31, 2010 unrealized losses was $66 million and $87 million, respectively.

At March 31, 2011, the fair value of PEF’s available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	28
Due after one through five years		14
Due after five through 10 years		38
Due after 10 years		21
Total	$	101

The following table presents selected information about PEF’s sales of available-for-sale securities during the three months ended March 31, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.

(in millions)	2011		2010
Proceeds	$	1,606	$	1,790
Realized gains		6		2
Realized losses		3		1

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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 March 31, 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 as previously discussed.

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 March 31, 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
March 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,089	$	-	$	-	$	1,089
Preferred stock and other equity		25		27		-		52
Corporate debt		-		88		-		88
U.S. state and municipal debt		-		104		-		104
U.S. and foreign government debt		77		155		-		232
Money market funds and other		2		74		-		76
Total nuclear decommissioning trust funds		1,193		448		-		1,641
Derivatives
Commodity forward contracts		-		34		-		34
Interest rate contracts		-		5		-		5
Other marketable securities
Money market and other		19		7		-		26
Total assets	$	1,212	$	494	$	-	$	1,706
Liabilities
Derivatives
Commodity forward contracts	$	-	$	405	$	32	$	437
Interest rate contracts		-		18		-		18
Contingent value obligations derivatives		-		15		-		15
Total liabilities	$	-	$	438	$	32	$	470
(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 derivatives		-		15		-		15
Total liabilities	$	-	$	512	$	36	$	548

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PEC
(in millions)	Level 1		Level 2		Level 3		Total
March 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	699	$	-	$	-	$	699
Preferred stock and other equity		16		-		-		16
Corporate debt		-		75		-		75
U.S. state and municipal debt		-		48		-		48
U.S. and foreign government debt		77		123		-		200
Money market funds and other		1		27		-		28
Total nuclear decommissioning trust funds		793		273		-		1,066
Derivatives
Commodity forward contracts		-		6		-		6
Interest rate contracts		-		4		-		4
Other marketable securities		2		-		-		2
Total assets	$	795	$	283	$	-	$	1,078
Liabilities
Derivatives
Commodity forward contracts	$	-	$	77	$	32	$	109
Interest rate contracts		-		11		-		11
Total liabilities	$	-	$	88	$	32	$	120
(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
March 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	390	$	-	$	-	$	390
Preferred stock and other equity		9		27		-		36
Corporate debt		-		13		-		13
U.S. state and municipal debt		-		56		-		56
U.S. and foreign government debt		-		32		-		32
Money market funds and other		1		47		-		48
Total nuclear decommissioning trust funds		400		175		-		575
Derivatives
Commodity forward contracts		-		28		-		28
Interest rate contracts		-		1		-		1
Other marketable securities		3		-		-		3
Total assets	$	403	$	204	$	-	$	607
Liabilities
Derivatives
Commodity forward contracts	$	-	$	328	$	-	$	328
Interest rate contracts		-		6		-		6
Total liabilities	$	-	$	334	$	-	$	334
(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

34

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 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 10 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.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the 2010 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

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. 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’ commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31 follows:

PROGRESS ENERGY
(in millions)	2011			2010
Derivatives, net at January 1	$	36		$	39
Total unrealized (gains) losses deferred as regulatory assets and liabilities, net		(4	)		13
Derivatives, net at March 31	$	32		$	52

PEC
(in millions)	2011			2010
Derivatives, net at January 1	$	36		$	27
Total unrealized (gains) losses deferred as regulatory assets and liabilities, net		(4	)		9
Derivatives, net at March 31	$	32		$	36

PEF
(in millions)	2011		2010
Derivatives, net at January 1	$	-	$	12
Total unrealized (gains) losses deferred as regulatory assets and liabilities, net		-		4
Derivatives, net at March 31	$	-	$	16

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Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. There were no Level 3 realized gains or losses, purchases, sales, issuances or settlements during the period.

9. BENEFIT PLANS

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

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

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	13		$	12		$	3	$	2
Interest cost		35			35			10		8
Expected return on plan assets		(45	)		(39	)		-		(1	)
Amortization of actuarial loss(a)		14			12			3		-
Other amortization, net(a)		2			2			1		1
Net periodic cost	$	19		$	22		$	17	$	10

(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		4
Expected return on plan assets		(23	)		(19	)		-		-
Amortization of actuarial loss		6			4			1		-
Other amortization, net		1			1			-		-
Net periodic cost	$	5		$	7		$	8	$	5

PEF
	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	6		$	5		$	1	$	-
Interest cost		15			15			4		3
Expected return on plan assets		(20	)		(17	)		-		-
Amortization of actuarial loss		8			7			2		-
Other amortization, net		-			-			1		1
Net periodic cost	$	9		$	10		$	8	$	4

In 2011, we expect to make contributions directly to pension plan assets of approximately $300 million-$400 million for us, including $200 million-$250 million for PEC and $100 million-$150 million for PEF. We contributed $210 million during the three months ended March 31, 2011, including $140 million for PEC and $70 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, an additional tax expense of $22 million for us, including $12 million for PEC and $10 million for PEF, was recognized during the three months ended March 31, 2010. See Note 16A in the 2010 Form 10-K.

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10. 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 $135 million and $164 million on the Progress Energy Consolidated Balance Sheets at March 31, 2011 and December 31, 2010, respectively. At March 31, 2011, Progress Energy had 282.9 million MMBtu notional of natural gas and 20.3 million gallons notional of 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 $18 million and $24 million on the PEC Consolidated Balance Sheets at March 31, 2011 and December 31, 2010, respectively. At March 31, 2011, PEC had 79.2 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 $117 million and $140 million on the PEF Balance Sheets at March 31, 2011 and December 31, 2010, respectively. At March 31, 2011, PEF had 203.7 million MMBtu notional of natural gas and 20.3 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 March 31, 2011, all open interest rate hedges will reach their mandatory termination dates within two and a half years. At March 31, 2011, including amounts related to terminated hedges, we had $59 million of after tax losses, including $31 million and $4 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income related to forward starting swaps. It is expected that in the next twelve months losses of $7 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $4 million at PEC. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates and changes in the timing of debt issuances at 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 other comprehensive income 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 March 31, 2011, Progress Energy had $750 million notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. Subsequent to March 31, 2011, PEC settled a $100 million notional forward starting swap and PEC and PEF entered into $100 million notional and $75 million notional forward starting swaps, respectively.

FAIR VALUE HEDGES

For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At March 31, 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 $382 million at March 31, 2011, for which Progress Energy has posted collateral of $135 million in the normal course of business. If the credit risk-related contingent

38

features underlying these agreements were triggered at March 31, 2011, Progress Energy would have been required to post an additional $247 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $101 million at March 31, 2011, for which PEC has posted collateral of $18 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2011, PEC would have been required to post an additional $83 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 $281 million at March 31, 2011, for which PEF has posted collateral of $117 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on March 31, 2011, PEF would have been required to post an additional $164 million of collateral with its counterparties.

D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

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

Instrument / Balance sheet location		March 31, 2011						December 31, 2010
(in millions)	Asset			Liability			Asset			Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets		$	-					$	1
Other assets and deferred debits			5						3
Derivative liabilities, current					$	13					$	32
Derivative liabilities, long-term						5						7
Total derivatives designated as hedging instruments			5			18			4			39
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets			24						11
Other assets and deferred debits			10						4
Derivative liabilities, current						206						226
Derivative liabilities, long-term						231						268
CVOs(b)
Other liabilities and deferred credits						15						15
Fair value of derivatives not designated as hedging instruments			34			452			15			509
Fair value loss transition adjustment(c)
Derivative liabilities, current						1						1
Derivative liabilities, long-term						3						3
Total derivatives not designated as hedging instruments			34			456			15			513
Total derivatives		$	39		$	474		$	19		$	552

(a)	Substantially all of these contracts receive regulatory treatment.
(b)	As discussed in Note 15 in the 2010 Form 10-K, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000.
(c)	In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the adoption of new accounting guidance for derivatives. The related liability is being amortized to earnings over the term of the related contracts.

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The following tables present the effect of derivative instruments on other comprehensive income (OCI) (See Note 5C) and the Consolidated Statements of Income for the three months ended March 31, 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)		$	2	$	(6	)		$	(1	)	$	(2	)		$	(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		$	(52	)	$	(59	)		$	23	$	(234	)

(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	)

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

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PEC

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

Instrument / Balance sheet location		March 31, 2011					December 31, 2010
(in millions)	Asset			Liability			Asset			Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Other assets and deferred debits		$	4					$	3
Derivative liabilities, current					$	7					$	7
Other liabilities and deferred credits						4						4
Total derivatives designated as hedging instruments			4			11			3			11
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets			3						1
Other assets and deferred debits			3						1
Derivative liabilities, current						41						45
Other liabilities and deferred credits						68						78
Fair value of derivatives not designated as hedging instruments			6			109			2			123
Fair value loss transition adjustment(b)
Derivative liabilities, current						1						1
Other liabilities and deferred credits						3						3
Total derivatives not designated as hedging instruments			6			113			2			127
Total derivatives		$	10		$	124		$	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 March 31, 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)		$	1	$	(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.

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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		$	(11	)	$	(7	)		$	7	$	(42	)

(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	)

(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 March 31, 2011 and December 31, 2010:

Instrument / Balance sheet location		March 31, 2011						December 31, 2010
(in millions)	Asset			Liability			Asset			Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets		$	1					$	-
Derivative liabilities, current					$	6					$	7
Total derivatives designated as hedging instruments			1			6			-			7
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets			21						10
Other assets and deferred debits			7						3
Derivative liabilities, current						165						181
Derivative liabilities, long-term						163						190
Total derivatives not designated as hedging instruments			28			328			13			371
Total derivatives		$	29		$	334		$	13		$	378

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

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The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Statements of Income for the three months ended March 31, 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)		$	-	$	(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 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		$	(41	)	$	(52	)		$	17	$	(192	)

(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.

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11. 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 March 31, 2011
Revenues
Unaffiliated		$	1,133		$	1,032		$	2			$	-			$	2,167
Intersegment			-			-			74				(74	)			-
Total revenues			1,133			1,032			76				(74	)			2,167
Ongoing Earnings			139			111			(48	)			-				202
Total Assets			14,880			13,698			20,670				(16,626	)			32,622
For the three months ended March 31, 2010
Revenues
Unaffiliated		$	1,263		$	1,270		$	2			$	-			$	2,535
Intersegment			-			-			61				(61	)			-
Total revenues			1,263			1,270			63				(61	)			2,535
Ongoing Earnings			147			113			(47	)			-				213

Management uses the non-GAAP financial measure “Ongoing Earnings” as a performance measure to evaluate the results of our segments and operations. A reconciliation of consolidated Ongoing Earnings to net income attributable to controlling interests for the three months ended March 31 is as follows:

(in millions)	2011			2010
Ongoing Earnings	$	202		$	213
Tax levelization		(2	)		(2	)
Change in tax treatment of the Medicare Part D subsidy (Note 9)		-			(22	)
Merger and integration costs, net of tax benefit of $-		(14	)		-
Continuing income attributable to noncontrolling interests, net of tax		1			2
Income from continuing operations before cumulative effect of change in   accounting principle		187			191
Discontinued operations, net of tax		(2	)		1
Cumulative effect of change in accounting principle, net of tax		-			(2	)
Net income attributable to noncontrolling interests, net of tax		(1	)		-
Net income attributable to controlling interests	$	184		$	190

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12. ENVIRONMENTAL MATTERS

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

A. HAZARDOUS AND SOLID WASTE

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

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 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.

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		-			-			-
Expenditures for environmental loss contingencies		(1	)		(5	)		(6	)
Balance, March 31, 2011(a)	$	19		$	10		$	29
Balance, December 31, 2009	$	22		$	20		$	42
Amount accrued for environmental loss contingencies		2			2			4
Expenditures for environmental loss contingencies		(2	)		(4	)		(6	)
Balance, March 31, 2010(a)	$	22		$	18		$	40

(a) 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		-
Expenditures for environmental loss contingencies		-
Balance, March 31, 2011(a)	$	12
Balance, December 31, 2009	$	13
Amount accrued for environmental loss contingencies		2
Expenditures for environmental loss contingencies		(2	)
Balance, March 31, 2010(a)	$	13

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

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		-			-			-
Expenditures for environmental loss contingencies		(1	)		(5	)		(6	)
Balance, March 31, 2011(a)	$	7		$	10		$	17
Balance, December 31, 2009	$	9		$	20		$	29
Amount accrued for environmental loss contingencies		-			2			2
Expenditures for environmental loss contingencies		-			(4	)		(4	)
Balance, March 31, 2010(a)	$	9		$	18		$	27

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

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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 13B).

PEC

PEC has recorded a minimum estimated total remediation cost for all of its remaining MGP sites based upon its historical experience with remediation of several of its MGP sites. The maximum amount of the range for all the sites cannot be determined at this time. 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 located in Raleigh, N.C. (Ward) site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At March 31, 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. The court also set a trial date for May 7, 2012. In June 2010, the court entered a case management order and discovery is proceeding. 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 past expenditures in addressing conditions at the site. In 2009, PEC and several of the other participating PRPs at the Ward site submitted a letter containing a good faith response to the EPA’s special notice letter. Another group of PRPs separately submitted a good faith response, which the EPA advised would be used to negotiate implementation of the required actions. The other PRPs’ good faith response was subsequently withdrawn. Discussions among representatives of certain PRPs, including PEC, and the EPA are ongoing. Although a loss is considered probable, an agreement among the PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.

PEF

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 Environmental Cost Recovery Clause (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. At March 31, 2011 and December 31, 2010, PEF has recorded a regulatory asset for the probable recovery of costs through the ECRC related to the sites included under the agreement with the FDEP.

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B. AIR AND WATER QUALITY

We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of Clean Smokestacks Act. The air quality controls installed to comply with 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 CAIR.

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 Transport Rule, which is the regulatory program that will replace the CAIR when finalized. The proposed Transport Rule contains new emissions trading programs for nitrogen oxides (NOx) and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets. The EPA plans to finalize the Transport Rule in 2011. 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 well positioned to comply with the Transport Rule. The outcome of the EPA’s rulemaking cannot be predicted. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, the current implementation of the CAIR continues to fulfill best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units. 

In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (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 March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGUs). 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 a 60-day public comment period, the EPA is scheduled to issue a final rule in November 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.

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.

The EPA is continuing to record allowance allocations under the CAIR NOx trading program, in some cases for years beyond the estimated 2011 finalization of the Transport Rule. The EPA’s continued recording of CAIR NOx allowance allocations does not guarantee that allowances will continue to be usable for compliance after a replacement rule is finalized or that they will continue to have value in the future. SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements. PEF’s CAIR expenses, including NOx allowance inventory expense, are recoverable through the ECRC. Emission allowances are included on the Balance Sheets in

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inventory and in other assets and deferred debits and have not changed materially from what was reported in the 2010 Form 10-K.

13. 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 March 31, 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.

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 March 31, 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 March 31, 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 March 31, 2011, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $307 million, including $31 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. At March 31, 2011 and December 31, 2010, we had recorded liabilities related to guarantees and indemnifications to third parties of approximately $31 million. These amounts included $6 million for PEF at March 31, 2011 and December 31, 2010. During the three months ended March 31, 2011, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

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

C. OTHER COMMITMENTS AND CONTINGENCIES

MERGER

Progress Energy and its directors have been 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

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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.

In each of the actions, the parties have agreed that the defendants need not move, plead, or otherwise respond to the complaint until thirty days after the plaintiff has filed an amended or consolidated amended complaint, or advised the defendants that it will not be filing such pleadings. These actions brought in the Superior Court, Wake County, N.C., have all been designated as Complex Business Cases and assigned to the North Carolina Business Court. The court scheduled an initial hearing and status conference for March 31, 2011, which by order dated March 30, 2011, the court continued until further notice. The court has not yet ruled on the pending motions.

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 Duke Energy’s Registration Statement on Form S-4, filed with the SEC on March 17, 2011. 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.

We cannot predict the outcome of these matters.

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 12).

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. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. The Utilities have asserted nearly $91 million in damages incurred between January 31, 1998, and December 31, 2005, the time period set by the court for damages in this case. The Utilities may file subsequent damage claims as they incur additional costs.

In 2008, the Utilities received a ruling from the U.S. 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 and other indirect expenses. The DOJ requested a rehearing en banc but the D.C. Court of Appeals denied the

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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, but the judge has not issued a ruling. In the event that the Utilities recover damages in this matter, such recovery will primarily offset capital assets and therefore is not expected to have a material impact on the Utilities’ results of operations. However, the Utilities cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000, (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); four coal-based solid synthetic fuels limited liability companies, three of which were wholly owned (Earthco); certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates). In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global had requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the expiration of the 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. 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 has not yet been scheduled. 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 collected by PEF pursuant to that statute with interest. 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. Initial and reply briefs have been filed by the appellants and PEF. The appellants filed their response brief on January 25, 2011. Oral argument was held on May 5, 2011. We cannot predict the outcome of this matter.

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OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, we have made accruals and disclosures to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on our consolidated results of operations or financial position.

14. 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 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.

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Condensed Consolidating Statement of Income
Three months ended March 31, 2011
(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	1,034		$	1,133		$	-		$	2,167
Affiliate revenues		-			-			74			(74	)		-
Total operating revenues		-			1,034			1,207			(74	)		2,167
Operating expenses
Fuel used in electric generation		-			355			363			-			718
Purchased power		-			153			67			-			220
Operation and maintenance		3			211			351			(71	)		494
Depreciation, amortization and accretion		-			25			129			-			154
Taxes other than on income		-			85			59			(4	)		140
Other		-			(10	)		-			-			(10	)
Total operating expenses		3			819			969			(75	)		1,716
Operating (loss) income		(3	)		215			238			1			451
Other income (expense)
Interest income		-			1			-			-			1
Allowance for equity funds used during construction		-			9			20			-			29
Other, net		-			5			(2	)		-			3
Total other income, net		-			15			18			-			33
Interest charges
Interest charges		73			75			51			-			199
Allowance for borrowed funds used during construction		-			(4	)		(5	)		-			(9	)
Total interest charges, net		73			71			46			-			190
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(76	)		159			210			1			294
Income tax (benefit) expense		(31	)		60			80			(2	)		107
Equity in earnings of consolidated subsidiaries		229			-			-			(229	)		-
Income from continuing operations		184			99			130			(226	)		187
Discontinued operations, net of tax		-			(1	)		(1	)		-			(2	)
Net income		184			98			129			(226	)		185
Net income attributable to noncontrolling interests,   net of tax		-			(1	)		-			-			(1	)
Net income attributable to controlling interests	$	184		$	97		$	129		$	(226	)	$	184

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Condensed Consolidating Statement of Income
Three months ended March 31, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	1,272		$	1,263		$	-		$	2,535
Affiliate revenues		-			-			61			(61	)		-
Total operating revenues		-			1,272			1,324			(61	)		2,535
Operating expenses
Fuel used in electric generation		-			413			483			-			896
Purchased power		-			213			50			-			263
Operation and maintenance		3			205			329			(57	)		480
Depreciation, amortization and accretion		-			124			122			-			246
Taxes other than on income		-			93			64			(3	)		154
Other		-			2			-			-			2
Total operating expenses		3			1,050			1,048			(60	)		2,041
Operating (loss) income		(3	)		222			276			(1	)		494
Other income (expense)
Interest income		2			-			1			(1	)		2
Allowance for equity funds used during construction		-			8			13			-			21
Other, net		(1	)		3			(7	)		-			(5	)
Total other income, net		1			11			7			(1	)		18
Interest charges
Interest charges		71			70			52			(2	)		191
Allowance for borrowed funds used during construction		-			(5	)		(4	)		-			(9	)
Total interest charges, net		71			65			48			(2	)		182
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(73	)		168			235			-			330
Income tax (benefit) expense		(30	)		69			97			3			139
Equity in earnings of consolidated subsidiaries		233			-			-			(233	)		-
Income from continuing operations before   cumulative effect of change in accounting principle		190			99			138			(236	)		191
Discontinued operations, net of tax		-			1			-			-			1
Cumulative effect of change in accounting principle,   net of tax		-			-			(2	)		-			(2	)
Net income		190			100			136			(236	)		190
Net (income) loss attributable to noncontrolling   interests, net of tax		-			(1	)		2			(1	)		-
Net income attributable to controlling interests	$	190		$	99		$	138		$	(237	)	$	190

54

Condensed Consolidating Balance Sheet
March 31, 2011
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	10,225	$	11,167	$	90		$	21,482
Current assets
Cash and cash equivalents		3		55		114		-			172
Receivables, net		-		436		444		-			880
Notes receivable from affiliated companies		89		27		72		(188	)		-
Regulatory assets		-		59		42		-			101
Derivative collateral posted		-		117		18		-			135
Income taxes receivable		34		1		20		(19	)		36
Prepayments and other current assets		14		745		914		(204	)		1,469
Total current assets		140		1,440		1,624		(411	)		2,793
Deferred debits and other assets
Investment in consolidated subsidiaries		14,143		-		-		(14,143	)		-
Regulatory assets		-		1,321		985		-			2,306
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		575		1,066		-			1,641
Other assets and deferred debits		130		243		891		(519	)		745
Total deferred debits and other assets		14,273		2,139		2,942		(11,007	)		8,347
Total assets	$	14,413	$	13,804	$	15,733	$	(11,328	)	$	32,622
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,047	$	4,739	$	5,728	$	(10,467	)	$	10,047
Noncontrolling interests		-		2		-		1			3
Total equity		10,047		4,741		5,728		(10,466	)		10,050
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		-		(36	)		273
Long-term debt, net		3,993		4,182		3,693		-			11,868
Total capitalization		14,040		9,266		9,480		(10,502	)		22,284
Current liabilities
Current portion of long-term debt		-		300		-		-			300
Short-term debt		79		-		-		-			79
Notes payable to affiliated companies		-		186		3		(189	)		-
Derivative liabilities		-		171		49		-			220
Other current liabilities		262		981		1,021		(224	)		2,040
Total current liabilities		341		1,638		1,073		(413	)		2,639
Deferred credits and other liabilities
Noncurrent income tax liabilities		2		560		1,697		(494	)		1,765
Regulatory liabilities		-		1,018		1,517		90			2,625
Other liabilities and deferred credits		30		1,322		1,966		(9	)		3,309
Total deferred credits and other liabilities		32		2,900		5,180		(413	)		7,699
Total capitalization and liabilities	$	14,413	$	13,804	$	15,733	$	(11,328	)	$	32,622

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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
Income taxes receivable		14		1		90		(53	)		52
Prepayments and other current assets		16		750		894		(220	)		1,440
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

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Condensed Consolidating Statement of Cash Flows
Three months ended March 31, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	280		$	257		$	337		$	(428	)	$	446
Investing activities
Gross property additions		-			(218	)		(283	)		-			(501	)
Nuclear fuel additions		-			(7	)		(50	)		-			(57	)
Purchases of available-for-sale securities and other investments		-			(1,661	)		(156	)		-			(1,817	)
Proceeds from available-for-sale securities and other investments		-			1,661			148			-			1,809
Changes in advances to affiliated companies		(75	)		21			42			12			-
Contributions to consolidated subsidiaries		(10	)		-			-			10			-
Other investing activities		-			43			5			(2	)		46
Net cash used by investing activities		(85	)		(161	)		(294	)		20			(520	)
Financing activities
Issuance of common stock, net		8			-			-			-			8
Dividends paid on common stock		(183	)		-			-			-			(183	)
Dividends paid to parent		-			(328	)		(100	)		428			-
Net increase in short-term debt		79			-			-			-			79
Proceeds from issuance of long-term debt, net		494			-			-			-			494
Retirement of long-term debt		(700	)		-			-			-			(700	)
Changes in advances from affiliated companies		-			11			-			(11	)		-
Contributions from parent		-			10			-			(10	)		-
Other financing activities		-			(4	)		(60	)		1			(63	)
Net cash used by financing activities		(302	)		(311	)		(160	)		408			(365	)
Net decrease in cash and cash equivalents		(107	)		(215	)		(117	)		-			(439	)
Cash and cash equivalents at beginning of period		110			270			231			-			611
Cash and cash equivalents at end of period	$	3		$	55		$	114		$	-		$	172

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Condensed Consolidating Statement of Cash Flows
Three months ended March 31, 2010
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(36	)	$	209		$	484		$	(71	)	$	586
Investing activities
Gross property additions		-			(275	)		(304	)		24			(555	)
Nuclear fuel additions		-			(8	)		(46	)		-			(54	)
Purchases of available-for-sale securities and other investments		-			(1,823	)		(163	)		-			(1,986	)
Proceeds from available-for-sale securities and other investments		-			1,827			150			-			1,977
Changes in advances to affiliated companies		(89	)		(2	)		296			(205	)		-
Return of investment in consolidated subsidiaries		30			-			-			(30	)		-
Contributions to consolidated subsidiaries		(21	)		-			-			21			-
Other investing activities		-			(1	)		-			-			(1	)
Net cash used by investing activities		(80	)		(282	)		(67	)		(190	)		(619	)
Financing activities
Issuance of common stock, net		197			-			-			-			197
Dividends paid on common stock		(175	)		-			-			-			(175	)
Dividends paid to parent		-			(50	)		-			50			-
Dividends paid to parent in excess of retained earnings		-			-			(30	)		30			-
Net decrease in short-term debt		(140	)		-			-			-			(140	)
Proceeds from issuance of long-term debt, net		-			591			-			-			591
Retirement of long-term debt		(100	)		-			-			-			(100	)
Changes in advances from affiliated companies		-			(211	)		6			205			-
Contributions from parent		-			10			19			(29	)		-
Other financing activities		-			-			(49	)		5			(44	)
Net cash (used) provided by financing activities		(218	)		340			(54	)		261			329
Net (decrease) increase in cash and cash equivalents		(334	)		267			363			-			296
Cash and cash equivalents at beginning of period		606			72			47			-			725
Cash and cash equivalents at end of period	$	272		$	339		$	410		$	-		$	1,021

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

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

The following MD&A contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors,” to the Progress Registrant’s annual report on Form 10-K for the fiscal year ended December 31, 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 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. Certain amounts for 2010 have been reclassified to conform to the 2011 presentation.

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, which will be subject to completion of the Merger and receipt of the requisite approval of the shareholders of Duke Energy. 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

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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 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, the Public Service Commission of South Carolina (SCPSC), the Florida Public Service Commission (FPSC), the Indiana Utility Regulatory Commission and the Ohio Public Utilities Commission. The status of these matters is as follows:

·   On March 17, 2011, Duke Energy filed a registration statement on Form S-4 with the SEC. This filing and its subsequent amendments contain a preliminary joint proxy statement for a special meeting of each company’s shareholders to vote on the Merger. Shareholder meetings for Duke Energy and Progress Energy for shareholders to vote on the Merger are expected in mid-summer.

·   On March 28, 2011, Progress Energy and Duke Energy submitted their Hart-Scott-Rodino filing with the U.S. Department of Justice 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 March 30, 2011, Progress Energy and Duke Energy made filings with the NRC for approval for transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses. NRC approval is expected to take six to nine months.

·   On April 4, 2011, Progress Energy and Duke Energy filed an application to approve the Merger with the Kentucky Public Service Commission. Procedural hearings have been scheduled for July 6, 2011.

·   On April 4, 2011, Progress Energy and Duke Energy made joint filings with the FERC, which assesses market power-related issues. 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. The FERC is expected to rule on the filings within 180 days.

·   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. Procedural hearings have been scheduled for September 20, 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. Procedural hearings have not been scheduled.

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.

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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 13C).

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 after excluding 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.

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 March 31, 2011
Ongoing Earnings	$	139		$	111		$	(48	)	$	202		$	0.69
Tax levelization		(2	)		(3	)		3			(2	)		(0.01	)
Merger and integration costs, net of tax(a)		(7	)		(7	)		-			(14	)		(0.05	)
Discontinued operations attributable   to controlling interests, net of tax		-			-			(2	)		(2	)		(0.01	)
Net income (loss) attributable to   controlling interests(b)	$	130		$	101		$	(47	)	$	184		$	0.62
Three months ended March 31, 2010
Ongoing Earnings	$	147		$	113		$	(47	)	$	213		$	0.75
Tax levelization		2			(2	)		(2	)		(2	)		-
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		-			-			1			1			-
Net income (loss) attributable to   controlling interests(b)	$	137		$	101		$	(48	)	$	190		$	0.67

(a)	Calculated using an 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 both PEC and PEF.

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.

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OVERVIEW

For the quarter ended March 31, 2011, our net income attributable to controlling interests was $184 million, or $0.62 per share, compared to net income attributable to controlling interests of $190 million, or $0.67 per share, for the same period in 2010. The decrease as compared to prior year was primarily due to:

·   unfavorable impact of extreme weather in 2010 at the Utilities;

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

·   lower wholesale revenues at PEF.

Offsetting these items were:

·   lower amortization expense at PEF and

·   lower income tax expense due to the change in the tax treatment of the Medicare Part D subsidy in 2010 (Ongoing Earnings adjustment).

PROGRESS ENERGY CAROLINAS

PEC contributed net income available to parent totaling $130 million and $137 million for the three months ended March 31, 2011 and 2010, respectively. The decrease in net income available to parent for the three months ended March 31, 2011, compared to the same period in 2010, was primarily due to the unfavorable impact of extreme weather in 2010 and the impact of merger and integration costs related to the Merger, partially offset by lower income tax expense due to the change in the tax treatment of the Medicare Part D subsidy in 2010 and favorable allowance for funds used during construction (AFUDC) equity. PEC contributed Ongoing Earnings of $139 million and $147 million for the three months ended March 31, 2011 and 2010, respectively. The 2011 Ongoing Earnings adjustments to net income available to parent were due to PEC recording a tax levelization charge of $2 million 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 due to PEC recording a tax levelization benefit of $2 million and a $12 million charge for the change in the tax treatment of the Medicare Part D subsidy. 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.

REVENUES

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

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A reconciliation of Base Revenues to GAAP operating revenues, including the percentage change by customer class, for the three months ended March 31 follows:

(in millions)
Customer Class	2011			Change			% Change			2010
Residential	$	332		$	(24	)		(6.7	)	$	356
Commercial		167			(6	)		(3.5	)		173
Industrial		83			3			3.8			80
Governmental		15			1			7.1			14
Unbilled		(35	)		(2	)		-			(33	)
Total retail base revenues		562			(28	)		(4.7	)		590
Wholesale base revenues		70			(5	)		(6.7	)		75
Total Base Revenues		632			(33	)		(5.0	)		665
Clause-recoverable regulatory revenues		7			6			600.0			1
Miscellaneous		34			(1	)		(2.9	)		35
Fuel and other pass-through revenues		460			(102	)		-			562
Total operating revenues	$	1,133		$	(130	)		(10.3	)	$	1,263

PEC’s total Base Revenues were $632 million and $665 million for the three months ended March 31, 2011 and 2010, respectively. The $33 million decrease in Base Revenues was due primarily to the $34 million unfavorable impact of weather. The unfavorable impact of weather was driven by 15 percent lower heating-degree days than 2010. Heating-degree days were 1 percent lower than normal in 2011 and were 19 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.

Clause-recoverable regulatory revenues were $7 million and $1 million for the three months ended March 31, 2011 and 2010, respectively. The $6 million increase in clause-recoverable regulatory revenues was due primarily to increased spending on DSM programs compared to 2010.

PEC’s electric energy sales in kilowatt-hours (kWh) and the percentage change by customer class for the three months ended March 31 were as follows:

(in millions of kWh)
Customer Class	2011			Change			% Change			2010
Residential		5,439			(449	)		(7.6	)		5,888
Commercial		3,287			(134	)		(3.9	)		3,421
Industrial		2,488			43			1.8			2,445
Governmental		386			11			2.9			375
Unbilled		(669	)		(39	)		-			(630	)
Total retail kWh sales		10,931			(568	)		(4.9	)		11,499
Wholesale		3,209			(603	)		(15.8	)		3,812
Total kWh sales		14,140			(1,171	)		(7.6	)		15,311

The decrease in retail and wholesale kWh sales in 2011 was primarily due to unfavorable weather compared to the prior year as previously discussed.

Wholesale kWh sales decreased primarily due to lower excess generation sales driven by favorable weather in the prior year. Despite the limited sales opportunities in the current year, wholesale base revenues declined to a lesser extent due to improved market dynamics.

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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, as well as energy purchased in the market to meet customer load. Fuel and a portion of purchased power expenses are recovered primarily through cost-recovery clauses, and as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection from or refund to customers 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 $430 million for the three months ended March 31, 2011, which represents a $103 million decrease compared to the same period in 2010. This decrease was primarily due to lower fuel and purchased power costs resulting from lower coal and natural gas prices; the generation mix, which was impacted by nuclear plant outages in 2010; and the lower system requirements resulting from unfavorable weather compared to 2010.

Operation and Maintenance

Operations and maintenance (O&M) expense was $295 million for the three months ended March 31, 2011, which represents a $10 million increase compared to the same period in 2010. This increase was primarily due to $12 million of merger and integration costs related to the Merger. Management does not consider merger and integration costs to be representative of PEC’s fundamental core earnings. Therefore, the impact of merger and integration costs is 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 $9 million compared to the same period in 2010.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion was $124 million for the three months ended March 31, 2011, which represents a $6 million increase compared to the same period in 2010. This increase was primarily due to unfavorable plant depreciation of $4 million due to the impact of higher depreciable asset base.

Total Other Income, Net

Total other income, net was $18 million for the three months ended March 31, 2011, which represents an $11 million increase compared to the same period in 2010. This increase was primarily due to favorable AFUDC equity of $7 million, related to increased construction project costs and the $3 million higher income recognized from the balanced billing program resulting from extreme weather in 2010.

Income Tax Expense

Income tax expense decreased $19 million for the three months ended March 31, 2011, as compared to the same period in 2010, primarily due to the $12 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 9) and the $11 million impact of lower pre-tax income. These favorable items are partially offset by the $4 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. PEC’s income tax expense was increased by $2 million for the three months ended March 31, 2011, compared to a decrease of $2 million for the three months ended March 31, 2010, 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 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 tax levelization and the change in the tax treatment of the Medicare Part D subsidy have been excluded in computing PEC’s Ongoing Earnings.

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PROGRESS ENERGY FLORIDA

PEF contributed net income available to parent totaling $101 million for each of the three months ended March 31, 2011 and 2010, respectively. Net income available to parent for the three months ended March 31, 2011, compared to the same period in 2010, was increased by lower amortization expense and lower income tax expense due to the change in the tax treatment of the Medicare Part D subsidy in 2010, offset by the unfavorable impact of extreme weather in 2010, lower wholesale base revenues, the impact of merger and integration costs related to the Merger and estimated Crystal River Unit No. 3 (CR3) joint owner replacement power costs. PEF contributed Ongoing Earnings of $111 million and $113 million for the three months ended March 31, 2011 and 2010, respectively. The 2011 Ongoing Earnings adjustments to net income available to parent were due to PEF recording a tax levelization charge of $3 million 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 due to PEF recording a tax levelization charge of $2 million and a $10 million charge for the change in the tax treatment of the Medicare Part D subsidy. Management does not consider these charges to be representative of PEF’s fundamental core earnings and excluded these charges in computing PEF’s Ongoing Earnings.

REVENUES

The revenue table that follows presents 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. 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 provided in accordance with GAAP.

A reconciliation of Base Revenues to GAAP operating revenues, including the percentage change by year and by customer class, for the three months ended March 31 follows:

(in millions)
Customer Class	2011			Change			% Change			2010
Residential	$	220		$	(41	)		(15.7	)	$	261
Commercial		78			(3	)		(3.7	)		81
Industrial		18			-			-			18
Governmental		20			(1	)		(4.8	)		21
Unbilled		(15	)		(14	)		-			(1	)
Total retail base revenues		321			(59	)		(15.5	)		380
Wholesale base revenues		25			(18	)		(41.9	)		43
Total Base Revenues		346			(77	)		(18.2	)		423
Clause-recoverable regulatory returns		45			7			18.4			38
Miscellaneous		51			(2	)		(3.8	)		53
Fuel and other pass-through revenues		590			(166	)		-			756
Total operating revenues	$	1,032		$	(238	)		(18.7	)	$	1,270

PEF’s total Base Revenues were $346 million and $423 million for the three months ended March 31, 2011 and 2010, respectively. The $77 million decrease in Base Revenues was due primarily to the $49 million unfavorable impact of weather, $18 million lower wholesale base revenues and the $9 million unfavorable impact of net retail customer growth and usage. The unfavorable impact of weather was driven by 56 percent lower heating degree days than 2010. Heating-degree days were 7 percent higher than normal in 2011 and were 143 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 unfavorable impact of net retail customer growth and usage was driven by a decrease in the average usage per retail customer, partially offset by a net 8,000 increase in the average number of customers for 2011 compared to 2010. The $18 million decrease in wholesale base revenues was due primarily to

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decreased revenues from contracts that expired in 2010 and changes to a contract with a major customer. Given the current economic conditions, PEF does not believe it is likely to replace in 2011 wholesale contracts that expired in 2010.

PEF’s clause-recoverable regulatory returns were $45 million and $38 million for 2011 and 2010, respectively. The $7 million higher revenues primarily relate to higher returns on ECRC assets due to placing approximately $230 million of CAIR projects into service in the second quarter of 2010.

PEF’s electric energy sales in kWh and the percentage change by customer class for the three months ended March 31 were as follows:

(in millions of kWh)
Customer Class	2011			Change			% Change			2010
Residential		4,281			(845	)		(16.5	)		5,126
Commercial		2,547			(50	)		(1.9	)		2,597
Industrial		772			4			0.5			768
Governmental		727			(7	)		(1.0	)		734
Unbilled		(356	)		(286	)		-			(70	)
Total retail kWh sales		7,971			(1,184	)		(12.9	)		9,155
Wholesale		478			(526	)		(52.4	)		1,004
Total kWh sales		8,449			(1,710	)		(16.8	)		10,159

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

The decrease in wholesale kWh sales in 2011 was primarily due to decreased revenues from contracts that expired in 2010 and changes to a contract with a major customer, as previously discussed.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost-recovery clauses and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection from or refund to customers 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 $508 million for the three months ended March 31, 2011, which represents a $118 million decrease compared to the same period in 2010. This decrease was primarily due to lower current year fuel and purchased power costs of $181 million, which includes a $9 million increase in joint owner replacement power costs related to the continued outage at CR3 (See Note 4B), and a decrease in the recovery of deferred capacity costs of $43 million, partially offset by higher net deferred fuel expense of $106 million. The lower fuel and purchased power costs were driven by lower system requirements in 2011 as a result of unfavorable weather as previously discussed and lower natural gas prices in 2011. The decrease in the recovery of deferred capacity costs was due to decreased current year rates. Deferred fuel expense increased due to the collection of fuel costs that were under-recovered in 2010 as a result of higher system requirements due to extreme weather.

Operation and Maintenance

O&M expense was $210 million for the three months ended March 31, 2011, which represents a $5 million increase compared to the same period in 2010. O&M expense increased primarily due to $11 million of merger and integration costs related to the Merger, partially offset by $7 million of ECRC costs resulting from a refund of the 2010 over-recovery. Management does not consider merger and integration costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of merger and integration costs is excluded in computing PEF’s

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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 $25 million for the three months ended March 31, 2011, which represents a $99 million decrease compared to the same period in 2010. Depreciation, amortization and accretion expense decreased primarily due to the $80 million reduction in the cost of removal component of amortization expense in accordance with the 2010 base rate settlement agreement (See Note 4B).

Other

Other operating expense was a gain of $12 million for the three months ended March 31, 2011, primarily due to a favorable litigation settlement.

Total Other Income, Net

Total other income, net was $12 million for the three months ended March 31, 2011, which is essentially flat compared to the same period in 2010. We expect AFUDC equity on eligible CR3 capital projects to continue to increase until the CR3 extended outage is complete.

Income Tax Expense

Income tax expense decreased $10 million for the three months ended March 31, 2011, compared to the same period in 2010, primarily due to 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 9). PEF’s income tax expense was increased by $3 million and $2 million for the three months ended March 31, 2011 and 2010, respectively, related to the 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 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 impact of tax levelization and the change in the tax treatment of the Medicare Part D subsidy have been 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 March 31
(in millions)	2011			2010
Interest expense	$	(79	)	$	(75	)
Other income		(1	)		(4	)
Income tax benefit		32			32
Ongoing Earnings		(48	)		(47	)
Tax levelization		3			(2	)
Discontinued operations attributable to controlling interests, net of tax		(2	)		1
Net loss attributable to controlling interests	$	(47	)	$	(48	)

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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 decreased by $3 million for the three months ended March 31, 2011 compared to an increase of $2 million for the same period 2010, 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.

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 March 31, 2011 and $1 million of income from discontinued operations attributable to controlling interests, net of tax, for the three months ended March 31, 2010. 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.

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. In recent years, rather than paying dividends to the Parent, the Utilities, to a large extent, have retained their free cash flow to fund their capital expenditures. For the three months ended March 31, 2011, PEC and PEF paid dividends

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to the Parent of $100 million and $325 million, respectively. 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. We do not expect to realize a material amount of proceeds from the sale of equity in 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, excluding the $22 million commitment that expired May 3, 2011. The credit facilities serve as back-ups to our commercial paper programs. To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At March 31, 2011, the Parent had no outstanding borrowings under its credit facility, $79 million of outstanding commercial paper and had issued $32 million of letters of credit, which were supported by the revolving credit facility. At March 31, 2011, PEC and PEF had no outstanding borrowings under their respective credit facilities and no outstanding commercial paper. Based on these outstanding amounts at March 31, 2011, there was a combined $1.867 billion available for additional borrowings, excluding the $22 million commitment expiring May 2011.

At March 31, 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 March 31, 2011, the majority of the Utilities’ open financial commodity hedges were in net mark-to-market liability positions. See Note 10A for additional information with regard to our commodity derivatives.

At March 31, 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 March 31, 2011, the sum 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 10B for additional information with regard to our interest rate derivatives.

On July 21, 2010, the Wall Street Reform and Consumer Protection Act (H.R. 4173) 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 expected to be determined as more detailed rules and regulations are published during 2011. 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.

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.

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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 $140 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The decrease was primarily due to a $210 million increase in pension plan funding and the $83 million unfavorable impact of extreme weather in 2010 as previously discussed, partially offset by $28 million of net cash refunds of collateral to counterparties on derivative contracts in 2011 compared to $157 million of net cash payments of collateral in 2010.

INVESTING ACTIVITIES

Net cash used by investing activities decreased by $99 million for the three months ended March 31, 2011, when compared to the same period in the prior year. This decrease was primarily due to a $54 million decrease in gross property additions, primarily due to lower spending for environmental compliance and nuclear projects at PEF; and a $47 million increase in cash provided by other investing activities primarily due to $27 million of litigation settlement proceeds and the $11 million receipt of Nuclear Electric Insurance Limited (NEIL) insurance proceeds for repairs at CR3 (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”).

FINANCING ACTIVITIES

Net cash used by financing activities increased by $694 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The increase was primarily due to a $600 million increase in long-term debt retirements, due to the Parent’s $700 million repayment of senior notes in March 2011 compared to the $100 million retirement of Series A Floating Rate Notes in January 2010.

A discussion of our 2011 financing activities follows:

On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due 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.

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 months ended March 31, 2011, we issued approximately 1.0 million shares of common stock through the Progress Energy Investor Plus Plan (IPP) and equity incentive plans resulting in approximately $8 million of net proceeds. For the three months ended March 31, 2010, we issued approximately 6.1 million shares of common stock through the IPP and equity incentive plans resulting in approximately $197 million of net proceeds.

SHORT-TERM DEBT

At March 31, 2011, Progress Energy had outstanding short-term debt consisting of commercial paper borrowings totaling $79 million at an interest rate of 0.36%. At the end of each month during the three months ended March 31, 2011, Progress Energy had a maximum short-term debt balance of $79 million and an average short-term debt balance of $26 million at a weighted average interest rate of 0.36%. Progress Energy’s short-term debt during the three months ended March 31, 2011 consisted solely of commercial paper borrowings.

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FUTURE LIQUIDITY AND CAPITAL RESOURCES

At March 31, 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 March 31, 2011, we have carried forward $836 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 customer’s future energy needs (See Item 1A, “Risk Factors,” to the 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.

The Parent’s RCA will expire in May 2012, with the exception of approximately $22 million that expired May 3, 2011. In the event we enter into a new credit facility for the Parent, we cannot predict the terms, prices, durations or participants in such facility.

Progress Energy and its subsidiaries have approximately $12.441 billion in outstanding long-term debt, including the $300 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 two notch downgrade by Moody’s, PEC’s tax-exempt bonds will continue to be rated at or above A3 while PEF’s would be below A3, most likely resulting in higher future interest rate resets for PEF’s tax-exempt bonds. 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 three months ended March 31, 2011, we contributed $210 million directly to pension plan assets and expect to make additional contributions of $100 million to $200 million in 2011 (See Note 9).

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

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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 March 31, 2011, we had posted approximately $135 million of cash collateral compared to $164 million of cash collateral posted at December 31, 2010. The majority of our current 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 ratings 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 and equity securities will depend on market conditions, operating cash flow and our specific needs. We may from time to time sell securities beyond the amount immediately needed to meet capital 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 March 31, 2011, the current portion of our long-term debt was $300 million. The current portion represents the $300 million July 2011 maturity at PEF, which we expect to refinance with long-term debt.

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 12 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 Fuel Cost Recovery

On May 5, 2011, PEC filed with the SCPSC an application for a $24 million increase in the fuel rate charged to its South Carolina ratepayers, driven by rising fuel prices. If approved, the increase will be effective July 1, 2011. On May 2, 2011, PEC also filed with the SCPSC for a $4 million increase in the DSM and EE rate, driven by the introduction of new and the expansion of existing DSM and EE programs. If approved, the increase will be effective July 1, 2011. We cannot predict the outcome of these matter.

PEC Construction of Generating Facilities

The NCUC has granted PEC permission to construct three new generating facilities: an approximately 600-MW combined cycle dual-fuel facility at its Richmond generation facility, 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 June 2011, January 2013 and December 2013, respectively.

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CR3 Outage

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL has confirmed that the CR3 initial delamination is a covered accident. 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 is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. 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 March 31, 2011:

(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	339		$	182
NEIL proceeds received		(144	)		(75	)
Insurance receivable at March 31, 2011		(85	)		(62	)
Balance for recovery	$	110		$	45

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. 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). PEF has recorded $229 million of NEIL replacement power cost reimbursements subsequent to the deductible period, which reduced the portion of the deferred fuel regulatory asset related to the extended CR3 outage to $110 million at March 31, 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.

PEF Nuclear Cost Recovery

On May 2, 2011, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $158 million which includes recovery of pre-construction and carrying costs and CCRC recoverable O&M expense incurred or anticipated to be incurred during 2012, recovery of $115 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. If approved, the decrease would begin with the first January 2012 billing cycle. We cannot predict the outcome of this matter.

PEF Demand-Side Management Cost Recovery

On December 30, 2009, the FPSC ordered PEF and other Florida utilities to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. As subsequently revised by the FPSC, PEF’s aggregate conservation goals over the next 10 years were: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). On March 30, 2010, PEF filed a petition for approval of its proposed DSM plan and to authorize cost recovery through the Energy Conservation Cost Recovery Clause (ECCR). On September 14, 2010, the FPSC held an agenda conference to approve PEF’s petition for the DSM plan. The FPSC ruled that while PEF’s proposed DSM plan met the cumulative, 10-year DSM goals set by the FPSC, the plan did not meet the annual DSM goals. On October 4, 2010, the FPSC denied PEF’s petition for the DSM plan, approved PEF’s solar pilot programs, and required PEF to file a revised proposed DSM plan that meets the annual goals set by the FPSC. PEF filed a revised proposed DSM plan on November 29, 2010. An agenda conference has been scheduled by the FPSC for May 24, 2011. We cannot predict the outcome of this matter.

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OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

At March 31, 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 10 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 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 March 31, 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 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 (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 12). 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 12A.

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

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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 completed several of the EPA’s recommendations for the active ponds and other recommended actions are under way. 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 the 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 expenses. Control equipment installed pursuant to the provisions of CAIR, 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.

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Clean Smokestacks Act

In 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of 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 expenses that PEC incurs in connection with its environmental compliance control facilities.

Clean Air Interstate 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.

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 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 (CR4) and Crystal River Unit No. 5 (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 allowance purchases.

In 2008, the U.S. Court of Appeals for the District of Columbia Circuit (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 Transport Rule, which is the regulatory program that will replace the CAIR when finalized. The proposed Transport Rule contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets. The EPA plans to finalize the Transport Rule in 2011. 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 well positioned to comply with the Transport Rule. The outcome of the EPA’s rulemaking cannot be predicted. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, the current implementation of the CAIR continues to fulfill BART for NOx and SO2 for BART-affected units under the CAVR. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO2 emissions reductions in addition to particulate matter emissions reductions for BART-eligible units.

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

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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 March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGUs). 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 a 60-day public comment period, the EPA is scheduled to issue a final rule in November 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 rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in 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. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. 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 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.

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.

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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 final Transport Rule. 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 Transport Rule will be determined upon finalization of the rule. As a result of the decision remanding the CAIR, 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 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

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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. The EPA plans to finalize the revisions by July 29, 2011, and to designate nonattainment areas by August 2012. The proposed revisions are significantly more stringent than the current NAAQS. Should additional nonattainment areas be designated in our service territories, we may be required to install additional emission controls at some of our facilities. The outcome of this matter cannot be predicted.

In 2010, the EPA announced a revision to the primary NAAQS for nitrogen dioxide. The EPA plans to designate nonattainment areas for the primary NAAQS for nitrogen dioxide by January 2012. Currently, there are no monitors reporting violation of this new standard in PEC’s or PEF’s 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 nitrogen dioxide NAAQS be designated in our service territories, we may be required to install additional controls at some of our facilities. Additionally, the EPA published the final new 1-hour NAAQS for SO2. 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.

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 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.

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

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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 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 are due on July 19, 2011. The outcome of this matter cannot be predicted.

OTHER ENVIRONMENTAL MATTERS

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. At the end of 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 will propose the standard by July 2011 and issue the final rule by May 2012. 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 the Utilities’ 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 adopted 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 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

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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 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.

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 March 31, 2011, we have incurred $133 million of allowable, 50 percent reimbursable, smart grid project costs, and have submitted to the DOE requests for reimbursement of $62 million, of which we have received $35 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.

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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. In March 2011, we advised the NCUC and the SCPSC, respectively, that the Weatherspoon coal units are expected to be retired on October 1, 2011.

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 issued an information notice to U.S. licensees describing the circumstances of the events in Japan. Additionally, an NRC special task force is conducting a comprehensive review of processes and regulations to determine whether the agency should make additional improvements to the nuclear regulatory system. 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.

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 within the concrete of the outer wall of the containment building, which resulted in an extension of the outage. After comprehensive analysis, we determined that the concrete delamination at CR3 was caused by redistribution of stresses on the containment wall that occurred when we 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 after the repair work was completed and during the late stages of retensioning the containment building. CR3 will remain out of service while we conduct a thorough engineering analysis and review of the new delamination and evaluate repair options. (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 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 polices 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 we receive 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 polices. 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 equipment. Work has been suspended on the remaining long lead time equipment items and PEF entered into suspension negotiations with the selected equipment vendors, substantially all of which were concluded in March 2011. We anticipate that all negotiations will be completed by the fourth quarter of 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

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true-up. While the amount of purchase order disposition costs cannot be determined until the negotiations are complete, we do not believe the costs, if any, will have a material impact on our operations.

SPENT NUCLEAR FUEL MATTERS

See Note 13 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 $1.055 billion has been used through March 31, 2011, to offset regular federal income tax liability and $836 million is being carried forward as deferred tax credits that do not expire.

See Note 13C and Items 1A, “Risk Factors,” and 7, “MD&A – Other Matters” 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 13C.

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” included within 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 $190 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The decrease was primarily due to a $140 million increase in pension plan funding and the $34 million unfavorable impact of extreme weather in 2010 as previously discussed.

Net cash used by investing activities increased $185 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The increase was primarily due to a $205 million change in advances to affiliated companies.

Net cash used by financing activities increased $115 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The increase was primarily due to the $100 million payment of dividends to the Parent in 2011.

SHORT-TERM DEBT

At March 31, 2011, PEC had no outstanding short-term debt. At the end of each month during the three months ended March 31, 2011, PEC had a maximum short-term debt balance of $2 million and an average short-term debt balance of $1 million at a weighted average interest rate of 0.35%. PEC’s short-term debt during the three months ended March 31, 2011, consisted solely of money pool borrowings.

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 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 March 31, 2011, PEC had issued $22 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 10 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market risk and derivatives.

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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” included within 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)(c) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities increased $82 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The increase was primarily due to the $22 million net cash refunds of collateral to counterparties on derivative contracts in 2011 compared to $137 million net cash payments of collateral in 2010, partially offset by the $49 million unfavorable impact of extreme weather in 2010 as previously discussed and $29 million lower tax refunds.

Net cash used by investing activities decreased $97 million for the three months ended March 31, 2011, when compared to the same period in the prior year. The decrease was primarily due to a $57 million decrease in gross property additions, primarily due to lower spending for environmental compliance and nuclear projects; and a $43 million increase in cash provided by other investing activities primarily due to $27 million of litigation settlement proceeds and the $11 million receipt of NEIL insurance proceeds for repairs at CR3 (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”).

Net cash used by financing activities increased $704 million for the three months ended March 31, 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 $325 million payment of dividends to the Parent in 2011, partially offset by a $212 million change in advances from affiliated companies.

SHORT-TERM DEBT

At March 31, 2011, PEF had outstanding short-term debt consisting of money pool borrowings totaling $7 million at an interest rate of 0.33%. At the end of each month during the three months ended March 31, 2011, PEF had a maximum short-term debt balance of $20 million and an average short-term debt balance of $10 million at a weighted average interest rate of 0.28%. PEF’s short-term debt during the three months ended March 31, 2011, included both money pool and commercial paper borrowings.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

MARKET RISK AND DERIVATIVES

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

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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 10). 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 Item 1A, “Risk Factors,” to the 2010 Form 10-K and “Safe Harbor for Forward-Looking Statements” for a discussion of the factors that may impact any such forward-looking statements made herein.

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

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

PROGRESS ENERGY

Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2010.

INTEREST RATE RISK

Our debt portfolio and our exposure to changes in interest rates at March 31, 2011, have changed from December 31, 2010. The total notional amount of fixed rate long-term debt at March 31, 2011, was $11.329 billion, with an average interest rate of 5.97% and fair market value of $12.4 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 March 31, 2011 and December 31, 2010, the total notional amount and fair market value of our variable rate long-term debt were $861 million. At March 31, 2011, the average interest rate of our variable rate long-term debt was 0.46% 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 March 31, 2011, we had $79 million of outstanding commercial paper and no loans outstanding under our credit facilities. At December 31, 2010, we had no outstanding commercial paper and no loans outstanding under our credit facilities. At March 31, 2011, and December 31, 2010, approximately 8 percent and 7 percent, respectively, of consolidated debt was in floating rate mode.

Based on our variable rate long-term and short-term debt balances at March 31, 2011, a 100 basis point change in interest rates would result in an annual pre-tax interest expense change of approximately $9 million.

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

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

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

In accordance with GAAP, interest rate derivatives that qualify as hedges are separated into one of two categories: cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest rate changes.

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

Cash Flow Hedges (dollars in millions)	Notional Amount		Mandatory Settlement		Pay			Receive (a)	Fair Value			Exposure (b)
Parent
Risk hedged at March 31, 2011
Anticipated 10-year debt issue	$	200		2012		4.20	%	3-month LIBOR	$	(1	)	$	(4	)
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 March 31, 2011
Anticipated 10-year debt issue (c)(d)	$	100		2011		4.31	%	3-month LIBOR	$	(7	)	$	(2	)
Anticipated 10-year debt issue	$	200		2012		4.27	%	3-month LIBOR	$	(1	)	$	(4	)
Anticipated 10-year debt issue	$	50		2013		4.43	%	3-month LIBOR	$	1		$	(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 March 31, 2011
Anticipated 10-year debt issue (e)	$	150		2011		4.18	%	3-month LIBOR	$	(6	)	$	(3	)
Anticipated 10-year debt issue	$	50		2013		4.30	%	3-month LIBOR	$	1		$	(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) rate was 0.30% at both March 31, 2011 and December 31, 2010.

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

(c) Subsequent to March 31, 2011, PEC entered into a $100 million notional forward starting swap with mandatory settlement in 2011 in anticipation of a 10-year debt issuance.

(d) Subsequent to March 31, 2011, PEC settled this $100 million notional forward starting swap.

(e) Subsequent to March 31, 2011, PEF entered into a $75 million notional forward starting swap with mandatory settlement in 2011 in anticipation of a 10-year debt issuance.

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 March 31, 2011 and December 31, 2010, the fair value of these funds was $1.641 billion and $1.571 billion, respectively, including $1.066 billion and $1.017 billion, respectively, for PEC and $575 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

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recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At March 31, 2011 and December 31, 2010, the fair value of CVOs was $15 million. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analyses performed on the CVOs uses quoted prices obtained from brokers or quote services to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. A hypothetical 10 percent increase in the March 31, 2011 market price would result in a $2 million increase in the fair value of the CVOs and a corresponding increase in the CVO liability.

COMMODITY PRICE RISK

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

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. At March 31, 2011, substantially all derivative commodity instrument positions were subject to retail regulatory treatment.

See Note 10 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 carried out an evaluation, with the participation of management, including our Chairman, President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PEC

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

There has been no change in PEC’s internal control over financial reporting during the quarter ended March 31, 2011, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

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

There has been no change in PEF’s internal control over financial reporting during the quarter ended March 31, 2011, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in 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.

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

RESTRICTED STOCK UNIT AWARD PAYOUTS

(a)   Securities Delivered. On January 27, 2011, February 3, 2011, February 8, 2011 and March 29, 2011, 2,576 shares, 559 shares, 1,529 shares and 403 shares, respectively, of our common stock were delivered to certain former employees pursuant to the terms of the Progress Energy 2002 and 2007 Equity Incentive Plans (individually and collectively EIP), which have been approved by Progress Energy’s shareholders. Additionally, on January 3, 2011, February 18, 2011, March 16, 2011, March 17, 2011, March 18, 2011 and March 21, 2011, 5,000 shares, 7,300 shares, 147,700 shares, 171,536 shares, 121,187 shares and 24,637 shares, respectively, of our common stock were delivered to certain current employees pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

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

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

PERFORMANCE SHARE SUB-PLAN AWARD PAYOUTS

(a)   Securities Delivered. On February 23, 2011, 258,896 shares of our common stock were delivered to certain current and former employees pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

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

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

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ISSUER PURCHASES OF EQUITY SECURITIES FOR FIRST 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)
January 1 – January 31		264,843	$	43.9422		N/A		N/A
February 1 – February 28		691,964		45.4279		N/A		N/A
March 1 – March 31		490,219		44.8921		N/A		N/A
Total		1,447,026	$	44.9745		N/A		N/A

(1) At March 31, 2011, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) The plan administrator purchased 609,000 shares of our common stock in open-market transactions to meet share delivery obligations under the 401(k).

(3) The plan administrator purchased 310,826 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 267,303 shares of our common stock in open-market transactions to meet share delivery obligations under the IPP.

(5) Progress Energy withheld 259,897 shares of our common stock during the first quarter of 2011 to pay taxes due upon the payout of certain Restricted Stock awards, Restricted Stock Unit awards and Performance Share Sub-Plan awards pursuant to the terms of the 2002 and 2007 EIP.

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ITEM 6. EXHIBITS

(a)   Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
*2a	Agreement and Plan of Merger, dated as of January 8, 2011, by and among Duke Energy Corporation, Diamond Acquisition Corporation and Progress Energy, Inc. (filed as Exhibit 2.1 to the Current Report on Form 8-K, dated January 8, 2011, File No. 1-15929).	X
*10(a)	Employment Term Sheet for William D. Johnson in connection with the Agreement and Plan of Merger, dated as of January 8, 2011, by and among Duke Energy Corporation, Diamond Acquisition Corporation and Progress Energy, Inc. (Exhibit C to the Agreement and Plan of Merger filed as Exhibit 2.1 to the Current Report on Form 8-K, dated January 8, 2011, File No. 1-15929).	X
*10(b)	Form of Letter Agreement, dated January 8, 2011, executed by certain officers of Progress Energy, Inc., waiving certain rights under Progress Energy, Inc.’s Management Change-in-Control Plan and their employment agreements (filed as Exhibit 10.1 to the Current Report on Form 8-K, dated January 8, 2011, File No. 1-15929).	X
*10(c)	Amendment to the Supplemental Senior Executive Retirement Plan, effective January 8, 2011 (filed as Exhibit 10.1 to the Current Report on Form 8-K, dated March 15, 2011, File No. 1-15929).	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

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32(e)	906 Certifications of Chief Executive Officer		X
32(f)	906 Certifications of Chief Financial Officer		X
101.INS	XBRL Instance Document**	X
101.SCH	XBRL Taxonomy Extension Schema Document	X
101.CAL	XBRL Taxonomy Calculation Linkbase Document	X
101.LAB	XBRL Taxonomy Label Linkbase Document	X
101.PRE	XBRL Taxonomy Presentation Linkbase Document	X

* Incorporated herein by reference as indicated.

** Attached as Exhibit 101 are the following financial statements and notes thereto for Progress Energy from the Quarterly Report on Form 10-Q for the quarter ended March 31, 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.

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

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SIGNATURES

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

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
	FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
Date: May 9, 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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