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 June 30, 2012

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	x	No	o

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

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

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

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

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

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

At August 2, 2012, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	100 (all of which were held directly by Duke Energy Corporation)
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 Comprehensive 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 Comprehensive 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 Comprehensive Income	13
	Unaudited Condensed Balance Sheets	14
	Unaudited Condensed Statements of Cash Flows	15
	Combined Notes to Unaudited Condensed Interim Financial Statements for Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a Progress Energy Florida, Inc.	16
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	72
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	109
ITEM 4.	CONTROLS AND PROCEDURES	112
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	113
ITEM 1A.	RISK FACTORS	113
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	113
ITEM 6.	EXHIBITS	115
SIGNATURES		117

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
2011 Form 10-K	Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2011
401(k)	Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC	Allowance for funds used during construction
Anclote	PEF’s Anclote Units 1 and 2
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, fuel and other pass-through revenues and refunds, if any
Brunswick	PEC’s Brunswick Nuclear Plant
Btu	British thermal unit
CAA	Clean Air Act
CAIR	Clean Air Interstate 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
CFTC	U.S. Commodity Futures Trading Commission
Clean Smokestacks Act	North Carolina Clean Smokestacks Act
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 1 and 2 coal-fired steam turbines
CR3	PEF’s Crystal River Nuclear Plant Unit 3
CR4 and CR5	PEF’s Crystal River Units 4 and 5 coal-fired steam turbines
CSAPR	Cross-State Air Pollution Rule
CVO	Contingent value obligation
D.C. Court of Appeals	U.S. Court of Appeals for the District of Columbia Circuit
DOE	U.S. Department of Energy
DOJ	U.S. Department of Justice
DSM	Demand-side management
Duke Energy	Duke Energy Corporation
Earthco	Four coal-based solid synthetic fuels limited liability companies of which three were wholly owned
ECCR	Energy Conservation Cost Recovery Clause
ECRC	Environmental Cost Recovery Clause

2

EE	Energy efficiency
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
Interim FERC Mitigation	Interim firm power sale agreements during construction of the long-term FERC mitigation
IPP	Progress Energy Investor Plus Plan
JDA	Joint Dispatch Agreement
kWh	Kilowatt-hours
Levy	PEF’s proposed Levy Units No. 1 and No. 2 Nuclear Power Plants
LIBOR	London Inter Bank Offered Rate
Long-term FERC Mitigation	Construction of seven transmission projects to increase power import capabilities into the PEC and Duke Energy Carolinas service territories
MACT	Maximum achievable control technology
MATS	Mercury and Air Toxics Standards
MCF	Master credit facility
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in PART I, Item 2 of this Form 10-Q
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
MW	Megawatts
MWh	Megawatt-hours
Moody’s	Moody’s Investors Service, Inc.
NAAQS	National Ambient Air Quality Standards
NCDOJ	North Carolina Department of Justice
NC Public Staff	Public Staff of the North Carolina Utilities Commission
NC REPS	North Carolina Renewable Energy and Energy Efficiency Portfolio Standard
NCUC	North Carolina Utilities Commission
NDT	Nuclear decommissioning trust
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NO2	Nitrogen dioxide
North Carolina Global Case	Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
NOx	Nitrogen oxides
NRC	Nuclear Regulatory Commission
O&M	Operation and maintenance expense
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income

3

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
ORS	South Carolina Office of Regulatory Staff
OTC	Over-the-counter
the Parent	Progress Energy, Inc. holding company on an unconsolidated basis
PEC	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
PEF	Florida Power Corporation d/b/a Progress Energy Florida, Inc.
PESC	Progress Energy Service Company, LLC
Power Agency	North Carolina Eastern Municipal Power Agency
PPACA	Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act
Preferred Securities	7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee	Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Affiliates	Five affiliated coal-based solid synthetic fuels facilities
Progress Energy	Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants	The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
PRP	Potentially responsible party, as defined in CERCLA
PSCSC	Public Service Commission of South Carolina
PSSP	Performance Share Sub-Plan
QF	Qualifying facility
RCA	Revolving credit agreement
Reagents	Commodities such as ammonia and limestone used in emissions control technologies
REPS	Renewable energy portfolio standard
the Registration Statement	The registration statement filed on Form S-4 by Duke Energy related to the merger
Robinson	PEC’s Robinson Nuclear Plant
ROE	Return on equity
RSU	Restricted stock unit
Section 29	Section 29 of the Code
Section 29/45K	General business tax credits earned after December 31, 2005 for synthetic fuels production in accordance with Section 29
Section 45K	Section 45K of the Code
Section 316(b)	Section 316(b) of the Clean Water Act
(See Note/s “#”)	For all sections, this is a cross-reference to the Combined Notes to the Financial Statements contained in PART I, Item 1 of this Form 10-Q
SERC	SERC Reliability Corporation
S&P	Standard & Poor’s Rating Services
SO2	Sulfur dioxide
SOx	Sulfur oxides
Subordinated Notes	7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement	Intercompany Income Tax Allocation Agreement
the Trust	FPC Capital I
the Utilities	Collectively, PEC and PEF
VIE	Variable interest entity
VSP	Voluntary severance plan
Wall Street Reform Act	Wall Street Reform and Consumer Protection Act
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: “Merger with Duke Energy” about the merger between Progress Energy and Duke Energy Corporation (Duke Energy) 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:

·   the impact of compliance with material restrictions of conditions related to the Duke Energy merger imposed by regulators could exceed our expectations;

·   our ability to successfully integrate our business with Duke Energy and realize cost savings and any other synergies expected from the merger;

·   our ability to maintain relationships with customers, employees or suppliers post-merger;

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

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

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

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

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

·   our 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;

·   our ability to recover in a timely manner, if at all, costs associated with future significant weather events through the regulatory process;

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

5

·   the Progress Registrants’ ability to control costs, including operations and maintenance (O&M) expense and large construction projects;

·   our subsidiaries’ ability to pay upstream dividends or distributions to Progress Energy, Inc. holding company (the Parent);

·   current economic conditions;

·   our 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 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’ most recent annual report on Form 10-K, which was filed with the SEC on February 29, 2012, 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
June 30, 2012
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
	Three months ended June 30						Six months ended June 30
(in millions except per share data)	2012			2011			2012			2011
Operating revenues	$	2,273		$	2,256		$	4,365		$	4,423
Operating expenses
Fuel used in electric generation		736			674			1,421			1,392
Purchased power		257			329			467			549
Operation and maintenance		627			510			1,156			1,004
Depreciation, amortization and accretion		231			179			397			333
Taxes other than on income		142			134			280			274
Other		5			2			5			(8	)
Total operating expenses		1,998			1,828			3,726			3,544
Operating income		275			428			639			879
Other income
Interest income		1			-			2			1
Allowance for equity funds used during construction		25			26			49			55
Other, net		1			7			14			10
Total other income, net		27			33			65			66
Interest charges
Interest charges		203			189			397			388
Allowance for borrowed funds used during construction		(11	)		(9	)		(20	)		(18	)
Total interest charges, net		192			180			377			370
Income from continuing operations before income tax		110			281			327			575
Income tax expense		42			101			118			208
Income from continuing operations		68			180			209			367
Discontinued operations, net of tax		(4	)		(2	)		7			(4	)
Net income		64			178			216			363
Net income attributable to noncontrolling interests, net of tax		(1	)		(2	)		(3	)		(3	)
Net income attributable to controlling interests	$	63		$	176		$	213		$	360
Average common shares outstanding – basic		297			296			297			295
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling   interests, net of tax	$	0.23		$	0.60		$	0.70		$	1.23
Discontinued operations attributable to controlling interests,   net of tax		(0.02	)		-			0.02			(0.01	)
Net income attributable to controlling interests	$	0.21		$	0.60		$	0.72		$	1.22
Dividends declared per common share	$	0.620		$	0.620		$	1.240		$	1.240
Net income amounts attributable to controlling interests
Income from continuing operations, net of tax	$	67		$	178		$	206		$	364
Discontinued operations, net of tax		(4	)		(2	)		7			(4	)
Net income attributable to controlling interests	$	63		$	176		$	213		$	360
Comprehensive income
Comprehensive income	$	60		$	157		$	217		$	346
Comprehensive income attributable to noncontrolling interests,   net of tax		(1	)		(2	)		(3	)		(3	)
Comprehensive income attributable to controlling interests	$	59		$	155		$	214		$	343
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

7

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	June 30, 2012			December 31, 2011
ASSETS
Utility plant
Utility plant in service	$	31,601		$	31,065
Accumulated depreciation		(12,151	)		(12,001	)
Utility plant in service, net		19,450			19,064
Other utility plant, net		272			217
Construction work in progress		2,711			2,449
Nuclear fuel, net of amortization		759			767
Total utility plant, net		23,192			22,497
Current assets
Cash and cash equivalents		73			230
Receivables, net		849			889
Inventory, net		1,427			1,438
Regulatory assets		302			275
Derivative collateral posted		124			147
Deferred tax assets		508			371
Prepayments and other current assets		104			133
Total current assets		3,387			3,483
Deferred debits and other assets
Regulatory assets		2,954			3,025
Nuclear decommissioning trust funds		1,757			1,647
Miscellaneous other property and investments		411			407
Goodwill		3,655			3,655
Other assets and deferred debits		368			345
Total deferred debits and other assets		9,145			9,079
Total assets	$	35,724		$	35,059
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 296   million and 295 million shares issued and outstanding, respectively	$	7,465		$	7,434
Accumulated other comprehensive loss		(164	)		(165	)
Retained earnings		2,596			2,752
Total common stock equity		9,897			10,021
Noncontrolling interests		3			4
Total equity		9,900			10,025
Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		12,739			11,718
Total capitalization		23,005			22,109
Current liabilities
Current portion of long-term debt		925			950
Short-term debt		345			671
Accounts payable		907			909
Interest accrued		197			200
Dividends declared		1			78
Customer deposits		342			340
Derivative liabilities		326			436
Accrued compensation and other benefits		168			195
Other current liabilities		359			306
Total current liabilities		3,570			4,085
Deferred credits and other liabilities
Noncurrent income tax liabilities		2,670			2,355
Accumulated deferred investment tax credits		99			103
Regulatory liabilities		2,612			2,700
Asset retirement obligations		1,299			1,265
Accrued pension and other benefits		1,656			1,625
Capital lease obligations		310			200
Derivative liabilities		300			352
Other liabilities and deferred credits		203			265
Total deferred credits and other liabilities		9,149			8,865
Commitments and contingencies (Notes 13 and 14)
Total capitalization and liabilities	$	35,724		$	35,059
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)
Six months ended June 30	2012			2011
Operating activities
Net income	$	216		$	363
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		481			425
Deferred income taxes and investment tax credits, net		169			178
Deferred fuel credit		(79	)		(29	)
Allowance for equity funds used during construction		(49	)		(55	)
Other adjustments to net income		39			167
Cash (used) provided by changes in operating assets and liabilities
Receivables		(9	)		(5	)
Inventory		8			(127	)
Other assets		14			16
Income taxes, net		1			56
Accounts payable		70			1
Accrued pension and other benefits		(74	)		(259	)
Other liabilities		(36	)		49
Net cash provided by operating activities		751			780
Investing activities
Gross property additions		(1,080	)		(1,004	)
Nuclear fuel additions		(65	)		(93	)
Purchases of available-for-sale securities and other investments		(625	)		(3,387	)
Proceeds from available-for-sale securities and other investments		610			3,364
Other investing activities		81			82
Net cash used by investing activities		(1,079	)		(1,038	)
Financing activities
Issuance of common stock, net		6			26
Dividends paid on common stock		(446	)		(366	)
Payments of short-term debt with original maturities greater than 90 days		(65	)		-
Proceeds from issuance of short-term debt with original maturities greater than 90 days		65			-
Net (decrease) increase in short-term debt		(326	)		314
Proceeds from issuance of long-term debt, net		1,432			494
Retirement of long-term debt		(450	)		(700	)
Other financing activities		(45	)		(69	)
Net cash provided (used) by financing activities		171			(301	)
Net decrease in cash and cash equivalents		(157	)		(559	)
Cash and cash equivalents at beginning of period		230			611
Cash and cash equivalents at end of period	$	73		$	52
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	237		$	256
Capital expenditures financed through capital leases		116			-
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
June 30, 2012
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
	Three months ended June 30						Six months ended June 30
(in millions)	2012			2011			2012			2011
Operating revenues	$	1,082		$	1,060		$	2,167		$	2,193
Operating expenses
Fuel used in electric generation		346			326			695			689
Purchased power		80			73			145			140
Operation and maintenance		386			293			760			588
Depreciation, amortization and accretion		134			126			268			250
Taxes other than on income		52			50			108			106
Other		3			-			2			-
Total operating expenses		1,001			868			1,978			1,773
Operating income		81			192			189			420
Other income (expense)
Interest income		-			1			-			1
Allowance for equity funds used during construction		17			18			32			38
Other, net		1			1			5			(1	)
Total other income, net		18			20			37			38
Interest charges
Interest charges		59			54			115			104
Allowance for borrowed funds used during construction		(6	)		(6	)		(11	)		(11	)
Total interest charges, net		53			48			104			93
Income before income tax		46			164			122			365
Income tax expense		15			57			39			127
Net income		31			107			83			238
Preferred stock dividend requirement		-			-			(1	)		(1	)
Net income available to parent	$	31		$	107		$	82		$	237
Comprehensive income	$	25		$	102		$	82		$	235
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 BALANCE SHEETS
(in millions)	June 30, 2012			December 31, 2011
ASSETS
Utility plant
Utility plant in service	$	17,857		$	17,439
Accumulated depreciation		(7,606	)		(7,567	)
Utility plant in service, net		10,251			9,872
Other utility plant, net		230			181
Construction work in progress		1,403			1,294
Nuclear fuel, net of amortization		513			540
Total utility plant, net		12,397			11,887
Current assets
Cash and cash equivalents		21			20
Receivables, net		459			492
Receivables from affiliated companies		12			13
Notes receivable from affiliated companies		229			-
Inventory, net		774			775
Deferred fuel cost		36			31
Derivative collateral posted		21			24
Deferred tax assets		144			142
Prepayments and other current assets		69			52
Total current assets		1,765			1,549
Deferred debits and other assets
Regulatory assets		1,356			1,310
Nuclear decommissioning trust funds		1,164			1,088
Miscellaneous other property and investments		185			188
Other assets and deferred debits		90			80
Total deferred debits and other assets		2,795			2,666
Total assets	$	16,957		$	16,102
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 200 million shares authorized, 160   million shares issued and outstanding	$	2,159		$	2,148
Accumulated other comprehensive loss		(72	)		(71	)
Retained earnings		2,780			3,011
Total common stock equity		4,867			5,088
Preferred stock		59			59
Long-term debt, net		4,690			3,693
Total capitalization		9,616			8,840
Current liabilities
Current portion of long-term debt		500			500
Short-term debt		-			188
Notes payable to affiliated companies		-			31
Accounts payable		472			527
Payables to affiliated companies		68			41
Interest accrued		82			77
Customer deposits		120			116
Derivative liabilities		89			130
Accrued compensation and other benefits		99			110
Other current liabilities		156			85
Total current liabilities		1,586			1,805
Deferred credits and other liabilities
Noncurrent income tax liabilities		2,084			1,976
Accumulated deferred investment tax credits		96			98
Regulatory liabilities		1,622			1,543
Asset retirement obligations		921			896
Accrued pension and other benefits		721			687
Capital lease obligations		125			11
Other liabilities and deferred credits		186			246
Total deferred credits and other liabilities		5,755			5,457
Commitments and contingencies (Notes 13 and 14)
Total capitalization and liabilities	$	16,957		$	16,102
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)
Six months ended June 30	2012			2011
Operating activities
Net income	$	83		$	238
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		330			322
Deferred income taxes and investment tax credits, net		95			119
Deferred fuel (credit) cost		(3	)		10
Allowance for equity funds used during construction		(32	)		(38	)
Other adjustments to net income		42			45
Cash (used) provided by changes in operating assets and liabilities
Receivables		(10	)		52
Receivables from affiliated companies		1			17
Inventory		1			(121	)
Other assets		(2	)		(8	)
Income taxes, net		(45	)		78
Accounts payable		12			(30	)
Payables to affiliated companies		27			(28	)
Accrued pension and other benefits		(35	)		(164	)
Other liabilities		(14	)		44
Net cash provided by operating activities		450			536
Investing activities
Gross property additions		(683	)		(579	)
Nuclear fuel additions		(50	)		(80	)
Purchases of available-for-sale securities and other investments		(271	)		(286	)
Proceeds from available-for-sale securities and other investments		256			262
Changes in advances to affiliated companies		(229	)		2
Other investing activities		69			9
Net cash used by investing activities		(908	)		(672	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		(310	)		(275	)
Net (decrease) increase in short-term debt		(188	)		198
Proceeds from issuance of long-term debt, net		988			-
Changes in advances from affiliated companies		(31	)		3
Other financing activities		1			(1	)
Net cash provided (used) by financing activities		459			(76	)
Net increase (decrease) in cash and cash equivalents		1			(212	)
Cash and cash equivalents at beginning of period		20			230
Cash and cash equivalents at end of period	$	21		$	18
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	150		$	181
Capital expenditures financed through capital leases		116			-
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
June 30, 2012
UNAUDITED CONDENSED STATEMENTS of COMPREHENSIVE INCOME
	Three months ended June 30						Six months ended June 30
(in millions)	2012			2011			2012			2011
Operating revenues	$	1,189		$	1,193		$	2,194		$	2,225
Operating expenses
Fuel used in electric generation		390			348			726			703
Purchased power		177			256			322			409
Operation and maintenance		246			224			406			434
Depreciation, amortization and accretion		92			48			119			73
Taxes other than on income		90			83			172			168
Other		(2	)		-			(2	)		(12	)
Total operating expenses		993			959			1,743			1,775
Operating income		196			234			451			450
Other income
Interest income		1			-			1			-
Allowance for equity funds used during construction		8			8			17			17
Other, net		-			1			-			4
Total other income, net		9			9			18			21
Interest charges
Interest charges		74			68			141			137
Allowance for borrowed funds used during construction		(5	)		(3	)		(9	)		(7	)
Total interest charges, net		69			65			132			130
Income before income tax		136			178			337			341
Income tax expense		53			65			126			126
Net income		83			113			211			215
Preferred stock dividend requirement		-			-			(1	)		(1	)
Net income available to parent	$	83		$	113		$	210		$	214
Comprehensive income	$	82		$	108		$	211		$	210
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)	June 30, 2012			December 31, 2011
ASSETS
Utility plant
Utility plant in service	$	13,579		$	13,461
Accumulated depreciation		(4,465	)		(4,356	)
Utility plant in service, net		9,114			9,105
Held for future use		42			36
Construction work in progress		1,308			1,155
Nuclear fuel, net of amortization		246			227
Total utility plant, net		10,710			10,523
Current assets
Cash and cash equivalents		19			16
Receivables, net		372			372
Receivables from affiliated companies		25			19
Inventory, net		654			663
Regulatory assets		266			244
Derivative collateral posted		103			123
Deferred tax assets		231			138
Prepayments and other current assets		20			39
Total current assets		1,690			1,614
Deferred debits and other assets
Regulatory assets		1,481			1,602
Nuclear decommissioning trust funds		593			559
Other assets and deferred debits		183			186
Total deferred debits and other assets		2,257			2,347
Total assets	$	14,657		$	14,484
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 60 million shares authorized,   100 shares issued and outstanding	$	1,762		$	1,757
Accumulated other comprehensive loss		(27	)		(27	)
Retained earnings		2,983			2,945
Total common stock equity		4,718			4,675
Preferred stock		34			34
Long-term debt, net		4,057			4,482
Total capitalization		8,809			9,191
Current liabilities
Current portion of long-term debt		425			-
Short-term debt		144			233
Notes payable to affiliated companies		243			8
Accounts payable		398			358
Payables to affiliated companies		39			25
Interest accrued		47			54
Customer deposits		222			224
Derivative liabilities		237			268
Accrued compensation and other benefits		43			53
Other current liabilities		158			112
Total current liabilities		1,956			1,335
Deferred credits and other liabilities
Noncurrent income tax liabilities		1,569			1,405
Regulatory liabilities		905			1,071
Asset retirement obligations		378			369
Accrued pension and other benefits		578			598
Capital lease obligations		185			189
Derivative liabilities		190			231
Other liabilities and deferred credits		87			95
Total deferred credits and other liabilities		3,892			3,958
Commitments and contingencies (Notes 13 and 14)
Total capitalization and liabilities	$	14,657		$	14,484
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)
Six months ended June 30	2012			2011
Operating activities
Net income	$	211		$	215
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		135			84
Deferred income taxes and investment tax credits, net		74			115
Deferred fuel credit		(76	)		(39	)
Allowance for equity funds used during construction		(17	)		(17	)
Other adjustments to net income		(16	)		105
Cash (used) provided by changes in operating assets and liabilities
Receivables		(10	)		(50	)
Receivables from affiliated companies		(6	)		(7	)
Inventory		6			(8	)
Other assets		19			31
Income taxes, net		31			73
Accounts payable		45			31
Payables to affiliated companies		14			(16	)
Accrued pension and other benefits		(34	)		(89	)
Other liabilities		24			39
Net cash provided by operating activities		400			467
Investing activities
Gross property additions		(380	)		(419	)
Nuclear fuel additions		(15	)		(13	)
Purchases of available-for-sale securities and other investments		(353	)		(3,091	)
Proceeds from available-for-sale securities and other investments		353			3,092
Other investing activities		25			73
Net cash used by investing activities		(370	)		(358	)
Financing activities
Dividends paid on preferred stock		(1	)		(1	)
Dividends paid to parent		(170	)		(400	)
Payments of short-term debt with original maturities greater than 90 days		(65	)		-
Proceeds from issuance of short-term debt with original maturities greater than 90 days		65			-
Net (decrease) increase in short-term debt		(89	)		67
Changes in advances from affiliated companies		235			(3	)
Other financing activities		(2	)		(3	)
Net cash used by financing activities		(27	)		(340	)
Net increase (decrease) in cash and cash equivalents		3			(231	)
Cash and cash equivalents at beginning of period		16			249
Cash and cash equivalents at end of period	$	19		$	18
Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	83		$	73
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 3, 5 through 11, 13 and 14
PEF	1 through 3, 5 through 11, 13 and 14

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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 collectively to 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). On July 2, 2012, Progress Energy, Inc. consummated the merger with Duke Energy Corporation (Duke Energy), and became, and will continue as, a direct wholly owned subsidiary of Duke Energy. The total consideration transferred in the merger, based on the closing price of Duke Energy common shares on July 2, 2012, was estimated at $18 billion. The merger is being recorded using the acquisition method of accounting. In accordance with SEC regulations, the Progress Registrants will not reflect the impacts of acquisition accounting in their financial statements based on the significance of the Progress Registrants’ outstanding public debt securities. These adjustments will be recorded by Duke Energy. See Note 2 for additional information regarding the merger.

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 12 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (PSCSC), 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, 2011 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

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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, 2011 (2011 Form 10-K).

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 2011 have been reclassified to conform to the 2012 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 Comprehensive Income were as follows:

	Three months ended June 30				Six months ended June 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	77	$	76	$	146	$	149
PEC		26		25		52		53
PEF		51		51		94		96

C. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE’s variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the primary beneficiary of and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary during 2011 or for the six months ended June 30, 2012. No financial or other support has been provided to the VIE during the periods presented.

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

(in millions)	June 30, 2012		December 31, 2011
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		2		1

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 an $8 million mandatory fixed price purchase offer for one of the buildings. The mandatory purchase offer was made in June 2012, and the counterparty has until May 14, 2013 to notify us as to whether the offer is accepted or rejected. Total lease payments to these counterparties under the lease agreements were $1 million for each of the three and six months ended June 30, 2012 and 2011, respectively. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

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

PEF

PEF has no significant variable interests in VIEs.

2. MERGER WITH DUKE ENERGY

On July 2, 2012, Progress Energy consummated the merger with Duke Energy, and became, and will continue as, a direct wholly owned subsidiary of Duke Energy. Under the terms of the merger agreement, each share of Progress Energy common stock was converted into 0.87083 shares of Duke Energy common stock as adjusted for the one-for-three reverse stock split of Duke Energy stock, effected in conjunction with, and immediately prior to, the merger. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock was converted into an option to acquire, or an equity award relating to, 0.87083 shares of Duke Energy common stock. The terms and vesting periods of outstanding options and equity awards were not changed as a result of the merger.

As a result of the merger, Progress Energy has 100 authorized, issued and outstanding shares of common stock, all of which are held by Duke Energy.

MERGER-RELATED REGULATORY MATTERS

Federal Energy Regulatory Commission

On June 8, 2012, the FERC conditionally approved the merger including Duke Energy and Progress Energy’s revised market power mitigation plan, the Joint Dispatch Agreement (JDA) and the joint Open Access Transmission Tariff (OATT). The revised market power mitigation plan provides for the construction of seven transmission projects (Long-term FERC Mitigation) and interim firm power sale agreements during the construction of the transmission projects (Interim FERC Mitigation). The Long-term FERC Mitigation is estimated to cost approximately $110 million. The Long-term FERC Mitigation plan will increase power imported into the Duke Energy Carolinas and PEC service areas and enhance competitive power supply options in the service areas. The

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construction of these projects will occur over the next two to three years. In conjunction with the Interim FERC Mitigation plan, Duke Energy Carolinas and PEC entered into power sale agreements that were effective with the consummation of the merger. These agreements, or similar power sale agreements, will be in place until the Long-term FERC Mitigation is operational. The agreements are for around-the-clock delivery of power during the winter and summer in quantities that vary by season and by peak period. The following table summarizes the amount of megawatts (MW) per hour contracted to be sold under the Interim FERC Mitigation agreements.

MW per hour	Duke Energy Carolinas		PEC		Duke Energy
Summer off-peak		300		500		800
Summer on-peak		150		325		475
Winter off-peak		225		-		225
Winter on-peak		25		-		25

The FERC order requires an independent party to monitor whether the power sale agreements remain in effect during construction of the transmission projects and provide quarterly reports to the FERC regarding the status of construction of the transmission projects.

·   On June 25, 2012, Duke Energy and Progress Energy accepted the conditions imposed by the FERC.

·   On July 10, 2012, certain intervenors requested a rehearing seeking to overturn the June 8, 2012 order by the FERC.

North Carolina Utilities Commission and Public Service Commission of South Carolina

In September 2011, Duke Energy and Progress Energy reached settlements with the Public Staff of the North Carolina Utilities Commission (NC Public Staff) and the South Carolina Office of Regulatory Staff (ORS) and certain other interested parties in connection with the regulatory proceedings related to the merger, the JDA and the OATT that were pending before the NCUC and PSCSC. These settlements were updated in May 2012 to reflect the results of ongoing merger related applications pending before the FERC. As part of these settlements and the application for approval of the merger by the NCUC and PSCSC, Duke Energy Carolinas and PEC agreed to the conditions and obligations listed below:

·   Guarantee of $650 million in system fuel and fuel-related savings over 60 to 78 months for North Carolina and South Carolina retail customers. The savings are expected to be achieved through coal blending, coal commodity and transportation savings, gas transportation savings and the joint dispatch of Duke Energy Carolinas and PEC generation fleets.

·   Duke Energy Carolinas and PEC will not seek recovery from retail customers for the cost of the Long-term FERC Mitigation for five years following merger consummation. After five years, Duke Energy Carolinas and PEC may seek to recover the costs of the Long-term FERC Mitigation, but must show that the projects are needed to provide adequate and reliable retail service regardless of the merger.

·   A $65 million rate reduction over the term of the Interim FERC Mitigation to reflect the cost of capacity not available to Duke Energy Carolinas and PEC retail customers during the Interim FERC Mitigation. The rate reduction will be achieved through a rider and will be apportioned between Duke Energy Carolinas and PEC retail customers.

·   Duke Energy Carolinas and PEC will not seek recovery from retail customers for any revenue shortfalls or fuel-related costs associated with the Interim FERC Mitigation. The Interim FERC Mitigation agreements were in a loss position for Progress Energy and Duke Energy as of the date of the merger consummation.

·   Duke Energy Carolinas and PEC will not seek recovery from retail customers for any of their allocable share of merger-related severance costs.

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·   Duke Energy Carolinas and PEC will provide community support through charitable contributions for four years, workforce development, low income energy assistance and green energy assistance at a total cost of approximately $100 million, which cannot be recovered from retail customers.

·   Duke Energy Carolinas and PEC will abide by revised North Carolina Regulatory Conditions and Code of Conduct governing their operations.

On June 29, 2012, the NCUC approved the merger application and the JDA application with conditions that were reflective of the settlement agreements described above. On July 2, 2012, the PSCSC approved the JDA application subject to Duke Energy Carolinas and PEC providing their South Carolina retail customers pro rata benefits equivalent to those approved by the NCUC in its merger approval order.

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings on the Duke Energy board of directors’ decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and CEO of Duke Energy subsequent to the merger close, as well as other related matters. See “Other Matters” for discussion of the investigation.

ACCOUNTING CHARGES TO BE RECOGNIZED

Duke Energy anticipates recording charges of approximately $450 million to $550 million in the second half of 2012 associated with the merger. This estimate includes the costs of the Long-term FERC Mitigation plan, Interim FERC Mitigation, the retail rate reduction associated with the Interim FERC Mitigation, employee severance as discussed below, obligations to provide community support and merger transaction expenses. The actual allocation of these charges to individual subsidiaries will be determined in the third quarter. The majority of these charges will be recognized by Duke Energy Carolinas and PEC.

We also expect to incur significant system integration and other merger-related transition costs primarily through 2014 that are necessary in order to achieve certain cost savings, efficiencies and other benefits anticipated to result from the merger with Duke Energy.

In conjunction with the merger, in November 2011, Duke Energy and Progress Energy offered a voluntary severance plan to certain eligible employees. Approximately 1,100 employees of the combined company accepted the termination benefits during the voluntary window period, which closed on November 30, 2011. The estimated amount of severance payments associated with this voluntary plan and other severance benefits are expected to range between $225 million and $275 million. A significant majority of the severance benefits will be recognized as expense in the second half of 2012 and the majority of the costs will be charged to Duke Energy Carolinas, PEC and PEF.

In connection with the merger, we established an employee retention plan for certain eligible employees. Payments under the plan were contingent upon the consummation of the merger and the employees’ continued employment through a specified time period following the merger. We estimate these payments will total $14 million, which will be recorded as merger and integration-related costs in the third quarter of 2012.

In 2011, we evaluated our business needs for office space after the merger and formulated an exit plan to vacate one of our corporate headquarters buildings. We have begun to gradually vacate the premises and will be fully vacated by January 1, 2013. In December 2011, we executed an agreement with a third party to sublease the building until 2035. The estimated exit cost liability associated with this exit plan is $17 million for us, of which $9 million of expense will be attributable to PEC, $4 million to PEF and $4 million to other Duke Energy subsidiaries. The exit cost liability is being recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. The costs of the exit plan are included in merger and integration-related costs.

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The following table presents a reconciliation of the beginning and ending exit cost liability balance:

(in millions)
Balance, December 31, 2011	$	5
Additional exit cost recognized		3
Balance, March 31, 2012		8
Additional exit cost recognized(a)		2
Balance, June 30, 2012(b)	$	10

(a)	PEC and PEF recognized exit costs of $1 million each for the three months ended June 30, 2012, and $3 million and $2 million, respectively, for the six months ended June 30, 2012.
(b)	Expense related to the recognition of the cumulative exit cost liability at June 30, 2012, was attributed to PEC and PEF totaling $7 million and $3 million, respectively.

The following table summarizes after-tax merger and integration-related costs, which are included on our Statements of Comprehensive Income:

	Three months ended June 30				Six months ended June 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	13	$	7	$	18	$	21
PEC		7		4		11		11
PEF		6		3		7		10

OTHER MATTERS

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings addressing the timing of the Duke Energy board of directors’ decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and Chief Executive Officer (CEO) of the new Duke Energy, as well as other matters.

Pursuant to the merger agreement, William D. Johnson, Chairman, President and CEO of Progress Energy became President and CEO of Duke Energy and James E. Rogers, Chairman, President and CEO of Duke Energy became Executive Chairman of Duke Energy upon close of the merger. Mr. Johnson subsequently resigned as the President and CEO of Duke Energy, effective July 3, 2012.

Pursuant to the NCUC’s July 6, 2012 order, Mr. Rogers appeared before the NCUC on July 10, 2012, and provided testimony regarding the approval and closing of the merger and his replacement of Mr. Johnson as the President and CEO of Duke Energy. On July 19, 2012, Mr. Johnson, as well as E. Marie McKee and James B. Hyler, Jr., both former members of the Progress Energy board of directors and current members of the post-merger Duke Energy board of directors, appeared before the NCUC. Ann M. Gray and Michael G. Browning, both members of the pre-merger and post-merger Duke Energy board of directors, appeared before the NCUC on July 20, 2012. All provided testimony on the timing of the decision to replace Mr. Johnson with Mr. Rogers, as well as other related matters.

The NCUC’s order also requests that Duke Energy provide certain documents related to the issue for its review. Duke Energy also received an Investigative Demand issued by the North Carolina Department of Justice (NCDOJ) on July 6, 2012, requesting the production of certain documents related to the issues which are also the subject of the NCUC Investigation. Duke Energy’s responses to these requests were submitted on August 7, 2012. Duke Energy is unable to predict the ultimate outcome of these proceedings.

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3. NEW ACCOUNTING STANDARDS

FAIR VALUE MEASUREMENT AND DISCLOSURES

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends Accounting Standards Codification (ASC) 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 was effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 resulted in additional disclosure in the notes to the financial statements but did not have an impact on our or the Utilities’ financial position, results of operations, or cash flows.

GOODWILL IMPAIRMENT TESTING

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it were determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 was effective for us on January 1, 2012 for both prospective interim and annual goodwill tests and will give us the option to perform the qualitative assessment to determine the need for a

two-step goodwill impairment test. The prospective impact of the adoption is not expected to be significant to our or the Utilities’ financial position, results of operations, or cash flows.

DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES

In December 2011, the FASB issued ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” which requires new disclosures to help financial statement users better understand the impact of offsetting arrangements on our balance sheet. The adoption of ASU 2011-11 will add disclosures showing both gross and net information about instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. ASU 2011-11 is effective for us on January 1, 2013, and will be retroactively applied.

4. DIVESTITURES

Included in discontinued operations, net of tax are amounts related to adjustments of our prior sales of diversified businesses. These adjustments are generally due to guarantees and indemnifications provided for certain legal, tax and environmental matters. See Note 14B for further discussion of our guarantees. The ultimate resolution of these matters could result in additional adjustments in future periods.

During the three months ended June 30, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $(4) million and $(2) million, respectively. During the six months ended June 30, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $7 million and $(4) million, respectively. Earnings for the six months ended June 30, 2012, relates primarily to an $18 million pre-tax gain from the reversal of certain environmental indemnification liabilities for which the indemnification period expired in the first quarter of 2012.

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5. REGULATORY MATTERS

On July 2, 2012, Progress Energy and Duke Energy consummated the previously announced merger. See Note 2 for regulatory information related to the merger with Duke Energy.

A. PEC RETAIL RATE MATTERS

COST-RECOVERY FILINGS

On June 4, 2012, PEC filed with the NCUC for a $40 million decrease in the fuel rate charged to its North Carolina retail ratepayers, driven by declining natural gas prices. If approved, the decrease will be effective December 1, 2012, and will decrease residential electric bills by $1.31 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. On June 4, 2012, PEC also filed for a $16 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate charged to its North Carolina retail ratepayers which, if approved, will be effective December 1, 2012, and will increase the residential electric bills by $0.70 per 1,000 kWh for DSM and EE cost recovery. The net impact of the filings results in an average decrease in residential electric bills of 0.6 percent. We cannot predict the outcome of these matters.

On June 27, 2012, the PSCSC approved a $23 million decrease in the fuel rate charged to PEC’s South Carolina ratepayers, driven by declining natural gas prices. The decrease was effective July 1, 2012, and decreased residential electric bills by $3.65 per 1,000 kWh. On May 23, 2012, the PSCSC approved a $5 million increase in the DSM and EE rate. The increase was effective July 1, 2012, and increased residential electric bills by $1.37 per 1,000 kWh. The net impact of the two filings resulted in an average decrease in residential electric bills of 2.3 percent.

OTHER MATTERS

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

On July 27, 2012, PEC announced accelerated plans to retire the 316-MW Cape Fear coal-fired generating units, originally planned to be retired in 2013, and to retire the 177-MW H.B. Robinson Unit 1 coal-fired generating unit. These units will be retired on October 1, 2012. The Robinson retirement combined with the previously announced retirements total more than 1,600 MW at five sites in the Carolinas.

The net carrying value of the remaining facilities at June 30, 2012, of $212 million is included in other utility plant, net on the Consolidated Balance Sheets. PEC expects to continue to include the five facilities' remaining net carrying value in rate base after retirement. 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 PSCSC until the earlier of the plant’s retirement or PEC’s completion and filing of a new depreciation study on or before March 31, 2013. The final recovery periods may change in connection with the regulators’ determination of the recovery of the remaining net carrying value.

B. PEF RETAIL RATE MATTERS

CR3 OUTAGE

In September 2009, Crystal River Nuclear Plant Unit 3 (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit’s steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options.

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Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur during the repair process.

PEF is analyzing the various aspects of the repair option as well as the option of early retirement. A number of factors could affect the decision to repair, the return-to-service date and repair costs incurred, including, but not limited to, state regulatory and NRC reviews, insurance recoveries from Nuclear Electric Insurance Limited (NEIL), the ability to obtain builder’s risk insurance with appropriate coverage, final engineering designs, vendor contract negotiations, the ultimate work scope completion, performance testing, weather and the impact of new information discovered during additional testing and analysis.

Based on an analysis of possible repair options performed by outside engineering consultants, PEF selected an option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The preliminary estimate of $900 million to $1.3 billion is currently under review and could change following completion of further detailed engineering studies, vendor negotiations and final risk assessments. These engineering studies and risk assessments include analyses by independent entities currently in progress. The risk assessment process includes analysis of events that, although currently deemed unlikely, could have a significant impact on the cost estimate or feasibility of repair. The cost range of the repair option, based on preliminary analysis, appears to be trending upward. PEF will update the current estimate as this effort is completed.

PEF has worked with two potential vendors for repair work and has received repair proposals from both vendors. After analyzing those proposals, PEF has selected a single vendor that PEF would engage to complete the repair of CR3 should the choice to repair CR3 be made. As a result of this selection, PEF recognized an $18 million expense for previously deferred costs associated with the non-selected vendor. These costs are included in O&M expense on our Statements of Comprehensive Income. See “2012 Settlement Agreement” for discussion of CR3 cost recovery and other provisions.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power when the unit is out of service as a result of these events. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through June 30, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. 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. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL has unresolved concerns and has not made any payments on the second delamination and has not provided a written coverage decision for either delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, we have agreed to mediation prior to commencing any formal dispute resolution. We are in the process of providing information as requested by NEIL and currently have scheduled the mediation to commence in fourth quarter of 2012. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, as of June 30, 2012, PEF has not recorded insurance receivables from NEIL related to either the first or second delamination. PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

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The following table summarizes the CR3 replacement power and repair costs and recovery through June 30, 2012:

(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	534		$	305
NEIL proceeds received to date		(162	)		(143	)
Balance for recovery(a)	$	372		$	162

(a) See "2012 Settlement Agreement" below for discussion of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

PEF believes the actions taken and costs incurred in response to the CR3 delaminations 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. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

2012 SETTLEMENT AGREEMENT

On February 22, 2012, the FPSC approved a comprehensive settlement agreement among PEF, the Florida Office of Public Counsel and other consumer advocates. The 2012 settlement agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: PEF’s proposed Levy Nuclear Power Plant (Levy) Nuclear Project cost recovery, the CR3 delamination prudence review then pending before the FPSC, and certain base rate issues. When all of the settlement provisions are factored in, the total increase in 2013 for residential customer bills will be approximately $4.93 per 1,000 kWh, or 4 percent.

Levy

Under the terms of the 2012 settlement agreement, PEF will set the residential cost-recovery factor of PEF’s proposed two units at Levy (see “Nuclear Cost Recovery – Levy Nuclear”) at $3.45 per 1,000 kWh effective in the first billing cycle of January 2013 and continuing for a five-year period. PEF will not recover any additional Levy costs from customers through the term of the agreement, or file for any additional recovery before March 1, 2017, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the combined license (COL) and any engineering, procurement and construction (EPC) cancellation costs, if PEF ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose PEF continuing to pursue a COL for Levy. After the five-year period, PEF will true up any actual costs not recovered under the Levy cost-recovery factor.

The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy (approximately $60 million) as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. PEF will have the discretion to accelerate and/or suspend such amortization in full or in part provided that PEF amortizes all of the regulatory asset by December 31, 2016.

CR3

Under the terms of the 2012 settlement agreement, PEF will be permitted to recover prudently incurred fuel and purchased power costs through the fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the return of CR3 to commercial service or December 31, 2016. If PEF does not begin repairs of CR3 prior to the end of 2012, PEF will refund replacement power costs on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. If PEF decides to retire and decommission CR3, PEF will refund $100 million of replacement power costs. However, in the event that repair activities continue beyond December 31, 2016, the parties are not prohibited from contesting PEF’s right to recover replacement power costs incurred after 2016. The parties to the agreement maintain the right to challenge the prudence and reasonableness of PEF’s fuel acquisition and power purchases, and other fuel prudence issues unrelated to the CR3 outage. All prudence issues from the steam generator project inception through the date of settlement approval by the FPSC are resolved.

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To the extent that PEF pursues the repair of CR3, PEF will establish an estimated cost and repair schedule with ongoing consultation with the parties to the agreement. The established cost, to be approved by our board of directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between our shareholders and PEF customers up to $400 million. The parties to the agreement agree to discuss the method of recovery of any overruns in excess of $400 million, with final decision by the FPSC if resolution cannot be reached. If the repairs begin prior to the end of 2012, the parties to the agreement waive their rights to challenge PEF’s decision to repair and the repair plan chosen by PEF. In addition, there will be limited rights to challenge recovery of the repair execution costs incurred prior to the final resolution on NEIL coverage. The parties to the agreement will discuss the treatment of any potential gap between NEIL repair coverage and the estimated cost, with final decision by the FPSC if resolution cannot be reached. If the repairs do not begin prior to the end of 2012, the parties to the agreement reserve the right to challenge the prudence of PEF’s repair decision, plan and implementation. Efforts to resolve insurance coverage with NEIL could continue past December 31, 2012.

PEF also retains sole discretion and flexibility to retire the unit without challenge from the parties to the agreement. If PEF decides to retire CR3, PEF is allowed to recover all remaining CR3 investments and to earn a return on the CR3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity (ROE) set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. The wholesale portion of CR3 investments, which are not covered by the 2012 settlement agreement, totals approximately $130 million as of June 30, 2012. The recoverability of the wholesale portion of CR3 will continue to be evaluated as decisions are made regarding repair or retirement. Recovery of the wholesale portion of CR3 under the retirement option is at risk based on prior treatment of early retired plants in wholesale rates. Any NEIL proceeds received after the settlement will be applied first to replacement power costs incurred after December 31, 2012, with the remainder used to write down the remaining CR3 investments.

Base Rates, Customer Refund and Other Terms

Under the terms of the 2012 settlement agreement, PEF will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million annual increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5 percent. PEF suspended depreciation expense and reversed certain regulatory liabilities associated with CR3 effective on the February 22, 2012 implementation date of the agreement, resulting in no adjustment for the three months ended June 30, 2012, and a $47 million benefit for the six months ended June 30, 2012, which reduced O&M expense. Additionally, costs associated with CR3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. PEF will accrue, for future rate-setting purposes, a carrying charge at a rate of 7.4 percent on the CR3 investment until CR3 is returned to service and placed back into retail rate base. Upon return of CR3 to commercial service, PEF will be authorized to increase its base rates for the annual revenue requirements of all CR3 investments. In the month following CR3’s return to commercial service, PEF’s ROE range will increase to between 9.7 percent and 11.7 percent. If PEF’s retail base rate earnings fall below the ROE range, as reported on a FPSC-adjusted or pro-forma basis on a PEF monthly earnings surveillance report, PEF may petition the FPSC to amend its base rates during the term of the agreement.

Under the terms of the 2012 settlement agreement, PEF will refund $288 million to customers through the fuel clause. PEF will refund $129 million in each of 2013 and 2014, and an additional $10 million annually to residential and small commercial customers in 2014, 2015 and 2016. At December 31, 2011, a regulatory liability was established for the $288 million to be refunded in future periods. The corresponding charge was recorded as a reduction of 2011 revenues.

The cost of pollution control equipment that PEF installed and has in-service at Crystal River Units 4 and 5 (CR4 and CR5) to comply with the Federal Clean Air Interstate Rule (CAIR) is currently recovered under the Environmental Cost Recovery Clause (ECRC). The 2012 settlement agreement provides for PEF to remove those assets from recovery in the ECRC and transfer those assets to base rates effective with the first billing cycle of January 2014. The related base rate increase will be in addition to the $150 million base rate increase effective January 2013. O&M expense associated with those assets will not be included in the base rates and will continue to be recovered through the ECRC.

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The 2012 settlement agreement provides for PEF to continue to recover carrying costs and other nuclear cost recovery clause-recoverable items related to the CR3 uprate project, but PEF will not seek an in-service recovery until nine months following CR3’s return to commercial service. Carrying costs will be recovered through the nuclear cost recovery clause until base rates have been increased for these assets.

The 2012 settlement agreement also allows PEF to continue to reduce amortization expense (cost of removal component) beyond the expiration of the 2010 settlement agreement through the term of the 2012 settlement agreement (see “Cost of Removal Reserve”). Additionally, the 2012 settlement agreement extends PEF’s ability to expedite recovery of the cost of named storms and to maintain a storm reserve at its level as of the implementation date of the agreement, and removed the maximum allowed monthly surcharge established by the 2010 settlement agreement.

COST OF REMOVAL RESERVE

The 2012 and 2010 settlement agreements provide PEF the discretion to reduce amortization expense (cost of removal component) by up to the balance in the cost of removal reserve until the earlier of (a) PEF’s applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 settlement agreement at the end of 2016. PEF may not reduce amortization expense if the reduction would cause PEF to exceed the appropriate high point of the ROE range, as established in the settlement agreements. Pursuant to the settlement agreements, PEF recognized a reduction in amortization expense of $54 million for the three months ended June 30, 2011. PEF recognized reductions in amortization expense of $58 million and $134 million for the six months ended June 30, 2012 and 2011, respectively. PEF did not recognize a reduction in amortization expense for the three months ended June 30, 2012. PEF had eligible cost of removal reserves of $232 million remaining at June 30, 2012, which 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 agreements.

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 project, together with the associated facilities, including transmission lines and substation facilities.

On April 30, 2012, as part of PEF’s annual nuclear cost recovery filing (see “Cost Recovery”), PEF updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current low natural gas prices, PEF has shifted the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 settlement agreement. Although the scope and overnight cost for Levy – including land acquisition, related transmission work and other required investments – remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF's preferred baseload generation option.

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CR3 Uprate

In 2007, the FPSC issued an order approving PEF’s Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3’s gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011 and accepted for review by the NRC on November 21, 2011. We cannot predict the outcome of this matter.

Cost Recovery

On April 30, 2012, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $152 million, which includes recovery of pre-construction and carrying costs and Capacity Cost-Recovery Clause (CCRC) recoverable O&M expense incurred or anticipated to be incurred during 2013, recovery of $88 million of prior years’ deferrals in 2013, as well as the estimated actual true-up of 2012 costs associated with the CR3 uprate and Levy projects, as permitted by the 2012 settlement agreement. This results in an increase in the nuclear cost-recovery charge of $2.23 per 1,000 kWh for residential customers, which if approved, would begin with the first January 2013 billing cycle. The FPSC has scheduled hearings in the matter for September 2012, with a decision expected in October 2012. We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT

On July 26, 2011, the FPSC voted to set PEF’s DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervenor filed a protest to the FPSC’s Proposed Agency Action order, asserting legal challenges to the order. The parties made legal arguments to the FPSC and the FPSC issued an order denying the protest on December 22, 2011. The intervenor then filed a notice of appeal of this order to the Florida Supreme Court on January 17, 2012. The FPSC and PEF have moved to dismiss the appeal for lack of standing. The Florida Supreme Court has delayed substantive replies by the parties to the proceeding until it has considered the motions to dismiss. We cannot predict the outcome of this matter.

OTHER MATTERS

On March 29, 2012, PEF announced plans to convert the 1,011-MW Anclote Units 1 and 2 (Anclote) from oil and natural gas fired to 100 percent natural gas fired and requested that the FPSC permit recovery of the estimated $79 million conversion cost through the ECRC. PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (see Note 13B). PEF anticipates that both converted units will be placed in service by the end of 2013. We cannot predict the outcome of this matter.

6. EQUITY

A. EARNINGS PER COMMON SHARE

There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three and six months ended June 30, 2012 and 2011. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial.

B. RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests represents minority shareholders’ proportionate share of the equity of a subsidiary.

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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, 2011	$	10,021		$	4		$	10,025
Net income(a)		213			1			214
Other comprehensive income		1			-			1
Issuance of shares through offerings and stock-   based compensation plans (See Note 6C)		31			-			31
Dividends declared		(369	)		-			(369	)
Distributions to noncontrolling interests		-			(2	)		(2	)
Balance, June 30, 2012	$	9,897		$	3		$	9,900
Balance, December 31, 2010	$	10,023		$	4		$	10,027
Net income(a)		360			1			361
Other comprehensive loss		(17	)		-			(17	)
Issuance of shares through offerings and stock-   based compensation plans (See Note 6C)		47			-			47
Dividends declared		(367	)		-			(367	)
Distributions to noncontrolling interests		-			(2	)		(2	)
Balance, June 30, 2011	$	10,046		$	3		$	10,049

(a) For the six months ended June 30, 2012, consolidated net income of $216 million includes $2 million attributable to preferred shareholders of subsidiaries. For the six months ended June 30, 2011, consolidated net income of $363 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.

C. COMMON STOCK

At June 30, 2012 and December 31, 2011, we had 500 million shares of common stock authorized under our charter, of which 296 million and 295 million shares were outstanding, respectively. Prior to the merger, we periodically issued shares of common stock through the Progress Energy Investor Plus Plan (IPP), equity incentive plans and other benefit plans. Effective July 2, 2012, each of our outstanding shares of common stock was converted into 0.87083 shares of Duke Energy stock (See Note 2). As a result of the merger, Progress Energy has 100 authorized, issued and outstanding shares of common stock, all of which are held by Duke Energy.

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The following table presents information for our common stock issuances:

	2012				2011
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Three months ended June 30
Total issuances		0.1	$	3		0.4	$	18
Six months ended June 30
Total issuances		0.9	$	6		1.4	$	26
Issuances through IPP		-		-		-		1

7. 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.

8. DEBT AND CREDIT FACILITIES

Material changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2011, are as follows.

On February 15, 2012, the Parent’s $478 million revolving credit agreement (RCA) was amended to extend the expiration date from May 3, 2012, to May 3, 2013, with its existing syndication of 14 financial institutions.

On March 1, 2012, PEF’s $425 million of 4.80% First Mortgage Bonds due March 1, 2013 was reclassified to current portion of long-term debt. PEF expects to fund this maturity with short-term borrowings and/or long-term debt issuances.

On March 8, 2012, the Parent issued $450 million of 3.15% Senior Notes due April 1, 2022. The net proceeds, along with available cash on hand, were used to retire the $450 million outstanding aggregate principal balance of our 6.85% Senior Notes due April 15, 2012.

On May 18, 2012, PEC issued $500 million of 2.80% First Mortgage Bonds due May 15, 2022 and $500 million of 4.10% First Mortgage Bonds due May 15, 2042. The net proceeds were used to retire at maturity the $500 million outstanding aggregate principal balance of PEC’s 6.50% Notes due July 15, 2012, and a portion of PEC’s outstanding commercial paper and notes payable to affiliated companies.

On July 2, 2012, the Parent terminated its $478 million RCA, and PEC and PEF terminated their respective $750 million RCAs and became borrowers under the Duke Energy Master Credit Facility (MCF). In November 2011, Duke Energy entered into a new $6.0 billion, five-year MCF, with $4.0 billion available at closing and the remaining $2.0 billion available following consummation of the merger. PEC and PEF each have borrowing capacity under the MCF up to $750 million. However, Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimit of each borrower, subject to a maximum sublimit of $1.0 billion for PEC and PEF. The Duke Energy MCF contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower, including PEC and PEF. Indebtedness as defined by the Duke Energy MCF includes certain

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letters of credit, surety bonds and guarantees not recorded on the Consolidated Balance Sheets. Following the merger, the cash needs of the Parent will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent dividends from other subsidiaries; borrowings under an intercompany note with Duke Energy; and/or equity contributions from Duke Energy.

9. FAIR VALUE DISCLOSURES

A. DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $13.937 billion and $12.941 billion at June 30, 2012 and December 31, 2011, respectively. The estimated fair value of this debt was $16.4 billion and $15.3 billion at June 30, 2012 and December 31, 2011, respectively, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

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 5C of the 2011Form 10-K. Nuclear decommissioning trust (NDT) funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes our available-for-sale securities at June 30, 2012 and December 31, 2011:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
June 30, 2012
Common stock equity	$	1,109	$	29	$	462
Preferred stock and other equity		47		-		14
Corporate debt		88		-		7
U.S. state and municipal debt		135		2		9
U.S. and foreign government debt		293		-		17
Money market funds and other		85		-		1
Total	$	1,757	$	31	$	510
December 31, 2011
Common stock equity	$	1,033	$	29	$	401
Preferred stock and other equity		29		-		11
Corporate debt		86		-		6
U.S. state and municipal debt		128		2		7
U.S. and foreign government debt		284		-		18
Money market funds and other		70		-		1
Total	$	1,630	$	31	$	444

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.

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The aggregate fair value of investments that related to the June 30, 2012 and December 31, 2011 unrealized losses was $151 million and $136 million, respectively.

At June 30, 2012, the fair value of our available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	54
Due after one through five years		213
Due after five through 10 years		156
Due after 10 years		107
Total	$	530

The following table presents selected information about our sales of available-for-sale securities during the three and six months ended June 30, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

	Three months ended June 30				Six months ended June 30
(in millions)	2012		2011		2012		2011
Proceeds	$	215	$	1,448	$	519	$	3,192
Realized gains		8		6		15		14
Realized losses		1		6		-		10

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $5.190 billion and $4.193 billion at June 30, 2012 and December 31, 2011, respectively. The estimated fair value of this debt was $5.8 billion and $4.7 billion at June 30, 2012 and December 31, 2011, respectively, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

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 5C of the 2011Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value.

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The following table summarizes PEC’s available-for-sale securities at June 30, 2012 and December 31, 2011:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
June 30, 2012
Common stock equity	$	727	$	19	$	293
Preferred stock and other equity		22		-		9
Corporate debt		73		-		6
U.S. state and municipal debt		62		-		4
U.S. and foreign government debt		229		-		15
Money market funds and other		54		-		1
Total	$	1,167	$	19	$	328
December 31, 2011
Common stock equity	$	673	$	20	$	255
Preferred stock and other equity		17		-		7
Corporate debt		69		-		5
U.S. state and municipal debt		56		-		3
U.S. and foreign government debt		226		-		16
Money market funds and other		60		-		1
Total	$	1,101	$	20	$	287

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.

The aggregate fair value of investments that related to the June 30, 2012 and December 31, 2011 unrealized losses was $109 million and $98 million, respectively.

At June 30, 2012, the fair value of PEC’s available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	10
Due after one through five years		203
Due after five through 10 years		91
Due after 10 years		71
Total	$	375

The following table presents selected information about PEC’s sales of available-for-sale securities during the three and six months ended June 30, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

	Three months ended June 30				Six months ended June 30
(in millions)	2012		2011		2012		2011
Proceeds	$	120	$	119	$	250	$	250
Realized gains		5		3		10		6
Realized losses		1		4		3		5

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PEF

DEBT

The carrying amount of PEF’s long-term debt, including current maturities, was $4.482 billion at June 30, 2012 and December 31, 2011. The estimated fair value of this debt was $5.5 billion and $5.4 billion at June 30, 2012 and December 31, 2011, respectively, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF’s nuclear plant as discussed in Note 5C of the 2011Form 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 June 30, 2012 and December 31, 2011:

(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
June 30, 2012
Common stock equity	$	382	$	10	$	169
Preferred stock and other equity		25		-		5
Corporate debt		15		-		1
U.S. state and municipal debt		73		2		5
U.S. and foreign government debt		64		-		2
Money market funds and other		31		-		-
Total	$	590	$	12	$	182
December 31, 2011
Common stock equity	$	360	$	9	$	146
Preferred stock and other equity		12		-		4
Corporate debt		17		-		1
U.S. state and municipal debt		72		2		4
U.S. and foreign government debt		58		-		2
Money market funds and other		10		-		-
Total	$	529	$	11	$	157

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.

The aggregate fair value of investments that related to the June 30, 2012 and December 31, 2011 unrealized losses was $42 million and $38 million, respectively.

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At June 30, 2012, the fair value of PEF’s available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	44
Due after one through five years		10
Due after five through 10 years		65
Due after 10 years		36
Total	$	155

The following table presents selected information about PEF’s sales of available-for-sale securities during the three and six months ended June 30, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

	Three months ended June 30				Six months ended June 30
(in millions)	2012		2011		2012		2011
Proceeds	$	95	$	1,329	$	269	$	2,935
Realized gains		3		3		5		8
Realized losses		2		2		3		5

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.

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We generally classify our and the Utilities’ long-term debt within Level 2. Fair value measurements of long-term debt are obtained from an independent third-party and may take into account a number of factors, including valuations of other comparable financial instruments in terms of rating, structure, maturity and/or covenant protection; comparable trades, where observable; and general interest rate and market conditions. We do not make any adjustments to the long-term debt fair value measurements obtained from the independent third-party and we corroborate the fair value measurements against comparable market data.

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 June 30, 2012 and December 31, 2011. 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.

PROGRESS ENERGY
(in millions)	Level 1		Level 2		Level 3		Total
June 30, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,109	$	-	$	-	$	1,109
Preferred stock and other equity		36		11		-		47
Corporate debt		-		88		-		88
U.S. state and municipal debt		-		135		-		135
U.S. and foreign government debt		128		165		-		293
Money market funds and other		1		84		-		85
Total nuclear decommissioning trust funds		1,274		483		-		1,757
Derivatives
Commodity forward contracts		-		8		-		8
Other marketable securities
Money market and other		16		-		-		16
Total assets	$	1,290	$	491	$	-	$	1,781
Liabilities
Derivatives
Commodity forward contracts	$	-	$	572	$	30	$	602
Interest rate contracts		-		22		-		22
Contingent value obligations		-		3		-		3
Total liabilities	$	-	$	597	$	30	$	627

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(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,033	$	-	$	-	$	1,033
Preferred stock and other equity		28		1		-		29
Corporate debt		-		86		-		86
U.S. state and municipal debt		-		128		-		128
U.S. and foreign government debt		87		197		-		284
Money market funds and other		-		87		-		87
Total nuclear decommissioning trust funds		1,148		499		-		1,647
Derivatives
Commodity forward contracts		-		5		-		5
Other marketable securities
Money market and other		20		-		-		20
Total assets	$	1,168	$	504	$	-	$	1,672
Liabilities
Derivatives
Commodity forward contracts	$	-	$	668	$	24	$	692
Interest rate contracts		-		93		-		93
Contingent value obligations		-		14		-		14
Total liabilities	$	-	$	775	$	24	$	799

PEC
(in millions)	Level 1		Level 2		Level 3		Total
June 30, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	727	$	-	$	-	$	727
Preferred stock and other equity		22		-		-		22
Corporate debt		-		73		-		73
U.S. state and municipal debt		-		62		-		62
U.S. and foreign government debt		105		124		-		229
Money market funds and other		1		50		-		51
Total nuclear decommissioning trust funds		855		309		-		1,164
Derivatives
Commodity forward contracts		-		2		-		2
Other marketable securities		2		-		-		2
Total assets	$	857	$	311	$	-	$	1,168
Liabilities
Derivatives
Commodity forward contracts	$	-	$	158	$	28	$	186
Interest rate contracts		-		11		-		11
Total liabilities	$	-	$	169	$	28	$	197

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(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	673	$	-	$	-	$	673
Preferred stock and other equity		17		-		-		17
Corporate debt		-		69		-		69
U.S. state and municipal debt		-		56		-		56
U.S. and foreign government debt		81		145		-		226
Money market funds and other		-		47		-		47
Total nuclear decommissioning trust funds		771		317		-		1,088
Other marketable securities		6		-		-		6
Total assets	$	777	$	317	$	-	$	1,094
Liabilities
Derivatives
Commodity forward contracts	$	-	$	177	$	24	$	201
Interest rate contracts		-		47		-		47
Total liabilities	$	-	$	224	$	24	$	248

PEF
(in millions)	Level 1		Level 2		Level 3		Total
June 30, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	382	$	-	$	-	$	382
Preferred stock and other equity		14		11		-		25
Corporate debt		-		15		-		15
U.S. state and municipal debt		-		73		-		73
U.S. and foreign government debt		23		41		-		64
Money market funds and other		-		34		-		34
Total nuclear decommissioning trust funds		419		174		-		593
Derivatives
Commodity forward contracts		-		6		-		6
Other marketable securities		1		-		-		1
Total assets	$	420	$	180	$	-	$	600
Liabilities
Derivatives
Commodity forward contracts	$	-	$	414	$	2	$	416
Interest rate contracts		-		11		-		11
Total liabilities	$	-	$	425	$	2	$	427

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(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	360	$	-	$	-	$	360
Preferred stock and other equity		11		1		-		12
Corporate debt		-		17		-		17
U.S. state and municipal debt		-		72		-		72
U.S. and foreign government debt		6		52		-		58
Money market funds and other		-		40		-		40
Total nuclear decommissioning trust funds		377		182		-		559
Derivatives
Commodity forward contracts		-		5		-		5
Other marketable securities		1		-		-		1
Total assets	$	378	$	187	$	-	$	565
Liabilities
Derivatives
Commodity forward contracts	$	-	$	491	$	-	$	491
Interest rate contracts		-		8		-		8
Total liabilities	$	-	$	499	$	-	$	499

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. Such models may be internally developed, but are similar to models commonly used across industries to value derivative contracts. To determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors may include forward commodity prices and price curves, volumes and notional amounts, location, interest rates and credit quality of us and our counterparties. Certain commodity derivatives are valued utilizing pricing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 11 for discussion of risk management activities and derivative transactions.

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.

Transfers into (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. Transfers into and out of each level are measured at the end of the period. There were no transfers into (out of) Levels 1, 2 and 3 during the period.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 16 in the 2011 Form 10-K. The CVOs not held by us are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

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QUALITATIVE AND QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENTS

A reconciliation of changes in the fair value of our and PEC’s commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the periods ended June 30 follows:

PROGRESS ENERGY
	Three months ended June 30					Six months ended June 30
(in millions)		2012		2011			2012		2011
Derivatives, net at beginning of period		$	27	$	32		$	24	$	36
Total losses, realized and unrealized - commodities   deferred as regulatory assets and liabilities, net			3		5			6		1
Derivatives, net at end of period		$	30	$	37		$	30	$	37

PEC
	Three months ended June 30					Six months ended June 30
(in millions)			2012		2011			2012		2011
Derivatives, net at beginning of period		$	27	$	32		$	24	$	36
Total losses, realized and unrealized - commodities   deferred as regulatory assets and liabilities, net			1		5			4		1
Derivatives, net at end of period		$	28	$	37		$	28	$	37

During the three and six months ended June 30, 2012 and 2011, PEF’s assets and liabilities classified as Level 3 were not material.

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.

For commodity derivative contracts classified as Level 3, we utilize internally-developed financial models based upon the income approach (discounted cash flow method) to measure the fair values. The primary inputs to these models are the forward commodity prices used to develop the forward price curves for the respective instrument. The pricing inputs are derived from published exchange transaction prices and other observable or public data sources. For the commodity derivative contracts classified as Level 3, the pricing inputs for natural gas forward price curves are not observable for the full term of the related contracts. In isolation, increases (decreases) in these unobservable natural gas forward prices would result in favorable (unfavorable) fair value adjustments. In the absence of observable market information that supports the pricing inputs, there is a presumption that the transaction price is equal to the last observable price for a similar period. We regularly evaluate and validate the pricing inputs we use to estimate fair value by a market participant price verification procedure, which provides a comparison of our forward commodity curves to market participant generated curves.

Quantitative information about our and PEC’s commodity derivative liabilities classified as Level 3 follows:

PROGRESS ENERGY
(in millions)	Fair Value			Valuation Technique	Unobservable Input	Range (price per MMBtu)
June 30, 2012
Commodity natural gas hedges		$	30	Discounted cash flow	Forward natural gas curves	$	3.956 - 4.374
PEC
(in millions)	Fair Value			Valuation Technique	Unobservable Input	Range (price per MMBtu)
June 30, 2012
Commodity natural gas hedges		$	28	Discounted cash flow	Forward natural gas curves	$	3.956 - 4.374

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10. BENEFIT PLANS

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

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

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	16		$	14		$	4	$	3
Interest cost		33			35			11		10
Expected return on plan assets		(46	)		(45	)		-		-
Amortization of actuarial loss(a)		26			18			9		3
Other amortization, net (a)		2			1			1		1
Net periodic cost	$	31		$	23		$	25	$	17

(a) Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

PEC
	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	7		$	6		$	2	$	2
Interest cost		15			16			6		5
Expected return on plan assets		(24	)		(23	)		-		-
Amortization of actuarial loss		10			7			6		1
Other amortization, net		2			1			-		-
Net periodic cost	$	10		$	7		$	14	$	8

PEF
	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	7		$	6		$	1	$	1
Interest cost		15			15			4		4
Expected return on plan assets		(20	)		(20	)		-		-
Amortization of actuarial loss		12			9			3		2
Other amortization, net		-			-			1		1
Net periodic cost	$	14		$	10		$	9	$	8

42

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

PROGRESS ENERGY
	Pension Benefits						OPEB
(in millions)	2012			2011			2012			2011
Service cost	$	32		$	27		$	7		$	6
Interest cost		67			70			21			20
Expected return on plan assets		(93	)		(91	)		(1	)		(1	)
Amortization of actuarial loss(a)		48			33			15			6
Other amortization, net (a)		4			3			2			3
Net periodic cost	$	58		$	42		$	44		$	34

(a) Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

PEC
	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	13		$	11		$	4	$	2
Interest cost		29			31			11		10
Expected return on plan assets		(47	)		(46	)		-		-
Amortization of actuarial loss		20			13			8		2
Other amortization, net		4			3			-		1
Net periodic cost	$	19		$	12		$	23	$	15

PEF
	Pension Benefits						OPEB
(in millions)	2012			2011			2012			2011
Service cost	$	14		$	12		$	3		$	2
Interest cost		29			30			9			9
Expected return on plan assets		(40	)		(39	)		(1	)		(1	)
Amortization of actuarial loss		23			17			5			4
Other amortization, net		-			-			2			2
Net periodic cost	$	26		$	20		$	18		$	16

In 2012, we expect to make contributions directly to pension plan assets of approximately $150 million for us, including $75 million for PEC and $75 million for PEF. The amounts we contribute may be impacted by recently enacted legislation as well as other factors. We contributed $42 million during the six months ended June 30, 2012, including $22 million for PEC and $20 million for PEF.

11. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We had a risk management committee that included senior executives from various business groups. The risk management committee was responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Following the consummation of the merger with Duke Energy, the risk management committee was replaced with Duke Energy’s Transaction and Risk Committee, which will be responsible for the oversight of risk at the combined company. The Transaction and Risk Committee will include senior executives from various functional areas. Following the consummation of the merger, PEC and PEF will continue to operate under their existing risk guidelines. Under our risk guidelines, 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.

43

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. Effective with the consummation of the merger with Duke Energy on July 2, 2012, Progress Energy entered into certain derivative power sales agreements with three counterparties in conjunction with the Interim FERC Mitigation Plan. See Note 2 for additional information regarding future charges related to the merger, including the Interim FERC Mitigation Plan.

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 2012 and 2013. 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 on the Progress Energy Consolidated Balance Sheets of $124 million and $147 million at June 30, 2012 and December 31, 2011, respectively. At June 30, 2012, Progress Energy had 394.6 million MMBtu notional of natural gas and 8.1 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases.

PEC's cash collateral asset included in derivative collateral posted on the PEC Consolidated Balance Sheets of $21 million and $24 million at June 30, 2012 and December 31, 2011, respectively. At June 30, 2012, PEC had 119.7 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 on the PEF Balance Sheets was $103 million and $123 million at June 30, 2012 and December 31, 2011, respectively. At June 30, 2012, PEF had 274.9 million MMBtu notional of natural gas and 8.1 million gallons notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases.

B. INTEREST RATE DERIVATIVES

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates, primarily through the use of forward starting 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.

44

At June 30, 2012, all open interest rate hedges will reach their mandatory termination dates within one and a half years. At June 30, 2012, including amounts related to terminated hedges, we had $142 million of after-tax losses, including $72 million and $25 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $14 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $7 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Utilities and changes in market value of currently open forward starting swaps.

At December 31, 2011, including amounts related to terminated hedges, we had $141 million of after-tax losses, including $71 million and $25 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps.

At June 30, 2012, we had $100 million notional of open forward starting swaps, including $50 million at PEC and $50 million at PEF. At December 31, 2011, we had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

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 $371 million at June 30, 2012, for which Progress Energy has posted collateral of $124 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at June 30, 2012, 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 $122 million at June 30, 2012, for which PEC has posted collateral of $21 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at June 30, 2012, PEC would have been required to post an additional $101 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 $249 million at June 30, 2012, for which PEF has posted collateral of $103 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on June 30, 2012, PEF would have been required to post an additional $146 million of collateral with its counterparties.

45

D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

The following table presents the fair value of derivative instruments at June 30, 2012 and December 31, 2011:
Instrument / Balance sheet location	June 30, 2012					December 31, 2011
(in millions)	Asset		Liability			Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current				$	2				$	2
Derivative liabilities, long-term					1					1
Interest rate derivatives
Derivative liabilities, current					11					76
Derivative liabilities, long-term					11					17
Total derivatives designated as hedging instruments					25					96
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets	$	3				$	5
Other assets and deferred debits		5					-
Derivative liabilities, current					312					357
Derivative liabilities, long-term					287					332
CVOs(b)
Other current liabilities					-					14
Other liabilities and deferred credits					3					-
Fair value of derivatives not designated as hedging   instruments		8			602		5			703
Fair value loss transition adjustment
Derivative liabilities, current					1					1
Derivative liabilities, long-term					1					2
Total derivatives not designated as hedging   instruments		8			604		5			706
Total derivatives	$	8		$	629	$	5		$	802

(a)	Substantially all of these contracts receive regulatory treatment.
(b)	As discussed in Note 16 in the 2011 Form 10-K, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000. Through a negotiated settlement agreement and subsequent tender offer between October 2011 and February 2012, we repurchased and continue to hold 83.4 million CVOs.

46

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended June 30, 2012 and 2011:

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)		2012			2011				2012			2011				2012		2011
Interest rate derivatives(c) (d)		$	(8	)	$	(16	)		$	(3	)	$	(2	)		$	-	$	-

(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 Comprehensive 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)		2012			2011				2012		2011
Commodity derivatives		$	(155	)	$	(76	)		$	38	$	(68	)

(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)	2012		2011
Commodity derivatives(a)	$	2	$	1
Fair value loss transition adjustment(a)		1		-
CVOs(a)		-		4
Total	$	3	$	5

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

47

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the six months ended June 30, 2012 and 2011:

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)		2012			2011				2012			2011				2012		2011
Interest rate derivatives(c) (d)		$	(6	)	$	(14	)		$	(6	)	$	(3	)		$	-	$	(2	)

(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 Comprehensive 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)		2012			2011				2012			2011
Commodity derivatives		$	(260	)	$	(128	)		$	(168	)	$	(44	)

(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)	2012		2011
Commodity derivatives(a)	$	2	$	1
Fair value loss transition adjustment(a)		1		-
CVOs(a)		8		4
Total	$	11	$	5

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

48

PEC
The following table presents the fair value of derivative instruments at June 30, 2012 and December 31, 2011:
Instrument / Balance sheet location	June 30, 2012						December 31, 2011
(in millions)		Asset		Liability				Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Derivative liabilities, current					$	-					$	38
Other liabilities and deferred credits						11						9
Total derivatives designated as hedging instruments						11						47
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		$	1					$	-
Other assets and deferred debits			1						-
Derivative liabilities, current						88						91
Other liabilities and deferred credits						98						110
Fair value of derivatives not designated as hedging   instruments			2			186			-			201
Fair value loss transition adjustment
Derivative liabilities, current						1						1
Other liabilities and deferred credits						1						2
Total derivatives not designated as hedging   instruments			2			188			-			204
Total derivatives		$	2		$	199		$	-		$	251

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

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended June 30, 2012 and 2011:

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)		2012			2011				2012			2011				2012		2011
Interest rate derivatives(c) (d)		$	(7	)	$	(6	)		$	(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 Comprehensive Income are classified in interest charges.

49

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2012			2011				2012		2011
Commodity derivatives		$	(39	)	$	(12	)		$	10	$	(19	)

(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)	2012		2011
Commodity derivatives(a)	$	2	$	1
Fair value loss transition adjustment(a)		1		-
Total	$	3	$	1

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

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the six months ended June 30, 2012 and 2011:

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)	2012			2011			2012			2011			2012		2011
Interest rate derivatives(c) (d)	$	(4	)	$	(5	)	$	(3	)	$	(2	)	$	-	$	-

(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 Comprehensive 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)		2012			2011				2012			2011
Commodity derivatives		$	(65	)	$	(22	)		$	(49	)	$	(13	)

(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.

50

Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2012		2011
Commodity derivatives(a)	$	2	$	1
Fair value loss transition adjustment(a)		1
Total	$	3	$	1

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

PEF

The following table presents the fair value of derivative instruments at June 30, 2012 and December 31, 2011:

Instrument / Balance sheet location	June 30, 2012						December 31, 2011
(in millions)		Asset		Liability				Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current					$	2					$	2
Derivative liabilities, long-term						1						1
Interest rate derivatives
Derivative liabilities, current						11						-
Derivative liabilities, long-term						-						8
Total derivatives designated as hedging instruments						14						11
Derivatives not designated as hedging instruments
Commodity derivatives(a)
Prepayments and other current assets		$	2					$	5
Other assets and deferred debits			4						-
Derivative liabilities, current						224						266
Derivative liabilities, long-term						189						222
Total derivatives not designated as hedging   instruments			6			413			5			488
Total derivatives		$	6		$	427		$	5		$	499

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

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The following tables present the effect of derivative instruments on the Statements of Comprehensive Income for the three months ended June 30, 2012 and 2011:

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)		2012			2011				2012		2011			2012		2011
Interest rate derivatives(c) (d)		$	(1	)	$	(5	)		$	-	$	-		$	-	$	-

(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 Comprehensive 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)		2012			2011				2012		2011
Commodity derivatives		$	(116	)	$	(64	)		$	28	$	(49	)

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

The following tables present the effect of derivative instruments on the Statements of Comprehensive Income for the six months ended June 30, 2012 and 2011:

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)		2012			2011				2012			2011			2012		2011
Interest rate derivatives(c) (d)		$	(1	)	$	(5	)		$	(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 Statements of Comprehensive Income are classified in interest charges.

52

Derivatives Not Designated as Hedging Instruments
Instrument	Realized Gain or (Loss)(a)							Unrealized Gain or (Loss)(b)
(in millions)		2012			2011				2012			2011
Commodity derivatives		$	(195	)	$	(106	)		$	(119	)	$	(31	)

(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.

12. 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 June 30, 2012
Revenues
Unaffiliated	$	1,082	$	1,189		$	2		$	-		$	2,273
Intersegment		-		-			72			(72	)		-
Total revenues		1,082		1,189			74			(72	)		2,273
Ongoing Earnings		42		85			(47	)		-			80
Total Assets		16,957		14,657			20,668			(16,558	)		35,724
For the three months ended June 30, 2011
Revenues
Unaffiliated	$	1,060	$	1,193		$	3		$	-		$	2,256
Intersegment		-		-			60			(60	)		-
Total revenues		1,060		1,193			63			(60	)		2,256
Ongoing Earnings		112		141			(42	)		-			211
For the six months ended June 30, 2012
Revenues
Unaffiliated	$	2,167	$	2,193		$	5		$	-		$	4,365
Intersegment		-		1			130			(131	)		-
Total revenues		2,167		2,194			135			(131	)		4,365
Ongoing Earnings		103		214			(94	)		-			223
For the six months ended June 30, 2011
Revenues
Unaffiliated	$	2,193	$	2,224		$	6		$	-		$	4,423
Intersegment		-		1			134			(135	)		-
Total revenues		2,193		2,225			140			(135	)		4,423
Ongoing Earnings		251		252			(90	)		-			413

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

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

	For the three months ended June 30
(in millions)		2012			2011
Ongoing Earnings		$	80		$	211
Tax levelization			(5	)		(4	)
CVO mark-to-market			-			4
Merger and integration costs, net of tax benefit of $6 and $4 (Note 2)			(13	)		(7	)
CR3 indemnification adjustment (charge), net of tax (expense) benefit of $(3) and $18			5			(26	)
Continuing income attributable to noncontrolling interests, net of tax			1			2
Income from continuing operations			68			180
Discontinued operations, net of tax			(4	)		(2	)
Net income attributable to noncontrolling interests, net of tax			(1	)		(2	)
Net income attributable to controlling interests		$	63		$	176
	For the six months ended June 30
(in millions)			2012			2011
Ongoing Earnings		$	223		$	413
Tax levelization			(12	)		(6	)
CVO mark-to-market			8			4
Merger and integration costs, net of tax benefit of $8 and $4 (Note 2)			(18	)		(21	)
CR3 indemnification adjustment (charge), net of tax (expense) benefit of $(3) and $18			5			(26	)
Continuing income attributable to noncontrolling interests, net of tax			3			3
Income from continuing operations			209			367
Discontinued operations, net of tax			7			(4	)
Net income attributable to noncontrolling interests, net of tax			(3	)		(3	)
Net income attributable to controlling interests		$	213		$	360

13. 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. We are evaluating the

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impacts of environmental regulations, which could include the potential need to retire additional generating facilities earlier than their current estimated useful lives.

A. HAZARDOUS AND SOLID WASTE

The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities’ coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal under federal hazardous waste rules. The other option would have the EPA set design and performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste with enforcement by the courts or state laws. 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 not expected before sometime in 2013, at the earliest. There are federal legislative proposals that may direct the EPA to regulate coal combustion residues destined for disposal as non-hazardous wastes. Environmental groups filed a lawsuit on April 5, 2012, in the U.S. District Court for the District of Columbia to require the EPA to complete its rulemaking process and finalize new regulations for the storage, transportation and disposal of coal combustion residues. On June 19, 2012, the U.S. District Court granted the petition for leave to intervene by the Utility Solid Waste Activities Group, of which we are a member. Compliance plans and estimated costs to meet the regulations or statutes will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

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

We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M expense on the Statements of Comprehensive Income 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, 2011	$	17		$	6		$	23
Amount accrued for environmental loss contingencies(a)		15			2			17
Expenditures for environmental loss contingencies(b)		(2	)		(4	)		(6	)
Balance, June 30, 2012(c)	$	30		$	4		$	34
Balance, December 31, 2010	$	20		$	15		$	35
Amount accrued for environmental loss contingencies(a)		-			3			3
Expenditures for environmental loss contingencies(b)		(2	)		(9	)		(11	)
Balance, June 30, 2011(c)	$	18		$	9		$	27

(a)	Amounts accrued are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012, our accruals were $12 million for the remediation of MGP and other sites and were not material for the remediation of distribution and substations transformers. For the three months ended June 30, 2011, our accruals for environmental loss contingencies were not material.
(b)	Expenditures are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, our expenditures for environmental loss contingencies were not material.
(c)	Expected to be paid out over one to 12 years.

PEC
(in millions)	MGP and Other Sites
Balance, December 31, 2011	$	11
Amount accrued for environmental loss contingencies(a)		4
Expenditures for environmental loss contingencies(b)		(1	)
Balance, June 30, 2012(c)	$	14
Balance, December 31, 2010	$	12
Amount accrued for environmental loss contingencies(a)		-
Expenditures for environmental loss contingencies(b)		-
Balance, June 30, 2011(c)	$	12

(a)	Amounts accrued are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012, PEC's accruals were $5 million for the remediation of MGP and other sites. For the three months ended June 30, 2011, PEC's accruals for the remediation of MGP and other sites were not material.
(b)	Expenditures are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, PEC's expenditures for the remediation of MGP and other sites were not material.
(c)	Expected to be paid out over one to ten years.

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PEF
(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2011	$	6		$	6		$	12
Amount accrued for environmental loss contingencies(a)		11			2			13
Expenditures for environmental loss contingencies(b)		(1	)		(4	)		(5	)
Balance, June 30, 2012(c)	$	16		$	4		$	20
Balance, December 31, 2010	$	8		$	15		$	23
Amount accrued for environmental loss contingencies(a)		-			3			3
Expenditures for environmental loss contingencies(b)		(2	)		(9	)		(11	)
Balance, June 30, 2011(c)	$	6		$	9		$	15

(a)	Amounts accrued are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012, PEF's accruals were $7 million for the remediation of MGP and other sites and were not material for the remediation of distribution and substation transformers. For the three months ended June 30, 2011, PEF's accruals for environmental loss contingencies were not material.
(b)	Expenditures are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, PEF's expenditures for environmental loss contingencies were not material.
(c)	Expected to be paid out over one to 12 years.

PROGRESS ENERGY

In addition to the Utilities’ sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 14B).

PEC

The accruals for PEC’s MGP and other sites relate to one former MGP site and other sites associated with PEC that have required, or are anticipated to require, investigation and/or remediation. Remediation of PEC’s other MGP sites has been substantially completed. During the three and six months ended June 30, 2012, PEC completed a preliminary remedial action plan for its remaining MGP site, which indicates a range of viable remedial approaches with estimated costs of $2 million to $25 million. PEC believes one approach has more merit than the other approaches and increased its accrual for the site to reflect the approximately $7 million estimated cost for the remedial approach considered to have more merit. The maximum amount of the range for all of PEC’s environmental 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). 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 June 30, 2012 and December 31, 2011, PEC’s recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against non-participating 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. The court established a “test case” program providing for a determination of liability on the part of a set of representative defendants. Summary judgment motions and responsive pleadings are being filed by and against these defendants and discovery and briefing were completed during the second quarter of 2012. Meanwhile, proceedings with respect to the other defendants have been stayed. The outcome of these matters cannot be predicted.

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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. On September 29, 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. On July 10, 2012, the EPA issued a Special Notice Letter to PEC and the other participating PRPs providing notification of the opportunity to perform and fund the tasks included in Ward OU2. The recipients have 60 days from receipt of the Special Notice Letter to submit a “good faith” offer to perform the work. 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. Remediation of one MGP site has been substantially completed. At June 30, 2012, PEF’s accrual primarily relates to an MGP site located in Orlando, Fla. The PRP group for the Orlando MGP site has agreed to an interim allocation for the Orlando MGP site and is conducting a feasibility study for remediation of soil and groundwater down to 50 feet, which has not been completed. The study preliminarily indicates a range of viable remedial approaches. During the three months ended June 30, 2012, the PRPs received refined estimates for the range of viable remedial approaches. Additionally, the PRPs believe one approach has more merit than the other approaches; however, the recommendation has not been submitted to or approved by the EPA at this time. During the six months ended June 30, 2012, one participating PRP ended its participation in the PRP group. The PRP allocations have been adjusted accordingly. The PRPs for the Orlando MGP site intend to seek recovery from the non-participating PRP, but no amount for recovery has been recorded. PEF has accrued its best estimate of its obligation with respect to the Orlando MGP site. Based on current estimates for the remedial approach considered to have more merit and its current allocation share, PEF accrued additional obligations of approximately $6 million and $9 million, respectively, during the three and six months ended June 30, 2012, for remediation of soil and groundwater down to 50 feet. Based on current estimates for the range of viable remedial approaches and its current allocation share, PEF could incur additional obligations of up to approximately $8 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material at least 200 feet below the surface. The layer between approximately 50 feet and 200 feet below the surface, which is clay, is not impacted. The maximum amount of the range for remediation, if any, below 200 feet at the Orlando MGP site and for PEF’s other 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. We cannot predict the outcome of this matter.

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

B. AIR AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations governing air and water quality, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act). The air quality controls installed to comply with nitrogen oxides (NOx) and sulfur dioxide (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

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requirements for NOx and SO2 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.

After prior mercury regulation was vacated in federal court, the EPA developed maximum achievable control technology (MACT) standards. The Mercury and Air Toxics Standards (MATS), which are the final MACT standards for coal-fired and oil-fired electric steam generating units, became effective on April 16, 2012. Compliance is due three years after the effective date with provision for a one-year extension granted by state agencies on a case-by-case basis. The MATS 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. Several petitions regarding portions of the MATS rule have been filed in the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals), including one by the Utility Air Regulatory Group, of which we are a member. On July 20, 2012, the EPA announced that it will reconsider the new source emissions standards contained in the MATS rule. 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. Due to significant investments in NOx and SO2 emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy. We are continuing to evaluate the impacts of the MATS on the Utilities. PEF’s Crystal River Units 1 and 2 (CR1 and CR2) are under evaluation for MATS compliance with the potential to be retired. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

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 for NOx and beginning in 2010 and 2015 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. A 2008 decision by the D.C. Court of Appeals remanded the CAIR without vacating it for the EPA to conduct further proceedings.

On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) to replace the CAIR. The CSAPR, which was scheduled to take effect on January 1, 2012, contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. A number of parties, including groups of which PEC and PEF are members, filed petitions for reconsideration and stay of, as well as legal challenges to, the CSAPR. On December 30, 2011, the D.C. Court of Appeals issued an order staying the implementation of the CSAPR, pending a decision by the court resolving the challenges to the rule. Oral argument for the CSAPR litigation occurred on April 13, 2012. As a result of the stay of CSAPR, the CAIR remains in effect. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. If the CSAPR is upheld, North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season trading program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required in 2014. Under the CSAPR, Florida is subject only to the NOx ozone season trading program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe PEC and PEF are positioned to comply with the CSAPR without the need for significant capital expenditures. We cannot predict the outcome of this matter.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at CR4 and CR5, which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire CR1 and CR2 as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 were originally scheduled to be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was anticipated to be around 2020. As discussed in Note 5B, major construction activities for Levy are being postponed, and the in-service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of developments that may delay the retirement of CR1 and CR2. We are currently evaluating the

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impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs. SO2 emission allowances will be utilized by the Utilities to comply with existing CAA requirements. NOx allowances cannot be utilized to comply with other requirements. As a result of the previously discussed D.C. Court of Appeals order staying the implementation of the CSAPR, the CAIR emission allowance program remains in effect. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits and have not changed materially from what was reported in the 2011Form 10-K.

14. COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2011 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 2011 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 June 30, 2012, our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 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 June 30, 2012, 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 June 30, 2012, 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 June 30, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $222 million, including $48 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 related to discontinued operations have no limitations as to time or maximum potential future payments. At June 30, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $31 million and $63 million, respectively. These amounts included $23 million and $37 million for PEF at June 30, 2012 and December 31, 2011, respectively. Our liabilities decreased primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 4) and the adjustment to the indemnification for the estimated future years’ joint owner replacement power costs related to CR3 (See Note 12). PEF’s liabilities decreased primarily due to the previously mentioned indemnification adjustment related to CR3. During the three and six months ended June 30, 2012, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

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In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 15).

Furthermore, effective with the consummation of the merger with Duke Energy on July 2, 2012, Progress Energy and Duke Energy have guaranteed to provide $650 million in system fuel savings for retail customers in North Carolina and South Carolina (See Note 2).

C. OTHER COMMITMENTS AND CONTINGENCIES

MERGER

On August 3, 2012, Duke Energy was served with a shareholder Derivative Complaint, which has been transferred to the North Carolina Business Court (Krieger v. Johnson, et al). The lawsuit names as defendants, William D. Johnson, James E. Rogers and the ten other members of the Duke Energy board of directors who were also members of the pre-merger Duke Energy board of directors. Duke Energy is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duty in granting excessive compensation to Mr. Johnson. We cannot predict the outcome of this matter.

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 13).

Water Discharge Permit

In October 2011, Earthjustice, on behalf of the Sierra Club and Florida Wildlife Federation, filed a petition seeking review of the water discharge permit issued to CR1, CR2 and CR3 raising a number of technical and legal issues with respect to the permit. In March 2012, a settlement was reached providing for the withdrawal of the petition and issuance by the FDEP of a revised water discharge permit identical in form to the one under appeal but with an 18-month term rather than the standard five-year term. The settlement fully resolved the current dispute.

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 for Disposal of Spent Nuclear Fuel.

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 and asserting damages incurred through 2005. In 2011, the judge in the U.S. Court of Federal Claims issued a ruling to award PEC substantially all their asserted damages. As a result, PEC recorded the award as an offset for past spent fuel storage costs incurred.

On December 12, 2011, the Utilities filed another complaint in the U.S. Court of Federal Claims against the DOE, claiming damages incurred from January 1, 2006, through December 31, 2010. The damages stem from the same breach of contract asserted in the previous litigation. On March 23, 2012, the Utilities filed their initial disclosure of $113 million damages with the U.S. Court of Federal Claims and the DOE. The total amount of damages could change during discovery, which is set to end on January 31, 2013. The Utilities may file subsequent damage claims as they incur additional costs. The next status conference to discuss trial dates is scheduled for January 10, 2013. We cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

In October 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000 (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco synthetic fuels facilities (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

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Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the 2007 expiration of the Internal Revenue Code Section 29 tax credit program, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

The jury awarded Global $78 million. In November 2009, the court 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 appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we made a $154 million payment, which represented payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. We continue to accrue interest related to this judgment. The appellate briefing process has been completed. Oral argument was held on September 27, 2011. We cannot predict the outcome of this matter.

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

OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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15. CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2011 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 12B in the 2011 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 Comprehensive Income, Balance Sheets and Statements of Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed consolidating statements, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the consolidated financial results of Florida Progress only, which is primarily comprised of its wholly owned subsidiary PEF. The Non-guarantor Subsidiaries column includes the consolidated financial results of all non-guarantor subsidiaries, which is primarily comprised of our wholly owned subsidiary PEC. The Other column includes elimination entries for all intercompany transactions and other consolidation adjustments. Financial statements for PEC and PEF are separately presented elsewhere in this Form 10-Q. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities.

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Condensed Consolidating Statement of Comprehensive Income
Three months ended June 30, 2012
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	1,191		$	1,082		$	-		$	2,273
Affiliate revenues		-			-			72			(72	)		-
Total operating revenues		-			1,191			1,154			(72	)		2,273
Operating expenses
Fuel used in electric generation		-			390			346			-			736
Purchased power		-			177			80			-			257
Operation and maintenance		3			246			448			(70	)		627
Depreciation, amortization and accretion		-			92			139			-			231
Taxes other than on income		-			90			54			(2	)		142
Other		-			4			2			(1	)		5
Total operating expenses		3			999			1,069			(73	)		1,998
Operating (loss) income		(3	)		192			85			1			275
Other income
Interest income		-			1			-			-			1
Allowance for equity funds used during construction		-			8			17			-			25
Other, net		-			1			1			(1	)		1
Total other income, net		-			10			18			(1	)		27
Interest charges
Interest charges		64			79			60			-			203
Allowance for borrowed funds used during   construction		-			(5	)		(6	)		-			(11	)
Total interest charges, net		64			74			54			-			192
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(67	)		128			49			-			110
Income tax (benefit) expense		(30	)		49			18			5			42
Equity in earnings of consolidated subsidiaries		100			-			-			(100	)		-
Income from continuing operations		63			79			31			(105	)		68
Discontinued operations, net of tax		-			(3	)		(1	)		-			(4	)
Net income		63			76			30			(105	)		64
Net income attributable to noncontrolling   interests, net of tax		-			(1	)		-			-			(1	)
Net income attributable to controlling interests	$	63		$	75		$	30		$	(105	)	$	63
Comprehensive income
Comprehensive income	$	59		$	76		$	25		$	(100	)	$	60
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(1	)		-			-			(1	)
Comprehensive income attributable to controlling   interests	$	59		$	75		$	25		$	(100	)	$	59

64

Condensed Consolidating Statement of Comprehensive Income
Three months ended June 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	1,196		$	1,060		$	-		$	2,256
Affiliate revenues		-			-			61			(61	)		-
Total operating revenues		-			1,196			1,121			(61	)		2,256
Operating expenses
Fuel used in electric generation		-			348			326			-			674
Purchased power		-			256			73			-			329
Operation and maintenance		1			223			343			(57	)		510
Depreciation, amortization and accretion		-			48			131			-			179
Taxes other than on income		-			83			51			-			134
Other		-			2			-			-			2
Total operating expenses		1			960			924			(57	)		1,828
Operating (loss) income		(1	)		236			197			(4	)		428
Other income
Allowance for equity funds used during construction		-			8			18			-			26
Other, net		4			1			-			2			7
Total other income, net		4			9			18			2			33
Interest charges
Interest charges		63			73			53			-			189
Allowance for borrowed funds used during   construction		-			(3	)		(6	)		-			(9	)
Total interest charges, net		63			70			47			-			180
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(60	)		175			168			(2	)		281
Income tax (benefit) expense		(24	)		64			60			1			101
Equity in earnings of consolidated subsidiaries		212			-			-			(212	)		-
Income from continuing operations		176			111			108			(215	)		180
Discontinued operations, net of tax		-			(2	)		-			-			(2	)
Net income		176			109			108			(215	)		178
Net income attributable to noncontrolling   interests, net of tax		-			(1	)		-			(1	)		(2	)
Net income attributable to controlling interests	$	176		$	108		$	108		$	(216	)	$	176
Comprehensive income
Comprehensive income	$	155		$	103		$	96		$	(197	)	$	157
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(1	)		-			(1	)		(2	)
Comprehensive income attributable to controlling   interests	$	155		$	102		$	96		$	(198	)	$	155

65

Condensed Consolidating Statement of Comprehensive Income
Six months ended June 30, 2012
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	2,198		$	2,167		$	-		$	4,365
Affiliate revenues		-			-			131			(131	)		-
Total operating revenues		-			2,198			2,298			(131	)		4,365
Operating expenses
Fuel used in electric generation		-			726			695			-			1,421
Purchased power		-			322			145			-			467
Operation and maintenance		4			406			870			(124	)		1,156
Depreciation, amortization and accretion		-			119			278			-			397
Taxes other than on income		-			172			112			(4	)		280
Other		-			4			2			(1	)		5
Total operating expenses		4			1,749			2,102			(129	)		3,726
Operating (loss) income		(4	)		449			196			(2	)		639
Other income
Interest income		1			1			-			-			2
Allowance for equity funds used during construction		-			17			32			-			49
Other, net		8			2			3			1			14
Total other income, net		9			20			35			1			65
Interest charges
Interest charges		130			152			115			-			397
Allowance for borrowed funds used during   construction		-			(9	)		(11	)		-			(20	)
Total interest charges, net		130			143			104			-			377
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(125	)		326			127			(1	)		327
Income tax (benefit) expense		(52	)		122			45			3			118
Equity in earnings of consolidated subsidiaries		286			-			-			(286	)		-
Income from continuing operations		213			204			82			(290	)		209
Discontinued operations, net of tax		-			8			(1	)		-			7
Net income		213			212			81			(290	)		216
Net income attributable to noncontrolling   interests, net of tax		-			(2	)		-			(1	)		(3	)
Net income attributable to controlling interests	$	213		$	210		$	81		$	(291	)	$	213
Comprehensive income
Comprehensive income	$	214		$	213		$	80		$	(290	)	$	217
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(2	)		-			(1	)		(3	)
Comprehensive income attributable to controlling   interests	$	214		$	211		$	80		$	(291	)	$	214

66

Condensed Consolidating Statement of Comprehensive Income
Six months ended June 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	-		$	2,230		$	2,193		$	-		$	4,423
Affiliate revenues		-			-			135			(135	)		-
Total operating revenues		-			2,230			2,328			(135	)		4,423
Operating expenses
Fuel used in electric generation		-			703			689			-			1,392
Purchased power		-			409			140			-			549
Operation and maintenance		4			434			694			(128	)		1,004
Depreciation, amortization and accretion		-			73			260			-			333
Taxes other than on income		-			168			110			(4	)		274
Other		-			(8	)		-			-			(8	)
Total operating expenses		4			1,779			1,893			(132	)		3,544
Operating (loss) income		(4	)		451			435			(3	)		879
Other income (expense)
Interest income		-			1			-			-			1
Allowance for equity funds used during construction		-			17			38			-			55
Other, net		4			6			(2	)		2			10
Total other income, net		4			24			36			2			66
Interest charges
Interest charges		136			148			104			-			388
Allowance for borrowed funds used during   construction		-			(7	)		(11	)		-			(18	)
Total interest charges, net		136			141			93			-			370
(Loss) income from continuing operations before   income tax and equity in earnings of consolidated   subsidiaries		(136	)		334			378			(1	)		575
Income tax (benefit) expense		(55	)		124			140			(1	)		208
Equity in earnings of consolidated subsidiaries		441			-			-			(441	)		-
Income from continuing operations		360			210			238			(441	)		367
Discontinued operations, net of tax		-			(3	)		(1	)		-			(4	)
Net income		360			207			237			(441	)		363
Net income attributable to noncontrolling   interests, net of tax		-			(2	)		-			(1	)		(3	)
Net income attributable to controlling interests	$	360		$	205		$	237		$	(442	)	$	360
Comprehensive income
Comprehensive income	$	343		$	202		$	228		$	(427	)	$	346
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(2	)		-			(1	)		(3	)
Comprehensive income attributable to controlling   interests	$	343		$	200		$	228		$	(428	)	$	343

67

Condensed Consolidating Balance Sheet
June 30, 2012
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	10,710	$	12,398	$	84		$	23,192
Current assets
Cash and cash equivalents		6		33		34		-			73
Receivables, net		-		375		474		-			849
Notes receivable from affiliated companies		62		-		388		(450	)		-
Regulatory assets		-		266		36		-			302
Derivative collateral posted		-		103		21		-			124
Prepayments and other current assets		137		934		1,099		(131	)		2,039
Total current assets		205		1,711		2,052		(581	)		3,387
Deferred debits and other assets
Investment in consolidated subsidiaries		13,871		-		-		(13,871	)		-
Regulatory assets		-		1,481		1,473		-			2,954
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		593		1,164		-			1,757
Other assets and deferred debits		115		235		875		(446	)		779
Total deferred debits and other assets		13,986		2,309		3,512		(10,662	)		9,145
Total assets	$	14,191	$	14,730	$	17,962	$	(11,159	)	$	35,724
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	9,897	$	4,770	$	5,432	$	(10,202	)	$	9,897
Noncontrolling interests		-		3		-		-			3
Total equity		9,897		4,773		5,432		(10,202	)		9,900
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		-		(36	)		273
Long-term debt, net		3,992		4,057		4,690		-			12,739
Total capitalization		13,889		9,173		10,181		(10,238	)		23,005
Current liabilities
Current portion of long-term debt		-		425		500		-			925
Short-term debt		201		144		-		-			345
Notes payable to affiliated companies		-		447		3		(450	)		-
Derivative liabilities		-		237		89		-			326
Other current liabilities		78		912		1,117		(133	)		1,974
Total current liabilities		279		2,165		1,709		(583	)		3,570
Deferred credits and other liabilities
Noncurrent income tax liabilities		-		1,006		2,084		(420	)		2,670
Regulatory liabilities		-		905		1,622		85			2,612
Other liabilities and deferred credits		23		1,481		2,366		(3	)		3,867
Total deferred credits and other liabilities		23		3,392		6,072		(338	)		9,149
Total capitalization and liabilities	$	14,191	$	14,730	$	17,962	$	(11,159	)	$	35,724

68

Condensed Consolidating Balance Sheet
December 31, 2011
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	-	$	10,523	$	11,887	$	87		$	22,497
Current assets
Cash and cash equivalents		117		92		21		-			230
Receivables, net		-		372		517		-			889
Notes receivable from affiliated companies		53		-		219		(272	)		-
Regulatory assets		-		244		31		-			275
Derivative collateral posted		-		123		24		-			147
Prepayments and other current assets		128		852		1,049		(87	)		1,942
Total current assets		298		1,683		1,861		(359	)		3,483
Deferred debits and other assets
Investment in consolidated subsidiaries		14,043		-		-		(14,043	)		-
Regulatory assets		-		1,602		1,423		-			3,025
Goodwill		-		-		-		3,655			3,655
Nuclear decommissioning trust funds		-		559		1,088		-			1,647
Other assets and deferred debits		140		242		856		(486	)		752
Total deferred debits and other assets		14,183		2,403		3,367		(10,874	)		9,079
Total assets	$	14,481	$	14,609	$	17,115	$	(11,146	)	$	35,059
CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,021	$	4,728	$	5,646	$	(10,374	)	$	10,021
Noncontrolling interests		-		4		-		-			4
Total equity		10,021		4,732		5,646		(10,374	)		10,025
Preferred stock of subsidiaries		-		34		59		-			93
Long-term debt, affiliate		-		309		-		(36	)		273
Long-term debt, net		3,543		4,482		3,693		-			11,718
Total capitalization		13,564		9,557		9,398		(10,410	)		22,109
Current liabilities
Current portion of long-term debt		450		-		500		-			950
Short-term debt		250		233		188		-			671
Notes payable to affiliated companies		-		238		34		(272	)		-
Derivative liabilities		38		268		130		-			436
Other current liabilities		161		839		1,112		(84	)		2,028
Total current liabilities		899		1,578		1,964		(356	)		4,085
Deferred credits and other liabilities
Noncurrent income tax liabilities		-		837		1,976		(458	)		2,355
Regulatory liabilities		-		1,071		1,543		86			2,700
Other liabilities and deferred credits		18		1,566		2,234		(8	)		3,810
Total deferred credits and other liabilities		18		3,474		5,753		(380	)		8,865
Total capitalization and liabilities	$	14,481	$	14,609	$	17,115	$	(11,146	)	$	35,059

69

Condensed Consolidating Statement of Cash Flows
Six months ended June 30, 2012
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	406		$	368		$	458		$	(481	)	$	751
Investing activities
Gross property additions		-			(380	)		(700	)		-			(1,080	)
Nuclear fuel additions		-			(15	)		(50	)		-			(65	)
Purchases of available-for-sale securities and other   investments		-			(354	)		(271	)		-			(625	)
Proceeds from available-for-sale securities and other   investments		-			354			256			-			610
Changes in advances to affiliated companies		(9	)		-			(169	)		178			-
Other investing activities		(13	)		25			70			(1	)		81
Net cash used by investing activities		(22	)		(370	)		(864	)		177			(1,079	)
Financing activities
Issuance of common stock, net		6			-			-			-			6
Dividends paid on common stock		(446	)		-			-			-			(446	)
Dividends paid to parent		-			(173	)		(310	)		483			-
Payments of short-term debt with original maturities   greater than 90 days		-			(65	)		-			-			(65	)
Proceeds from issuance of short-term debt with original   maturities greater than 90 days		-			65			-			-			65
Net decrease in short-term debt		(49	)		(89	)		(188	)		-			(326	)
Proceeds from issuance of long-term debt, net		444			-			988			-			1,432
Retirement of long-term debt		(450	)		-			-			-			(450	)
Changes in advances from affiliated companies		-			209			(31	)		(178	)		-
Other financing activities		-			(4	)		(40	)		(1	)		(45	)
Net cash (used) provided by financing activities		(495	)		(57	)		419			304			171
Net (decrease) increase in cash and cash equivalents		(111	)		(59	)		13			-			(157	)
Cash and cash equivalents at beginning of period		117			92			21			-			230
Cash and cash equivalents at end of period	$	6		$	33		$	34		$	-		$	73

70

Condensed Consolidating Statement of Cash Flows
Six months ended June 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	477		$	413		$	567		$	(677	)	$	780
Investing activities
Gross property additions		-			(419	)		(585	)		-			(1,004	)
Nuclear fuel additions		-			(13	)		(80	)		-			(93	)
Purchases of available-for-sale securities and other   investments		-			(3,093	)		(294	)		-			(3,387	)
Proceeds from available-for-sale securities and other   investments		-			3,095			269			-			3,364
Changes in advances to affiliated companies		(80	)		22			40			18			-
Contributions to consolidated subsidiaries		(10	)		-			-			10			-
Other investing activities		-			74			8			-			82
Net cash used by investing activities		(90	)		(334	)		(642	)		28			(1,038	)
Financing activities
Issuance of common stock, net		26			-			-			-			26
Dividends paid on common stock		(366	)		-			-			-			(366	)
Dividends paid to parent		-			(403	)		(275	)		678			-
Net increase in short-term debt		49			67			198			-			314
Proceeds from issuance of long-term debt, net		494			-			-			-			494
Retirement of long-term debt		(700	)		-			-			-			(700	)
Changes in advances from affiliated companies		-			16			3			(19	)		-
Contributions from parent		-			10			-			(10	)		-
Other financing activities		-			(6	)		(63	)		-			(69	)
Net cash used by financing activities		(497	)		(316	)		(137	)		649			(301	)
Net decrease in cash and cash equivalents		(110	)		(237	)		(212	)		-			(559	)
Cash and cash equivalents at beginning of period		110			270			231			-			611
Cash and cash equivalents at end of period	$	-		$	33		$	19		$	-		$	52

71

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, PEC and PEF. As used in this report, Progress Energy, which includes 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 the Utilities. The term “Progress Registrants” refers collectively to the three separate registrants: Progress Energy, PEC and PEF. Information contained herein relating to PEC and PEF individually is filed by such company on its own behalf. Neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

The following MD&A contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors” to the Progress Registrants’ 2011 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 Comprehensive 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 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 2011 Form 10-K.

MERGER WITH DUKE ENERGY

On July 2, 2012, Progress Energy consummated the merger with Duke Energy, and became a direct wholly owned subsidiary of Duke Energy. Under the terms of the merger agreement, each share of Progress Energy common stock was converted into 0.87083 shares of Duke Energy common stock as adjusted for the one-for-three reverse stock split of Duke Energy stock effected in conjunction with, and immediately prior to, the merger. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock was converted into an option to acquire, or an equity award relating to, 0.87083 shares of Duke Energy common stock. The total consideration transferred in the merger was based on the closing price of Duke Energy common shares on July 2, 2012, and was estimated at $18 billion. The merger is being recorded using the acquisition method of accounting. Under SEC regulations, the Progress Registrants will not reflect the impacts of acquisition accounting in their financial statements based on the significance of the Progress Registrants’ outstanding public debt securities. These adjustments will be recorded by Duke Energy. See Note 2 for additional information regarding the merger.

The information presented in this Form 10-Q for the three and six months ended June 30, 2012 and 2011, are presented solely for the Progress Registrants on a stand-alone basis. The results of our operations will be included in Duke Energy’s results of operations beginning on July 2, 2012.

72

PROGRESS ENERGY

RESULTS OF OPERATIONS

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

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

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 June 30, 2012
Ongoing Earnings	$	42		$	85		$	(47	)	$	80		$	0.27
Tax levelization		(4	)		(1	)		-			(5	)		(0.02	)
Merger and integration costs, net of tax(a)		(7	)		(6	)		-			(13	)		(0.04	)
CR3 indemnification adjustment, net of tax(a)		-			5			-			5			0.02
Discontinued operations attributable to controlling   interests, net of tax		-			-			(4	)		(4	)		(0.02	)
Net income (loss) attributable to controlling interests(b)	$	31		$	83		$	(51	)	$	63		$	0.21
Three months ended June 30, 2011
Ongoing Earnings	$	112		$	141		$	(42	)	$	211		$	0.71
Tax levelization		(1	)		1			(4	)		(4	)		(0.01	)
CVO mark-to-market		-			-			4			4			0.01
Merger and integration costs, net of tax(a)		(4	)		(3	)		-			(7	)		(0.02	)
CR3 indemnification charge, net of tax(a)		-			(26	)		-			(26	)		(0.09	)
Discontinued operations attributable to controlling   interests, net of tax		-			-			(2	)		(2	)		-
Net income (loss) attributable to controlling interests(b)	$	107		$	113		$	(44	)	$	176		$	0.60
Six months ended June 30, 2012
Ongoing Earnings	$	103		$	214		$	(94	)	$	223		$	0.75
Tax levelization		(10	)		(2	)		-			(12	)		(0.04	)
CVO mark-to-market		-			-			8			8			0.03
Merger and integration costs, net of tax(a)		(11	)		(7	)		-			(18	)		(0.06	)
CR3 indemnification adjustment, net of tax(a)		-			5			-			5			0.02
Discontinued operations attributable to controlling   interests, net of tax		-			-			7			7			0.02
Net income (loss) attributable to controlling interests(b)	$	82		$	210		$	(79	)	$	213		$	0.72
Six months ended June 30, 2011
Ongoing Earnings	$	251		$	252		$	(90	)	$	413		$	1.40
Tax levelization		(3	)		(2	)		(1	)		(6	)		(0.02	)
CVO mark-to-market		-			-			4			4			0.01
Merger and integration costs, net of tax(a)		(11	)		(10	)		-			(21	)		(0.07	)
CR3 indemnification charge, net of tax(a)		-			(26	)		-			(26	)		(0.09	)
Discontinued operations attributable to controlling   interests, net of tax		-			-			(4	)		(4	)		(0.01	)
Net income (loss) attributable to controlling interests(b)	$	237		$	214		$	(91	)	$	360		$	1.22

(a)	Calculated using assumed tax rate of 40 percent to the extent items are tax deductible.
(b)	Net income attributable to controlling interests is shown net of preferred stock dividend requirement of $(1) million at both PEC and PEF for the six months ended June 30, 2012 and 2011.

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Management uses the non-GAAP financial measure Ongoing Earnings (i) as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; (iii) as a measure for determining levels of incentive compensation; and (iv) in communications with our board of directors, employees, shareholders, analysts and investors concerning our financial performance. Management believes this non-GAAP measure is appropriate for understanding the business and assessing our potential future performance, because excluded items are limited to those that management believes are not representative of our fundamental core earnings (See Note 12).

OVERVIEW

For the three months ended June 30, 2012, our net income attributable to controlling interests was $63 million, or $0.21 per share, compared to net income attributable to controlling interests of $176 million, or $0.60 per share, for the same period in 2011. The decrease as compared to prior year was primarily due to:

·   higher O&M expense at the Utilities;

·   higher depreciation and amortization expense at PEF; and

·   unfavorable impact of weather at the Utilities.

Offsetting these items was:

·   lower CR3 indemnification charge for the estimated joint owner replacement power costs for future years (through the expiration of the indemnification provisions of the joint owner agreement) (Ongoing Earnings adjustment).

For the six months ended June 30, 2012, our net income attributable to controlling interests was $213 million, or $0.72 per share, compared to net income attributable to controlling interests of $360 million, or $1.22 per share, for the same period in 2011. The decrease as compared to prior year was primarily due to:

·   higher O&M expense at PEC;

·   unfavorable impact of weather at the Utilities; and

·   higher depreciation and amortization expense at the Utilities.

Offsetting these items was:

·   lower CR3 indemnification charge for the estimated joint owner replacement power costs for future years (through the expiration of the indemnification provisions of the joint owner agreement) (Ongoing Earnings adjustment).

PROGRESS ENERGY CAROLINAS

PEC contributed net income available to parent totaling $31 million and $107 million for the three months ended June 30, 2012 and 2011, respectively. The decrease in net income available to parent was primarily due to higher O&M expense resulting from an additional nuclear refueling outage and the unfavorable impact of weather. PEC contributed Ongoing Earnings of $42 million and $112 million for the three months ended June 30, 2012 and 2011. The Ongoing Earnings adjustments to net income available to parent were a $4 million and $1 million tax levelization charge for 2012 and 2011, respectively, and a $7 million and $4 million charge, net of tax, for merger and integration costs for 2012 and 2011, respectively. Management does not consider these items to be representative of PEC’s fundamental core earnings and excluded these items in computing PEC’s Ongoing Earnings.

PEC contributed net income available to parent totaling $82 million and $237 million for the six months ended June 30, 2012 and 2011, respectively. The decrease in net income available to parent was primarily due to higher O&M expense resulting from two additional nuclear refueling outages and the unfavorable impact of weather. PEC contributed Ongoing Earnings of $103 million and $251 million for the six months ended June 30, 2012 and 2011, respectively. The Ongoing Earnings adjustments to net income available to parent were a $10 million and $3 million

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tax levelization charge for 2012 and 2011, respectively, and an $11 million charge, net of tax, for merger and integration costs for both 2012 and 2011, respectively. Management does not consider these items to be representative of PEC’s fundamental core earnings and excluded these items in computing PEC’s Ongoing Earnings.

Three Months Ended June 30, 2012, Compared to Three Months Ended June 30, 2011

REVENUES

The revenue tables that follow present the total amount and percentage change of total operating revenues and its components. “Base Revenues" is a non-GAAP measure and is defined as operating revenues excluding clause recoverable regulatory returns, miscellaneous revenues, fuel and other pass-through revenues and refunds, if any. 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. PEC’s clause-recoverable regulatory revenues include renewable energy clause revenues and the return on asset component of DSM and EE. The reconciliation and analysis that follow are a complement to the financial information provided in accordance with GAAP.

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

(in millions)
Customer Class	2012		Change			% Change			2011
Residential	$	228	$	(20	)		(8.1	)	$	248
Commercial		169		(5	)		(2.9	)		174
Industrial		86		(2	)		(2.3	)		88
Governmental		13		(2	)		(13.3	)		15
Unbilled		16		9		NM				7
Total retail base revenues		512		(20	)		(3.8	)		532
Wholesale base revenues		82		11			15.5			71
Total Base Revenues		594		(9	)		(1.5	)		603
Clause-recoverable regulatory revenues		11		4			57.1			7
Miscellaneous		33		1			3.1			32
Fuel and other pass-through revenues		444		26		NM				418
Total operating revenues	$	1,082	$	22			2.1		$	1,060
NM - not meaningful

PEC’s total Base Revenues were $594 million and $603 million for the three months ended June 30, 2012 and 2011, respectively. The $9 million decrease in Base Revenues was primarily due to the $27 million unfavorable impact of weather, partially offset by $11 million higher wholesale base revenues and the $8 million favorable impact of retail customer growth and usage. The unfavorable impact of weather was driven by 22 percent lower cooling-degree days than 2011. Additionally, cooling-degree days were 1 percent lower than normal in 2012 compared to 31 percent higher than normal in 2011. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2011 Form 10-K for a summary of degree days and weather estimation. The higher wholesale base revenues were primarily due to the $7 million impact of an amended capacity contract with a major customer that began in May 2012. This capacity revenue was offset by additional purchased power expense and therefore does not have a material impact on earnings. These revenues and associated expenses will continue through the expiration of the contract in December 2012. The favorable impact of retail customer growth and usage was primarily due to an increase in the average usage per retail customer and a net 12,000 increase in the average number of customers for 2012 compared to 2011.

Clause-recoverable regulatory revenues were $11 million and $7 million for the three months ended June 30, 2012 and 2011, respectively. The $4 million increase in clause-recoverable regulatory revenues was primarily due to increased spending on new and existing DSM programs compared to 2011.

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

(in millions of kWh)
Customer Class	2012		Change			% Change			2011
Residential		3,544		(363	)		(9.3	)		3,907
Commercial		3,354		(86	)		(2.5	)		3,440
Industrial		2,683		1			-			2,682
Governmental		381		7			1.9			374
Unbilled		198		124		NM				74
Total retail kWh sales		10,160		(317	)		(3.0	)		10,477
Wholesale		3,306		337			11.4			2,969
Total kWh sales		13,466		20			0.1			13,446

Retail kWh sales decreased primarily due to the unfavorable impact of weather compared to the prior year as previously discussed.

Wholesale kWh sales increased primarily due to a decrease in jointly-owned production resulting from nuclear refueling outages which led the joint owner to purchase from PEC.

EXPENSES

Fuel and Purchased Power

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

Fuel and purchased power expenses were $426 million for the three months ended June 30, 2012, which represents a $27 million increase compared to the same period in 2011. This increase was primarily due to the impact of higher fuel rates.

Operation and Maintenance

O&M expense was $386 million for the three months ended June 30, 2012, which represents a $93 million increase compared to the same period in 2011. This increase was primarily due to $56 million higher nuclear plant outage costs, $10 million higher substation and line maintenance costs related to a reliability initiative, $9 million higher employee benefit expenses and $5 million higher merger and integration costs. The higher nuclear plant outage costs are primarily due to one extended nuclear refueling outage for the second quarter in 2012 compared to no outage in the same period in 2011. 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.

Total Interest Charges, Net

Total interest charges, net was $53 million for the three months ended June 30, 2012, which represents a $5 million increase compared to the same period in 2011. This increase was primarily due to higher average long-term debt outstanding.

Income Tax Expense

Income tax expense decreased $42 million for the three months ended June 30, 2012, as compared to the same period in 2011, primarily due to the $47 million tax impact of lower pre-tax income, partially offset by the $3

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million impact of tax levelization. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Because this adjustment will vary each quarter, but will have no effect on net income for the year, management does not consider this adjustment to be representative of PEC’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEC’s Ongoing Earnings.

Six Months Ended June 30, 2012, Compared to Six Months Ended June 30, 2011

REVENUES

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

(in millions)
Customer Class	2012		Change			% Change			2011
Residential	$	505	$	(75	)		(12.9	)	$	580
Commercial		331		(10	)		(2.9	)		341
Industrial		165		(6	)		(3.5	)		171
Governmental		27		(3	)		(10.0	)		30
Unbilled		9		37		NM				(28	)
Total retail base revenues		1,037		(57	)		(5.2	)		1,094
Wholesale base revenues		151		7			4.9			144
Total Base Revenues		1,188		(50	)		(4.0	)		1,238
Clause-recoverable regulatory returns		22		8			57.1			14
Miscellaneous		67		4			6.3			63
Fuel and other pass-through revenues		890		12		NM				878
Total operating revenues	$	2,167	$	(26	)		(1.2	)	$	2,193

PEC’s total Base Revenues were $1.188 billion and $1.238 billion for the six months ended June 30, 2012 and 2011, respectively. The $50 million decrease in Base Revenues was primarily due to the $75 million unfavorable impact of weather, partially offset by the $19 million favorable impact of retail customer growth and usage. The unfavorable impact of weather was driven by 24 percent lower heating-degree days and 16 percent lower cooling-degree days than 2011. Additionally, in 2012, heating-degree days were 28 percent lower than normal and cooling-degree days were 7 percent higher than normal, whereas in 2011, heating-degree days were 5 percent lower than normal and cooling-degree days were 31 percent higher than normal. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2011 Form 10-K for a summary of degree days and weather estimation. The favorable impact of retail customer growth and usage was driven by an increase in the average usage per retail customer and a net 10,000 increase in the average number of customers for 2012 compared to 2011.

Clause-recoverable regulatory returns were $22 million and $14 million for the six months ended June 30, 2012 and 2011, respectively. The $8 million increase in clause-recoverable returns was due primarily to increased spending on new and existing DSM programs compared to 2011.

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

(in millions of kWh)
Customer Class	2012		Change			% Change			2011
Residential		7,979		(1,367	)		(14.6	)		9,346
Commercial		6,470		(257	)		(3.8	)		6,727
Industrial		5,112		(58	)		(1.1	)		5,170
Governmental		744		(16	)		(2.1	)		760
Unbilled		65		660		NM				(595	)
Total retail kWh sales		20,370		(1,038	)		(4.8	)		21,408
Wholesale		6,264		86			1.4			6,178
Total kWh sales		26,634		(952	)		(3.5	)		27,586

Retail kWh sales decreased primarily due to the unfavorable impact of weather compared to the prior year as previously discussed.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $840 million for the six months ended June 30, 2012, which represents an $11 million increase compared to the same period in 2011. This increase was primarily due to the $49 million impact of higher fuel rates and the $30 million impact of generation mix, which was driven by nuclear refueling outages in 2012, partially offset by the $67 million impact of lower system requirements resulting from unfavorable weather compared to 2011.

Operation and Maintenance

O&M expense was $760 million for the six months ended June 30, 2012, which represents a $172 million increase compared to the same period in 2011. This increase was primarily due to $121 million higher nuclear plant outage costs, $22 million higher employee benefit expenses related to updated actuarial estimates and unfavorable claims experience and $11 million higher substation and line maintenance costs related to a reliability initiative, partially offset by $1 million lower merger and integration costs. The higher nuclear plant outage costs are primarily due to three extended nuclear refueling outages in 2012 compared to only one outage during the same period in 2011. 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.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion was $268 million for the six months ended June 30, 2012, which represents an $18 million increase compared to the same period in 2011. This increase was primarily due to higher depreciable asset base driven by the combined-cycle unit at the Smith Energy Complex, which was placed in service in June 2011.

Total Interest Charges, Net

Total interest charges, net was $104 million for the six months ended June 30, 2012, which represents an $11 million increase compared to the same period in 2011. This increase was primarily due to higher average long-term debt outstanding.

Income Tax Expense

Income tax expense decreased $88 million for the six months ended June 30, 2012, as compared to the same period in 2011, primarily due to the $97 million impact of lower pre-tax income, partially offset by the $7 million impact of tax levelization. As previously discussed, management does not consider tax levelization to be representative of

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PEC’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEC’s Ongoing Earnings.

PROGRESS ENERGY FLORIDA

PEF contributed net income available to parent totaling $83 million and $113 million for the three months ended June 30, 2012 and 2011, respectively. The decrease in net income available to parent was primarily due to the prior-year reduction of the cost of removal component of amortization expense as allowed under the 2010 settlement agreement, higher O&M expense and the unfavorable impact of weather, partially offset by a prior-year indemnification charge for the joint owner replacement power costs related to the continued outage of CR3. PEF contributed Ongoing Earnings of $85 million and $141 million for the three months ended June 30, 2012 and 2011, respectively. The Ongoing Earnings adjustments to net income available to parent were a $1 million tax levelization charge and a $1 million tax levelization benefit for 2012 and 2011, respectively; a $6 million and $3 million charge, net of tax, for merger and integration costs for 2012 and 2011, respectively; and a $5 million adjustment, net of tax and $26 million charge, net of tax, for indemnification for the estimated future years’ joint owner replacement power costs for CR3 for 2012 and 2011, respectively. Management does not consider these items to be representative of PEF’s fundamental core earnings and excluded these items in computing PEF’s Ongoing Earnings.

PEF contributed net income available to parent totaling $210 million and $214 million for the six months ended June 30, 2012 and 2011, respectively. The decrease in net income available to parent was primarily due to a decrease in the reduction of the cost of removal component of amortization expense as allowed under the 2012 and 2010 settlement agreements and the unfavorable impact of weather, partially offset by a prior-year indemnification charge for the joint owner replacement power costs related to the continued outage of CR3, lower O&M expense, higher wholesale base revenues and higher miscellaneous revenues. PEF contributed Ongoing Earnings of $214 million and $252 million for the six months ended June 30, 2012 and 2011, respectively. The Ongoing Earnings adjustments to net income available to parent were a $2 million tax levelization charge for both 2012 and 2011; a $7 million and $10 million charge, net of tax, for merger and integration costs for 2012 and 2011, respectively; and a $5 million adjustment, net of tax, and a $26 million charge, net of tax, for indemnification for the estimated future years’ joint owner replacement power costs for CR3 for 2012 and 2011, respectively. Management does not consider these items to be representative of PEF’s fundamental core earnings and excluded these items in computing PEF’s Ongoing Earnings.

Three Months Ended June 30, 2012, Compared to Three Months Ended June 30, 2011

REVENUES

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

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

(in millions)
Customer Class	2012		Change			% Change			2011
Residential	$	232	$	(8	)		(3.3	)	$	240
Commercial		89		(2	)		(2.2	)		91
Industrial		19		-			-			19
Governmental		23		-			-			23
Unbilled		17		(10	)	NM				27
Total retail base revenues		380		(20	)		(5.0	)		400
Wholesale base revenues		34		5			17.2			29
Total Base Revenues		414		(15	)		(3.5	)		429
Clause-recoverable regulatory returns		44		(2	)		(4.3	)		46
Miscellaneous		65		9			16.1			56
Fuel and other pass-through revenues		666		4		NM				662
Total operating revenues	$	1,189	$	(4	)		(0.3	)	$	1,193

PEF’s total Base Revenues were $414 million and $429 million for the three months ended June 30, 2012 and 2011, respectively. The $15 million decrease in Base Revenues was due primarily to the $19 million unfavorable impact of weather, partially offset by $5 million higher wholesale base revenues. The unfavorable impact of weather was driven by 11 percent lower cooling-degree days than 2011. Cooling-degree days were 3 percent higher than normal in 2012 compared to 16 percent higher than normal in 2011. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2011 Form 10-K for a summary of degree days and weather estimation. The $5 million increase in wholesale base revenues was due primarily to contract changes with a major customer.

Miscellaneous revenues were $65 million and $56 million for the three months ended June 30, 2012 and 2011, respectively. The $9 million increase in miscellaneous revenues was primarily due to higher open access transmission tariff rates in 2012 compared to 2011.

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

(in millions of kWh)
Customer Class	2012		Change			% Change			2011
Residential		4,525		(156	)		(3.3	)		4,681
Commercial		2,961		(71	)		(2.3	)		3,032
Industrial		808		(41	)		(4.8	)		849
Governmental		813		(9	)		(1.1	)		822
Unbilled		397		(267	)	NM				664
Total retail kWh sales		9,504		(544	)		(5.4	)		10,048
Wholesale		433		(375	)		(46.4	)		808
Total kWh sales		9,937		(919	)		(8.5	)		10,856

Retail kWh sales decreased primarily due to the unfavorable impact of weather as previously discussed.

Wholesale kWh sales decreased primarily due to the unfavorable impact of weather, which resulted in decreased deliveries under a certain capacity contract. Despite the decrease in wholesale kWh sales, wholesale base revenues increased primarily due to demand charges associated with a contract with a major customer.

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EXPENSES

Fuel and Purchased Power

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

Fuel and purchased power expenses were $567 million for the three months ended June 30, 2012, which represents a $37 million decrease compared to the same period in 2011. This decrease was primarily due to lower fuel and purchased power costs of $158 million, partially offset by an increase in deferred fuel expense of $118 million. The lower fuel and purchased power costs were driven by the combined $100 million impact of lower natural gas prices in 2012, a shift in generation mix, and lower system requirements in 2012 as a result of the unfavorable impact of weather. Additionally, there was a $52 million lower CR3 indemnification charge for the estimated joint owner replacement power costs for future years (through the expiration of the indemnification provisions of the joint owner agreement). The increase in deferred fuel expense is primarily due to higher under-recovered fuel costs in 2011 as a result of higher system requirements driven by favorable weather. Management does not consider the CR3 indemnification of future years’ joint owner replacement power costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

Operation and Maintenance

O&M expense was $246 million for the three months ended June 30, 2012, which represents a $22 million increase compared to the same period in 2011. This increase was primarily due to recognition as expense of $18 million previously deferred costs related to the CR3 repair project as discussed in Note 5B and $3 million higher merger and integration costs. Management does not consider merger and integration costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’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 $29 million compared to the same period in 2011.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $92 million for the three months ended June 30, 2012, which represents a $44 million increase compared to the same period in 2011. This increase was primarily due to the $54 million prior-year reduction of the cost of removal component of amortization expense as allowed under the 2010 settlement agreement (See Note 5B), partially offset by $16 million lower nuclear cost-recovery amortization primarily related to the Levy project. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and, therefore, has no material impact on earnings. Note 5B in this Form 10-Q and Note 8C in the 2011 Form 10-K provide additional information about these regulatory expenses.

Income Tax Expense

Income tax expense decreased $12 million for the three months ended June 30, 2012, compared to the same period in 2011, primarily due to the $17 million tax impact of lower pre-tax income, partially offset by the $2 million impact of tax levelization. GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Because this adjustment will vary each quarter, but will have no effect on net income for the year, management does not consider this adjustment to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

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Six Months Ended June 30, 2012, Compared to Six Months Ended June 30, 2011

REVENUES

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

(in millions)
Customer Class	2012		Change			% Change			2011
Residential	$	424	$	(35	)		(7.6	)	$	459
Commercial		167		(2	)		(1.2	)		169
Industrial		36		(1	)		(2.7	)		37
Governmental		44		1			2.3			43
Unbilled		29		17		NM				12
Total retail base revenues		700		(20	)		(2.8	)		720
Wholesale base revenues		68		13			23.6			55
Total Base Revenues		768		(7	)		(0.9	)		775
Clause-recoverable regulatory returns		93		2			2.2			91
Miscellaneous		118		12			11.3			106
Fuel and other pass-through revenues		1,215		(38	)	NM				1,253
Total operating revenues	$	2,194	$	(31	)		(1.4	)	$	2,225

PEF’s total Base Revenues were $768 million and $775 million for the six months ended June 30, 2012 and 2011, respectively. The $7 million decrease in Base Revenues was due primarily to the $21 million unfavorable impact of weather, partially offset by $13 million higher wholesale base revenues. The unfavorable impact of weather was driven by 31 percent lower heating-degree days and 1 percent lower cooling-degree days than 2011. Cooling-degree days were 12 percent higher than normal in 2012 and were 13 percent higher than normal in 2011. See Item 1, “Business – Seasonality and the Impact of Weather,” to the 2011 Form 10-K for a summary of degree days and weather estimation. The $13 million increase in wholesale base revenues was primarily due to a new contract with a major customer.

Miscellaneous revenues were $118 million and $106 million for the six months ended June 30, 2012 and 2011, respectively. The $12 million increase in miscellaneous revenues was primarily due to higher open access transmission tariff rates in 2012 compared to 2011.

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

(in millions of kWh)
Customer Class	2012		Change			% Change			2011
Residential		8,230		(732	)		(8.2	)		8,962
Commercial		5,526		(52	)		(0.9	)		5,578
Industrial		1,565		(56	)		(3.5	)		1,621
Governmental		1,566		17			1.1			1,549
Unbilled		731		422		NM				309
Total retail kWh sales		17,618		(401	)		(2.2	)		18,019
Wholesale		731		(555	)		(43.2	)		1,286
Total kWh sales		18,349		(956	)		(5.0	)		19,305

Retail kWh sales decreased primarily due to the unfavorable impact of weather as previously discussed.

Wholesale kWh sales decreased primarily due to the unfavorable impact of weather, which resulted in decreased deliveries under a certain capacity contract. Despite the decrease in wholesale kWh sales, wholesale base revenues increased primarily due to demand charges associated with a contract with a major customer.

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EXPENSES

Fuel and Purchased Power

Fuel and purchased power expenses were $1.048 billion for the six months ended June 30, 2012, which represents a $64 million decrease compared to the same period in 2011. This decrease was primarily due to lower fuel and purchased power costs of $188 million, partially offset by an increase in deferred fuel expense of $116 million. The lower fuel and purchased power costs were driven by the combined $114 million impact of lower natural gas prices in 2012, a shift in generation mix, and lower system requirements in 2012 as a result of the unfavorable impact of weather. Additionally, there was a $52 million lower CR3 indemnification charge for the estimated joint owner replacement power costs for future years (through the expiration of the indemnification provisions of the joint owner agreement). The increase in deferred fuel expense is primarily due to higher under-recovered fuel costs in 2011 as a result of higher system requirements driven by favorable weather. Management does not consider the CR3 indemnification of future years’ joint owner replacement power costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

Operation and Maintenance

O&M expense was $406 million for the six months ended June 30, 2012, which represents a $28 million decrease compared to the same period in 2011. This decrease was primarily due to the $47 million reversal of certain regulatory liabilities in accordance with the 2012 settlement agreement and $4 million lower merger and integration costs, partially offset by recognition as expense of $18 million previously deferred costs related to the CR3 repair project as previously discussed (See Note 5B). Management does not consider merger and integration costs to be representative of PEF’s fundamental core earnings. Therefore, the impact of this item is excluded in computing PEF’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 decreased $17 million compared to the same period in 2011.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion expense was $119 million for the six months ended June 30, 2012, which represents a $46 million increase compared to the same period in 2011. This increase was primarily due to the $76 million decrease in the reduction of the cost of removal component of amortization expense as allowed under the 2012 and 2010 settlement agreements (See Note 5B), partially offset by $39 million lower nuclear cost-recovery amortization primarily related to the Levy project. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and, therefore, has no material impact on earnings. Note 5B in this Form 10-Q and Note 8C in the 2011 Form 10-K provide additional information about these regulatory expenses.

Other

Other operating expense was a gain of $12 million for the six months ended June 30, 2011, primarily due to a favorable litigation judgment.

Income Tax Expense

Income tax expense was $126 million for the six months ended June 30, 2012 and 2011. PEF’s income tax expense was increased by $2 million for the six months ended June 30, 2012 and 2011, related to the impact of tax levelization. As previously discussed, management does not consider this adjustment to be representative of PEF’s fundamental core earnings. Accordingly, the impact of this item is excluded in computing PEF’s Ongoing Earnings.

CORPORATE AND OTHER

The Corporate and Other segment primarily includes the operations of the Parent, PESC and 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.

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The following table reconciles Corporate and Other’s Ongoing Earnings to GAAP net income attributable to controlling interests:

	Three months ended June 30,						Six months ended June 30,
(in millions)	2012			2011			2012			2011
Other interest expense	$	(70	)	$	(68	)	$	(141	)	$	(147	)
Other income tax benefit		29			27			53			59
Other expense		(6	)		(1	)		(6	)		(2	)
Ongoing Earnings		(47	)		(42	)		(94	)		(90	)
Tax levelization		-			(4	)		-			(1	)
CVO mark-to-market		-			4			8			4
Discontinued operations attributable to   controlling interests, net of tax		(4	)		(2	)		7			(4	)
Net loss attributable to controlling interests	$	(51	)	$	(44	)	$	(79	)	$	(91	)

OTHER INCOME TAX BENEFIT

Other income tax benefit decreased $6 million for the six months ended June 30, 2012 compared to the same period in 2011, primarily due to the $5 million impact at the Corporate level resulting from the deductions for domestic production activities taken by the Utilities.

ONGOING EARNINGS ADJUSTMENTS

Tax Levelization

GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was not impacted for the three and six months ended June 30, 2012, compared to an increase in income tax expense of $4 million and $1 million for the three and six months ended June 30, 2011, respectively, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Because this adjustment will vary each quarter, but will have no effect on net income for the year, management does not consider this adjustment to be representative of our fundamental core earnings.

CVO Mark-to-Market

Progress Energy issued 98.6 million CVOs in connection with the acquisition of Florida Progress in 2000. Each CVO represents the right of the holder to receive contingent payments based on the performance of four synthetic fuels facilities purchased by subsidiaries of Florida Progress in October 1999. The payments are based on the net after-tax cash flows the facilities generate. See Note 16 in the 2011 Form 10-K for further information.

As of June 30, 2012, Progress Energy has repurchased and holds 83.4 million of the outstanding CVOs. At June 30, 2012 and 2011, the CVOs not held by Progress Energy had fair values of $3 million and $11 million, respectively. The gain/loss recognized due to changes in fair value of the CVOs is recorded in other, net on the Consolidated Statements of Comprehensive Income. There was no change in the fair value of the CVOs for the three months ended June 30, 2012. Progress Energy recorded a gain of $4 million for the three months ended June 30, 2011 to record the changes in fair value of the CVOs. Progress Energy recorded a gain of $8 million and $4 million for the six months ended June 30, 2012 and 2011, respectively, to record the changes in fair value of the CVOs. The CVOs had average unit prices of $0.21 and $0.12 at June 30, 2012 and 2011, respectively. Because Progress Energy is unable to predict the changes in the fair value of the CVOs, management does not consider this adjustment to be representative of our fundamental core earnings. Therefore, the impact of changes in fair value of CVOs is excluded in computing our Ongoing Earnings.

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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 $4 million and $2 million of loss from discontinued operations attributable to controlling interests, net of tax, for the three months ended June 30, 2012 and 2011, respectively. We recognized $7 million of income from discontinued operations attributable to controlling interests, net of tax, and $4 million of loss from discontinued operations attributable to controlling interests, net of tax, for the six months ended June 30, 2012 and 2011, respectively. The $11 million increase for the six months ended June 30, 2012 compared to the same period in 2011 is primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period expired in the first quarter of 2012. 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. Following the merger with Duke Energy, our operating cash flow, substantially all of which is generated by the Utilities, intercompany borrowings, our participation in the Duke Energy MCF, our ability to access the long-term debt capital markets and/or equity contributions from Duke Energy will provide our sources of liquidity. As discussed in “Future Liquidity and Capital Resources” below, synthetic fuels tax credits will provide an additional source of liquidity as those credits are realized.

The majority of our operating costs are related to the Utilities. Most of these costs are recovered from ratepayers in accordance with various rate plans. We are allowed to recover certain fuel, purchased power and other costs incurred by PEC and PEF through their respective recovery clauses. The types of costs recovered through clauses vary by jurisdiction. Fuel price volatility and plant performance can lead to over- or under-recovery of fuel costs, as changes in fuel expense are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility and plant performance can be both a source of and a use of liquidity resources, depending on what phase of the cycle of price volatility we are experiencing and/or how our plants are performing. Changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows, but not materially affect net income. In addition, as discussed in “Future Liquidity and Capital Resources” below, the timing of applicable CR3 repair and the associated replacement power cost recovery from NEIL could impact short-term borrowing needs.

Following the merger with Duke Energy, PEC, PEF and PESC receive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to participating affiliates. The money pool is structured such that the participants separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between the money pool participants. Per the terms of the money pool arrangement, the parent companies, including Duke Energy Corporation and Progress Energy, Inc., may loan funds to their participating subsidiaries, but may not borrow funds through the money pool. The internal money pools that our subsidiaries participated in prior to the merger were terminated upon consummation of the merger.

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 interest and principal payments on the Parent’s $4.0 billion of senior unsecured debt. The Parent’s needs will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; borrowings under an intercompany note with Duke Energy and/or equity contributions from Duke Energy. During the six months ended June 30, 2012, PEC paid dividends of $310 million and PEF paid dividends of $170 million to the Parent. A number of factors impact the Utilities’ decision or ability to pay dividends to 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 from the Utilities from year to year. In addition, the Parent and the Utilities may seek equity contributions from Duke Energy Corporation depending on their cash flow needs.

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At June 30, 2012, we had a combined $1.978 billion of RCAs for the Parent, PEC and PEF. The RCAs served as back-ups to our commercial paper programs. To the extent amounts were reserved for commercial paper or letters of credit outstanding, they were not available for additional borrowings. At June 30, 2012, the Parent had no outstanding borrowings under its credit facility, $201 million of outstanding commercial paper and $2 million of outstanding letters of credit, which were supported by the RCA. At June 30, 2012, PEC and PEF had no outstanding borrowings under their respective RCAs. PEC had no outstanding commercial paper and PEF had $144 million of outstanding commercial paper.

On July 2, 2012, the Parent terminated its $478 million RCA, and PEC and PEF terminated their respective $750 million RCAs and became borrowers under the Duke Energy MCF. In November 2011, Duke Energy entered into a new $6.0 billion, five-year MCF, with $4.0 billion available at closing and the remaining $2.0 billion available following consummation of the merger. PEC and PEF each have borrowing capacity under the MCF up to $750 million. However, Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimit of each borrower, subject to a maximum sublimit of $1.0 billion each for PEC and PEF. Following the merger, the cash needs of the Parent will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; borrowings under an intercompany note from Duke Energy and/or equity contributions from Duke Energy. Neither Progress Energy, Inc., PEC nor PEF will issue commercial paper following the merger.

At June 30, 2012, 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 June 30, 2012, the majority of the Utilities’ open financial commodity hedges were in net mark-to-market liability positions. See Note 11A for additional information with regard to our commodity derivatives.

At June 30, 2012, 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 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 June 30, 2012, PEC’s and PEF’s open pay-fixed forward starting swaps were each in a net mark-to-market liability position. See Note 11B for additional information with regard to our interest rate derivatives.

The 2010 Wall Street Reform and Consumer Protection Act (the Wall Street Reform Act) provides for the comprehensive regulation of swaps and security-based swaps, applying in respects to the bilateral and over-the-counter (OTC) derivatives markets. Generally, the Wall Street Reform Act provides for certain exemptions from the mandatory clearing and exchange trading requirements for certain participants (such as end-users that are not swap dealers) that engage in hedging activities to mitigate or hedge physical risk. The U.S. Commodity Futures Trades Commission (CFTC) had extended the deadline for significant aspects of the legislation until the earlier of December 31, 2012, or issuance and effectiveness of final implementing regulations. On July 10, 2012, the CFTC issued its final rule defining a “swap.” This rule will become effective 60 days after it is published in the Federal Register, and upon its effectiveness the other rules will also begin to take effect. We are studying the issued rules and timing of their implementation to prepare for applicable compliance requirements. We are also studying the impact of the rules on our hedging transactions; however, it is difficult to predict how the market will adjust to the new regulations. In general, the proposed regulations are anticipated to cause some changes to the OTC derivatives markets that may affect market-makers and companies that trade or hedge using financial products, such as the requirement to clear OTC derivatives through a central clearinghouse or exchange. Given that we enter into commodity and interest rate hedges to mitigate commercial risk and/or hedge physical positions, rather than as part of a regular swap business, we do not believe we meet the definitions of “swap dealer” or “major swap participant” under the rules. Therefore, we expect that we will be exempt from the law’s mandatory clearing and trading provisions, subject to certain reporting requirements. Nevertheless, this requirement could raise the incremental cost of hedging activities as it may require these counterparties to post additional margin and maintenance margin for OTC derivatives, which would then increase the liquidity requirements needed to support these activities. Currently, we have credit collateral thresholds in place with our counterparties that do not require the posting of collateral unless the market value of our hedges drops below the negotiated threshold dollar value. Additionally, we have negotiated several bi-lateral non-margin hedging agreements with counterparties where margin posting is not required on certain transactions. Even assuming we are considered exempt from certain mandatory clearing of OTC

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derivatives and more stringent collateral requirements under the proposed regulation because our hedging activities are for the purpose of managing commercial risk for customers and not for speculative trading purposes, we may yet be subject to higher incremental costs for hedging transactions because of the margining requirements imposed on our counterparties. If some of our counterparties are subject to higher liquidity requirements due to the proposed regulation, we could be subject to higher incremental costs for hedging transactions in the form of potential increases in bid/offer spreads on market hedge transactions; potential reduction by certain counterparties in the use of non-marginable OTC transactions; and potential reduction in the number of counterparties who will be available for hedging transactions with us.

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 2011 Form 10-K.

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

HISTORICAL FOR 2012 AS COMPARED TO 2011

CASH FLOWS FROM OPERATIONS

Net cash provided by operating activities decreased $29 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The decrease was primarily due to the $144 million net increase in O&M expense and the $96 million unfavorable impact of weather, both at the Utilities as previously discussed, an increase in payments for terminations of interest rate locks of $57 million and a $45 million decrease in NEIL reimbursements for replacement power costs resulting from the CR3 extended outage (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”), partially offset by a $187 million decrease in pension plan funding and $135 million lower cash used for inventory. The decrease in cash used for inventory was primarily due to lower purchases of coal inventory reflecting favorable natural gas prices in 2012 combined with higher purchases for planned outages and maintenance activities in 2011.

INVESTING ACTIVITIES

Net cash used by investing activities increased by $41 million for the six months ended June 30, 2012, when compared to the same period in the prior year. This increase was primarily due to a $76 million increase in gross property additions, the $32 million decrease in NEIL insurance proceeds for repairs at CR3 and $27 million of litigation judgment proceeds received in the prior year, partially offset by receipt of a DOE award of which $62 million was applicable to past capitalized spent fuel storage costs at PEC and $28 million lower nuclear fuel purchases. The increase in gross property additions was primarily due to increased capital expenditures for nuclear and transmission projects, partially offset by lower spending for generation projects.

FINANCING ACTIVITIES

Net cash provided by financing activities increased by $472 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The increase was primarily due to a $548 million increase in proceeds from short-term and long-term debt, net of retirements, partially offset by an $80 million increase in dividends paid primarily related to a special dividend paid in January 2012 to align our dividend schedule with that of Duke Energy.

A discussion of our 2012 financing activities follows:

On February 15, 2012, the Parent’s $478 million RCA was amended to extend the expiration date from May 3, 2012, to May 3, 2013, with its existing syndication of 14 financial institutions. On July 2, 2012, the Parent

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terminated its $478 million RCA, and PEC and PEF terminated their respective $750 million RCAs and became borrowers under the Duke Energy MCF.

On March 1, 2012, the Parent, as a well-known seasoned issuer, PEC and PEF filed a combined shelf registration statement with the SEC, which became effective upon filing with the SEC. The registration statement is effective for three years and does not limit the amount or number of various securities that can be issued. On July 3, 2012, the Parent deregistered its equity securities from the registration statement in connection with the merger, but retained its ability to issue senior debt securities and junior subordinated debentures under the registration statement. Following the merger, we do not expect the Parent to issue any new securities of these types. Under PEC’s and PEF’s registration statements, they may issue various long-term debt securities and preferred stock.

On March 8, 2012, the Parent issued $450 million of 3.15% Senior Notes due April 1, 2022. The net proceeds, along with available cash on hand, were used to retire the $450 million outstanding aggregate principal balance of our 6.85% Senior Notes due April 15, 2012.

On May 18, 2012, PEC issued $500 million of 2.80% First Mortgage Bonds due May 15, 2022 and $500 million of 4.10% First Mortgage Bonds due May 15, 2042. The net proceeds were used to retire at maturity the $500 million outstanding aggregate principal balance of PEC’s 6.50% Notes due July 15, 2012 and a portion of PEC’s outstanding commercial paper and notes payable to affiliated companies.

SHORT-TERM DEBT

At June 30, 2012, Progress Energy had outstanding short-term debt consisting of commercial paper borrowings totaling $345 million at a weighted average interest rate of 0.49%. At the end of each month during the three months ended June 30, 2012, Progress Energy had a maximum short-term debt balance of $1.12 billion and an average short-term debt balance of $642 million at a weighted average interest rate of 0.52%.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2012, there were no material changes in our discussion under “Liquidity and Capital Resources” in Item 7 to the 2011 Form 10-K, other than as described below and in “Historical for 2012 as Compared to 2011 – 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 June 30, 2012, we have carried forward $865 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 the Duke Energy MCF, participation in the Duke Energy money pool arrangement, the intercompany note with Duke Energy, equity contributions from Duke Energy and/or long-term debt issuances, which are dependent on our ability to successfully access capital markets.

Credit rating downgrades could negatively impact our ability to access the capital markets and respond to major events such as hurricanes. Our cost of capital could also be higher, which could ultimately increase prices for our customers. It is important for us to maintain our credit ratings and have access to the capital markets in order to reliably serve customers, invest in capital improvements and prepare for our customers’ future energy needs (See Item 1A, “Risk Factors” to 2011 Form 10-K).

Prior to the merger with Duke Energy, we typically issued commercial paper to meet short-term liquidity needs. Following the merger, our short-term liquidity needs will typically be met through participation in the Duke Energy money pool arrangement and the intercompany note with Duke Energy, which will both be funded in part by commercial paper issuances by Duke Energy. If liquidity conditions deteriorate and negatively impact the

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commercial paper market, we will need to evaluate other, potentially more expensive, options for meeting short-term liquidity needs, which may include borrowing under the Duke Energy MCF, issuing short-term notes and/or issuing long-term debt.

Progress Energy and its subsidiaries have approximately $13.937 billion in outstanding long-term debt, including the $925 million current portion. Currently, approximately $860 million of the Utilities’ debt obligations, approximately $620 million at PEC and approximately $240 million at PEF, are tax-exempt auction rate securities insured by bond insurance. These tax-exempt bonds have experienced and continue to experience failed auctions. Assuming the failed auctions persist, future interest rate resets on our tax-exempt auction rate bond portfolio will be dependent on the volatility experienced in the indices that dictate our interest rate resets and/or rating agency actions that may lower our tax-exempt bond ratings. In the event of a one-notch downgrade of PEC’s and/or PEF’s senior secured debt rating by S&P, the ratings of such utility’s tax-exempt bonds would be below A-, most likely resulting in higher future interest rate resets. In the event of a one-notch downgrade by Moody’s, PEC’s and PEF’s tax-exempt bonds will continue to be rated at or above A3. We will continue to monitor this market and evaluate options to mitigate our exposure to future volatility.

The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations under our defined benefit pension plans. Although a number of factors impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the obligations under our defined benefit pension plans. During the six months ended June 30, 2012, we contributed $42 million directly to pension plan assets and expect to make total contributions of approximately $150 million in 2012. The amounts we contribute may be impacted by recently enacted legislation as well as other factors (See Note 10).

As discussed in “Liquidity and Capital Resources” and in “Other Matters – Environmental Matters,” over the long term, compliance with environmental regulations and meeting the anticipated load growth at the Utilities as described under “Other Matters – Energy Demand” will require the Utilities to make significant capital investments. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation. As discussed in “Other Matters – Nuclear – Potential New Construction,” PEF is shifting the in-service date for the first Levy unit to 2024, with the second unit following 18 months later.

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, 2011, have impacted the amount of collateral posted with counterparties. At June 30, 2012, we had posted approximately $124 million of cash collateral compared to $147 million of cash collateral posted at December 31, 2011. The majority of our financial hedge agreements will settle in 2012 and 2013. Additional commodity market price decreases could result in significant increases in the derivative collateral that we are required to post with counterparties. We continually monitor our derivative positions in relation to market price activity. Credit rating downgrades could also require us to post additional cash collateral for commodity hedges in a liability position as certain derivative instruments require us to post collateral on liability positions based on our credit ratings.

The amount and timing of future sales of debt will depend on market conditions, operating cash flow and our specific liquidity needs. We may from time to time sell securities beyond the amount immediately needed to meet our capital or liquidity requirements in order to pre-fund 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 June 30, 2012, the current portion of our long-term debt was $925 million, including $500 million at PEC and $425 million at PEF. PEC retired its 6.50% Notes due July 15, 2012 with proceeds from its May 18, 2012 issuance of $500 million 2.80% First Mortgage Bonds due May 15, 2022, and $500 million 4.10% First Mortgage Bonds due May 15, 2042. PEF expects to fund its $425 million of First Mortgage Bonds due March 1, 2013, with short-term borrowings and/or long-term debt issuances.

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Both PEC and PEF can issue additional first mortgage bonds under their respective first mortgage bond indentures based on property additions, retirements of first mortgage bonds and the deposit of cash if certain conditions are satisfied. Most first mortgage bond issuances by PEC and PEF require that adjusted net earnings be at least twice the annual interest requirement for bonds currently outstanding and to be outstanding. PEF’s ratio of net earnings to the annual interest requirement for bonds outstanding, as defined in PEF’s mortgage, was below 2.0 times at June 30, 2012. PEF’s June 30, 2012 ratio of net earnings was impacted by a $288 million charge recorded in December 2011 for amounts to be refunded to customers (See Note 5B). Until this ratio, which is calculated based on results for 12 consecutive months, is above 2.0 times, PEF’s capacity to issue additional first mortgage bonds is limited to $300 million based on retirements of previously issued first mortgage bonds. In the event PEF’s long-term debt requirements exceed its first mortgage bond capacity, it can access alternative sources of capital including, but not limited to, issuing unsecured public debt or through private placement, borrowing under the money pool, entering into bilateral direct loan arrangements, and, if necessary, utilizing the available capacity under the Duke Energy MCF.

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, including the CR3 outage and nuclear cost recovery, as discussed in Note 5 and “Other Matters – Nuclear,” and recovery of environmental costs, as discussed in Note 13 and in “Other Matters – Environmental Matters,” may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Energy legislation enacted in recent years may impact our liquidity over the long term, including among others, provisions regarding cost recovery, mandated renewable portfolio standards, DSM and EE.

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

PEC Cost Recovery Filings

On June 4, 2012, PEC filed with the NCUC for a $40 million decrease in the fuel rate charged to its North Carolina retail ratepayers, driven by declining natural gas prices. If approved, the decrease will be effective December 1, 2012. On June 4, 2012, PEC also filed for a $16 million increase in the DSM and EE rate charged to its North Carolina retail ratepayers which, if approved, will be effective December 1, 2012. We cannot predict the outcome of these matters.

On June 27, 2012, the PSCSC approved a $23 million decrease in the fuel rate charged to PEC’s South Carolina ratepayers, driven by declining natural gas prices, effective July 1, 2012. On May 23, 2012, the PSCSC approved a $5 million increase in the DSM and EE rate, effective July 1, 2012.

PEF CR3 Outage

The preliminary estimate of $900 million to $1.3 billion is currently under review and could change following completion of further detailed engineering studies, vendor negotiations and final risk assessments.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power when the unit is out of service as a result of these events. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through June 30, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. 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. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL

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has unresolved concerns and has not made any payments on the second delamination and has not provided a written coverage decision for either delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, we have agreed to mediation prior to commencing any formal dispute resolution. We are in the process of providing information as requested by NEIL and currently have scheduled the mediation to commence in fourth quarter of 2012. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, as of June 30, 2012, PEF has not recorded insurance receivables from NEIL related to either the first or second delamination. PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

The following table summarizes the CR3 replacement power and repair costs and recovery through June 30, 2012:

(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	534		$	305
NEIL proceeds received		(162	)		(143	)
Balance for recovery(a)	$	372		$	162

(a) See "2012 Settlement Agreement" below for discussion of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

PEF 2012 Settlement Agreement

On February 22, 2012, the FPSC approved a comprehensive settlement agreement among PEF, the Florida Office of Public Counsel and other consumer advocates. The agreement, which will continue through the last billing cycle of December 2016, addresses three principle matters: cost recovery of Levy, the CR3 delamination prudence review then pending before the FPSC and certain base rate issues. The agreement sets the Levy cost-recovery factor at a fixed amount during the term of the settlement and also allows PEF to recover investments and replacement power costs for CR3 in various circumstances. The parties to the agreement have waived or limited their rights to challenge the prudence of various costs related to CR3. The agreement provides for a $150 million annual increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5 percent. In the month following CR3’s return to commercial service, PEF’s ROE range will increase to 9.7 percent to 11.7 percent. Additionally, PEF will refund $288 million to customers through the fuel clause over four years, beginning in 2013. See Note 5B for additional provisions of the 2012 settlement agreement.

PEF Cost-Recovery Filings

On April 30, 2012, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $152 million, which includes recovery of pre-construction and carrying costs and CCRC recoverable O&M expense incurred or anticipated to be incurred during 2013, recovery of $88 million of prior years’ deferrals in 2013, as well as the estimated actual true-up of 2012 costs associated with the CR3 uprate and Levy projects, as permitted by the 2012 settlement agreement. If approved, the new rates would begin with the first January 2013 billing cycle. 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 June 30, 2012, our guarantees have not changed materially from what was reported in the 2011 Form 10-K.

Effective with the consummation of the merger with Duke Energy on July 2, 2012, Progress Energy and Duke Energy have guaranteed to provide $650 million in system fuel savings for retail customers in North Carolina and South Carolina (See Note 2).

MARKET RISK AND DERIVATIVES

Under our risk management policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk” for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2011 Form 10-K can result from new contracts, changes in existing contracts, and the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs. At June 30, 2012,our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 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. We are evaluating the impacts of environmental regulations, which could include the potential need to retire additional generating facilities earlier than their current estimated useful lives. The table below summarizes the status of key environmental regulations that impact, or may impact, the Utilities. The table is followed by a detailed discussion of each regulation.

	Status	Primarily Regulates	Compliance Strategy
Impacting Solid Waste
Coal Combustion Residuals
	Final rule is not expected before 2013	Storage, use and disposal of coal ash and flue gas desulfurization materials	Proposed rule included two significantly different options. Compliance method cannot be determined until the rule is finalized

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           Status              Primarily Regulates                    Compliance Strategy

Impacting Air Quality
CAIR / CSAPR
	CAIR in effect pending resolution of appeal of CSAPR	NOx, SO2	Previously installed air pollution controls and fleet modernization projects, and use of emission allowances
MATS
	Compliance due April 2015 with provisions for one-year extension from state agencies on case-by- case basis	Mercury and other hazardous metals, acid gases, hydrogen fluoride, dioxin/furan from coal- and oil-fired generating units	Previously installed air pollution controls and fleet modernization projects largely address for PEC; for PEF, additional controls and/or fleet modernization required
NC Mercury
	NC-specific requirements in effect	Mercury	Federal MATS compliance
CAVR – BART provisions
	Effective 2013	NOx, SO2 and particulate matter	Assessing BART impact; EPA allows CSAPR compliance to fulfill BART requirements
NC Clean Smokestacks
	In effect	NOx, SO2	Currently in compliance. Retirement of selected coal-fired generation facilities and replacement with natural gas-fired generation for post-2013
NAAQS
	In effect	Ozone, NO2, SO2 and particulate matter	Currently in compliance. Additional controls may be necessary if nonattainment is determined
GHG New Source Performance Standards
	Proposed rule issued March 27, 2012	GHGs	Case-by-case determination for new units

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           Status              Primarily Regulates                    Compliance Strategy

Impacting Water Quality
Effluent Guideline Revisions
	Proposed regulation anticipated by November 20, 2012	Wastewater discharges from steam- electric power plant	Cannot be determined until final rule is issued
316(b)
	Final rules are expected by June 27, 2013	Cooling water intake structures for steam-electric power plants	Modification of traveling screens; assessment of environmental impacts and alternative technologies for reducing those impacts; and possible installation of new technologies

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the CERCLA authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida or 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 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 5 and 13). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. Hazardous and solid waste management matters are discussed in detail in Note 13A.

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 at this time the total costs that may be incurred in connection with the remediation of all sites. It is probable that current estimates could change and additional losses, which could be material, may be incurred in the future.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residuals, 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 residuals. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residuals management and disposal under federal hazardous waste rules. The other option would have the EPA set performance standards for coal combustion residuals management facilities and regulate disposal of coal combustion residuals as nonhazardous waste (as most states do now). 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 recycled coal combustion residuals. A final rule is not expected before sometime in 2013, at the earliest. There are federal legislative proposals that may direct the EPA to regulate coal combustion residues destined for disposal as non-hazardous wastes. Environmental groups filed a lawsuit on April 5, 2012, in the U.S. District Court for the District of Columbia to require the EPA to complete its rulemaking process and finalize new

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regulations for the storage, transportation and disposal of coal combustion residues. On June 19, 2012, the U.S. District Court granted the petition for leave to intervene by the Utility Solid Waste Activities Group, of which we are a member. Compliance plans and estimated costs to meet the requirements of new regulations or statutes 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

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations, which are discussed below, may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. However, the outcome of these matters cannot be predicted.

Clean Air Interstate Rule/Cross-State Air Pollution Rule

The CAIR, issued by the EPA, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2. States were required to adopt rules implementing the CAIR, and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR. A 2008 decision by the D.C. Court of Appeals remanded the CAIR without vacating it for the EPA to conduct further proceedings.

On July 7, 2011, the EPA issued the CSAPR to replace the CAIR. The CSAPR, which was scheduled to take effect on January 1, 2012, contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. A number of parties, including groups of which PEC and PEF are members, filed petitions for reconsideration and stay of, as well as legal challenges to, the CSAPR. On December 30, 2011, the D.C. Court of Appeals issued an order staying the implementation of the CSAPR, pending a decision by the court resolving the challenges to the rule. Oral argument for the CSAPR litigation occurred on April 13, 2012. As a result of the stay of CSAPR, the CAIR will remain in effect. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. If the CSAPR is upheld, North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season trading program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required in 2014. Under the CSAPR, Florida is subject only to the NOx ozone season trading program. We cannot predict the outcome of this matter.

Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe PEC and PEF are positioned to comply with the CSAPR without the need for significant capital expenditures. 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, largely address the CAIR and CSAPR requirements for NOx and SO2 for our North Carolina units at PEC. NOx and SO2 emission control equipment are in service at PEF’s CR4 and CR5, and we plan to continue compliance with the CAIR in 2012 through a combination of emission controls, continued use of natural gas at applicable facilities and use of emission allowances.

Under an agreement with the FDEP, PEF will retire CR1 and CR2 and operate emission control equipment at CR4 and CR5. CR1 and CR2 were originally scheduled to be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was anticipated to be around 2020. As discussed in Note 5B and “Other Matters – Nuclear – Potential New Construction,” major construction activities for Levy are being postponed, and the in-

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service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of developments that may delay the retirement of CR1 and CR2 (see further discussion under “Mercury Regulation” and “Clean Air Visibility Rule”). We are continuing to evaluate the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

Mercury Regulation

After prior mercury regulation was vacated in federal court, the EPA developed MACT standards. The MATS, which are the final MACT standards for coal-fired and oil-fired electric steam generating units, became effective on April 16, 2012. Compliance is due three years after the effective date with provision for a one-year extension granted by state agencies on a case-by-case basis. The MATS 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. Several petitions regarding portions of the MATS rule have been filed in the D.C. Court of Appeals, including one by the Utility Air Regulatory Group, of which we are a member. On July 20, 2012, the EPA announced that it will reconsider the new source emissions standards contained in the MATS rule. 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. Due to significant investments in NOx and SO2 emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy (See Note 5B). We are continuing to evaluate the impacts of the MATS on the Utilities. CR1 and CR2 are under evaluation for MATS compliance with the potential to be retired. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

Clean Air Visibility Rule

The EPA’s Clean Air Visibility Rule (CAVR) requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in certain specially protected areas, including national parks and wilderness areas, designated as Class I areas. To help restore visibility in those areas, states must require the identified facilities to install best available retrofit technology (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 and CR1 and CR2. The reductions associated with BART begin in 2013. As discussed in Note 5A, 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, under an agreement with the FDEP, PEF will retire CR1 and CR2 as coal-fired units, and will convert Anclote to 100 percent natural gas.

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 continues to satisfy BART for NOx and SO2. In addition, on June 7, 2012, the EPA published a final rule providing that compliance with the requirements in the CSAPR will fulfill the BART requirements for SO2 and NOx under the regional haze program.Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of SO2 emissions in addition to particulate matter emissions for PEF’s BART-eligible units, because Florida will no longer be subject to the current CAIR SO2 emissions provisions. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. 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. Effective March 28, 2012, the FDEP completed 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.

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In March 2012, the EPA published a settlement that sets a schedule for action on the regional haze state implementation plans submitted by the states. The deadlines in the consent decree provide that all final EPA actions on the regional haze state implementation plans are to occur no later than November 15, 2012; however, a date for final action on the Florida state implementation plan was not included. On July 20, 2012, the EPA filed a proposed consent decree that requires the EPA to issue a final rule for its May 25, 2012 proposed limited approval of Florida’s regional haze state implementation plan by November 15, 2012. It also requires the EPA to issue a proposed rule by December 3, 2012, and a final rule by July 15, 2013, addressing the remainder of Florida’s state implementation plan. The FDEP is working with the EPA to complete development of an approvable regional haze state implementation plan. On April 13, 2012, the EPA indicated to the FDEP that it would initiate a federal process for making BART determinations for eligible sources in Florida. The FDEP responded with a list of companies working with the FDEP on the appropriate BART determinations, and the EPA agreed not to take action against those companies. PEF worked with the FDEP on BART determinations for Anclote and CR1 and CR2, which were included in the July 2012 FDEP submittal to the EPA. The outcome of these matters cannot be predicted.

Clean Smokestacks Act

The 2002 enactment of the Clean Smokestacks Act requires North Carolina’s electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,000 MW of coal-fired generation capacity in North Carolina 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 implemented a plan to retire, by the end of 2013, its coal-fired generating facilities in North Carolina (originally 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. The first units were retired in 2011. We anticipate that these actions will satisfy the Clean Smokestacks Act limits subsequent to 2013.

Compliance Strategy

Both PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, the CSAPR, the CAVR, MATS 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 and CSAPR 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 the CAIR are in service.

The FPSC approved PEF’s petition to develop and implement an Integrated Clean Air Compliance Plan to comply with the CAIR, the Clean Air Mercury Rule and the CAVR and for recovery of prudently incurred costs necessary to achieve this strategy through the ECRC. The Clean Air Mercury Rule was subsequently vacated and the CAIR was remanded (see previous discussion regarding mercury rules and the remanding of the CAIR and its potential impact on CAVR). PEF’s April 2, 2012 filing with the FPSC for true-up of final 2011 environmental costs included a review of the Integrated Clean Air Compliance Plan, which reconfirmed the efficacy of the recommended plan and the cost-effectiveness of PEF’s retrofit options for each generating unit in relation to expected changes in environmental regulations. PEF does not currently plan to install the air pollution control equipment at Anclote previously anticipated in its approved Integrated Clean Air Compliance Plan as the plant will be converted to 100 percent natural gas. Additional costs may be incurred if pollution controls are required in order to comply with the requirements of the CAVR, as discussed previously, or to meet compliance requirements of the CSAPR. Subsequent rule interpretations, increases in the underlying material, labor and equipment costs, equipment availability, or the unexpected acceleration of compliance dates, among other things, could result in material 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 2011 Form 10-K. Costs to comply with environmental laws and regulations are eligible for regulatory recovery

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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. Additional compliance plans for PEC and PEF to meet the requirements of the CSAPR have not been completed. Compliance plans and costs to meet the requirements of the CAVR are being reassessed, and we cannot predict the impact that the EPA’s further proceedings will have on our compliance with the CAVR requirements. Compliance plans to meet the requirements of the MATS are being developed. We currently estimate that if the decision is made to retire PEF’s CR1 and CR2, MATS compliance costs at the Utilities could range from $150 million to $300 million. If the units are not retired, PEF’s MATS compliance costs could exceed $1 billion. 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 material.

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. In November 2011, environmental groups petitioned the court to require the EPA to issue a proposal regarding reconsideration of the standards by February 15, 2012, and issue a final rule by September 15, 2012. On January 23, 2012, the EPA replied to the petition with a schedule that would require the agency to issue a proposed rule by June 2012 and a final rule by June 2013. On June 29, 2012, the EPA published a proposed revision to the PM2.5 (particulate matter that is 2.5 micrometers in diameter and smaller) NAAQS that would reduce the annual standard to within the range of 12 to 13 micrograms per cubic meter from the current 15 micrograms per cubic meter. Compliance would be due by 2020. The EPA also proposed a secondary urban visibility standard. Comments on the proposal are due August 31, 2012. The outcome of this matter cannot be predicted.

In 2010, the EPA announced a revision to the primary NAAQS for nitrogen dioxide (NO2). Currently, there are no monitors reporting violation of this new standard in our service territories, but an expanded monitoring network will provide additional data, which could result in additional nonattainment areas. Also, the EPA revised the 1-hour NAAQS for SO2 in 2010. The EPA plans to implement the new 1-hour NAAQS for SO2 using 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. However, no additional nonattainment areas have been designated to date in our service territories and on April 12, 2012, the EPA indicated that it will not require modeling for state implementation plan submittals required by June 2013. On July 17, 2012, the D.C. Court of Appeals upheld the new one-hour NAAQS for NO2, and on July 20, 2012, the D.C. Court of Appeals upheld the new one-hour NAAQS for SO2. Should additional nonattainment areas for the NAAQS for NO2 and SO2 be designated in our service territories, we may be required to install additional emission controls at some of our facilities.

On March 21, 2011, the EPA issued its final rule on the combined review of the secondary NAAQS for NOx and sulfur oxides (SOx). In this rulemaking, the EPA established the secondary standards for NOx and SOx NAAQS as equal to the existing secondary standards for NO2 and SO2. For NOx, the new standard is 53 parts per billion averaged over one year, measured as NO2. For SOx, the new standard is 500 parts per billion averaged over three hours, measured as SO2. Given there currently are not any nonattainment areas for the secondary NO2 and SO2

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NAAQS in our service territories, we consider it unlikely that nonattainment areas will be designated for the secondary NAAQS for NOx and SOx.

Global Climate Change

State, federal and international attention to global climate change is expected to result in the regulation of carbon dioxide (CO2) and other greenhouse gases (GHG). We continue to believe that this issue requires a national policy framework – one that provides certainty and consistency. Our balanced solution as discussed in “Other Matters – Energy Demand” is a comprehensive plan to meet the anticipated demand in our service territories and provides a solid basis for slowing and reducing CO2 emissions by focusing on energy efficiency, alternative and renewable energy and a state-of-the-art power system.

The EPA 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 GHG emissions from new automobiles. According to the EPA this also subjects stationary sources, such as coal-fired power plants, to regulation of GHG emissions under the CAA. In 2009, the EPA finalized the Endangerment Finding that six GHGs (CO2, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) pose a threat to public health and welfare under the CAA. In 2010, the EPA promulgated the “tailoring rule” which establishes thresholds for applicability of the Prevention of Significant Deterioration and Title V permitting program requirements for GHG emissions from stationary sources such as power plants and manufacturing facilities. A number of parties filed petitions for review of this finding and related rules in the D.C. Court of Appeals. On June 26, 2012, the D.C. Circuit issued its opinion in the litigation involving the EPA’s GHG rules, finding for the EPA in all of the challenges: Endangerment finding and the EPA’s denial of petitions for reconsideration of endangerment finding; GHG emission standards for light-duty motor vehicles; Tailoring rule and Reconsideration of the December 2008 Johnson Memorandum; Historical Interpretation/Grounds Arising After case. The court concluded that the Endangerment Finding and Tailpipe Rule were neither arbitrary nor capricious and that no petitioner has standing to challenge the Timing and Tailoring Rules. Some parties may file motions for rehearing or for rehearing en banc with the D.C. Circuit and/or filing a petition for a writ of certiorari with the Supreme Court. The outcome of this matter cannot be predicted. 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 material 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.

On April 13, 2012, the EPA published in the Federal Register its proposed rule to establish CO2 emissions standards for pulverized coal, integrated gasification combined cycle, and natural gas combined cycle electric generating units that are permitted and constructed in the future. The proposal would not apply to any of PEC’s or PEF’s coal and natural gas generation plants that are currently under construction or in operation. Any future pulverized coal and integrated gasification combined cycle units will have to employ carbon capture and storage technology to meet the CO2 emission standard the EPA has proposed. The proposed standard will not require new natural gas combined cycle facilities to install carbon capture and storage technology. Management does not expect any material impact on the future results of operations or cash flows based on the EPA’s proposal. The final rule, however, could be significantly different from the proposal. It is not known when the EPA might finalize the rule.

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

Reductions in CO2 emissions to the levels specified by the Kyoto Protocol, potential new international treaties or federal or state proposals could be materially adverse to our financial position or results of operations if associated

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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.

WATER QUALITY

General

As a result of the operation of certain pollution control equipment required to address 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 applicable regulations have not kept pace with changes in the electric power industry, including 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. In late 2010, the EPA and several environmental groups agreed on a schedule for revision of the steam-electric effluent guidelines, which are the federal rules used to establish limits for water discharges under the National Pollutant Discharge Elimination System. According to a joint stipulation filed by the EPA and the environmental groups in the U.S. District Court for the District of Columbia, the EPA is to release the proposed rule by November 20, 2012, and take final action on the rule by April 28, 2014. The outcome of this matter cannot be predicted.

More stringent effluent limitations contained in the current water discharge permit for the Mayo Steam Electric Plant became effective in June 2011. The plant is currently unable to comply with those limitations. The North Carolina Division of Water Quality issued a special order by consent on June 25, 2012, that requires the development and installation of enhanced water pollution control technology and defers the agency’s enforcement of the more stringent effluent limitations until PEC’s planned project to bring the plant into compliance is completed. The special order by consent does not prevent actions by the EPA or third parties. Thus, the outcome of these matters cannot be determined.

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. 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. In July 2012, the settlement was modified to extend the EPA’s requirement to issue final Section 316(b) rules to June 27, 2013.

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On April 20, 2011, the EPA published its proposed regulations for cooling water intake structures at existing power generating, 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 uniform nationwide standards for impingement mortality (immobilization of aquatic organisms against an intake screen) and case-by-case, site-specific standards for entrainment mortality (lethal effects due to passage of aquatic organisms into a cooling system). PEC and PEF submitted comments on the proposed rule. The outcome of this matter cannot be predicted.

REGULATORY ENVIRONMENT

The Utilities’ operations in North Carolina, South Carolina and Florida are regulated by the NCUC, the PSCSC 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 5, including specific retail rate matters, the status of the issues and the associated effects on our consolidated financial statements.

In 2010, we accepted a grant from the 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 150,000 smart meters and additional public infrastructure for plug-in electric vehicles. Projects funded by the grant must be completed by April 2013. As permitted by the grant contract, we have requested a one-year extension from the DOE. We are continuing to work with the DOE to obtain approval for the proposed extension. We cannot predict the outcome of this matter.

Through June 30, 2012, we have incurred $298 million of allowable, 50 percent reimbursable, smart grid project costs and have submitted requests to the DOE for reimbursement of $144 million, of which we have received $131 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 2011 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.

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

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On July 27, 2012, PEC announced accelerated plans to retire the 316-MW Cape Fear coal-fired generating units, originally planned to be retired in 2013, and to retire the 177-MW H.B. Robinson Unit 1 coal-fired generating unit. These units will be retired on October 1, 2012. The Robinson retirement combined with the previously announced retirements total more than 1,600 MW at five sites in the Carolinas.

As discussed in Note 5B, PEF announced that the oil and natural gas-fired Anclote Units 1 and 2 will be converted to 100 percent natural gas fired. The Anclote units, which have a combined 1,011 MW of generating capacity, are expected to be placed in service by the end of 2013.

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.

FUKUSHIMA RESPONSE

Following the events at the Fukushima Daiichi nuclear power station in Japan, we conducted thorough inspections at each of our four nuclear sites during 2011. The initial inspections have not identified any significant vulnerabilities, however, we are reviewing designs to increase safety margins to external events. Emergency-response capabilities, written procedures and engineering specifications were reviewed to verify each site’s ability to respond in the unlikely event of station blackout or record flood. In 2012, we are working to establish industry best practices and improve the safety standards and margin using the three layers of safety approach used in the U.S.: protection, mitigation and emergency response. Emergency equipment is currently being added at each station to perform key safety functions in the event that backup power sources are lost permanently. These improvements are in addition to the numerous layers of safety measures and systems previously in place.

In March 2011, the NRC formed a task force to conduct a comprehensive review of processes and regulations to determine whether the agency should make additional improvements to the nuclear regulatory system. On July 13, 2011, the task force proposed a set of improvements designed to ensure protection, enhance accident mitigation, strengthen emergency preparedness and improve efficiency of NRC programs. The recommendations were further prioritized into three tiers based on the safety enhancement level. On March 12, 2012, the NRC issued three regulatory orders requiring safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at a plant, ensuring reliable hardened containment vents and enhancing spent fuel pool instrumentation. The NRC held public meetings with stakeholders to develop implementation guidance that is expected to be issued by the NRC in August 2012. Plants are then required to submit implementation plans to the NRC by February 28, 2013, and complete implementation of the safety enhancements within two refueling outages or by December 31, 2016, whichever comes first. Each plant is also required to reassess their seismic and flooding hazards using present-day methods and information, conduct inspections to ensure protection against hazards in the current design basis, and re-evaluate emergency communications systems and staffing levels. In May 2012, the NRC issued guidance on re-evaluating emergency communications systems and staffing levels and performing seismic and flooding walkdowns. The NRC is expected to issue guidance on performing seismic and flooding re-evaluations in November 2012. Notices for Tier 2 and 3 recommendations are expected to be issued later this year.

We are committed to compliance with all safety enhancements ordered by the NRC, the cost of which could be material. With the NRC’s continuing review of the remaining recommendations, we cannot predict to what extent the NRC will impose additional licensing and safety-related requirements, or the costs of complying with such requirements. The tight timeframe required to complete the necessary safety enhancements by no later than 2016 could lead to even higher costs. Upon receipt of additional guidance from the NRC and a collaborative industry review, we will be able to determine our implementation plan and associated costs. See Item 1A, “Risk Factors”, in the 2011 Form 10-K for further discussion of applicable risk factors.

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CR3 OUTAGE

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

PEF is analyzing the various aspects of the repair option as well as the option of early retirement. A number of factors could affect the decision to repair, the return-to-service date and repair costs incurred, including, but not limited to, state regulatory and NRC reviews, insurance recoveries from NEIL, the ability to obtain builder’s risk insurance with appropriate coverage, final engineering designs, vendor contract negotiations, the ultimate work scope completion, performance testing, weather and the impact of new information discovered during additional testing and analysis (See Note 5B).

POTENTIAL NEW CONSTRUCTION

During 2008, PEC and PEF filed COL applications to potentially construct new nuclear plants in North Carolina and Florida. We anticipate that the NRC will issue the COLs no earlier than 2013 if the current licensing schedule remains on track. However, due to the March 12, 2012 NRC orders mentioned above, delays in NRC issuance of the final safety review for the COLs are possible.

We have focused on Levy given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce GHG emissions, as well as existing state legislative policy that is supportive of nuclear projects. PEF has entered into an 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 as discussed below.

On April 30, 2012, as part of PEF’s annual nuclear cost recovery filing (See Note 5B), PEF updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current, low natural gas prices, PEF is shifting the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 settlement agreement. Although the scope and overnight cost for Levy – including land acquisition, related transmission work and other required investments – remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

SPENT NUCLEAR FUEL MATTERS

See Note 14 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 $1.026 billion has been used through June 30, 2012, to offset regular federal income tax liability and $865 million is being carried forward as deferred tax credits that do not expire.

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See Note 14C and Item 1A, “Risk Factors,” and “MD&A – Other Matters – Synthetic Fuels Tax Credits” to the 2011 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 14C.

NEW ACCOUNTING STANDARDS

See Note 3 for a discussion of the impact of new accounting standards.

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PEC

The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors,” to the 2011 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 $86 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The decrease was primarily due to a $172 million increase in O&M expense, the $75 million unfavorable impact of weather, $69 million in lower net tax refunds and $36 million paid for interest rate locks terminated in conjunction with the issuance of long-term debt, partially offset by a $128 million decrease in pension plan funding and $122 million lower cash used for inventory. The decrease in cash used for inventory was primarily due to lower purchases of coal inventory reflecting favorable natural gas prices in 2012 combined with higher purchases for planned outages and maintenance activities in 2011.

Net cash used by investing activities increased $236 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The increase was primarily due to a $231 million change in advances to affiliated companies and a $104 million increase in gross property additions, partially offset by receipt of a DOE award of which $62 million was applicable to past capitalized spent fuel storage costs and $30 million lower nuclear fuel purchases. The increase in gross property additions was primarily due to increased capital expenditures for nuclear and transmission projects, partially offset by decreased spending on generation projects.

Net cash provided by financing activities increased $535 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The increase was primarily due to the $1 billion issuance of first mortgage bonds in 2012, partially offset by $188 million in commercial paper repayments in 2012 compared with $198 million of borrowings in 2011 and the $35 million increase in payment of dividends to the Parent.

SHORT-TERM DEBT

At June 30, 2012, PEC had no outstanding short-term debt. At the end of each month during the three months ended June 30, 2012, PEC had a maximum short-term debt balance of $575 million and an average short-term debt balance of $200 million at a weighted average interest rate of 0.55%. PEC’s short-term debt during the three months ended June 30, 2012, included both commercial paper and 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 June 30, 2012 and December 31, 2011, PEC had issued $10 million and $19 million of guarantees for future financial or performance assurance,

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respectively. PEC does not believe conditions are likely for significant performance under the guarantees of performance issued.

Effective with the consummation of the merger with Duke Energy on July 2, 2012, Progress Energy and Duke Energy have guaranteed to provide $650 million in system fuel savings for retail customers in North Carolina and South Carolina (See Note 2).

MARKET RISK AND DERIVATIVES

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

CONTRACTUAL OBLIGATIONS

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

OTHER MATTERS

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

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PEF

The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors,” to the 2011 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

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

RESULTS OF OPERATIONS

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

LIQUIDITY AND CAPITAL RESOURCES

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

Net cash provided by operating activities decreased $67 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The decrease was primarily due to $103 million higher net cash for taxes, a $45 million decrease in NEIL reimbursements for replacement power costs resulting from the CR3 extended outage (See “Future Liquidity and Capital Resources – Regulatory Matters and Recovery of Costs – CR3 Outage”) and the $21 million less favorable impact of weather as previously discussed, partially offset by a $57 million decrease in pension plan funding and a $28 million decrease in O&M expense as previously discussed.

Net cash used by investing activities increased $12 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The increase was primarily due to a $32 million decrease in NEIL insurance proceeds for repairs at CR3 and $27 million of litigation judgment proceeds received in the prior year, partially offset by a $39 million decrease in gross property additions and $11 million of increased smart grid reimbursement proceeds.

Net cash used by financing activities decreased $313 million for the six months ended June 30, 2012, when compared to the same period in the prior year. The decrease was primarily due to the $238 million change in advances from affiliated companies and the $230 million decrease in payment of dividends to the Parent, partially offset by $89 million in commercial paper repayments in 2012 compared with $67 million of borrowings in 2011.

SHORT-TERM DEBT

At June 30, 2012, PEF had $387 million of outstanding short-term debt, consisting of both commercial paper and money pool borrowings, at a weighted average interest rate of 0.33%. At the end of each month during the three months ended June 30, 2012, PEF had a maximum short-term debt balance of $387 million and an average short-term debt balance of $356 million at a weighted average interest rate of 0.46%. PEF’s short-term debt during the three months ended June 30, 2012, included both commercial paper and money pool 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 11 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 had a risk management committee that included senior executives from various business groups. The risk management committee was responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Following the consummation of the merger with Duke Energy, the risk management committee was replaced with Duke Energy’s Transaction and Risk Committee which will be responsible for the oversight of risk at the combined company. The Transaction and Risk Committee will include senior executives from various functional areas.Following the consummation of the merger, PEC and PEF will continue to operate under their existing risk guidelines. Under our risk guidelines, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk to the extent that the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties (See Note 11). Both PEC and PEF also have limited counterparty exposure for commodity hedges (primarily gas and oil hedges) by spreading concentration risk over a number of counterparties.

The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors,” found within Part II of this Form 10-Q and Item 1A, “Risk Factors,” to the 2011 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.

Certain market risks are inherent in our financial instruments, which arise from transactions entered into in the normal course of business. Our primary exposures are changes in interest rates with respect to our long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to our 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, 2011.

INTEREST RATE RISK

Our debt portfolio and our exposure to changes in interest rates at June 30, 2012, have changed from December 31, 2011. The total notional amount of fixed rate long-term debt at June 30, 2012, was $12.828 billion, with an average interest rate of 5.45% and fair market value of $15.2 billion. Subsequent to June 30, 2012, PEC retired at maturity $500 million of 6.50% Notes due July 15, 2012. The total notional amount of fixed rate long-term debt at December 31, 2011, was $11.829 billion, with an average interest rate of 5.76% and fair market value of $14.1 billion. At both June 30, 2012 and December 31, 2011, the total notional amount and fair market value of our variable rate long-term debt was $861 million. At June 30, 2012 the average interest rate of our variable rate long-term debt was 0.36% and at December 31, 2011, the average interest rate of our variable rate long-term debt was 0.30%.

In addition to our variable rate long-term debt, at June 30, 2012, we had approximately $345 million of outstanding commercial paper, which is also exposed to floating interest rates, and no loans outstanding under our credit facilities. At December 31, 2011, we had approximately $667 million of outstanding commercial paper and no loans under our credit facilities. At June 30, 2012, and December 31, 2011, approximately 8 percent and 11 percent of consolidated debt was in floating rate mode.

Based on our variable rate debt balances at June 30, 2012,a 100 basis point change in interest rates would result in an annual pre-tax interest expense change of approximately $12 million.

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

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

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

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

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

Cash Flow Hedges (dollars in millions)	Notional Amount		Mandatory Settlement		Pay			Receive (a)	Fair Value			Exposure (b)
Parent
Risk hedged at June 30, 2012
			None
Risk hedged at December 31, 2011
Anticipated 10-year debt issue	$	200		2012		4.20	%	3-month LIBOR	$	(38	)	$	(5	)
PEC
Risk hedged at June 30, 2012
Anticipated 10-year debt issue	$	50		2013		4.43	%	3-month LIBOR	$	(11	)	$	(1	)
Risk hedged at December 31, 2011
Anticipated 10-year debt issue	$	200		2012		4.27	%	3-month LIBOR	$	(38	)	$	(5	)
Anticipated 10-year debt issue	$	50		2013		4.43	%	3-month LIBOR	$	(9	)	$	(1	)
PEF
Risk hedged at June 30, 2012
Anticipated 10-year debt issue	$	50		2013		4.30	%	3-month LIBOR	$	(11	)	$	(1	)
Risk hedged at December 31, 2011
Anticipated 10-year debt issue	$	50		2013		4.30	%	3-month LIBOR	$	(9	)	$	(1	)

(a) 3-month London Inter Bank Offered Rate (LIBOR) was 0.46% at June 30, 2012and 0.58% at December 31, 2011.

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

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

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fluctuations in equity markets and to changes in interest rates. At June 30, 2012 and December 31, 2011, the fair value of these funds was $1.757 billion and $1.647 billion, respectively, including $1.164 billion and $1.088 billion, respectively, for PEC and $593 million and $559 million, respectively, for PEF. We actively monitor our portfolio by benchmarking the performance of our investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK

CVOs are recorded at fair value, and gains and losses from changes in fair value are recognized in earnings. The 15.2 million outstanding CVOs not held by Progress Energy at June 30, 2012, had a fair value of $3 million. The 18.5 million outstanding CVOs not held by Progress Energy at December 31, 2011, had a fair value of $14 million. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analyses performed on the CVOs use observable 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 June 30, 2012 market price does not have a significant impact on the fair value of the CVOs and the corresponding 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 June 30, 2012, substantially all derivative commodity instrument positions were subject to retail regulatory treatment.

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

Furthermore, effective with the consummation of the merger with Duke Energy on July 2, 2012, Progress Energy entered into certain derivative power sales agreements with three counterparties in conjunction with the Interim FERC Mitigation Plan. See Note 2 for additional information regarding future charges related to the merger, including the Interim FERC Mitigation Plan.

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, 2011.

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

Pursuant to the Securities Exchange Act of 1934, we, PEC and PEF carried out an evaluation, with the participation of management, including our 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, PEC’s and PEF’s internal control over financial reporting during the quarter ended June 30, 2012, that has materially affected, or is reasonably likely to materially affect, our, PEC’s or PEF’s internal control over financial reporting.

Subsequent to the consummation of the merger with Duke Energy on July 2, 2012, William D. Johnson is no longer Chief Executive Officer of Progress Energy, Lloyd M. Yates is no longer Chief Executive Officer of PEC, and Vincent M. Dolan is no longer Chief Executive Officer of PEF. James E. Rogers, Chairman, President and Chief Executive Officer of Duke Energy, is now Chief Executive Officer of Progress Energy, PEC and PEF.

Also subsequent to the consummation of the merger, Jeffrey M. Stone is no longer Chief Accounting Officer and Mark F. Mulhern is no longer Chief Financial Officer of Progress Energy, PEC and PEF. Steven K. Young is now Chief Accounting Officer and Lynn J. Good is now Chief Financial Officer of Progress Energy, PEC and PEF.

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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 14C).

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 2011 Form 10-K, which could materially affect our business, financial condition or financial results. The risks described in the 2011 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 April 20, 2012, June 7, 2012, June 8, 2012, June 12, 2012 and June 22, 2012, 36,172 shares, 73 shares, 1,825 shares, 45,800 shares and 1,782 shares, respectively, of our common stock were delivered to certain current and former employees pursuant to the terms of the Progress Energy 2007 Equity Incentive Plan (the EIP) which has been approved by Progress Energy’s shareholders. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.

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

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

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

PERFORMANCE SHARE SUB-PLAN AWARD PAYOUTS

(a)   Securities Delivered.  On April 2, 2012, 2,626 shares of our common stock were delivered to certain 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 former employees to exert their utmost efforts on Progress Energy’s behalf and thus enhance our performance while aligning the employees’ interest with those of our shareholders.

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

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ISSUER PURCHASES OF EQUITY SECURITIES FOR SECOND QUARTER OF 2012

Period	(a) Total Number of Shares (or Units) Purchased (1)(2)(3)(4)		(b) Average Price Paid Per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1)		(d) Maximum Number (or Approximate Dollar  Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (1)
April 1 – April 30		165,370	$	51.9448		N/A		N/A
May 1 – May 31		79,800		54.4728		N/A		N/A
June 1 – June 30		25,208		59.2401		N/A		N/A
Total		270,378		53.3711		N/A		N/A

(1) At June 30, 2012, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock. Effective July 2, 2012, each of our outstanding shares of common stock was converted into 0.87083 shares of Duke Energy stock.

(2) The plan administrator purchased 152,600 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy 401(k) Savings & Stock Ownership Plan.

(3) The plan administrator purchased 90,656 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) Progress Energy withheld 27,122 shares of our common stock during the second quarter of 2012 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 our 2002 and 2007 EIPs.

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ITEM 6. EXHIBITS

(a)   Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
*3(a)	Articles of Incorporation of Progress Energy, Inc. (filed as Exhibit 3.1 to Current Report on Form 8-K dated July 2, 2012, File No. 1-15929).	X
*3(b)	Bylaws of Progress Energy, Inc. (filed as Exhibit 3.2 to Current Report on Form 8-K dated July 2, 2012, File No. 1-15929).	X
*10	Credit Agreement, dated as of November 18, 2011, among Duke Energy Corporation and certain of its subsidiaries party thereto, as Borrowers, the lenders listed therein and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to Duke Energy Corporation’s Current Report on Form 8-K filed on November 25, 2011, File No. 1-32853).		X	X
31(a)	302 Certifications of Chief Executive Officer	X
31(b)	302 Certifications of Chief Financial Officer	X
31(c)	302 Certifications of Chief Executive Officer		X
31(d)	302 Certifications of Chief Financial Officer		X
31(e)	302 Certifications of Chief Executive Officer			X
31(f)	302 Certifications of Chief Financial Officer			X
32(a)	906 Certifications of Chief Executive Officer	X
32(b)	906 Certifications of Chief Financial Officer	X
32(c)	906 Certifications of Chief Executive Officer		X
32(d)	906 Certifications of Chief Financial Officer		X
32(e)	906 Certifications of Chief Executive Officer			X
32(f)	906 Certifications of Chief Financial Officer			X
101.INS	XBRL Instance Document**	X	X	X
101.SCH	XBRL Taxonomy Extension Schema Document	X	X	X
101.CAL	XBRL Taxonomy Calculation Linkbase Document	X	X	X
101.LAB	XBRL Taxonomy Label Linkbase Document	X	X	X

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101.PRE	XBRL Taxonomy Presentation Linkbase Document	X	X	X
101.DEF	XBRL Taxonomy Definition Linkbase Document	X	X	X

*    Incorporated herein by reference as indicated.

** Attached as Exhibit 101 are the following financial statements and notes thereto for Progress Energy, PEC and PEF from the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, formatted in Extensible Business Reporting Language (XBRL): (i) the Unaudited Condensed Consolidated Statements of Comprehensive 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 for PEC and PEF in Exhibit 101 to this Quarterly Report on Form 10-Q is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections.

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SIGNATURES

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

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
	FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
Date: August 8, 2012	(Registrants)
	By: /s/ Lynn J. Good
	Lynn J. Good
	Executive Vice President and Chief Financial Officer
	By: /s/ Steven K. Young
	Steven K. Young
	Vice President, Chief Accounting Officer and Controller

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