Duke Energy CORP - FORM 8-K - EX-99.1 - CONSOLIDATED FINANCIAL STATEMENTS AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2011

Attached files

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8-K - FORM 8-K - Duke Energy CORP	d309952d8k.htm
EX-99.2 - UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION. - Duke Energy CORP	d309952dex992.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - Duke Energy CORP	d309952dex231.htm

Exhibit 99.1

PROGRESS ENERGY, INC.

CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2011 and for the years ended December 31, 2011, 2010 and 2009

The following financial statements, supplementary data and financial statement schedules are included herein:

Progress Energy, Inc. (Progress Energy)

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income for the Years Ended December 31, 2011, 2010 and 2009

Consolidated Balance Sheets at December 31, 2011 and 2010

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

Consolidated Statements of Changes in Total Equity for the Years Ended December 31, 2011, 2010 and 2009

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009

Combined Notes to the Financial Statements for Progress Energy, Inc.


Note 1 – Organization and Summary of Significant Accounting Policies
Note 2 – Merger
Note 3 – New Accounting Standards
Note 4 – Divestitures
Note 5 – Property, Plant and Equipment
Note 6 – Receivables
Note 7 – Inventory
Note 8 – Regulatory Matters
Note 9 – Goodwill
Note 10 – Equity
Note 11 – Preferred Stock of Subsidiaries
Note 12 – Debt and Credit Facilities
Note 13 – Investments
Note 14 – Fair Value Disclosures
Note 15 – Income Taxes
Note 16 – Contingent Value Obligations
Note 17 – Benefit Plans
Note 18 – Risk Management Activities and Derivatives Transactions
Note 19 – Related Party Transactions
Note 20 – Financial Information by Business Segment
Note 21 – Environmental Matters
Note 22 – Commitments and Contingencies
Note 23 – Condensed Consolidating Statements
Note 24 – Quarterly Financial Data (Unaudited)

Consolidated Financial Statement Schedule for the years ended December 31, 2011, 2010 and 2009: Schedule II – Valuation and Qualifying Accounts

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.:

We have audited the accompanying consolidated balance sheets of Progress Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, changes in total equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Progress Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2012

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of INCOME


(in millions except per share data)
Years ended December 31	2011			2010			2009
Operating revenues	$	8,907		$	10,190		$	9,885

Operating expenses
Fuel used in electric generation		2,893			3,300			3,752
Purchased power		1,093			1,279			911
Operation and maintenance		2,036			2,027			1,894
Depreciation, amortization and accretion		701			920			986
Taxes other than on income		562			580			557
Other		34			30			13

Total operating expenses		7,319			8,136			8,113

Operating income		1,588			2,054			1,772

Other income (expense)
Interest income		2			7			14
Allowance for equity funds used during construction		103			92			124
Other, net		(58	)		—			6

Total other income, net		47			99			144

Interest charges
Interest charges		760			779			718
Allowance for borrowed funds used during construction		(35	)		(32	)		(39	)

Total interest charges, net		725			747			679

Income from continuing operations before income tax		910			1,406			1,237
Income tax expense		323			539			397

Income from continuing operations		587			867			840
Discontinued operations, net of tax		(5	)		(4	)		(79	)

Net income		582			863			761
Net income attributable to noncontrolling interests, net of tax		(7	)		(7	)		(4	)

Net income attributable to controlling interests	$	575		$	856		$	757

Average common shares outstanding – basic		296			291			279

Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	1.96		$	2.96		$	2.99
Discontinued operations attributable to controlling interests, net of tax		(0.02	)		(0.01	)		(0.28	)

Net income attributable to controlling interests	$	1.94		$	2.95		$	2.71

Dividends declared per common share	$	2.119		$	2.480		$	2.480

Amounts attributable to controlling interests
Income from continuing operations, net of tax	$	580		$	860		$	836
Discontinued operations, net of tax		(5	)		(4	)		(79	)

Net income attributable to controlling interests	$	575		$	856		$	757

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

PROGRESS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS


(in millions)	December 31, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	31,065		$	29,708
Accumulated depreciation		(12,001	)		(11,567	)

Utility plant in service, net		19,064			18,141
Other utility plant, net		217			220
Construction work in progress		2,449			2,205
Nuclear fuel, net of amortization		767			674

Total utility plant, net		22,497			21,240

Current assets
Cash and cash equivalents		230			611
Receivables, net		889			1,033
Inventory		1,438			1,226
Regulatory assets		275			176
Derivative collateral posted		147			164
Deferred tax assets		371			156
Prepayments and other current assets		133			110

Total current assets		3,483			3,476

Deferred debits and other assets
Regulatory assets		3,025			2,374
Nuclear decommissioning trust funds		1,647			1,571
Miscellaneous other property and investments		407			413
Goodwill		3,655			3,655
Other assets and deferred debits		345			325

Total deferred debits and other assets		9,079			8,338

Total assets	$	35,059		$	33,054

CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 295 million and 293 million shares issued and outstanding, respectively	$	7,434		$	7,343
Accumulated other comprehensive loss		(165	)		(125	)
Retained earnings		2,752			2,805

Total common stock equity		10,021			10,023

Noncontrolling interests		4			4

Total equity		10,025			10,027

Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		11,718			11,864

Total capitalization		22,109			22,257

Current liabilities
Current portion of long-term debt		950			505
Short-term debt		671			—
Accounts payable		909			994
Interest accrued		200			216
Dividends declared		78			184
Customer deposits		340			324
Derivative liabilities		436			259
Accrued compensation and other benefits		195			175
Other current liabilities		306			298

Total current liabilities		4,085			2,955

Deferred credits and other liabilities
Noncurrent income tax liabilities		2,355			1,696
Accumulated deferred investment tax credits		103			110
Regulatory liabilities		2,700			2,635
Asset retirement obligations		1,265			1,200
Accrued pension and other benefits		1,625			1,514
Derivative liabilities		352			278
Other liabilities and deferred credits		465			409

Total deferred credits and other liabilities		8,865			7,842

Commitments and contingencies (Notes 21 and 22)

Total capitalization and liabilities	$	35,059		$	33,054

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CASH FLOWS


(in millions) Years ended December 31	2011			2010			2009
Operating activities
Net income	$	582		$	863		$	761
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		870			1,083			1,135
Deferred income taxes and investment tax credits, net		353			478			220
Deferred fuel (credit) cost		(102	)		(2	)		290
Allowance for equity funds used during construction		(103	)		(92	)		(124	)
Amount to be refunded to customers (Note 8C)		288			—			—
Pension, postretirement and other employee benefits		180			198			135
Other adjustments to net income		50			49			136
Cash provided (used) by changes in operating assets and liabilities
Receivables		175			(200	)		26
Inventory		(210	)		98			(99	)
Derivative collateral posted		20			(23	)		200
Other assets		(23	)		(1	)		14
Income taxes, net		51			90			(14	)
Accounts payable		(69	)		125			(26	)
Accrued pension and other benefits		(396	)		(164	)		(285	)
Other liabilities		(51	)		35			(98	)

Net cash provided by operating activities		1,615			2,537			2,271

Investing activities
Gross property additions		(2,066	)		(2,221	)		(2,295	)
Nuclear fuel additions		(226	)		(221	)		(200	)
Purchases of available-for-sale securities and other investments		(5,017	)		(7,009	)		(2,350	)
Proceeds from available-for-sale securities and other investments		4,970			6,990			2,314
Insurance proceeds		79			64			—
Other investing activities		48			(3	)		(1	)

Net cash used by investing activities		(2,212	)		(2,400	)		(2,532	)

Financing activities
Issuance of common stock, net		53			434			623
Dividends paid on common stock		(734	)		(717	)		(693	)
Payments of short-term debt with original maturities greater than 90 days		—			—			(629	)
Net increase (decrease) in short-term debt		667			(140	)		(381	)
Proceeds from issuance of long-term debt, net		1,286			591			2,278
Retirement of long-term debt		(1,000	)		(400	)		(400	)
Other financing activities		(56	)		(19	)		8

Net cash provided (used) by financing activities		216			(251	)		806

Net (decrease) increase in cash and cash equivalents		(381	)		(114	)		545
Cash and cash equivalents at beginning of year		611			725			180

Cash and cash equivalents at end of year	$	230		$	611		$	725

Supplemental disclosures
Cash paid for interest less amount capitalized, net	$	793		$	709		$	701
Cash (received) paid for income taxes		(78	)		(56	)		87
Significant noncash transactions
Accrued property additions		334			313			252
Asset retirement obligation additions and estimate revisions		(4	)		(36	)		(384	)

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CHANGES in TOTAL EQUITY


	Common Stock							Accumulated
	Outstanding				Unearned			Other
(in millions except per share data)	Shares		Amount		ESOP Shares			Comprehensive (Loss) Income			Retained Earnings			Noncontrolling Interests			Total Equity

Balance, December 31, 2008		264	$	6,206	$	(25	)	$	(116	)	$	2,622		$	6		$	8,693
Net income^(a)				—		—			—			757			—			757
Other comprehensive income				—		—			29			—			—			29
Issuance of shares		17		623		—			—			—			—			623
Allocation of ESOP shares				8		13			—			—			—			21
Stock-based compensation expense				36		—			—			—			—			36
Dividends ($2.480 per share)				—		—			—			(704	)		—			(704	)
Distributions to noncontrolling interests				—		—			—			—			(1	)		(1	)
Other				—		—			—			—			1			1


Balance, December 31, 2009		281		6,873		(12	)		(87	)		2,675			6			9,455
Cumulative effect of change in accounting principle				—		—			—			—			(2	)		(2	)
Net income^(a)				—		—			—			856			3			859
Other comprehensive loss				—		—			(38	)		—			—			(38	)
Issuance of shares		12		434		—			—			—			—			434
Allocation of ESOP shares				9		12			—			—			—			21
Stock-based compensation expense				27		—			—			—			—			27
Dividends ($2.480 per share)				—		—			—			(726	)		—			(726	)
Distributions to noncontrolling interests				—		—			—			—			(2	)		(2	)
Other				—		—			—			—			(1	)		(1	)


Balance, December 31, 2010		293		7,343		—			(125	)		2,805			4			10,027
Net income^(a)				—		—			—			575			3			578
Other comprehensive loss				—		—			(40	)		—			—			(40	)
Issuance of shares		2		53		—			—			—			—			53
Stock-based compensation expense				38		—			—			—			—			38
Dividends ($2.119 per share)				—		—			—			(628	)		—			(628	)
Distributions to noncontrolling interests				—		—			—			—			(3	)		(3	)

Balance, December 31, 2011		295	$	7,434	$	—		$	(165	)	$	2,752		$	4		$	10,025

^(a)

For the year ended December 31, 2011, consolidated net income of $582 million includes $4 million attributable to preferred shareholders of subsidiaries. For the year ended December 31, 2010, consolidated net income of $863 million includes $4 million attributable to preferred shareholders of subsidiaries. For the year ended December 31, 2009, consolidated net income of $761 million includes $4 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.

See Notes to Progress Energy, Inc. Consolidated Financial Statements

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME


(in millions) Years ended December 31,	2011			2010			2009
Net income	$	582		$	863		$	761
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $5, $4 and $4)		8			6			6
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $3, $2 and $3)		5			3			4
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $56, $22 and $(10))		(87	)		(34	)		16
Net unrecognized items for pension and other postretirement benefits (net of tax (expense) benefit of $(24), $8 and $(1))		34			(13	)		2
Other (net of tax benefit of $-)		—			—			1

Other comprehensive (loss) income		(40	)		(38	)		29

Comprehensive income		542			825			790
Comprehensive income attributable to noncontrolling interests, net of tax		(7	)		(7	)		(4	)

Comprehensive income attributable to controlling interests	$	535		$	818		$	786

See Notes to Progress Energy, Inc. Consolidated Financial Statements.

PROGRESS ENERGY, INC.

CONSOLIDATED NOTES TO FINANCIAL STATEMENTS

In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to the Combined Notes. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.	ORGANIZATION

PROGRESS ENERGY

The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC).

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 20 for further information about our segments.

PEC

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

PEF

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

B.	BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), including GAAP for regulated operations. The financial statements include the activities of the Parent and our majority-owned and controlled subsidiaries. The Utilities are subsidiaries of Progress Energy, and, as such, their financial condition and results of operations and cash flows are also consolidated, along with our nonregulated subsidiaries, in our consolidated financial statements. Intercompany balances and transactions have been eliminated in consolidation.

Noncontrolling interests in subsidiaries along with the income or loss attributed to these interests are included in noncontrolling interests in both the Consolidated Balance Sheets and in the Consolidated Statements of Income. The

results of operations for noncontrolling interests are reported on a net of tax basis if the underlying subsidiary is structured as a taxable entity.

Unconsolidated investments in companies over which we do not have control, but have the ability to exercise influence over operating and financial policies, are accounted for under the equity method of accounting. These investments are primarily in limited liability corporations and limited liability partnerships, and the earnings from these investments are recorded on a pre-tax basis. Other investments are stated principally at cost. These equity and cost method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. See Note 13 for more information about our investments.

Our presentation of operating, investing and financing cash flows combines the respective cash flows from our continuing and discontinued operations as permitted under GAAP.

These combined notes accompany and form an integral part of Progress Energy’s and PEC’s consolidated financial statements and PEF’s financial statements.

Certain amounts for 2010 and 2009 have been reclassified to conform to the 2011 presentation.

C.	CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. 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 for this VIE during 2009 through 2011. No financial or other support has been provided to the VIE during the periods presented.

The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets at December 31:


(in millions)	2011		2010
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		—
Prepayments and other current assets		—		1
Accounts payable		—		5

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

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $2 million annually in 2011, 2010 and 2009. 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 in VIEs within the Progress Energy section.

PEF

PEF has no significant variable interests in VIEs.

D.	SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES AND ASSUMPTIONS

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

REVENUE RECOGNITION

We recognize revenue when it is realized or realizable and earned when all of the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; our price to the buyer is fixed or determinable; and collectability is reasonably assured. We recognize electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utility base revenues earned when service has been delivered but not billed by the end of the accounting period. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix. Customer prepayments are recorded as deferred revenue and recognized as revenues as the services are provided.

Periodically, we are permitted to start charging customers for proposed rate increases prior to receiving final approval from our regulatory authorities. Such amounts charged are subject to refund upon issuance of the final rate order. In addition, we may be required to refund amounts to customers for previously recognized revenues, through approved orders or settlement agreements, which are not related to proposed rate increases. We recognize revenue subject to refund when it is earned, and separately establish a reserve for amounts that could be refunded when it is probable that revenue will be refunded to customers. See Note 8C for discussion of revenue to be refunded in connection with the 2012 settlement agreement.

FUEL COST DEFERRALS

Fuel expense includes fuel costs and other recoveries that were previously deferred through fuel clauses established by the Utilities’ regulators. These clauses allow the Utilities to recover fuel costs, fuel-related costs and portions of purchased power costs through surcharges on customer rates. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers.

EXCISE TAXES

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

The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of income for the years ended December 31 were as follows:


(in millions)	2011		2010		2009
Progress Energy	$	315	$	345	$	333
PEC		110		119		108
PEF		205		226		225

RELATED PARTY TRANSACTIONS

Our subsidiaries provide and receive services, at cost, to and from the Parent and its subsidiaries, in accordance with FERC regulations. The costs of the services are billed on a direct-charge basis, whenever possible, and on allocation factors for general costs that cannot be directly attributed. In the subsidiaries’ financial statements, billings from affiliates are capitalized or expensed depending on the nature of the services rendered.

UTILITY PLANT

Utility plant in service is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs of units of property as well as indirect construction costs. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property (including planned major maintenance activities), and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred, with the exception of nuclear outages at PEF. Pursuant to a regulatory order, PEF accrues for nuclear outage costs in advance of scheduled outages, which generally occur every two years. Maintenance activities under long-term service agreements with third parties are capitalized or expensed as appropriate as if the Utilities had performed the activities. Generally, the cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. For generating facilities to be retired or abandoned significantly before the end of their useful lives, the net carrying value is reclassified from plant in service, net to other utility plant, net when it becomes probable they will be retired or abandoned. When such facilities are removed from service, the remaining net carrying value is then reclassified to regulatory assets in accordance with the expected ratemaking treatment. Removal or disposal costs that do not represent asset retirement obligations (AROs) are charged to a regulatory liability.

Allowance for funds used during construction (AFUDC) represents the estimated costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform system of accounts, AFUDC is charged to the cost of the plant. Both the debt and equity components of AFUDC are noncash amounts within the Consolidated Statements of Income. The equity funds component of AFUDC is credited to other income, and the borrowed funds component is credited to interest charges.

Nuclear fuel is classified as a fixed asset and included in the utility plant section of the Consolidated Balance Sheets. Nuclear fuel in the front-end fuel processing phase is considered work in progress and not amortized until placed in service.

DEPRECIATION AND AMORTIZATION – UTILITY PLANT

Substantially all depreciation of utility plant other than nuclear fuel is computed on the straight-line method based on the estimated remaining useful life of the property, adjusted for estimated salvage (See Note 5A). Pursuant to their rate-setting authority, the NCUC, SCPSC and FPSC can also grant approval to accelerate or reduce depreciation and amortization rates of utility assets (See Note 8).

Amortization of nuclear fuel costs is computed primarily on the units-of-production method and included within fuel used in electric generation in the Consolidated Statements of Income.

FEDERAL GRANT

The American Recovery and Reinvestment Act, signed into law in February 2009, contains provisions promoting energy efficiency (EE) and renewable energy. On April 28, 2010, we accepted a grant from the United States Department of Energy (DOE) for $200 million in federal matching infrastructure funds in support of our smart grid initiatives. PEC and PEF each will receive up to $100 million over a three-year period as project work progresses. The DOE will provide reimbursement for 50 percent of allowable project costs, as incurred, up to the DOE’s maximum obligation of $200 million. Projects funded by the grant must be completed by April 2013.

In accounting for the federal grant, we have elected to reduce the cost basis of select smart grid projects. As the select capital projects are placed into service, this will reduce depreciation expense over the life of the assets. Reimbursements by the DOE are deferred as a short-term or long-term liability on the Consolidated Balance Sheets based on their expected date of application to the select projects. Reimbursements related to capital projects are included in other investing activities in the Statement of Cash Flows when cash is received.

ASSET RETIREMENT OBLIGATIONS

AROs are legal obligations associated with the retirement of certain tangible long-lived assets. The present values of retirement costs for which we have a legal obligation are recorded as liabilities with an equivalent amount added to the asset cost and depreciated over the useful life of the associated asset. The liability is then accreted over time by applying an interest method of allocation to the liability. Accretion expense is included in depreciation, amortization and accretion in the Consolidated Statements of Income. AROs have no impact on the income of the Utilities as the effects are offset by the establishment of regulatory assets and regulatory liabilities in order to reflect the ratemaking treatment of the related costs.

CASH AND CASH EQUIVALENTS

We consider cash and cash equivalents to include unrestricted cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

RECEIVABLES, NET

We record accounts receivable at net realizable value. This value includes an allowance for estimated uncollectible accounts to reflect any loss anticipated on the accounts receivable balances. The allowance for uncollectible accounts reflects our estimate of probable losses inherent in the accounts receivable, unbilled revenue, and other receivables balances. We calculate this allowance based on our history of write-offs, level of past due accounts, prior rate of recovery experience and relationships with and economic status of our customers.

INVENTORY

We account for inventory, including emission allowances, using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. Materials and supplies are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Materials reserves are established for excess and obsolete inventory.

REGULATORY ASSETS AND LIABILITIES

The Utilities’ operations are subject to GAAP for regulated operations, which allows a regulated company to record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, the Utilities record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 8A). Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Additionally, management continually assesses whether any regulatory

liabilities have been incurred. The regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process.

NUCLEAR COST DEFERRALS

PEF accounts for costs incurred in connection with the proposed nuclear expansion in Florida in accordance with FPSC regulations, which establish an alternative cost-recovery mechanism. PEF is allowed to accelerate the recovery of prudently incurred siting, preconstruction costs, AFUDC and incremental operation and maintenance expenses resulting from the siting, licensing, design and construction of a nuclear plant through PEF’s capacity cost-recovery clause. Nuclear costs are deemed to be recovered up to the amount of the FPSC-approved projections, and the deferral of unrecovered nuclear costs accrues a carrying charge equal to PEF’s approved AFUDC rate. Unrecovered nuclear costs eligible for accelerated recovery are deferred and recorded as regulatory assets in the Consolidated Balance Sheets and are amortized in the period the costs are collected from customers.

GOODWILL AND INTANGIBLE ASSETS

Goodwill is subject to at least an annual assessment for impairment by applying a two-step, fair value-based test. This assessment could result in periodic impairment charges. We perform our annual goodwill impairment test as of October 31 each year and perform an interim test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Intangible assets are amortized based on the economic benefit of their respective lives.

UNAMORTIZED DEBT PREMIUMS, DISCOUNTS AND EXPENSES

Long-term debt premiums, discounts and issuance expenses are amortized over the terms of the debt issues. Any expenses or call premiums associated with the reacquisition of debt obligations by the Utilities are amortized over the applicable lives using the straight-line method consistent with ratemaking treatment (See Note 8A).

INCOME TAXES

We and our affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to PEC and PEF in accordance with the Intercompany Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provides an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the carryover of uncompensated tax benefits, which primarily relate to deferred synthetic fuels tax credits. Income taxes are provided for as if PEC and PEF filed separate returns.

Deferred income taxes have been provided for temporary differences. These occur when the book and tax carrying amounts of assets and liabilities differ. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. Credits for the production and sale of synthetic fuels are deferred credits to the extent they cannot be or have not been utilized in the annual consolidated federal income tax returns, and are included in income tax expense (benefit) of discontinued operations in the Consolidated Statements of Income. We accrue for uncertain tax positions when it is determined that it is more likely than not that the benefit will not be sustained on audit by the taxing authority, including resolutions of any related appeals or litigation processes, based solely on the technical merits of the associated tax position. If the recognition threshold is met, the tax benefit recognized is measured at the largest amount of the tax benefit that, in our judgment, is greater than 50 percent likely to be realized. Interest expense on tax deficiencies and uncertain tax positions is included in net interest charges, and tax penalties are included in other, net in the Consolidated Statements of Income.

DERIVATIVES

GAAP requires that an entity recognize all derivatives as assets or liabilities on the balance sheet and measure those instruments at fair value, unless the derivatives meet the GAAP criteria for normal purchases or normal sales and are designated as such. We generally designate derivative instruments as normal purchases or normal sales whenever the criteria are met. If normal purchase or normal sale criteria are not met, we will generally designate the derivative

instruments as cash flow or fair value hedges if the related hedge criteria are met. We have elected not to offset fair value amounts recognized for derivative instruments and related collateral assets and liabilities with the same counterparty under a master netting agreement. Certain economic derivative instruments (primarily fuel-related) receive regulatory accounting treatment, under which unrealized gains and losses are recorded as regulatory liabilities and assets, respectively, until the contracts are settled. Cash flows from derivative instruments are generally included in cash provided by operating activities on the Statements of Cash Flows. See Note 18 for additional information regarding risk management activities and derivative transactions.

LOSS CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

We accrue for loss contingencies, such as unfavorable results of litigation, when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. With the exception of legal fees that are incremental direct costs of an environmental remediation effort, we do not accrue an estimate of legal fees when a contingent loss is initially recorded, but rather when the legal services are actually provided.

As discussed in Note 21, we accrue environmental remediation liabilities when the criteria for loss contingencies have been met. We record accruals for probable and estimable costs, including legal fees, related to environmental sites on an undiscounted basis. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Certain environmental expenses receive regulatory accounting treatment, under which the expenses are recorded as regulatory assets. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable or on actual receipt of recovery. Environmental expenditures that have future economic benefits are capitalized in accordance with our asset capitalization policy.

IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS

We review the recoverability of long-lived tangible and intangible assets whenever impairment indicators exist. Examples of these indicators include current period losses, combined with a history of losses or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an impairment indicator exists for assets to be held and used, then the asset group is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows or the asset group is to be disposed of, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group.

We review our equity investments to evaluate whether or not a decline in fair value below the carrying value is an other-than-temporary decline. We consider various factors, such as the investee’s cash position, earnings and revenue outlook, liquidity and management’s ability to raise capital in determining whether the decline is other-than-temporary. If we determine that an other-than-temporary decline in value exists, the investments are written down to fair value with a new cost basis established.

2.	MERGER AGREEMENT

On January 8, 2011, Duke Energy and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction (the Merger) and become a wholly owned subsidiary of Duke Energy. The Merger Agreement originally had a termination date of January 8, 2012, which has been extended by the parties to July 8, 2012.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be canceled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an

option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the Merger. Accordingly, the adjusted exchange ratio is expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.

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

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

Shareholder Approval

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

Federal Regulatory Approvals

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On March 28, 2011, Progress Energy and Duke Energy submitted their Hart-Scott-Rodino filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act. However, the period in which Progress Energy and Duke Energy may close the Merger consistent with their Hart-Scott-Rodino obligations will expire on April 26, 2012. Because the Merger is not expected to close on or before April 26, 2012, Progress Energy and Duke Energy intend to make new filings under the Hart-Scott-Rodino Act in order to be able to close the Merger after such date and continue to meet their obligations under the Hart-Scott-Rodino Act.

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On January 5, 2012, the Federal Communications Commission extended its approval of the Assignment of Authorization filings to transfer control of certain licenses. The extended approval expires on July 12, 2012.

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On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC’s acceptance of market power mitigation measures to address the FERC’s finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina wholesale power markets. Progress Energy and Duke Energy filed a market power mitigation plan with the FERC on October 17, 2011 that proposed a “virtual divestiture” under which power up to a certain amount would have been offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. On December 14, 2011, the FERC affirmed its conditional approval of the merger, but the FERC rejected the proposed market power mitigation plan. On February 22, 2012, Progress Energy and Duke Energy filed a notification with the NCUC of their intention to file a second market power mitigation plan with the FERC. The revised mitigation plan consists of two phases. Phase 1 is an interim mitigation that consists of a virtual divestiture whereby the companies propose a three-year plan to sell capacity and firm energy during the summer (June – August) and winter (December – February) to new market participants. Together, the companies would sell 800 MWs during summer off-peak hours, 475 MWs during summer peak hours, 225 MWs during winter off-peak hours, and 25 MWs during winter peak hours. The companies expect to secure contracts with potential buyers prior to filing the mitigation plan with the FERC. Phase 2 is a permanent mitigation that consists of constructing up to eight transmission projects in the combined service

territories, which will expand the capability to import wholesale power into the Carolinas. The construction, preliminarily estimated to cost $75 million to $150 million, would begin after the Merger closes and take approximately three years to complete. The companies will be working with the North Carolina Public Staff and the South Carolina Office of Regulatory Staff (ORS) on appropriate state ratemaking treatment associated with the measures in the revised market mitigation plan and other merger-related issues. Final agreement to the proposed mitigation efforts will be subject to resolution of the state ratemaking issues. The NCUC has up to 30 days to review the revised mitigation plan before it is filed with the FERC.

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On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a Joint Dispatch Agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the Merger. The second filing is a joint open access transmission tariff (OATT) pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate. On December 14, 2011, in conjunction with the aforementioned decision on the proposed market power mitigation plan, the FERC dismissed these related filings as not ripe for decision. As allowed under the FERC’s December 14, 2011 order, Progress Energy and Duke Energy intend to refile the Joint Dispatch Agreement and OATT upon filing of the second market power mitigation plan with the FERC.

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On December 2, 2011, the NRC approved the filing requesting an indirect transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses.

State Regulatory Approvals

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On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed a settlement with the ORS, a party to the North Carolina proceedings to resolve the ORS’s issues in the North Carolina proceeding. Under the settlement agreement with the North Carolina Public Staff, Progress Energy and Duke Energy will provide $650 million in system fuel cost savings for customers in North Carolina and South Carolina over the five years following the close of the Merger, maintain their current level of community support in North Carolina for the next four years, and provide $15 million for low-income energy assistance and workforce development in North Carolina. The settlement agreement also provides that direct merger-related expenses will not be recovered from customers; however, PEC may request recovery of costs incurred to create operational savings. The NCUC held hearings regarding the application on September 20-22, 2011. On November 23, 2011, Progress Energy and Duke Energy filed proposed orders and briefs with the NCUC. The docket will remain open pending the FERC’s issuance of its final orders on the merger-related actions before the FERC.

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On April 25, 2011, Progress Energy and Duke Energy filed an application for approval of the merger of PEC and Duke Energy Carolinas and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the application of the merger of PEC and Duke Energy Carolinas, as the merger of these entities is not likely to occur for several years after the close of the Merger. The SCPSC held hearings regarding the application for approval of the Joint Dispatch Agreement on December 12, 2011. During the hearing, PEC, Duke Energy Carolinas and the ORS agreed to terminate the settlement agreement, which resolved the ORS’s issues in the NCUC merger proceeding, and replaced it with a commitment by PEC and Duke Energy Carolinas to provide PEC’s and Duke Energy Carolinas’ retail customers in South Carolina pro rata benefits equivalent to those approved by the NCUC in its order ruling upon PEC’s and Duke Energy Carolinas’ merger application. The docket will remain open pending the FERC’s issuance of its final orders on the merger-related actions before the FERC.

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

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the Merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share. In the fourth quarter of 2011, our board of directors declared a partial dividend payment to Progress Energy shareholders to align Progress Energy’s dividend payment schedule with that of Duke Energy such that following the closing of the Merger, all stockholders of the combined company would receive dividends under the Duke Energy dividend schedule.

Certain substantial changes in ownership of Progress Energy, including the Merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 15).

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

Certain Progress Energy shareholders filed class action lawsuits in the state and federal courts in North Carolina against Progress Energy and each of the members of Progress Energy’s board of directors, which have been subsequently settled (See Note 22D).

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

In connection with the Merger, we announced plans to offer a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the Merger. The window for eligible employees to request a voluntary end to their employment under the VSP opened on November 7, 2011, and ended on November 30, 2011. Approximately 650 employees requested and were approved for separation under the VSP in December 2011. The cost of the VSP is estimated to be between $90 million to $100 million, including $65 million to $70 million and $25 million to $30 million related to PEC and PEF, respectively. If the employee is not required to work for a significant period after the consummation of the Merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the Merger. If a significant retention period exists, the costs of benefits equal to what would be paid under our existing severance plan will be measured and recorded upon consummation of the Merger. Any additional benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the Merger and formulated an exit plan to vacate one of our corporate headquarters buildings. Under the plan, we will gradually vacate the premises beginning in the fourth quarter of 2011 through January 1, 2013. 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 $12 million of expense is attributable to PEC and $5 million to PEF. The exit cost liability will be recognized proportionately as we vacate the premises. During the fourth quarter of 2011, we recorded exit cost liabilities of $5 million for us, of which $3 million of expense is attributable to PEC and $2 million to PEF. These costs are included in merger and integration-related costs.

In connection with the Merger, we incurred merger and integration-related costs of $46 million, net of tax, including $25 million, net of tax, and $21 million, net of tax, at PEC and PEF, respectively, for the year ended December 31, 2011. These costs are included in operations and maintenance (O&M) expense in our Consolidated Statements of Income.

3.	NEW ACCOUNTING STANDARDS

FAIR VALUE MEASUREMENT AND DISCLOSURES

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

In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends ASC 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 is effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 will result in changes in certain fair value measurement principles, as well as additional disclosure in the notes to the financial statements. However, the impact of adoption is not expected to be significant to our or the Utilities’ financial position, results of operations or cash flows.

GOODWILL IMPAIRMENT TESTING

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

We have completed our business strategy of divesting nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. 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 22C for further discussion of our guarantees. The ultimate resolution of these matters could result in additional adjustments in future periods. The information below presents the impacts of the divestitures on net income attributable to controlling interests.

A.	TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES

Prior to 2008, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 (Section 29) of the Code and as redesignated effective 2006 as Section 45K of the Code (Section 45K and, collectively, Section 29/45K). The production and sale of these products qualified for federal income tax credits so long as certain requirements were satisfied. As a result of the expiration of the tax credit program, all of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007. During 2008, we also sold coal terminals and docks in West Virginia and Kentucky. The accompanying consolidated financial statements reflect the operations of our terminal operations and synthetic fuels businesses as discontinued operations.

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates. As a result, during the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. See Note 22D for further discussion.

Results of coal terminals and docks and synthetic fuels businesses discontinued operations for the years ended December 31 were as follows:


(in millions)	2011			2010			2009
Loss before income taxes and noncontrolling interest	$	(8	)	$	(11	)	$	(125	)
Income tax benefit, including tax credits		3			5			47

Loss from discontinued operations attributable to controlling interests	$	(5	)	$	(6	)	$	(78	)

The total income tax benefit presented in the preceding table includes deferred income tax benefit (expense) of $28 million, $124 million and $(86) million for the years ended December 31, 2011, 2010 and 2009, respectively, related to synthetic fuels tax credits.

B.	OTHER DIVERSIFIED BUSINESSES

Also included in discontinued operations are amounts related to adjustments of our prior sales of other diversified businesses. During the years ended December 31, 2011, 2010 and 2009, gains and losses related to post-closing adjustments and pre-divestiture contingencies of other diversified businesses were not material to our results of operations.

5.	PROPERTY, PLANT AND EQUIPMENT

A.	UTILITY PLANT

The balances of electric utility plant in service at December 31 are listed below, with a range of depreciable lives (in years) for each:


	Depreciable		Progress Energy				PEC				PEF
(in millions)	Lives		2011		2010		2011		2010		2011		2010
Production plant		3-41	$	16,728	$	16,042	$	9,978	$	9,354	$	6,585	$	6,523
Transmission plant		7-75		3,853		3,530		1,825		1,626		2,028		1,904


Distribution plant	13-67		9,053		8,715		4,887		4,687		4,166		4,028
General plant and other	5-35		1,431		1,421		749		721		682		700

Utility plant in service		$	31,065	$	29,708	$	17,439	$	16,388	$	13,461	$	13,155

Generally, electric utility plant at PEC and PEF, other than nuclear fuel, is pledged as collateral for the first mortgage bonds of PEC and PEF, respectively (See Note 12). In the 2012 settlement agreement, PEF agreed to remove PEF’s Crystal River Unit No. 3 Nuclear Plant (CR3) from rate base and will reclassify CR3 to a regulatory asset and suspend depreciation expense (See Note 8C).

As discussed in Note 8B, PEC intends to retire no later than December 31, 2013, all of its coal-fired generating facilities in North Carolina that do not have scrubbers. These facilities total approximately 1,500 megawatts (MW) at four sites. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units. At December 31, 2011, the $15 million net carrying value of this retired facility is included in regulatory assets on the Consolidated Balance Sheets.

AFUDC is charged to the cost of the plant for certain projects in accordance with the regulatory provisions for each jurisdiction. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the rates charged to customers by the Utilities over the service life of the property. The composite AFUDC rate for PEC’s electric utility plant was 8.7 percent in 2011 and 9.2 percent in 2010 and 2009. The composite AFUDC rate for PEF’s electric utility plant was 7.4 percent, effective beginning April 1, 2010, based on its authorized return on equity (ROE) approved in the 2010 settlement agreement. This rate was unchanged by the 2012 settlement agreement (See Note 8C). Prior to April 1, 2010, the composite AFUDC rate for PEF’s electric utility plant was 8.8 percent.

Our depreciation provisions on utility plant and amortization of other utility plant, net, as a percent of average depreciable property other than nuclear fuel, were 2.3 percent, 2.0 percent and 2.4 percent in 2011, 2010 and 2009, respectively. The depreciation provisions related to utility plant and amortization of other utility plant, net were $675 million, $635 million and $626 million in 2011, 2010 and 2009, respectively. In addition to utility plant depreciation provisions, depreciation, amortization and accretion expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 5C) and regulatory approved expenses (See Notes 8 and 21).

PEC’s depreciation provisions on utility plant and amortization of other utility plant, net, as a percent of average depreciable property other than nuclear fuel, were 2.1 percent for 2011, 2010 and 2009. The depreciation provisions related to utility plant and amortization of other utility plant, net were $360 million, $338 million and $328 million in 2011, 2010 and 2009, respectively. In addition to utility plant depreciation provisions, depreciation, amortization and accretion expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 5C) and regulatory approved expenses (See Note 8B).

PEF’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.4 percent in 2011, 1.9 percent in 2010 and 2.7 percent in 2009. The depreciation provisions related to utility plant were $315 million, $297 million and $299 million in 2011, 2010 and 2009, respectively. In addition to utility plant depreciation provisions, depreciation, amortization and accretion expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 5C) and regulatory approved expenses (See Note 8C).

During 2010, PEF updated the depreciation rates approved by the FPSC in the 2009 base rate case. The rate change was effective January 1, 2010, and resulted in a decrease in depreciation expense of $43 million for 2010. Additionally, in December 2010, PEF filed the FPSC-approved depreciation rates with the FERC for use in its formula transmission rate for its OATT. The FERC filing requested depreciation rates be applied retroactively to January 1, 2010, whereby, if approved, the depreciation rate changes would result in a reduction to the depreciation expense charged to PEF’s OATT customers, beginning June 1, 2011. The FERC on July 15, 2011, rejected the proposed adjustments to depreciation reserves.

Nuclear fuel, net of amortization at December 31, 2011 and 2010, was $767 million and $674 million, respectively, for Progress Energy; $540 million and $480 million, respectively, for PEC; and $227 million and $194 million,

respectively, for PEF. The amount not yet in service at December 31, 2011 and 2010, was $575 million and $367 million, respectively, for Progress Energy; $322 million and $199 million, respectively, for PEC; and $253 million and $168 million, respectively, for PEF. Amortization of nuclear fuel costs, including disposal costs associated with obligations to the DOE and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities, was $160 million, $132 million and $159 million for the years ended December 31, 2011, 2010 and 2009, respectively. This amortization expense is included in fuel used in electric generation in the Consolidated Statements of Income. PEC’s amortization of nuclear fuel costs for the years ended December 31, 2011, 2010 and 2009 was $160 million, $132 million and $134 million, respectively. PEF’s amortization of nuclear fuel costs for the year ended December 31, 2009, was $25 million. PEF did not have any amortization of nuclear fuel costs for the years ended December 31, 2011 and 2010, due to the CR3 outage (See Note 8C).

PEF’s construction work in progress related to certain nuclear projects receives regulatory treatment. At December 31, 2011, PEF had $555 million of accelerated recovery of construction work in progress, of which $177 million was a component of a nuclear cost-recovery clause regulatory asset. At December 31, 2010, PEF had $519 million of accelerated recovery of construction work in progress, of which $237 million was a component of a nuclear cost-recovery clause regulatory asset. See Note 8C for further discussion of PEF’s nuclear cost recovery.

B.	JOINT OWNERSHIP OF GENERATING FACILITIES

PEC and PEF hold ownership interests in certain jointly owned generating facilities. Each is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to the additional costs. Each of the Utilities’ share of operating costs of the jointly owned generating facilities is included within the corresponding line in the Statements of Income. The co-owner of Intercession City Unit P11 has exclusive rights to the output of the unit during the months of June through September. PEF has that right for the remainder of the year.

PEC’s and PEF’s ownership interests in the jointly owned generating facilities are listed below with related information at December 31:


(in millions) Subsidiary	Facility	Company Ownership Interest			Plant Investment		Accumulated Depreciation		Construction Work in Progress
2011
PEC	Mayo		83.83	%	$	807	$	296	$	13
PEC	Harris		83.83	%		3,254		1,635		66
PEC	Brunswick		81.67	%		1,739		951		52
PEC	Roxboro Unit 4		87.06	%		733		470		12
PEF	Crystal River Unit 3		91.78	%		909		498		803
PEF	Intercession City Unit P11		66.67	%		23		12		—

2010
PEC	Mayo		83.83	%	$	798	$	294	$	8
PEC	Harris		83.83	%		3,255		1,604		16
PEC	Brunswick		81.67	%		1,702		939		38
PEC	Roxboro Unit 4		87.06	%		706		457		22
PEF	Crystal River Unit 3		91.78	%		901		497		648
PEF	Intercession City Unit P11		66.67	%		23		11		—

In the tables above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Shearon Harris Nuclear Plant (Harris), which are not applicable to the joint owner’s ownership interest in Harris.

In the tables above, construction work in progress for CR3 is not reduced by the accelerated recovery of qualifying project costs under the FPSC nuclear cost-recovery rule (see Note 8C).

C.	ASSET RETIREMENT OBLIGATIONS

At December 31, 2011 and 2010, our asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant, net of accumulated depreciation totaled $87 million and $90 million, respectively. PEC had immaterial asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant at December 31, 2011 and 2010. Primarily due to the impact of updated escalation factors in 2010, as discussed below, at December 31, 2011 and 2010, PEF had no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant. At December 31, 2011 and 2010, additional PEF-related asset retirement costs, net of accumulated depreciation, of $87 million and $90 million, respectively, were recorded at Progress Energy as purchase accounting adjustments recognized when we purchased Florida Progress Corporation (Florida Progress) in 2000.

The fair value of funds set aside in the Utilities’ nuclear decommissioning trust (NDT) funds for the nuclear decommissioning liability totaled $1.647 billion and $1.571 billion at December 31, 2011 and 2010, respectively (See Notes 13 and 14). The fair value of funds set aside in the NDT funds for the nuclear decommissioning liability totaled $1.088 billion and $1.017 billion at December 31, 2011 and 2010, respectively, for PEC and $559 million and $554 million, respectively, for PEF (See Notes 13 and 14). Net NDT unrealized gains are included in regulatory liabilities (See Note 8A).

Progress Energy’s and PEC’s nuclear decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million each in 2011, 2010 and 2009. As discussed below, PEF has suspended its accrual for nuclear decommissioning. Management believes that nuclear decommissioning costs that have been and will be recovered through rates by PEC and PEF will be sufficient to provide for the costs of decommissioning.

We recognized a benefit of $98 million in 2011 and expenses of $87 million and $141 million in 2010 and 2009, respectively, for the disposal or removal of utility assets that do not meet the definition of AROs, which are included in depreciation, amortization and accretion expense. PEC’s related expenses were $125 million, $122 million and $106 million in 2011, 2010 and 2009, respectively. Due to a $250 million and $60 million cost of removal credit in 2011 and 2010, respectively, as allowed by the 2010 settlement agreement approved by the FPSC (See Note 8C), PEF recognized a benefit of $223 million and $35 million in 2011 and 2010, respectively. PEF’s related expenses were $35 million in 2009.

The Utilities recognize removal, nonirradiated decommissioning and dismantlement of fossil generation plant costs in regulatory liabilities on the Consolidated Balance Sheets (See Note 8A). At December 31, such costs consisted of:


	Progress Energy				PEC				PEF
(in millions)	2011		2010		2011		2010		2011		2010
Removal costs	$	1,302	$	1,503	$	1,065	$	1,000	$	237	$	503
Nonirradiated decommissioning costs		223		233		185		172		38		61
Dismantlement costs		125		121		—		—		125		121

Non-ARO cost of removal	$	1,650	$	1,857	$	1,250	$	1,172	$	400	$	685

The NCUC requires that PEC update its cost estimate for nuclear decommissioning every five years. PEC received a new site-specific estimate of decommissioning costs for Robinson Nuclear Plant (Robinson) Unit No. 2, Brunswick Nuclear Plant (Brunswick) Units No. 1 and No. 2, and Harris, in December 2009, which was filed with the NCUC on March 16, 2010. PEC’s estimate is based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring after operating license expiration. These decommissioning cost estimates also include interim spent fuel storage costs associated with maintaining spent nuclear fuel on site until such time that it can be transferred to a DOE facility (See Note 22D). These estimates, in 2009 dollars, were $687 million for Unit No. 2 at Robinson, $591 million for Brunswick Unit No. 1, $585 million for Brunswick Unit No. 2 and $1.126 billion for Harris. The estimates are subject to change

based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in Brunswick and Harris. See Note 8D for information about the NRC operating licenses held by PEC.

The FPSC requires that PEF update its cost estimate for nuclear decommissioning every five years. PEF received a new site-specific estimate of decommissioning costs for CR3 in October 2008, which PEF filed with the FPSC in 2009 as part of PEF’s base rate filing. However, the FPSC deferred review of PEF’s nuclear decommissioning study from the rate case to be addressed in 2010 in order for FPSC staff to assess PEF’s study in combination with other utilities anticipated to submit nuclear decommissioning studies in 2010. PEF was not required to prepare a new site-specific nuclear decommissioning study in 2010; however, PEF was required to update the 2008 study with the most currently available escalation rates in 2010, which was filed with the FPSC in December 2010. We expect the FPSC to issue an order in 2012. PEF’s estimate is based on prompt dismantlement decommissioning and includes interim spent fuel storage costs associated with maintaining spent nuclear fuel on site until such time that it can be transferred to a DOE facility (See Note 22D). The estimate, in 2008 dollars, is $751 million and is subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimate excludes the portion attributable to other co-owners of CR3. See Note 8D for information about the NRC operating license held by PEF for CR3. Based on the 2008 estimate, assumed operating license renewal and updated escalation factors in 2010, PEF decreased its asset retirement cost to zero and its ARO liability by approximately $37 million in 2010. Retail accruals on PEF’s reserves for nuclear decommissioning were previously suspended under the terms of previous base rate settlement agreements. PEF expects to continue this suspension based on its 2010 nuclear decommissioning filing. No nuclear decommissioning reserve accrual is recorded at PEF following a FERC accounting order issued in November 2006.

The FPSC requires that PEF update its cost estimate for fossil plant dismantlement every four years. PEF received an updated fossil dismantlement study estimate in 2008, which PEF filed with the FPSC in 2009 as part of PEF’s base rate filing. As a result of the base rate case, the FPSC approved an annual fossil dismantlement accrual of $4 million. PEF’s reserve for fossil plant dismantlement was approximately $148 million and $144 million at December 31, 2011 and 2010, including amounts in the ARO liability for asbestos abatement, discussed below.

PEC and PEF have recognized ARO liabilities related to asbestos abatement costs. The ARO liabilities related to asbestos abatement costs were $23 million and $26 million at December 31, 2011 and 2010, respectively, at PEC and $29 million and $27 million at December 31, 2011 and 2010, respectively, at PEF.

Additionally, PEC and PEF have recognized ARO liabilities related to landfill capping costs. The ARO liabilities related to landfill capping costs were $6 million and $3 million at December 31, 2011 and 2010, respectively, at PEC and $7 million and $6 million at December 31, 2011 and 2010, respectively, at PEF.

We have identified but not recognized AROs related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by us. These easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the specified purpose. The ARO is not estimable for such easements, as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO would be recorded at that time.

The following table presents the changes to the AROs during the years ended December 31. Revisions to prior estimates of the PEC and PEF regulated ARO are primarily related to the updated cost estimates for nuclear decommissioning and asbestos described above.


(in millions)	Progress Energy		PEC		PEF
Asset retirement obligations at January 1, 2010	$	1,170	$	801	$	369
Additions		4		4		—


Accretion expense		65			46			19
Revisions to prior estimates		(39	)		(2	)		(37	)

Asset retirement obligations at December 31, 2010		1,200			849			351
Accretion expense		67			49			18
Revisions to prior estimates		(2	)		(2	)		—

Asset retirement obligations at December 31, 2011	$	1,265		$	896		$	369

D.	INSURANCE

The Utilities are members of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members’ nuclear generating facilities. Under the primary program, each company is insured for $500 million at each of its respective nuclear plants. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $1.750 billion on each nuclear plant.

Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL. Both PEC and PEF are insured under this program, following a 12-week deductible period, for 52 weeks in the amounts ranging from $3.5 million to $4.5 million per week. Additional weeks of coverage ranging from 71 weeks to 110 weeks are provided at 80 percent of the above weekly amounts. For the current policy period, the companies are subject to retrospective premium assessments of up to approximately $29 million with respect to the primary coverage, $40 million with respect to the decontamination, decommissioning and excess property coverage, and $25 million for the incremental replacement power costs coverage, in the event covered losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant, before any proceeds can be used for decommissioning, plant repair or restoration. Each company is responsible to the extent losses may exceed limits of the coverage described above. At December 31, 2011, PEF has an outstanding claim with NEIL for CR3 (See Notes 6 and 8C).

Both of the Utilities are insured against public liability for a nuclear incident up to $12.595 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed for a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from each insured nuclear incident exceed the primary level of coverage provided by American Nuclear Insurers, each company would be subject to pro rata assessments of up to $117.5 million for each reactor owned for each incident. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $17.5 million per reactor owned per incident. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before August 29, 2013.

Under the NEIL policies, if there were multiple terrorism losses within one year, NEIL would make available one industry aggregate limit of $3.240 billion for noncertified acts, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.

The Utilities self-insure their transmission and distribution lines against loss due to storm damage and other natural disasters. PEF maintains a storm damage reserve and has a regulatory mechanism to recover the costs of named storms on an expedited basis (See Note 8C).

For loss or damage to non-nuclear properties, excluding self-insured transmission and distribution lines, the Utilities are insured under an all-risk property insurance program with a total limit of $600 million per loss. The basic deductible is $2.5 million per loss, and there is no outage or replacement power coverage under this program.

6.	RECEIVABLES

Income taxes receivable and interest income receivables are not included in receivables. These amounts are included in prepayments and other current assets or shown separately on the Consolidated Balance Sheets. At December 31 receivables were comprised of:


	Progress Energy						PEC						PEF
(in millions)	2011			2010			2011			2010			2011			2010
Trade accounts receivable	$	520		$	651		$	276		$	346		$	244		$	303
Unbilled accounts receivable		157			223			102			136			55			87
Other receivables		168			75			123			47			20			12
NEIL receivable (Note 8C)		71			119			—			—			71			119
Allowance for doubtful receivables		(27	)		(35	)		(9	)		(10	)		(18	)		(25	)

Total receivables, net	$	889		$	1,033		$	492		$	519		$	372		$	496

Other receivables for Progress Energy and PEC above include $92 million at December 31, 2011, related to the award from the DOE for asserted damages associated with spent nuclear fuel (See Note 22D).

7.	INVENTORY

At December 31 inventory was comprised of:


	Progress Energy				PEC				PEF
(in millions)	2011		2010		2011		2010		2011		2010
Fuel for production	$	681	$	542	$	323	$	192	$	358	$	350
Materials and supplies		747		676		446		395		301		281
Emission allowances		4		8		1		3		3		5
Other		6		—		5		—		1		—

Total inventory	$	1,438	$	1,226	$	775	$	590	$	663	$	636

Emission allowances above exclude long-term emission allowances included in other assets and deferred debits on the Consolidated Balance Sheets for Progress Energy, PEC and PEF of $28 million, $4 million and $24 million, respectively, at December 31, 2011. Long-term emission allowances for Progress Energy, PEC and PEF were $33 million, $5 million and $28 million, respectively, at December 31, 2010.

8.	REGULATORY MATTERS

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

A.	REGULATORY ASSETS AND LIABILITIES

As regulated entities, the Utilities are subject to the provisions of GAAP for regulated operations. Accordingly, the Utilities record certain assets and liabilities resulting from the effects of the ratemaking process that would not be recorded under GAAP for nonregulated entities. Regulatory assets may be recorded for certain employee benefit costs of unregulated affiliates that will be allocated to the Utilities and recovered through rates of the Utilities. Our and the Utilities’ ability to continue to meet the criteria for application of GAAP for regulated operations could be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that GAAP for regulated operations no longer applies to a separable portion of our operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism was provided. Additionally, such an event would require the Utilities to determine if any impairment to other assets, including utility plant, exists and write down impaired assets to their fair values.

Except for portions of deferred fuel costs and loss on reacquired debt, all regulatory assets earn a return or the cash has not yet been expended, in which case the assets are offset by liabilities that do not incur a carrying cost. We expect to fully recover our regulatory assets and refund our regulatory liabilities through customer rates under current regulatory practice.

At December 31 the balances of regulatory assets (liabilities) were as follows:

PROGRESS ENERGY


(in millions)	2011			2010
Deferred fuel costs – current (Notes 8B and 8C)	$	275		$	169
Nuclear deferral (Note 8C)		—			7

Total current regulatory assets		275			176

Nuclear deferral (Note 8C)^(a)		117			178
Deferred impact of ARO (Note 5C)^(b)		137			122
Income taxes recoverable through future rates^(c)		352			302
Loss on reacquired debt^(d)		29			31
Postretirement benefits (Note 17)^(e)		1,506			1,105
Derivative mark-to-market adjustment (Note 18A)^(f)		708			505
DSM/Energy-efficiency deferral (Note 8B)^(g)		92			57
Other		84			74

Total long-term regulatory assets		3,025			2,374

Environmental (Note 8C)		(7	)		(45	)
Energy conservation (Note 8C)		(19	)		(11	)
Nuclear deferral (Note 8C)		(15	)		—
Other current regulatory liabilities		(7	)		(3	)

Total current regulatory liabilities		(48	)		(59	)

Amount to be refunded to customers (Note 8C)^(h)		(288	)		—
Non-ARO cost of removal (Note 5C)^(b)		(1,650	)		(1,857	)
Deferred impact of ARO (Note 5C)^(b)		(146	)		(143	)
Net nuclear decommissioning trust unrealized gains (Note 5C)⁽ⁱ⁾		(412	)		(421	)
Storm reserve (Note 8C)^(j)		(132	)		(136	)
Other		(72	)		(78	)

Total long-term regulatory liabilities		(2,700	)		(2,635	)

Net regulatory assets (liabilities)	$	552		$	(144	)

PEC


(in millions)	2011			2010
Deferred fuel costs – current (Note 8B)	$	31		$	71

Deferred impact of ARO (Note 5C)^(b)		124			112
Income taxes recoverable through future rates^(c)		140			103
Loss on reacquired debt^(d)		12			13
Postretirement benefits (Note 17)^(e)		691			545
Derivative mark-to-market adjustment (Note 18A)^(f)		200			121
DSM/Energy-efficiency deferral (Note 8B)^(g)		92			57
Other		51			36

Total long-term regulatory assets		1,310			987

Deferred fuel costs – current (Note 8B)		(2	)		—

Non-ARO cost of removal (Note 5C)^(b)		(1,250	)		(1,172	)
Net nuclear decommissioning trust unrealized gains (Note 5C)⁽ⁱ⁾		(266	)		(267	)
Other		(27	)		(22	)

Total long-term regulatory liabilities		(1,543	)		(1,461	)

Net regulatory liabilities	$	(204	)	$	(403	)

PEF


(in millions)	2011			2010
Deferred fuel costs – current (Note 8C)	$	244		$	98
Nuclear deferral (Note 8C)		—			7

Total current regulatory assets		244			105

Nuclear deferral (Note 8C)^(a)		117			178
Income taxes recoverable through future rates^(c)		212			199
Loss on reacquired debt^(d)		17			18
Postretirement benefits (Note 17)^(e)		702			560
Derivative mark-to-market adjustment (Note 18A)^(f)		508			384
Other		46			48

Total long-term regulatory assets		1,602			1,387

Environmental (Note 8C)		(7	)		(45	)
Energy conservation (Note 8C)		(19	)		(11	)
Nuclear deferral (Note 8C)		(15	)		—
Other current regulatory liabilities		(5	)		(3	)

Total current regulatory liabilities		(46	)		(59	)

Amount to be refunded to customers (Note 8C)^(h)		(288	)		—
Non-ARO cost of removal (Note 5C)^(b)		(400	)		(685	)
Deferred impact of ARO (Note 5C)^(b)		(45	)		(47	)
Net nuclear decommissioning trust unrealized gains (Note 5C)⁽ⁱ⁾		(146	)		(154	)
Storm reserve (Note 8C)^(j)		(132	)		(136	)
Other		(60	)		(62	)

Total long-term regulatory liabilities		(1,071	)		(1,084	)

Net regulatory assets	$	729		$	349

The recovery and amortization periods for these regulatory assets and (liabilities) at December 31, 2011, are as follows:

^(a)	Recorded and recovered or amortized as approved by the appropriate state utility commission over a period not exceeding five years.

^(b)	Asset retirement and removal liabilities are recorded over the related property lives, which may range up to 65 years, and will be settled and adjusted following completion of the related activities.

^(c)	Income taxes recoverable through future rates are recovered over the related property lives, which may range up to 65 years.

^(d)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 30 years.

^(e)

Recovered and amortized over the remaining service period of employees. In accordance with a 2009 FPSC order, PEF’s 2009 deferred pension expense of $34 million will be amortized to the extent that annual pension expense is less than the $27 million allowance provided for in base rates (See Note 17).

^(f)	Related to derivative unrealized gains and losses that are recorded as a regulatory liability or asset, respectively, until the contracts are settled. After contract settlement and consumption of the related fuel, the realized gains or losses are passed through the fuel cost-recovery clause.

^(g)	Recorded and recovered or amortized as approved by the appropriate state utility commission over a period not exceeding 10 years.

^(h)	Recorded as a result of the 2012 settlement agreement to be refunded to customers through the fuel clause over four years beginning in 2013 (see Note 8C).

⁽ⁱ⁾	Related to unrealized gains and losses on NDT funds that are recorded as a regulatory asset or liability, respectively, until the funds are used to decommission a nuclear plant.

^(j)	Utilized as storm restoration expenses are incurred.

B.	PEC RETAIL RATE MATTERS

BASE RATES

PEC’s base rates are subject to the regulatory jurisdiction of the NCUC and SCPSC. In PEC’s most recent base rate cases in 1988, the NCUC and the SCPSC each authorized a ROE of 12.75 percent.

COST RECOVERY FILINGS

On November 14, 2011, the NCUC approved PEC’s settlement agreement for an $85 million increase in the fuel rate charged to its North Carolina retail ratepayers, driven by rising fuel prices. The settlement agreement updated certain costs from PEC’s original filing and included the impact of a $24 million disallowance of replacement power costs resulting from prior-year performance of PEC’s nuclear plants. The increase was effective December 1, 2011, and increased residential electric bills by $2.75 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. Also on November 14, 2011, the NCUC approved PEC’s request for a $24 million increase in the demand-side management (DSM) and EE rate charged to its North Carolina ratepayers. The increase was effective December 1, 2011, and increased the residential electric bills by $1.08 per 1,000 kWh for DSM and EE cost recovery. On November 10, 2011, the NCUC approved PEC’s request for a $9 million increase for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS). The increase was effective December 1, 2011, and decreased the residential electric bills by $0.02 per 1,000 kWh. The residential NC REPS rate decreased while the total amount to be recovered increased due to the allocation of the NC REPS recovery between customer classes. The net impact of the settlement agreement and filings results in an average increase in residential electric bills of 3.7 percent. At December 31, 2011, PEC’s North Carolina deferred fuel and DSM/EE balances were $31 million and $78 million, respectively.

On June 29, 2011, the SCPSC approved a $22 million increase in the fuel rate charged to its South Carolina ratepayers, driven by rising fuel prices. The increase was effective July 1, 2011, and increased residential electric bills by $3.45 per 1,000 kWh. Also on June 29, 2011, the SCPSC approved a $4 million increase in the DSM and EE rate. The increase was effective July 1, 2011, and increased residential electric bills by $1.25 per 1,000 kWh. The net impact of the two filings resulted in an average increase in residential electric bills of 4.7 percent. At December 31, 2011, PEC’s South Carolina deferred fuel and DSM/EE balances were $(2) million and $14 million, respectively.

OTHER MATTERS

Construction of Generating Facilities

On June 1, 2011, a newly constructed 600-MW combined cycle natural gas-fueled unit at the Smith Energy Complex was placed in service.

On October 22, 2009, the NCUC issued its order granting PEC a Certificate of Public Convenience and Necessity to construct an approximately 950-MW combined cycle natural gas-fueled electric generating facility at a site in Wayne County, N.C. PEC projects that the generating facility will be in service by January 2013.

On June 9, 2010, the NCUC issued its order granting PEC a Certificate of Public Convenience and Necessity to construct an approximately 620-MW combined cycle natural gas-fueled electric generating facility at a site in New Hanover County, N.C., to replace the existing coal-fired generation at this site. PEC projects that the generating facility will be in service in December 2013.

Planned Retirements of Generating Facilities

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

The net carrying value of the three remaining facilities at December 31, 2011, of $163 million is included in other utility plant, net on the Consolidated Balance Sheets. Consistent with ratemaking treatment, PEC will continue to depreciate each plant using the current depreciation lives and rates on file with the NCUC and the SCPSC until the earlier of the plant’s retirement or PEC’s completion and filing of a new depreciation study on or before March 31, 2013. The net carrying value of the retired facility at December 31, 2011, of $15 million is included in regulatory assets on the Consolidated Balance Sheets. PEC expects to include the four facilities’ remaining net carrying value in rate base after retirement. The final recovery periods may change in connection with the regulators’ determination of the recovery of the remaining net carrying value.

C.	PEF RETAIL RATE MATTERS

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

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

PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. The decision related to repairing or decommissioning CR3 is complex and subject to a number of unknown factors, including but not limited to, the cost of repair and the likelihood of obtaining NRC approval to restart CR3 after repair. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments.

PEF maintains insurance for property damage and incremental costs of replacement power resulting from prolonged accidental outages through NEIL as discussed in Note 5D. NEIL has confirmed that the CR3 initial delamination is a covered accident but has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through

December 31, 2011. 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. PEF has not yet received a definitive determination from NEIL about the insurance coverage related to the second delamination. In addition, no replacement power reimbursements were received from NEIL in the second half of 2011. These considerations led us to conclude that at December 31, 2011, it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, PEF has suspended recording any further insurance receivables from NEIL related to the second delamination and removed the associated $222 million NEIL receivable. PEF recorded a corresponding $154 million addition to its deferred fuel regulatory asset and a $68 million addition to construction work in progress. Negotiations continue with NEIL regarding coverage associated with the second delamination, and 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 December 31, 2011:


(in millions)	Replacement power costs			Repair costs
Spent to date	$	478		$	258
NEIL proceeds received		(162	)		(136	)
Insurance receivable at December 31, 2011, net		(55	)		(3	)

Balance for recovery^(a)	$	261		$	119

^(a)	See “2012 Settlement Agreement” and “Fuel Cost Recovery” below for discussion of PEF’s ability to recover prudently incurred fuel and purchase 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.

On October 25, 2010, the FPSC approved PEF’s motion to establish a separate spin-off docket to review the prudence and costs related to the outage and replacement fuel and power costs associated with the CR3 extended outage. The FPSC subsequently issued an order dividing the docket into three phases. The first phase will include a prudence review of the events and decisions of PEF leading up to the first delamination event. The second phase will be a consideration of the prudence of PEF’s decision to repair or decommission CR3. The third phase of this docket will include the decisions and events subsequent to the first delamination leading up to the March 14, 2011 delamination event and the subsequent repair of the containment building. See “2012 Settlement Agreement – CR3” below for a discussion of the resolution of this docket.

2012 SETTLEMENT AGREEMENT

On February 22, 2012, the FPSC approved a comprehensive settlement agreement between 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 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. 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. 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. 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 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 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 term of the agreement or the return of CR3 to commercial service. 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. The parties to the agreement waive their right to challenge PEF’s recovery of these costs. 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.

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 meet 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.

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 ROE set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. Additionally, 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 will suspend depreciation expense and reverse certain regulatory

liabilities associated with CR3 effective on the implementation date of the agreement. Additionally, rate base 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. The parties to the agreement reserve the right to participate in any hearings challenging the appropriateness of PEF’s CR3 revenue requirements. In the month following CR3’s return to commercial service, PEF’s ROE range will increase to 9.7 percent to 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 as of December 31, 2011, 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 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 expenses associated with those assets will not be included in the base rates and will continue to be recovered through the ECRC.

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. This reduction is limited by the eligible remaining balance of the cost of removal reserve ($246 million at December 31, 2011). 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.

2010 SETTLEMENT AGREEMENT

On June 1, 2010, the FPSC approved a settlement agreement between PEF and the interveners, with the exception of the Florida Association for Fairness in Ratemaking, to the 2009 rate case. As part of the settlement, PEF withdrew its motion for reconsideration of the rate case order. Among other provisions, under the terms of the settlement agreement, PEF will maintain base rates at current levels through the last billing cycle of 2012. The settlement agreement also provides that PEF will have the discretion to reduce amortization expense (cost of removal component) by up to $150 million in 2010, up to $250 million in 2011, and up to any remaining balance in the cost of removal reserve in 2012 until the earlier of (a) PEF’s applicable cost of removal reserve reaches zero, or (b) the expiration of the settlement agreement at the end of 2012. In the event PEF reduces amortization expense by less than the annual amounts for 2010 or 2011, PEF may carry forward (i.e., increase the annual cap by) any unused cost of removal reserve amounts in subsequent years during the term of the agreement. The balance of the cost of removal reserve is impacted by accruals in accordance with PEF’s latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreement. For the year ended December 31, 2011, PEF recognized a $250 million reduction in amortization expense pursuant to the settlement agreement. PEF had eligible cost of removal reserves of $246 million remaining at December 31, 2011. The settlement agreement also provides PEF with the opportunity to earn a ROE of up to 11.5 percent and provides that if PEF’s actual retail base rate earnings fall below a 9.5 percent ROE on an adjusted or pro-forma basis, as reported on a historical 12-month basis during the term of the agreement, PEF may seek general, limited or interim base rate relief, or any

combination thereof. Prior to requesting any such relief, PEF must have reflected on its referenced surveillance report associated amortization expense reductions of at least $150 million. The settlement agreement does not preclude PEF from requesting the FPSC to approve the recovery of costs (a) that are of a type which traditionally and historically would be, have been or are presently recovered through cost-recovery clauses or surcharges; or (b) that are incremental costs not currently recovered in base rates, which the legislature or FPSC determines are clause recoverable; or (c) which are recoverable through base rates under the nuclear cost-recovery legislation or the FPSC’s nuclear cost-recovery rule. PEF also may, at its discretion, accelerate in whole or in part the amortization of certain regulatory assets over the term of the settlement agreement. Finally, PEF will be allowed to recover the costs of named storms on an expedited basis after depletion of the storm damage reserve. Specifically, 60 days following the filing of a cost-recovery petition with the FPSC and based on a 12-month recovery period, PEF can begin recovery, subject to refund, through a surcharge of up to $4.00 per 1,000 kWh on monthly residential customer bills for storm costs. In the event the storm costs exceed that level, any excess additional costs will be deferred and recovered in a subsequent year or years as determined by the FPSC. Additionally, the order approving the settlement agreement allows PEF to use the surcharge to replenish the storm damage reserve to $136 million, the level as of June 1, 2010, after storm costs are fully recovered. At December 31, 2011, PEF’s storm damage reserve was $132 million.

On September 14, 2010, the FPSC approved a reduction to PEF’s AFUDC rate, from 8.8 percent to 7.4 percent. This new rate is based on PEF’s updated authorized ROE and all adjustments approved on January 11, 2010, in PEF’s base rate case and will be used for all purposes except for nuclear recoveries with original need petitions submitted on or before December 31, 2010, as permitted by FPSC regulations.

FUEL COST RECOVERY

On November 22, 2011, the FPSC approved an increase of the total fuel-cost recovery by $162 million, increasing the residential rate by $3.32 per 1,000 kWh, or 2.78 percent, effective January 1, 2012. This increase is due to an increase of $3.99 per 1,000 kWh for the projected recovery of fuel costs offset by a decrease of $0.67 per 1,000 kWh for the projected recovery through the Capacity Cost-Recovery Clause (CCRC). The increase in the projected recovery of fuel costs is due to an under-recovery from the prior year. The decrease in the CCRC is primarily due to lower anticipated costs associated with Levy, and the deferral of 2011 and 2012 estimated costs associated with PEF’s CR3 uprate project until 2012 (see “Nuclear Cost Recovery”), partially offset by increased capacity costs and a reduction of the refund related to an over-recovery from the prior year. Within the fuel clause, PEF received approval to collect, subject to refund, replacement power costs related to the CR3 nuclear plant outage (See “CR3 Outage” and “2012 Settlement Agreement”).

At December 31, 2011, PEF’s deferred fuel regulatory liability was $44 million comprised of a $244 million current regulatory asset and a $288 million noncurrent regulatory liability (See “2012 Settlement Agreement”). The current regulatory asset of $244 million includes the $154 million of replacement power costs that were previously recorded as a receivable from NEIL (See “CR3 Outage”).

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 Levy, together with the associated facilities, including transmission lines and substation facilities. Levy is needed to maintain electric system reliability and integrity, provide fuel and generating diversity, and allow PEF to continue to provide adequate electricity to its customers at a reasonable cost. The proposed Levy units will be advanced passive light water nuclear reactors, each with a generating capacity of approximately 1,100 MW. The petition included projections that Levy Unit No. 1 would be placed in service by June 2016 and Levy Unit No. 2 by June 2017. The filed, nonbinding project cost estimate for Levy Units No. 1 and No. 2 was approximately $14 billion for generating facilities and approximately $3 billion for associated transmission facilities.

In PEF’s 2010 nuclear cost-recovery filing (See “Cost Recovery”), PEF identified a schedule shift in the Levy project that resulted from the NRC’s 2009 determination that certain schedule-critical work that PEF had proposed to perform within the scope of its Limited Work Authorization request submitted with the COL application will not be authorized until the NRC issues the COL. Consequently, major construction activities on Levy have been postponed until after the NRC issues the COL for the units, which is expected in 2013 if the current licensing schedule remains on track. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF’s preferred baseload generation option.

Crystal River Unit No. 3 Nuclear Plant 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.

Cost Recovery

In 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million through the CCRC, which primarily consisted of preconstruction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to help mitigate the initial price impact on its customers, as part of its filing, PEF proposed collecting certain costs over a five-year period, with associated carrying costs on the unrecovered balance. The FPSC approved the alternate proposal allowing PEF to recover revenue requirements associated with the nuclear cost-recovery clause through the CCRC beginning with the first billing cycle of January 2010. The remainder, with minor adjustments, will also be recovered through the CCRC. In adopting PEF’s proposed rate management plan for 2010, the FPSC permitted PEF to annually reconsider changes to the recovery of deferred amounts to afford greater flexibility to manage future rate impacts. The rate management plan included the 2009 reclassification to the nuclear cost-recovery clause regulatory asset of $198 million of capacity revenues and the accelerated amortization of $76 million of preconstruction costs. The cumulative amount of $274 million was recorded as a nuclear cost-recovery regulatory asset at December 31, 2009, and is projected to be recovered by the end of 2014. At December 31, 2011, PEF’s nuclear cost-recovery regulatory asset was $102 million, comprised of a $15 million current regulatory liability and a $117 million noncurrent regulatory asset. PEF will continue to recover nuclear costs as provided for by the 2012 settlement agreement.

On October 24, 2011, the FPSC approved a $78 million decrease in the amount charged to PEF’s ratepayers for nuclear cost recovery, which is a component of, and is included in, the fuel cost recovery (See “Fuel Cost Recovery”), including recovery of preconstruction and carrying costs and CCRC-recoverable O&M expense anticipated to be incurred during 2012, recovery of $60 million of prior years’ deferrals in 2012, as well as the estimated actual true-up of 2011 costs associated with the Levy and CR3 uprate projects. Also included is the stipulation of PEF’s filed motion with the FPSC to defer until 2012 the approval of the long-term feasibility analysis of completing the CR3 uprate, and the determination of reasonableness on, and recovery of, 2011 and 2012 estimated costs. This resulted in an estimated decrease in the nuclear cost-recovery charge of $2.67 per 1,000 kWh for residential customers, beginning with the first January 2012 billing cycle.

DEMAND-SIDE MANAGEMENT COST RECOVERY

On July 26, 2011, the FPSC voted to set PEF’s DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener 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 intervener then filed a notice of appeal of this order to the Florida Supreme Court on January 17, 2012. We cannot predict the outcome of this matter.

On November 1, 2011, the FPSC approved PEF’s request to decrease the Energy Conservation Cost Recovery Clause (ECCR) residential rate by $0.11 per 1,000 kWh, or 0.1 percent of the total residential rate, effective January 1, 2012. The decrease in the ECCR is primarily due to an increased refund of a prior period over-recovery, partially offset by an increase in conservation program costs. At December 31, 2011, PEF’s over-recovered deferred ECCR balance was $19 million.

OTHER MATTERS

On November 22, 2011, the FPSC approved PEF’s request to increase the ECRC by $24 million, increasing the residential rate by $0.54 per 1,000 kWh, or 0.5 percent, effective January 1, 2012. The increase in the ECRC is primarily due to the 2011 rates including a return of a prior period over-recovery, partially offset by a decrease in the related O&M expense. At December 31, 2011, PEF’s over-recovered deferred ECRC was $7 million.

On March 20, 2009, PEF filed a petition with the FPSC for expedited approval of the deferral of $53 million in 2009 pension expense. PEF requested that the deferral of pension expense continue until the recovery of these costs is provided for in FPSC-approved base rates. On June 16, 2009, the FPSC approved the deferral of the retail portion of actual 2009 pension expense. As a result of the order, PEF deferred pension expense of $34 million for the year ended December 31, 2009. PEF will not earn a carrying charge on the deferred pension regulatory asset. The deferral of pension expense did not result in a change in PEF’s 2009 retail rates or prices. In accordance with the order, subsequent to 2009 PEF will amortize the deferred pension regulatory asset to the extent that annual pension expense is less than the $27 million allowance provided for in the base rates established in the 2010 base rate proceeding. In the event such amortization is insufficient to fully amortize the regulatory asset, PEF can seek recovery of the remaining unamortized amount in a base rate proceeding no earlier than 2015. As of December 31, 2011, PEF has not recorded any amortization related to the deferred pension regulatory asset. The 2012 settlement agreement allows for accelerated amortization of all or part of this deferred pension regulatory asset.

D.	NUCLEAR LICENSE RENEWALS

PEC’s nuclear units are currently operating under licenses that expire between 2030 and 2046. The NRC operating license held by PEF for CR3 currently expires in December 2016. PEF applied for a 20-year renewal of the license in 2008. The NRC’s remaining open items in the license renewal process are associated with the containment structure repair. Once the repair design has been completed and evaluated, the NRC may proceed with the renewal application review of the containment structure. Assuming the repair is successful, management believes CR3 will satisfy the requirements for the license renewal.

9.	GOODWILL

Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility reporting units and our goodwill impairment tests are performed at the utility reporting unit level. At December 31, 2011 and 2010, our carrying amount of goodwill was $3.655 billion, with $1.922 billion assigned to PEC and $1.733 billion assigned to PEF. The amounts assigned to PEC and PEF are recorded in our Corporate and Other business segment. We perform our annual impairment test as of October 31 of each year. The results of our 2011 annual test of goodwill indicated that the carrying amounts of goodwill were not impaired.

10.

EQUITY

A.	COMMON STOCK

PROGRESS ENERGY

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

There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2011, there were no significant restrictions on the use of retained earnings (See Note 2 and Note 12B).

The following table presents information for our common stock issuances for the years ended December 31:


	2011				2010				2009
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		2.0	$	53		12.2	$	434		17.5	$	623
Issuances under an underwritten public offering^(a)		—		—		—		—		14.4		523
Issuances through 401(k) and/or IPP		—		1		11.2		431		2.5		100

^(a)	The shares issued under an underwritten public offering were issued on January 12, 2009, at a public offering price of $37.50.

PEC

At December 31, 2011 and December 31, 2010, PEC was authorized to issue up to 200 million shares of common stock. All shares issued and outstanding are held by Progress Energy. There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2011, there were no significant restrictions on the use of retained earnings. See Note 12B for additional dividend restrictions related to PEC.

PEF

At December 31, 2011 and December 31, 2010, PEF was authorized to issue up to 60 million shares of common stock. All PEF common shares issued and outstanding are indirectly held by Progress Energy. There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2011, there were no significant restrictions on the use of retained earnings. See Note 12B for additional dividend restrictions related to PEF.

B.	STOCK-BASED COMPENSATION

EMPLOYEE STOCK OWNERSHIP PLAN

We sponsor the 401(k) for which substantially all full-time nonbargaining unit employees and certain part-time nonbargaining unit employees within participating subsidiaries are eligible. The 401(k), which has a matching feature, encourages systematic savings by employees and provides a method of acquiring Progress Energy common stock and other diverse investments. The 401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire Progress Energy common stock to satisfy 401(k) common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the 401(k). Common stock acquired with the proceeds of an ESOP loan was held by the 401(k) Trustee in a suspense account.

The common stock was released from the suspense account and made available for allocation to participants as the ESOP loan was repaid. Such allocations were used to partially meet common stock needs related to matching and incentive contributions and/or reinvested dividends. All or a portion of the dividends paid on ESOP suspense shares and on ESOP shares allocated to participants may be used to repay ESOP acquisition loans. Dividends that are used to repay such loans, paid directly to participants or reinvested by participants, are deductible for income tax purposes. By December 31, 2010, no ESOP suspense shares were outstanding and the ESOP acquisition loan was repaid.

ESOP shares allocated to plan participants totaled 13.4 million at December 31, 2010. Our matching compensation cost under the 401(k) is determined based on matching percentages as defined in the plan. Through December 31, 2010, such compensation cost was allocated to participants’ accounts in the form of Progress Energy common stock. Beginning in 2011, such compensation cost was allocated to participants’ accounts in the same investments and election percentages as the participants’ contributions. In 2010, we met common stock share needs with open market purchases and with shares released from the ESOP suspense account. Matching costs met with shares released from the suspense account totaled $12 million for the years ended December 31, 2010 and 2009, respectively. In 2011, we met common stock share needs with open market purchases.

We also sponsor the Savings Plan for Employees of Florida Progress Corporation, which is an ESOP plan that covers bargaining unit employees of PEF.

Total matching cost for both plans was $44 million, $43 million and $41 million for the years ended December 31, 2011, 2010 and 2009, respectively.

PEC

PEC’s matching costs met with shares released from the ESOP suspense account totaled $8 million for the years ended December 31, 2010 and 2009, respectively. Total matching cost was $23 million, $23 million and $22 million for the years ended December 31, 2011, 2010 and 2009, respectively.

PEF

PEF’s matching costs met with shares released from the ESOP suspense account totaled $3 million and $4 million for the years ended December 31, 2010 and 2009, respectively. Total matching cost for both plans was $14 million, $14 million and $12 million for the years ended December 31, 2011, 2010 and 2009, respectively.

OTHER STOCK-BASED COMPENSATION PLANS

We have additional compensation plans for our officers and key employees that are stock-based in whole or in part. Our long-term compensation program currently includes two types of equity-based incentives: performance shares under the Performance Share Sub-Plan (PSSP) and restricted stock programs. The compensation program was established pursuant to our 1997 Equity Incentive Plan (EIP) and was continued under our 2002 and 2007 EIPs, as amended and restated from time to time. As authorized by the EIPs, we may grant up to 20 million shares of Progress Energy common stock through our long-term compensation program.

Beginning in 2009, shares issued under the redesigned PSSP use total shareholder return and earnings growth as two equally weighted performance measures. The outcome of the performance measures can result in an increase or decrease from the target number of performance shares granted. We distribute common stock shares to participants equivalent to the number of performance shares that ultimately vest. We issue new shares of common stock to satisfy the requirements of the PSSP program. Also, the fair value of the stock-settled award is generally established at the grant date based on the fair value of common stock on that date, with subsequent adjustments made to reflect the status of the performance measure. Compensation expense for all awards is reduced by estimated forfeitures. At December 31, 2011, there were an immaterial number of stock-settled performance target shares outstanding. The final number of shares issued will be dependent upon the outcome of the performance measures discussed above.

Beginning in 2007, we began issuing restricted stock units (RSUs) rather than the previously issued restricted stock awards for our officers, vice presidents, managers and key employees. RSUs awarded to eligible employees are

generally subject to either three- or five-year cliff vesting or three- or five-year graded vesting. We issue new shares of common stock to satisfy the requirements of the RSU program. Compensation expense, based on the fair value of common stock at the grant date, is recognized over the applicable vesting period, with corresponding increases in common stock equity. RSUs are included as shares outstanding in the basic earnings per share calculation and are converted to shares upon vesting. At December 31, 2011, there were an immaterial number of RSUs outstanding.

The total fair value of RSUs vested during the years ended December 31, 2011, 2010 and 2009, was $24 million, $24 million and $16 million, respectively. No cash was expended to purchase stock to satisfy RSU plan obligations in 2011, 2010 and 2009. The RSUs vested during 2011 had a weighted-average grant date fair value of $39.16.

Our Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $33 million for the year ended December 31, 2011, with a recognized tax benefit of $13 million. The total expense recognized on our Consolidated Statements of Income for other stock-based compensation plans was $27 million, with a recognized tax benefit of $11 million, and $37 million, with a recognized tax benefit of $14 million, for the years ended December 31, 2010 and 2009, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

At December 31, 2011, unrecognized compensation cost related to nonvested other stock-based compensation plan awards totaled $33 million, which is expected to be recognized over a weighted-average period of 1.6 years.

PEC

PEC’s Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $20 million for the year ended December 31, 2011, with a recognized tax benefit of $8 million. The total expense recognized on PEC’s Consolidated Statements of Income for other stock-based compensation plans was $16 million, with a recognized tax benefit of $6 million, and $22 million, with a recognized tax benefit of $9 million, for the years ended December 31, 2010 and 2009, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

PEF

PEF’s Statements of Income included total recognized expense for other stock-based compensation plans of $13 million for the year ended December 31, 2011, with a recognized tax benefit of $5 million. The total expense recognized on PEF’s Statements of Income for other stock-based compensation plans was $11 million, with a recognized tax benefit of $4 million, and $14 million, with a recognized tax benefit of $5 million, for the years ended December 31, 2010 and 2009, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

C.	EARNINGS PER COMMON SHARE

Basic earnings per common share are based on the weighted-average number of common shares outstanding, which includes the effects of unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents. Diluted earnings per share include the effects of the nonvested portion of performance share awards and the effect of stock options outstanding.

A reconciliation of the weighted-average number of common shares outstanding for the years ended December 31 for basic and dilutive purposes follows:


(in millions)	2011		2010		2009
Weighted-average common shares – basic		295.8		290.7		279.4
Net effect of dilutive stock-based compensation plans		0.1		0.1		0.1

Weighted-average shares – fully diluted		295.9		290.8		279.5

There were no adjustments to net income or to income from continuing operations attributable to controlling interests between the calculations of basic and fully diluted earnings per common share. There were 0.8 million and

1.5 million stock options outstanding at December 31, 2010 and 2009, respectively, which were not included in the weighted-average number of shares for computing the fully diluted earnings per share because they were antidilutive. As of December 31, 2011, there were no antidilutive stock options outstanding.

D.	ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss, net of tax, at December 31 were as follows:


	Progress Energy						PEC						PEF
(in millions)	2011			2010			2011			2010			2011			2010
Cash flow hedges	$	(143	)	$	(63	)	$	(71	)	$	(33	)	$	(27	)	$	(4	)
Pension and other postretirement benefits		(22	)		(62	)		—			—			—			—

Total accumulated other comprehensive loss	$	(165	)	$	(125	)	$	(71	)	$	(33	)	$	(27	)	$	(4	)

11.

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.

At December 31, 2011 and 2010, preferred stock outstanding consisted of the following:


	Shares
(dollars in millions, except share and per share data)	Authorized		Outstanding		Redemption Price		Total

*PEC*
Cumulative, no par value $5 Preferred Stock		300,000		236,997	$	110.00	$	24
Cumulative, no par value Serial Preferred Stock		20,000,000
$4.20 Serial Preferred				100,000		102.00		10
$5.44 Serial Preferred				249,850		101.00		25
Cumulative, no par value Preferred Stock A		5,000,000		—		—		—
No par value Preference Stock		10,000,000		—		—		—

Total PEC								59


*PEF*
Cumulative, $100 par value Preferred Stock		4,000,000
4.00% $100 par value Preferred				39,980		104.25		4
4.40% $100 par value Preferred				75,000		102.00		8
4.58% $100 par value Preferred				99,990		101.00		10
4.60% $100 par value Preferred				39,997		103.25		4
4.75% $100 par value Preferred				80,000		102.00		8
Cumulative, no par value Preferred Stock		5,000,000		—		—		—
$100 par value Preference Stock		1,000,000		—		—		—

Total PEF								34

Total preferred stock of subsidiaries							$	93

12.

DEBT AND CREDIT FACILITIES

A.	DEBT AND CREDIT FACILITIES

At December 31 our long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2011):


(in millions)			2011			2010
*Parent*
Senior unsecured notes, maturing 2012-2039	6.28	%	$	4,000		$	4,200
Unamortized premium and discount, net				(7	)		(6	)
Current portion of long-term debt				(450	)		(205	)

Long-term debt, net				3,543			3,989


*PEC*
First mortgage bonds, maturing 2013-2038	5.17	%		3,025			2,525
First mortgage bonds/pollution control obligations, maturing 2017-2024	0.57	%		669			669
Senior unsecured notes, maturing 2012	6.50	%		500			500
Miscellaneous notes	6.00	%		5			5
Unamortized premium and discount, net				(6	)		(6	)
Current portion of long-term debt				(500	)		—

Long-term debt, net				3,693			3,693


*PEF*
First mortgage bonds, maturing 2013-2040	5.56	%		4,100			4,100
First mortgage bonds/pollution control obligations, maturing 2018-2027	0.57	%		241			241
Medium-term notes, maturing 2028	6.75	%		150			150
Unamortized premium and discount, net				(9	)		(9	)
Current portion of long-term debt				—			(300	)

Long-term debt, net				4,482			4,182

Progress Energy consolidated long-term debt, net			$	11,718		$	11,864


*Florida Progress Funding Corporation (See Note 23)*
Debt to affiliated trust, maturing 2039	7.10	%	$	309		$	309
Unamortized premium and discount, net				(36	)		(36	)

Long-term debt, affiliate			$	273		$	273

On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due January 15, 2021. The net proceeds of $495 million, along with available cash on hand, were used to retire the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011. Accordingly, we classified $495 million of the Parent’s $700 million 7.10% Senior Notes due March 1, 2011 as long-term debt at December 31, 2010.

On July 15, 2011, PEF paid at maturity $300 million of its 6.65% First Mortgage Bonds with proceeds from short-term debt.

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

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

On January 15, 2010, the Parent paid at maturity $100 million of its Series A Floating Rate Notes with a portion of the proceeds from the $950 million of Senior Notes issued on November 19, 2009.

On March 25, 2010, PEF issued $250 million of 4.55% First Mortgage Bonds due April 1, 2020, and $350 million of 5.65% First Mortgage Bonds due April 1, 2040. Proceeds were used to repay the outstanding balance of PEF’s notes payable to affiliated companies, to repay the maturity of PEF’s $300 million 4.50% First Mortgage Bonds due June 1, 2010, and for general corporate purposes.

At December 31, 2011 and 2010, we had committed lines of credit used to support our commercial paper and other short-term borrowings. At December 31, 2011 and 2010, we had no outstanding borrowings under our revolving credit agreements (RCAs). We are required to pay fees to maintain our credit facilities.

The following tables summarize our RCAs and available capacity at December 31:


(in millions)		Total		Outstanding		Reserved^(a)		Available
2011
Parent	Five-year (expiring 5/3/12)^(b)	$	478	$	—	$	252	$	226
PEC	Three-year (expiring 10/15/13)		750		—		184		566
PEF	Three-year (expiring 10/15/13)		750		—		233		517

Total credit facilities		$	1,978	$	—	$	669	$	1,309


2010
Parent	Five-year (expiring 5/3/12)	$	500	$	—	$	31	$	469
PEC	Three-year (expiring 10/15/13)		750		—		—		750
PEF	Three-year (expiring 10/15/13)		750		—		—		750

Total credit facilities		$	2,000	$	—	$	31	$	1,969

^(a)

To the extent amounts are reserved for commercial paper or letters of credit outstanding, they are not available for additional borrowings. At December 31, 2011 and 2010, the Parent had issued $2 million and $31 million, respectively, of letters of credit supported by the RCA. Additionally, on December 31, 2011, the Parent, PEC and PEF had $250 million, $184 million and $233 million, respectively, of outstanding commercial paper supported by the RCA.

^(b)	On February 15, 2012, the Parent’s RCA was amended to extend its expiration date to May 3, 2013.

The combined RCAs of the Parent, PEC and PEF total $1.978 billion and are supported by 23 financial institutions. The RCAs are used to provide liquidity support for issuances of commercial paper and other short-term obligations, and for general corporate purposes. Fees and interest rates under the RCAs are determined based upon the respective credit ratings of the Parent’s, PEC’s and PEF’s long-term unsecured senior noncredit-enhanced debt, as rated by Moody’s Investor Services, Inc. (Moody’s) and Standard & Poor’s Rating Services (S&P). The RCAs do not include material adverse change representations for borrowings or financial covenants for interest coverage.

The Parent entered into a five-year RCA on May 3, 2006. On May 2, 2008, the expiration date of the RCA was extended to May 3, 2012. The Parent ratably reduced the size of the RCA to $500 million on October 15, 2010, and the RCA was further reduced to $478 million on May 3, 2011, following the expiration of one financial institution’s credit commitment. 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 syndicate of 14 financial institutions.

PEC and PEF entered into $750 million, three-year RCAs with a syndication of 22 financial institutions on October 15, 2010. The RCAs, which expire October 15, 2013, replaced PEC’s and PEF’s previous RCAs, which were set to expire on June 28, 2011, and March 28, 2011, respectively.

See “Covenants and Default Provisions” for additional provisions related to the RCAs.

The following table summarizes short-term debt, comprised of outstanding commercial paper and other miscellaneous short-term debt, and related weighted-average interest rates at December 31:


(in millions)	2011					2010
Parent		0.50	%	$	250		—	%	$	—
PEC		0.49			188		—			—
PEF		0.51			233		—			—

Total		0.50	%	$	671		—	%	$	—

Long-term debt maturities during the next five years are as follows:


(in millions)	Progress Energy Consolidated		PEC		PEF
2012	$	950	$	500	$	—
2013		830		405		425
2014		300		—		—
2015		1,000		700		300
2016		300		—		—

B.	COVENANTS AND DEFAULT PROVISIONS

FINANCIAL COVENANTS

The Parent’s, PEC’s and PEF’s credit lines contain various terms and conditions that could affect the ability to borrow under these facilities. All of the credit facilities include a defined maximum total debt to total capitalization ratio (leverage). At December 31, 2011, the maximum and calculated ratios for the Progress Registrants, pursuant to the terms of the agreements, were as follows:


Company	Maximum Ratio			Actual Ratio^(a)
Parent		68	%		58	%
PEC		65	%		46	%
PEF		65	%		51	%

^(a)	Indebtedness as defined by the credit agreement includes certain letters of credit, surety bonds and guarantees not recorded on the Consolidated Balance Sheets.

CROSS-DEFAULT PROVISIONS

Each of these credit agreements contains cross-default provisions for defaults of indebtedness in excess of the following thresholds: $50 million for the Parent and $35 million each for PEC and PEF. Under these provisions, if the applicable borrower or certain subsidiaries of the borrower fail to pay various debt obligations in excess of their respective cross-default threshold, the lenders of that credit facility could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility. The Parent’s cross-default provision can be triggered by the Parent and its significant subsidiaries, as defined in the credit agreement. PEC’s and PEF’s cross-default provisions can be triggered only by defaults of indebtedness by PEC and its subsidiaries and PEF, respectively, not by each other or by other affiliates of PEC and PEF.

Additionally, certain of the Parent’s long-term debt indentures contain cross-default provisions for defaults of indebtedness in excess of amounts ranging from $25 million to $50 million; these provisions apply only to other obligations of the Parent, primarily commercial paper issued by the Parent, not its subsidiaries. In the event that these indenture cross-default provisions are triggered, the debt holders could accelerate payment of approximately $4.000 billion in long-term debt. Certain agreements underlying our indebtedness also limit our ability to incur additional liens or engage in certain types of sale and leaseback transactions.

OTHER RESTRICTIONS

Neither the Parent’s Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends, so long as no shares of preferred stock are outstanding. At December 31, 2011, the Parent had no shares of preferred stock outstanding. See Note 2 for information regarding restrictions on dividends relative to the Progress Energy and Duke Energy Agreement and Plan of Merger.

Certain documents restrict the payment of dividends by the Parent’s subsidiaries as outlined below.

PEC

PEC’s mortgage indenture provides that as long as any first mortgage bonds are outstanding, cash dividends and distributions on its common stock and purchases of its common stock are restricted to aggregate net income available for PEC since December 31, 1948, plus $3 million, less the amount of all preferred stock dividends and distributions, and all common stock purchases, since December 31, 1948. At December 31, 2011, none of PEC’s cash dividends or distributions on common stock was restricted.

In addition, PEC’s Articles of Incorporation provide that so long as any shares of preferred stock are outstanding, the aggregate amount of cash dividends or distributions on common stock since December 31, 1945, including the amount then proposed to be expended, shall be limited to 75 percent of the aggregate net income available for common stock if common stock equity falls below 25 percent of total capitalization, as defined by PEC’s Articles of Incorporation, and to 50 percent if common stock equity falls below 20 percent. PEC’s Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75 percent of the current year’s net income available for dividends if common stock equity falls below 25 percent of total capitalization, and to 50 percent if common stock equity falls below 20 percent. At December 31, 2011, PEC’s common stock equity was approximately 57.6 percent of total capitalization. At December 31, 2011, none of PEC’s cash dividends or distributions on common stock was restricted.

PEF

PEF’s mortgage indenture provides that as long as any first mortgage bonds are outstanding, it will not pay any cash dividends upon its common stock, or make any other distribution to the stockholders, except a payment or distribution out of net income of PEF subsequent to December 31, 1943. At December 31, 2011, none of PEF’s cash dividends or distributions on common stock was restricted.

In addition, PEF’s Articles of Incorporation provide that so long as any shares of preferred stock are outstanding, no cash dividends or distributions on common stock shall be paid, if the aggregate amount thereof since April 30, 1944, including the amount then proposed to be expended, plus all other charges to retained earnings since April 30, 1944, exceeds all credits to retained earnings since April 30, 1944, plus all amounts credited to capital surplus after April 30, 1944, arising from the donation to PEF of cash or securities or transfers of amounts from retained earnings to capital surplus. PEF’s Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75 percent of the current year’s net income available for dividends if common stock equity falls below 25 percent of total capitalization, as defined by PEF’s Articles of Incorporation, and to 50 percent if common stock equity falls below 20 percent. On December 31, 2011, PEF’s common stock equity was approximately 50.9 percent of total capitalization. At December 31, 2011, none of PEF’s cash dividends or distributions on common stock was restricted.

C.	COLLATERALIZED OBLIGATIONS

PEC’s and PEF’s first mortgage bonds, including pollution control obligations, are collateralized by their respective mortgage indentures. Each mortgage constitutes a first lien on substantially all of the fixed properties of the respective company, subject to certain permitted encumbrances and exceptions. Each mortgage also constitutes a lien on subsequently acquired property. At December 31, 2011, PEC and PEF had a total of $3.694 billion and $4.341 billion, respectively, of first mortgage bonds outstanding, including those related to pollution control obligations.

Each mortgage allows the issuance of additional first mortgage bonds 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 was below 2.0 times at December 31, 2011. PEF’s 2011 net earnings were impacted by a $288 million charge recorded in December 2011 for amounts to be refunded to customers (See Note 8C). Until this ratio, which is calculated based on results for 12 consecutive months, is above 2.0 times, PEF’s capacity to issue first mortgage bonds is limited to a portion of retired first mortgage bonds. In the event PEF’s long-term debt requirements exceed its first mortgage bond capacity, it could issue unsecured debt.

D.	GUARANTEES OF SUBSIDIARY DEBT

See Note 19 on related party transactions for a discussion of obligations guaranteed or secured by affiliates.

E.	HEDGING ACTIVITIES

We use interest rate derivatives to adjust the fixed and variable rate components of our debt portfolio and to hedge cash flow risk related to commercial paper and fixed-rate debt to be issued in the future. See Note 18 for a discussion of risk management activities and derivative transactions.

13.

INVESTMENTS

A.	INVESTMENTS

At December 31, 2011 and 2010, we had investments in various debt and equity securities, cost investments, company-owned life insurance and investments held in trust funds as follows:


	Progress Energy				PEC				PEF
(in millions)	2011		2010		2011		2010		2011		2010
Nuclear decommissioning trust (See Notes 5C and 14)	$	1,647	$	1,571	$	1,088	$	1,017	$	559	$	554
Equity method investments^(a)		14		16		1		3		2		2
Cost investments^(b)		2		5		2		4		—		—
Company-owned life insurance^(c)		47		46		39		37		—		—
Benefit investment trusts^(d)		176		175		105		97		37		37

Total	$	1,886	$	1,813	$	1,235	$	1,158	$	598	$	593

^(a)

Investments in unconsolidated companies are accounted for using the equity method of accounting (See Note 1) and are included in miscellaneous other property and investments on the Consolidated Balance Sheets. These investments are primarily in limited liability corporations and limited partnerships, and the earnings from these investments are recorded on a pre-tax basis.

^(b)	Investments stated principally at cost are included in miscellaneous other property and investments on the Consolidated Balance Sheets.

^(c)	Investments in company-owned life insurance approximate fair value due to the nature of the investments and are included in miscellaneous other property and investments on the Consolidated Balance Sheets.

^(d)

Benefit investment trusts are included in miscellaneous other property and investments on the Consolidated Balance Sheets. At December 31, 2011 and 2010, $173 million and $166 million, respectively, of investments in company-owned life insurance were held in Progress Energy’s trusts. Substantially all of PEC’s and PEF’s benefit investment trusts are invested in company-owned life insurance.

B.	IMPAIRMENT OF INVESTMENTS

Declines in fair value of available-for-sale securities to below the cost basis that are judged to be other than temporary are included in long-term regulatory assets or liabilities on the Consolidated Balance Sheets for securities held in our nuclear decommissioning trust funds and in operation and maintenance expense and other, net on the Consolidated Statements of Income for securities in our benefit investment trusts, other available-for-sale securities and equity and cost method investments. See Note 14 for additional information. There were no material other-than-temporary impairments recognized in earnings in 2011, 2010 or 2009.

14.

FAIR VALUE DISCLOSURES

A.	DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $12.941 billion and $12.642 billion at December 31, 2011 and 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $15.3 billion and $14.0 billion at December 31, 2011 and 2010, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities’ nuclear plants (See Note 5C). NDT funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, we hold other debt investments classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.

The following table summarizes our available-for-sale securities at December 31:


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
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


2010
Common stock equity	$	1,021	$	13	$	408
Preferred stock and other equity		28		—		11
Corporate debt		90		—		6
U.S. state and municipal debt		132		4		3
U.S. and foreign government debt		264		2		10
Money market funds and other		52		—		1

Total	$	1,587	$	19	$	439

The NDT funds and other available-for-sale debt investments held in certain benefit trusts are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and unrealized gains for 2011 and 2010 relate to the NDT funds. There were no material unrealized losses and unrealized gains for the other available-for-sale debt securities held in benefit trusts at December 31, 2011 and 2010.

The aggregate fair value of investments that related to the December 31, 2011 and 2010 unrealized losses was $136 million and $195 million, respectively.

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


(in millions)
Due in one year or less	$	44
Due after one through five years		231
Due after five through 10 years		147
Due after 10 years		90

Total	$	512

The following table presents selected information about our sales of available-for-sale securities for the years ended December 31. Realized gains and losses were determined on a specific identification basis.


(in millions)	2011		2010		2009
Proceeds	$	4,640	$	6,747	$	2,207
Realized gains		30		21		26
Realized losses		33		27		87

Proceeds were primarily related to NDT funds. Realized gains and losses for investments in the benefit investment trusts were not material. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At December 31, 2011 and 2010, our other securities had no investments in a continuous loss position for greater than 12 months.

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $4.193 billion and $3.693 billion at December 31, 2011 and 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.7 billion and $4.0 billion at December 31, 2011 and 2010, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC’s nuclear plants (See Note 5C). NDT funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes PEC’s available-for-sale securities at December 31:


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
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


2010
Common stock equity	$	652	$	10	$	256
Preferred stock and other equity		14		—		6
Corporate debt		72		—		5
U.S. state and municipal debt		51		1		1
U.S. and foreign government debt		199		1		9
Money market funds and other		42		—		1

Total	$	1,030	$	12	$	278

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds.

The aggregate fair value of investments that related to the December 31, 2011 and 2010 unrealized losses was $98 million and $104 million, respectively.

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


(in millions)
Due in one year or less	$	16
Due after one through five years		184
Due after five through 10 years		100
Due after 10 years		62

Total	$	362

The following table presents selected information about PEC’s sales of available-for-sale securities for the years ended December 31. Realized gains and losses were determined on a specific identification basis.


(in millions)	2011		2010		2009
Proceeds	$	496	$	419	$	622
Realized gains		13		10		9
Realized losses		16		19		36

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

PEF

DEBT

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

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF’s nuclear plant (See Note 5C). The NDT funds are presented on the Balance Sheets at fair value.

The following table summarizes PEF’s available-for-sale securities at December 31:


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
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


2010
Common stock equity	$	369	$	3	$	152
Preferred stock and other equity		14		—		5
Corporate debt		14		—		1
U.S. state and municipal debt		81		3		2
U.S. and foreign government debt		62		1		1
Money market funds and other		10		—		—

Total	$	550	$	7	$	161

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds.

The aggregate fair value of investments that related to the December 31, 2011 and 2010 unrealized losses was $38 million and $87 million, respectively.

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


(in millions)
Due in one year or less	$	28
Due after one through five years		47
Due after five through 10 years		47
Due after 10 years		28


Total	$	150

The following table presents selected information about PEF’s sales of available-for-sale securities for the years ended December 31. Realized gains and losses were determined on a specific identification basis.


(in millions)	2011		2010		2009
Proceeds	$	4,130	$	6,170	$	1,471
Realized gains		17		10		14
Realized losses		17		8		50

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

B.	FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, our and the Utilities’ financial assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2011 and 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PROGRESS ENERGY


(in millions)	Level 1		Level 2		Level 3		Total
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


(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,021	$	—	$	—	$	1,021
Preferred stock and other equity		22		6		—		28
Corporate debt		—		86		—		86
U.S. state and municipal debt		—		132		—		132
U.S. and foreign government debt		79		182		—		261
Money market funds and other		1		42		—		43

Total nuclear decommissioning trust funds		1,123		448		—		1,571
Derivatives
Commodity forward contracts		—		15		—		15
Interest rate contracts		—		4		—		4
Other marketable securities
Corporate debt		—		4		—		4
U.S. and foreign government debt		—		3		—		3
Money market and other		18		—		—		18

Total assets	$	1,141	$	474	$	—	$	1,615


Liabilities
Derivatives
Commodity forward contracts	$	—	$	458	$	36	$	494
Interest rate contracts		—		39		—		39
Contingent value obligations		—		15		—		15

Total liabilities	$	—	$	512	$	36	$	548

PEC


(in millions)	Level 1		Level 2		Level 3		Total
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


(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	652	$	—	$	—	$	652
Preferred stock and other equity		14		—		—		14
Corporate debt		—		72		—		72
U.S. state and municipal debt		—		51		—		51
U.S. and foreign government debt		76		123		—		199
Money market funds and other		1		28		—		29

Total nuclear decommissioning trust funds		743		274		—		1,017
Derivatives
Commodity forward contracts		—		2		—		2
Interest rate contracts		—		3		—		3
Other marketable securities		4		—		—		4

Total assets	$	747	$	279	$	—	$	1,026


Liabilities
Derivatives
Commodity forward contracts	$	—	$	87	$	36	$	123
Interest rate contracts		—		11		—		11

Total liabilities	$	—	$	98	$	36	$	134

PEF


(in millions)	Level 1		Level 2		Level 3		Total
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


(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	369	$	—	$	—	$	369
Preferred stock and other equity		8		6		—		14
Corporate debt		—		14		—		14
U.S. state and municipal debt		—		81		—		81
U.S. and foreign government debt		3		59		—		62
Money market funds and other		—		14		—		14

Total nuclear decommissioning trust funds		380		174		—		554
Derivatives
Commodity forward contracts		—		13		—		13
Other marketable securities		1		—		—		1

Total assets	$	381	$	187	$	—	$	568


Liabilities
Derivatives
Commodity forward contracts	$	—	$	371	$	—	$	371
Interest rate contracts		—		7		—		7

Total liabilities	$	—	$	378	$	—	$	378

The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities’ credit risk on our liabilities.

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the 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 18 for discussion of risk management activities and derivative transactions.

NDT funds reflect the assets of the Utilities’ nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2.

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

Contingent Value Obligations (CVOs), which are derivatives, are discussed further in Note 16. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and classified CVOs as Level 3 at that date. Prior to September 30, 2011, the CVOs were recorded at fair value based on observable prices from a less-than-active market and classified as Level 2. In November 2011, we commenced a public tender offer that expired on February 15, 2012. All CVOs not tendered as of December 31, 2011, were classified as Level 2 based on observable prices in the less-than-active market.

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

A reconciliation of changes in the fair value of our and the Utilities’ derivatives, net classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:

PROGRESS ENERGY


(in millions)	2011			2010			2009
Derivatives, net at beginning of period	$	36		$	39		$	41
Total losses (gains), realized and unrealized – commodities deferred as regulatory assets and liabilities, net		21			44			13
Repurchases of CVOs under settlement and tender offer		(60	)		—			—
Transfers into Level 3 – CVOs		74			—			—
Transfers out of Level 3 – CVOs		(14	)		—			—
Transfers in (out) of Level 3, net – commodities		(33	)		(47	)		(15	)

Derivatives, net at end of period	$	24		$	36		$	39

PEC


(in millions)	2011			2010			2009
Derivatives, net at beginning of period	$	36		$	27		$	22
Total losses (gains), realized and unrealized – commodities deferred as regulatory assets and liabilities, net		20			27			7
Transfers in (out) of Level 3, net – commodities		(32	)		(18	)		(2	)

Derivatives, net at end of period	$	24		$	36		$	27

PEF


(in millions)	2011			2010			2009
Derivatives, net at beginning of period	$	—		$	12		$	19
Total losses (gains), realized and unrealized – commodities deferred as regulatory assets and liabilities, net		1			17			6
Transfers in (out) of Level 3, net – commodities		(1	)		(29	)		(13	)

Derivatives, net at end of period	$	—		$	—		$	12

Substantially all unrealized gains and losses on the Utilities’ derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Realized and unrealized losses on the change in fair value of our CVOs are discussed in Note 18.

15.

INCOME TAXES

We provide deferred income taxes for temporary differences between book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. To the extent that the establishment of deferred income taxes is different from the recovery of taxes by the Utilities through the ratemaking process, the differences are deferred pursuant to GAAP for regulated operations. A regulatory asset or liability has been recognized for the impact of tax expenses or benefits that are recovered or refunded in different periods by the Utilities pursuant to rate orders. We accrue for uncertain tax positions when it is determined that it is more likely than not that the benefit will not be sustained on audit by the taxing authority based solely on the technical merits of the associated tax position. If the recognition threshold is met, the tax benefit recognized is measured at the largest amount that, in our judgment, is greater than 50 percent likely to be realized.

PROGRESS ENERGY

Accumulated deferred income tax assets (liabilities) at December 31 were:


(in millions)	2011			2010
Deferred income tax assets
Derivative instruments	$	309		$	204
Income taxes refundable through future rates		375			271
Pension and other postretirement benefits		591			447
Other		522			501
Tax credit carry forwards		872			839
Net operating loss carry forwards		291			105
Valuation allowance		(71	)		(60	)

Total deferred income tax assets		2,889			2,307

Deferred income tax liabilities
Accumulated depreciation and property cost differences		(3,098	)		(2,439	)
Income taxes recoverable through future rates		(1,271	)		(875	)
Other		(303	)		(386	)

Total deferred income tax liabilities		(4,672	)		(3,700	)

Total net deferred income tax liabilities	$	(1,783	)	$	(1,393	)

The above amounts were classified on the Consolidated Balance Sheets as follows:


(in millions)	2011			2010
Current deferred income tax assets, included in deferred tax assets	$	371		$	156
Noncurrent deferred income tax assets, included in other assets and deferred debits		27			34
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(2,181	)		(1,583	)

Total net deferred income tax liabilities	$	(1,783	)	$	(1,393	)

At December 31, 2011, we had the following tax credit and net operating loss carry forwards:

•

$868 million of federal alternative minimum tax credits that do not expire.

•

$4 million of federal general business credits that will expire during the period 2028 through 2031.

•

$623 million of gross federal net operating loss carry forwards that will expire during 2031. $14 million of the gross federal net operating loss carry forward is related to excess tax deductions resulting from stock-based compensation plans. The tax benefit from the utilization of this portion of the federal net operating loss carry forward will be recorded as a credit to common stock when realized.

•

$1.9 billion of gross state net operating loss carry forwards that will expire during the period 2012 through 2031.

Valuation allowances have been established due to the uncertainty of realizing certain future state tax benefits. We had a net increase of $11 million in our deferred income tax assets and valuation allowances during 2011 related to prior year state net operating loss carry forwards at Progress Fuels Corporation.

We believe it is more likely than not that the results of future operations will generate sufficient taxable income to allow for the utilization of the remaining deferred tax assets.

Certain substantial changes in ownership of Progress Energy, including the proposed merger between Progress Energy and Duke Energy (See Note 2), can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards.

Reconciliations of our effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:


	2011			2010			2009
Effective income tax rate		35.6	%		38.3	%		32.1	%
State income taxes, net of federal benefit		(4.3	)		(4.3	)		(3.7	)
Investment tax credit amortization		0.8			0.5			0.8
Employee stock ownership plan dividends		1.4			0.9			1.0
Domestic manufacturing deduction		—			—			0.8
AFUDC equity		2.6			1.4			2.2
Other differences, net		(1.1	)		(1.8	)		1.8

Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Income tax expense applicable to continuing operations for the years ended December 31 was comprised of:


(in millions)	2011			2010			2009
Current
Federal	$	(91	)	$	(46	)	$	227
State		29			(13	)		41

Total current income tax expense (benefit)		(62	)		(59	)		268

Deferred
Federal		578			542			114
State		27			100			25

Total deferred income tax expense		605			642			139

Investment tax credit		(7	)		(7	)		(10	)
Net operating loss carry forward		(213	)		(37	)		—

Total income tax expense	$	323		$	539		$	397

Total income tax expense applicable to continuing operations excluded the following:

•

Taxes related to discontinued operations recorded net of tax for 2011, 2010 and 2009, which are presented separately in Note 4A.

•

Taxes related to other comprehensive income recorded net of tax for 2011, 2010 and 2009, which are presented separately on the Consolidated Statements of Comprehensive Income.

•

An immaterial amount of current tax benefit, which was recorded in common stock during 2010, related to excess tax deductions resulting from vesting of restricted stock awards, vesting of RSUs, vesting of stock-settled PSSP awards and exercises of nonqualified stock options pursuant to the terms of our EIP. No net current tax benefit was recorded in common stock during 2011 and 2009.

At December 31, 2011, 2010 and 2009, our liability for unrecognized tax benefits was $173 million, $176 million and $160 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $6 million, $8 million and $9 million at December 31, 2011, 2010 and 2009, respectively. The following table presents the changes to unrecognized tax benefits during the years ended December 31:


(in millions)	2011			2010			2009
Unrecognized tax benefits at beginning of period	$	176		$	160		$	104

Gross amounts of increases as a result of tax positions taken in a prior period		88			10			11

Gross amounts of decreases as a result of tax positions taken in a prior period		(24	)		(4	)		(3	)

Gross amounts of increases as a result of tax positions taken in the current period		9			14			52

Gross amounts of decreases as a result of tax positions taken in the current period		(8	)		(4	)		(4	)

Amounts of net decreases relating to settlements with taxing authorities		(68	)		—			—

Unrecognized tax benefits at end of period	$	173		$	176		$	160

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Our federal tax years are open for examination from 2007 forward, and our open state tax years in our major jurisdictions generally are from 2003 forward. In 2011, the IRS completed its examination of the 2004 and 2005 tax years. It is reasonably possible that unrecognized tax benefits will decrease by approximately $25 million during the 12-month period ending December 31, 2012, due to IRS review of open tax years. Any potential decrease will not have a material impact on our results of operations.

We include interest expense related to unrecognized tax benefits in net interest charges and we include penalties in other, net on the Consolidated Statements of Income. During 2011, 2010 and 2009, the net interest (benefit) expense related to unrecognized tax benefits was $(24) million, $9 million and $9 million, respectively, of which a respective $(22) million, $5 million and $5 million (benefit) expense component was deferred as a regulatory asset by PEF, which is amortized as a charge to interest expense over a three-year period or less. During 2011, PEF charged the unamortized balance of the regulatory asset to interest expense. During 2011, 2010 and 2009, there were no penalties related to unrecognized tax benefits. At December 31, 2011, 2010 and 2009, we accrued $21 million, $45 million and $36 million, respectively, for interest and penalties, which were included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets.

PEC

Accumulated deferred income tax assets (liabilities) at December 31 were:


(in millions)	2011			2010
Deferred income tax assets
ARO liability	$	101		$	103
Derivative instruments		96			49
Income taxes refundable through future rates		142			142
Pension and other postretirement benefits		244			180
Other		168			158
Tax credit carry forwards		3			—
Net operating loss carry forwards		54			—

Total deferred income tax assets		808			632

Deferred income tax liabilities
Accumulated depreciation and property cost differences		(1,908	)		(1,552	)
Income taxes recoverable through future rates		(541	)		(421	)
Investments		(103	)		(104	)
Other		(17	)		(35	)

Total deferred income tax liabilities		(2,569	)		(2,112	)

Total net deferred income tax liabilities	$	(1,761	)	$	(1,480	)

The above amounts were classified on the Consolidated Balance Sheets as follows:


(in millions)	2011			2010
Current deferred income tax assets, included in deferred tax assets	$	142		$	65
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,903	)		(1,545	)

Total net deferred income tax liabilities	$	(1,761	)	$	(1,480	)

At December 31, 2011, PEC had the following tax credit and net operating loss carry forwards:

•

$3 million of federal general business credits that will expire during the period 2028 through 2031.

•

$161 million of gross federal net operating loss carry forwards that will expire during 2031. $6 million of the gross federal net operating loss carry forward is related to excess tax deductions resulting from stock-based compensation plans. The tax benefit from the utilization of this portion of the federal net operating loss carry forward will be recorded as a credit to common stock when realized.

•

$1 million of gross state net operating loss carry forwards that will expire during the period 2012 through 2030.

Reconciliations of PEC’s effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:


	2011			2010			2009
Effective income tax rate		33.2	%		36.8	%		35.0	%
State income taxes, net of federal benefit		(2.3	)		(3.2	)		(2.8	)
Investment tax credit amortization		0.7			0.6			0.7
Domestic manufacturing deduction		—			0.4			0.9
AFUDC equity		2.2			1.5			0.6
Other differences, net		1.2			(1.1	)		0.6

Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Income tax expense for the years ended December 31 was comprised of:


(in millions)	2011			2010			2009
Current
Federal	$	(27	)	$	73		$	192
State		21			(8	)		21

Total current income tax expense (benefit)		(6	)		65			213

Deferred
Federal		316			238			57
State		6			53			13

Total deferred income tax expense		322			291			70

Investment tax credit		(6	)		(6	)		(6	)
Net operating loss carry forward		(54	)		—			—

Total income tax expense	$	256		$	350		$	277

Total income tax expense excluded taxes related to other comprehensive income recorded net of tax for 2011, 2010 and 2009, which are presented separately on the Consolidated Statements of Comprehensive Income.

PEC and each of its wholly owned subsidiaries have entered into the Tax Agreement with the Parent (See Note 1D). PEC’s intercompany tax receivable was approximately $4 million and $78 million at December 31, 2011 and 2010, respectively.

At December 31, 2011, 2010 and 2009, PEC’s liability for unrecognized tax benefits was $73 million, $74 million and $59 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $1 million, $4 million and $5 million at December 31, 2011, 2010 and 2009, respectively. The following table presents the changes to unrecognized tax benefits during the years ended December 31:


(in millions)	2011			2010			2009
Unrecognized tax benefits at beginning of period	$	74		$	59		$	38
Gross amounts of increases as a result of tax positions taken in a prior period		19			8			6
Gross amounts of decreases as a result of tax positions taken in a prior period		(14	)		(2	)		(2	)
Gross amounts of increases as a result of tax positions taken in the current period		8			10			17
Gross amounts of decreases as a result of tax positions taken in the current period		(4	)		(1	)		—
Amounts of net decreases relating to settlements with taxing authorities		(10	)		—			—

Unrecognized tax benefits at end of period	$	73		$	74		$	59

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. PEC’s open federal tax years are from 2007 forward, and PEC’s open state tax years in our major jurisdictions generally are from 2003 forward. In 2011, the IRS completed its examination of the 2004 and 2005 tax years. PEC is not aware of any tax positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease during the 12-month period ending December 31, 2012.

PEC includes interest expense related to unrecognized tax benefits in net interest charges and we include penalties in other, net on the Consolidated Statements of Income. During 2011, 2010 and 2009, the interest (benefit) expense recorded related to unrecognized tax benefits was $(6) million, $4 million and $3 million, respectively. During 2011, 2010 and 2009, there were no penalties related to unrecognized tax benefits. At December 31, 2011, 2010 and 2009,

we accrued $8 million, $14 million and $10 million, respectively, for interest and penalties, which were included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets.

PEF

Accumulated deferred income tax assets (liabilities) at December 31 were:


(in millions)	2011			2010
Deferred income tax assets
Derivative instruments	$	198		$	145
Income taxes refundable through future rates		198			93
Pension and other postretirement benefits		224			170
Reserve for storm damage		52			52
Unbilled revenue		39			61
Other		101			82
Tax credit carry forwards		1			3
Net operating loss carry forwards		41			9

Total deferred income tax assets		854			615

Deferred income tax liabilities
Accumulated depreciation and property cost differences		(1,180	)		(874	)
Deferred fuel recovery		(40	)		(65	)
Deferred nuclear cost recovery		(68	)		(94	)
Income taxes recoverable through future rates		(685	)		(454	)
Investments		(56	)		(60	)
Other		(12	)		(18	)

Total deferred income tax liabilities		(2,041	)		(1,565	)

Total net deferred income tax liabilities	$	(1,187	)	$	(950	)

The above amounts were classified on the Balance Sheets as follows:


(in millions)	2011			2010
Current deferred income tax assets, included in deferred tax assets	$	138		$	77
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,325	)		(1,027	)

Total net deferred income tax liabilities	$	(1,187	)	$	(950	)

At December 31, 2011, PEF had the following tax credit and net operating loss carry forwards:

•

$1 million of federal general business credits that will expire during the period 2029 through 2031.

•

$120 million of gross federal net operating loss carry forwards that will expire during 2031. $3 million of the gross federal net operating loss carry forward is related to excess tax deductions resulting from stock-based compensation plans. The tax benefit from the utilization of this portion of the federal net operating loss carry forward will be recorded as a credit to common stock when realized.

Reconciliations of PEF’s effective income tax rate to the statutory federal income tax rate for the years ended December 31 follow:


	2011			2010			2009
Effective income tax rate		36.3	%		37.9	%		31.1	%
State income taxes, net of federal benefit		(3.5	)		(3.2	)		(3.0	)
Investment tax credit amortization		0.3			0.2			0.7
Domestic manufacturing deduction		—			—			0.8
AFUDC equity		1.4			0.8			3.4
Other differences, net		0.5			(0.7	)		2.0

Statutory federal income tax rate		35.0	%		35.0	%		35.0	%

Income tax expense for the years ended December 31 was comprised of:


(in millions)	2011			2010			2009
Current
Federal	$	(60	)	$	(44	)	$	125
State		5			(4	)		20

Total current income tax expense (benefit)		(55	)		(48	)		145

Deferred
Federal		255			293			57
State		22			41			11

Total deferred income tax expense		277			334			68

Investment tax credit		(1	)		(1	)		(4	)
Net operating loss carry forward		(41	)		(9	)		—

Total income tax expense	$	180		$	276		$	209

Total income tax expense excluded the following:

•

Taxes related to other comprehensive income recorded net of tax for 2011, 2010 and 2009, which are presented separately on the Statements of Comprehensive Income.

•

PEF has entered into the Tax Agreement with the Parent (See Note 1D). PEF’s intercompany tax receivable was approximately $23 million and $71 million at December 31, 2011 and 2010, respectively.

At December 31, 2011, 2010 and 2009, PEF’s liability for unrecognized tax benefits was $80 million, $99 million and $98 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $1 million, $2 million and $3 million at December 31, 2011, 2010 and 2009, respectively. The following table presents the changes to unrecognized tax benefits during the years ended December 31:


(in millions)	2011			2010			2009
Unrecognized tax benefits at beginning of period	$	99		$	98		$	62
Gross amounts of increases as a result of tax positions taken in a prior period		66			2			5
Gross amounts of decreases as a result of tax positions taken in a prior period		(21	)		(1	)		(1	)
Gross amounts of increases as a result of tax positions taken in the current period		1			3			35
Gross amounts of decreases as a result of tax positions taken in the current period		(4	)		(3	)		(3	)
Amounts of net decreases relating to settlements with taxing authorities		(61	)		—			—

Unrecognized tax benefits at end of period	$	80		$	99		$	98

We file consolidated federal and state income tax returns that include PEF. PEF’s open federal tax years are from 2007 forward, and PEF’s open state tax years generally are from 2003 forward. In 2011, the IRS completed its examination of the 2004 and 2005 tax years. It is reasonably possible that unrecognized tax benefits will decrease by approximately $20 million during the 12-month period ending December 31, 2012, due to IRS review of open tax years. Any potential decrease will not have a material impact on our results of operations.

Pursuant to a regulatory order, PEF records interest expense related to unrecognized tax benefits as a regulatory asset, which is amortized over a three-year period or less, with the amortization included in net interest charges on the Statements of Income. Penalties are included in other, net on the Statements of Income. During 2011, 2010 and 2009, interest (benefit) expense recorded as a regulatory asset was $(22) million, $5 million and $5 million, respectively, and there were no penalties recorded related to unrecognized tax benefits. During 2011, PEF charged the unamortized balance of the regulatory asset to interest expense. At December 31, 2011, 2010 and 2009, PEF accrued $7 million, $29 million and $24 million, respectively, for interest and penalties, which were included in prepayments and other current assets and other liabilities and deferred credits on the Balance Sheets.

16.

CONTINGENT VALUE OBLIGATIONS

In connection with the acquisition of Florida Progress during 2000, the Parent issued 98.6 million CVOs. Each CVO represents the right of the holder to receive contingent payments based on the performance of four coal-based solid synthetic fuels limited liability companies, three of which were wholly owned (Earthco), purchased by subsidiaries of Florida Progress in October 1999. All of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007 (See Note 4A). The payments are based on the net after-tax cash flows the facilities generated. We make deposits into a CVO trust for estimated contingent payments due to CVO holders based on the results of operations and the utilization of tax credits. The balance of the CVO trust at December 31, 2011 and 2010, was $11 million and is included in other assets and deferred debits on the Consolidated Balance Sheets. Future payments from the trust to CVO holders will not be made until certain conditions are satisfied and will include principal and interest earned during the investment period net of expenses deducted. Interest earned on the payments held in trust for 2011 and 2010 was insignificant.

On June 10, 2011, Davidson Kempner Partners, M.H. Davidson & Co., Davidson Kempner Institutional Partners, L.P., and Davidson Kempner International, Ltd. (jointly, Davidson Kempner) filed a lawsuit against us (see Note 22D) related to their ownership of CVOs. On October 3, 2011, we entered a settlement agreement and release with

Davidson Kempner under which the parties mutually released all claims related to the CVOs and we purchased all of Davidson Kempner’s CVOs at a negotiated purchase price of $0.75 per CVO. In November 2011, we also commenced a tender offer for all remaining outstanding CVOs at the same purchase price. The tender offer expired on February 15, 2012, and as a result, 83.4 million CVOs were repurchased through the settlement agreement or through the tender offer. The CVOs are derivatives and are recorded at fair value. At September 30, 2011, the purchase price included in the settlement agreement and subsequent tender offer represented the fair value of the CVOs. Prior to September 30, 2011, and at December 31, 2011, the CVOs were recorded at fair value based on observable prices from a less-than-active market (see Note 14). A pre-tax loss of $59 million from the changes in fair value during 2011 is recorded in other, net on the Consolidated Statements of Income. At December 31, 2011, the CVO liability included in other current liabilities on our Consolidated Balance Sheets was $14 million based on the 18.5 million outstanding CVOs not held by the Parent. At December 31, 2010, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $15 million based on the 98.6 million CVOs outstanding.

17.

BENEFIT PLANS

A.	POSTRETIREMENT BENEFITS

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. We use a measurement date of December 31 for our pension and OPEB plans.

COSTS OF BENEFIT PLANS

Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

To determine the market-related value of assets, we use a five-year averaging method for a portion of the pension assets and fair value for the remaining portion. We have historically used the five-year averaging method. When we acquired Florida Progress in 2000, we retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets.

The tables below provide the components of the net periodic benefit cost for the years ended December 31. A portion of net periodic benefit cost is capitalized as part of construction work in progress.

PROGRESS ENERGY

		$(182)			$(182)			$(182)			$(182)			$(182)			$(182)
	Pension Benefits									OPEB
(in millions)	2011			2010			2009			2011			2010			2009
Service cost	$	53		$	48		$	42		$	11		$	16		$	7
Interest cost		141			140			138			41			45			31
Expected return on plan assets		(182	)		(157	)		(133	)		(2	)		(4	)		(4	)
Amortization of actuarial loss^(a)		69			51			54			12			13			1
Other amortization, net ^(a)		7			6			6			5			5			5

Net periodic cost before deferral^(b)	$	88		$	88		$	107		$	67		$	75		$	40

^(a)	Adjusted to reflect PEF’s rate treatment (See Note 17B).

^(b)

PEF received permission from the FPSC to defer the retail portion of certain 2009 pension expense. The FPSC order did not change the total net periodic pension cost, but deferred a portion of the costs to be recovered in future periods. During 2009, PEF deferred $34 million of net periodic pension costs as a regulatory asset. See Note 8C.

PEC

		$(182)			$(182)			$(182)			$(182)			$(182)			$(182)
	Pension Benefits									OPEB
(in millions)	2011			2010			2009			2011			2010			2009
Service cost	$	21		$	19		$	18		$	5		$	5		$	5
Interest cost		63			64			64			20			20			16
Expected return on plan assets		(91	)		(77	)		(67	)		—			(2	)		(2	)
Amortization of actuarial loss		26			16			11			5			4			—
Other amortization, net		5			6			6			1			1			1

Net periodic cost	$	24		$	28		$	32		$	31		$	28		$	20


*PEF*

	Pension Benefits									OPEB
(in millions)	2011			2010			2009			2011			2010			2009
Service cost	$	25		$	22		$	19		$	5		$	10		$	2
Interest cost		59			59			56			18			22			13
Expected return on plan assets		(78	)		(68	)		(56	)		(2	)		(2	)		(1	)
Amortization of actuarial loss		33			31			38			7			9			—
Other amortization, net		—			—			—			4			4			3

Net periodic cost before deferral^(a)	$	39		$	44		$	57		$	32		$	43		$	17

^(a)

The following tables provide a summary of amounts recognized in other comprehensive income and other comprehensive income reclassification adjustments for amounts included in net income for 2011, 2010 and 2009. The tables also include comparable items that affected regulatory assets. Amounts that would otherwise be recorded in other comprehensive income are recorded as adjustments to regulatory assets consistent with the recovery of the related costs through the ratemaking process.

PROGRESS ENERGY

		$(182)			$(182)			$(182)			$(182)			$(182)			$(182)
	Pension Benefits									OPEB
(in millions)	2011			2010			2009			2011			2010			2009
Other comprehensive income (loss)
Recognized for the year
Net actuarial (loss) gain	$	(20	)	$	(11	)	$	(1	)	$	(2	)	$	(10	)	$	4
Regulatory asset adjustment		84			—			—			(4	)		—			—
Reclassification adjustments
Net actuarial loss		10			4			5			—			—			1
Other, net		2			—			—			—			—			1
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain		(307	)		(65	)		10			(95	)		(164	)		64
Reclassification adjustment		(84	)		—			—			4			—			—
Other, net		—			—			(3	)		—			—			—
Amortized to income^(a)
Net actuarial loss		59			47			49			12			13			—
Other, net		5			6			6			5			5			4

^(a)	These amounts were amortized as a component of net periodic cost, as reflected in the previous net periodic cost table. Refer to that table for information regarding the deferral of a portion of net periodic pension cost.

PEC

		$(182)			$(182)			$(182)			$(182)			$(182)			$(182)
	Pension Benefits									OPEB
(in millions)	2011			2010			2009			2011			2010			2009
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain	$	(134	)	$	(24	)	$	(14	)	$	(49	)	$	(64	)	$	38
Other, net		—			—			(2	)		—			—			—
Amortized to income
Net actuarial loss		26			16			11			5			4			—
Other, net		5			6			6			1			1			1

*PEF*

	Pension Benefits									OPEB
(in millions)	2011			2010			2009			2011			2010			2009
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain	$	(147	)	$	(41	)	$	24		$	(39	)	$	(100	)	$	26
Other, net		—			—			(1	)		—			—			—
Amortized to income^(a)
Net actuarial loss		33			31			38			7			9			—
Other, net		—			—			—			4			4			3

^(a)	These amounts were amortized as a component of net periodic cost, as reflected in the previous net periodic cost table. Refer to that table for information regarding the deferral of a portion of net periodic pension cost.

The following weighted-average actuarial assumptions were used by Progress Energy in the calculation of its net periodic cost:

		$(182)			$(182)			$(182)			$(182)			$(182)			$(182)
	Pension Benefits									OPEB
	2011			2010			2009			2011			2010			2009
Discount rate		5.60	%		6.00	%		6.30	%		5.70	%		6.05	%		6.20	%
Rate of increase in future compensation
Bargaining		4.50	%		4.50	%		4.25	%		—			—			—
Supplementary plans		5.25	%		5.25	%		5.25	%		—			—			—
Expected long-term rate of return on plan assets		8.50	%		8.75	%		8.75	%		5.00	%		6.60	%		6.80	%

The weighted-average actuarial assumptions used by PEC and PEF were not materially different from the assumptions above, as applicable, except that the expected long-term rate of return on OPEB plan assets was 5.00% for PEF for all years presented and for PEC was 8.75% for 2010 and 2009. PEC held no OPEB plan assets during 2011.

The expected long-term rates of return on plan assets were determined by considering long-term projected returns based on the plans’ target asset allocations. Specifically, return rates were developed for each major asset class and weighted based on the target asset allocations. The projected returns were benchmarked against historical returns for reasonableness. We decreased our expected long-term rate of return on pension assets by 0.25% in 2011, primarily due to a shift in our investment strategy. See the “Assets of Benefit Plans” section below for additional information regarding our investment policies and strategies.

BENEFIT OBLIGATIONS AND ACCRUED COSTS

GAAP requires us to recognize in our statement of financial condition the funded status of our pension and other postretirement benefit plans, measured as the difference between the fair value of the plan assets and the benefit obligation as of the end of the fiscal year.

Reconciliations of the changes in the Progress Registrants’ benefit obligations and the funded status as of December 31, 2011 and 2010 are presented in the tables below, with each table followed by related supplementary information.

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Projected benefit obligation at January 1	$	2,609		$	2,422		$	733		$	543
Service cost		53			48			11			16
Interest cost		141			140			41			45
Settlements		(6	)		—			—			—
Benefit payments		(129	)		(129	)		(42	)		(44	)
Plan amendment		—			1			—			—
Actuarial loss		238			127			98			173

Obligation at December 31		2,906			2,609			841			733
Fair value of plan assets at December 31		2,191			1,891			37			33

Funded status	$	(715	)	$	(718	)	$	(804	)	$	(700	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $2.906 billion and $2.609 billion at December 31, 2011 and 2010, respectively. Those plans had accumulated benefit obligations totaling $2.854 billion and $2.563 billion at December 31, 2011 and 2010, respectively, and plan assets of $2.191 billion and $1.891 billion at December 31, 2011 and 2010, respectively.

The accrued benefit costs reflected in the Consolidated Balance Sheets at December 31 were as follows:


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Current liabilities	$	(10	)	$	(10	)	$	(22	)	$	(22	)
Noncurrent liabilities		(705	)		(708	)		(782	)		(678	)

Funded status	$	(715	)	$	(718	)	$	(804	)	$	(700	)

The following table provides a summary of amounts not yet recognized as a component of net periodic cost at December 31:


	Pension Benefits				OPEB
(in millions)	2011		2010		2011		2010
Recognized in accumulated other comprehensive loss
Net actuarial loss	$	34	$	90	$	—	$	5
Other, net		2		9		—		1
Recognized in regulatory assets, net
Net actuarial loss		1,139		824		274		183
Other, net		56		55		3		9

Total not yet recognized as a component of net periodic cost^(a)	$	1,231	$	978	$	277	$	198

^(a)	All components are adjusted to reflect PEF’s rate treatment (See Note 17B).

The following table presents the amounts we expect to recognize as components of net periodic cost in 2012:


(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss^(a)	$	91	$	23
Amortization of other, net^(a)		9		4

^(a)	Adjusted to reflect PEF’s rate treatment (See Note 17B).

PEC


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Projected benefit obligation at January 1	$	1,188		$	1,120		$	352		$	282
Service cost		21			19			5			5
Interest cost		63			64			20			20
Benefit payments		(56	)		(56	)		(19	)		(19	)
Actuarial loss		86			41			49			64

Obligation at December 31		1,302			1,188			407			352
Fair value of plan assets at December 31		1,091			884			—			—

Funded status	$	(211	)	$	(304	)	$	(407	)	$	(352	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $1.302 billion and $1.188 billion at December 31, 2011 and 2010, respectively. Those plans had accumulated benefit obligations totaling $1.297 billion and $1.184 billion at December 31, 2011 and 2010, respectively, and plan assets of $1.091 billion and $884 million at December 31, 2011 and 2010, respectively.

The accrued benefit costs reflected on the Balance Sheets at December 31 were as follows:


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Current liabilities	$	(2	)	$	(2	)	$	(19	)	$	(19	)
Noncurrent liabilities		(209	)		(302	)		(388	)		(333	)

Funded status	$	(211	)	$	(304	)	$	(407	)	$	(352	)

The table below provides a summary of amounts not yet recognized as a component of net periodic cost at December 31:


	Pension Benefits				OPEB
(in millions)	2011		2010		2011		2010
Recognized in regulatory assets
Net actuarial loss	$	527	$	418	$	121	$	76
Other, net		43		49		—		2

Total not yet recognized as a component of net periodic cost	$	570	$	467	$	121	$	78

The following table presents the amounts PEC expects to recognize as components of net periodic cost in 2012:


(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss	$	37	$	11
Amortization of other, net		8		—

PEF


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Projected benefit obligation at January 1	$	1,087		$	992		$	326		$	219
Service cost		25			22			5			10
Interest cost		59			59			18			22
Plan amendment		—			1			—			—
Benefit payments		(58	)		(58	)		(21	)		(23	)
Actuarial loss		110			71			40			98

Obligation at December 31		1,223			1,087			368			326
Fair value of plan assets at December 31		969			871			37			33

Funded status	$	(254	)	$	(216	)	$	(331	)	$	(293	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $1.223 billion and $1.087 billion at December 31, 2011 and 2010, respectively. Those plans had accumulated benefit obligations totaling $1.184 billion and $1.049 billion at December 31, 2011 and 2010, respectively, and plan assets of $969 million and $871 million at December 31, 2011 and 2010, respectively.

The accrued benefit costs reflected in the Balance Sheets at December 31 were as follows:


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Current liabilities	$	(3	)	$	(3	)	$	—		$	—
Noncurrent liabilities		(251	)		(213	)		(331	)		(293	)

Funded status	$	(254	)	$	(216	)	$	(331	)	$	(293	)

The following table provides a summary of amounts not yet recognized as a component of net periodic cost at December 31.


	Pension Benefits				OPEB
(in millions)	2011		2010		2011		2010
Recognized in regulatory assets, net
Net actuarial loss	$	520	$	406	$	139	$	107
Other, net		6		6		3		7

Total not yet recognized as a component of net periodic cost	$	526	$	412	$	142	$	114

The following table presents the amounts PEF expects to recognize as components of net periodic cost in 2012:


(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss	$	45	$	12
Amortization of other, net		—		3

The following weighted-average actuarial assumptions were used in the calculation of our year-end obligations:


	Pension Benefits						OPEB
	2011			2010			2011			2010
Discount rate		4.75	%		5.65	%		4.85	%		5.75	%
Rate of increase in future compensation
Bargaining		4.00	%		4.50	%		—			—
Supplementary plans		5.25	%		5.25	%		—			—
Initial medical cost trend rate for pre-Medicare Act benefits		—			—			8.75	%		8.50	%
Initial medical cost trend rate for post-Medicare Act benefits		—			—			8.75	%		8.50	%
Ultimate medical cost trend rate		—			—			5.00	%		5.00	%
Year ultimate medical cost trend rate is achieved		—			—			2020			2017

The weighted-average actuarial assumptions for PEC and PEF were the same or were not significantly different from those indicated above, as applicable. The rates of increase in future compensation include the effects of cost of living adjustments and promotions.

Our primary defined benefit retirement plan for nonbargaining employees is a “cash balance” pension plan. Therefore, we use the traditional unit credit method for purposes of measuring the benefit obligation of this plan. Under the traditional unit credit method, no assumptions are included about future changes in compensation, and the accumulated benefit obligation and projected benefit obligation are the same.

MEDICAL COST TREND RATE SENSITIVITY

The medical cost trend rates were assumed to decrease gradually from the initial rates to the ultimate rates. The effects of a 1 percent change in the medical cost trend rate are shown below.


	Progress Energy			PEC			PEF
1 percent increase in medical cost trend rate
Effect on total of service and interest cost	$	3		$	1		$	1
Effect on postretirement benefit obligation		43			21			19
1 percent decrease in medical cost trend rate
Effect on total of service and interest cost		(2	)		(1	)		(1	)
Effect on postretirement benefit obligation		(31	)		(15	)		(14	)

ASSETS OF BENEFIT PLANS

In the plan asset reconciliation tables that follow, our, PEC’s and PEF’s employer contributions to qualified plans for 2011 include contributions directly to pension plan assets of $334 million, $217 million and $112 million, respectively, and for 2010 include contributions directly to pension plan assets of $129 million, $95 million and $34 million, respectively. Substantially all of the remaining employer contributions represent benefit payments made directly from the Progress Registrants’ assets. The OPEB benefit payments presented in the plan asset reconciliation tables that follow represent the cost after participant contributions. Participant contributions represent approximately 16 percent of gross benefit payments for Progress Energy, 21 percent for PEC and 12 percent for PEF. The OPEB benefit payments are also reduced by prescription drug-related federal subsidies received. In 2011, the subsidies totaled $5 million for us, $2 million for PEC and $2 million for PEF. In 2010, the subsidies totaled $3 million for us, $1 million for PEC and $2 million for PEF.

Reconciliations of the fair value of plan assets at December 31 follow:

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Fair value of plan assets January 1	$	1,891		$	1,673		$	33		$	55
Actual return on plan assets		91			208			3			2
Benefit payments, including settlements		(135	)		(129	)		(42	)		(44	)
Employer contributions		344			139			43			20

Fair value of plan assets at December 31	$	2,191		$	1,891		$	37		$	33

PEC


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Fair value of plan assets January 1	$	884		$	749		$	—		$	21
Actual return on plan assets		44			94			—			2
Benefit payments		(56	)		(56	)		(19	)		(19	)
Employer contributions (reimbursements)		219			97			19			(4	)

Fair value of plan assets at December 31	$	1,091		$	884		$	—		$	—

PEF


	Pension Benefits						OPEB
(in millions)	2011			2010			2011			2010
Fair value of plan assets January 1	$	871		$	794		$	33		$	32
Actual return on plan assets		41			98			4			1
Benefit payments		(58	)		(58	)		(21	)		(23	)
Employer contributions		115			37			21			23

Fair value of plan assets at December 31	$	969		$	871		$	37		$	33

The Progress Registrants’ primary objectives when setting investment policies and strategies are to manage the assets of the pension plan to ensure that sufficient funds are available at all times to finance promised benefits and to invest the funds such that contributions are minimized, within acceptable risk limits. We periodically perform studies to analyze various aspects of our pension plans including asset allocations, expected portfolio return, pension contributions and net funded status. One of our key investment objectives is to achieve a rate of return significantly in excess of the discount rate used to measure the plan liabilities over the long term. As of December 31, 2011, the target pension asset allocations are 29 percent domestic equity, 19 percent international equity, 35 percent domestic fixed income, 10 percent private equity and timber and 7 percent absolute return hedge funds. Tactical shifts (plus or minus 5 percent) in asset allocation from the target allocations are made based on the near-term view of the risk and return tradeoffs of the asset classes. Domestic equity includes investments across large, medium and small capitalized domestic stocks, using investment managers with value, growth and core-based investment strategies and includes both long only and long/short equity managers. International equity includes investments in foreign stocks in both developed and emerging market countries, using a mix of value and growth-based investment strategies and includes both long only and long/short equity managers. Domestic fixed income primarily includes domestic investment grade long duration fixed income investments. OPEB plan assets, representing all PEF’s OPEB plan assets, are invested in domestic governmental securities.

PROGRESS ENERGY

The following table sets forth by level within the fair value hierarchy our pension plan assets at December 31, 2011 and 2010. See Note 14 for detailed information regarding the fair value hierarchy.


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2011
Assets
Cash and cash equivalents	$	82	$	33	$	—	$	115
International equity securities		47		—		—		47
Domestic equity securities		266		—		—		266
Private equity securities		—		—		153		153
Corporate bonds		—		407		—		407
U.S. state and municipal debt		—		42		—		42
U.S. and foreign government debt		247		102		—		349
Commingled funds		—		490		—		490
Hedge funds		—		159		147		306
Timber investments		—		—		11		11
Other investments		—		5		—		5

Fair value of plan assets	$	642	$	1,238	$	311	$	2,191


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Cash and cash equivalents	$	—	$	94	$	—	$	94
International equity securities		40		—		—		40
Domestic equity securities		286		—		—		286
Private equity securities		—		—		147		147
Corporate bonds		—		216		—		216
U.S. state and municipal debt		—		19		—		19
U.S. and foreign government debt		144		30		—		174
Commingled funds		—		847		—		847
Hedge funds		—		51		2		53
Timber investments		—		—		11		11
Other investments		—		4		—		4

Fair value of plan assets	$	470	$	1,261	$	160	$	1,891

Our other postretirement benefit plan assets had a fair value of $37 million and $33 million, which consisted of U.S. state and municipal assets classified as Level 2 in the fair value hierarchy at December 31, 2011, and December 31, 2010, respectively.

A reconciliation of changes in the fair value of our pension plan assets classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:


(in millions)	Private Equity Securities		Hedge Funds		Timber Investments			Total
2011
Balance at January 1	$	147	$	2	$	11		$	160
Net realized and unrealized gains ^(a)		—		4		1			5
Transfers in		—		52		—			52
Purchases, sales and distributions, net		6		89		(1	)		94

Balance at December 31	$	153	$	147	$	11		$	311


(in millions)	Private Equity Securities		Hedge Funds		Timber Investments			Total
2010
Balance at January 1	$	122	$	2	$	14		$	138
Net realized and unrealized gains (losses)^(a)		7		—		(2	)		5
Purchases, sales and distributions, net		18		—		(1	)		17

Balance at December 31	$	147	$	2	$	11		$	160

^(a)	Substantially all amounts relate to investments held at December 31.

PEC

The following table sets forth by level within the fair value hierarchy PEC’s pension plan assets at December 31, 2011 and 2010. See Note 14 for detailed information regarding the fair value hierarchy.


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2011
Assets
Cash and cash equivalents	$	41	$	16	$	—	$	57
International equity securities		24		—		—		24
Domestic equity securities		133		—		—		133
Private equity securities		—		—		76		76
Corporate bonds		—		203		—		203
U.S. state and municipal debt		—		21		—		21
U.S. and foreign government debt		123		51		—		174
Commingled funds		—		244		—		244
Hedge funds		—		79		73		152
Timber investments		—		—		5		5
Other investments		—		2		—		2

Fair value of plan assets	$	321	$	616	$	154	$	1,091


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Cash and cash equivalents	$	—	$	44	$	—	$	44
International equity securities		19		—		—		19
Domestic equity securities		134		—		—		134
Private equity securities		—		—		69		69
Corporate bonds		—		101		—		101
U.S. state and municipal debt		—		9		—		9
U.S. and foreign government debt		67		14		—		81
Commingled funds		—		396		—		396
Hedge funds		—		24		1		25
Timber investments		—		—		5		5
Other investments		—		1		—		1

Fair value of plan assets	$	220	$	589	$	75	$	884

A reconciliation of changes in the fair value of PEC’s pension plan assets classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:


(in millions)	Private Equity Securities		Hedge Funds		Timber Investments			Total
2011
Balance at January 1	$	69	$	1	$	5		$	75
Net realized and unrealized gains^(a)		—		2		—			2
Transfers in		—		26		—			26
Purchases, sales and distributions, net		7		44		—			51

Balance at December 31	$	76	$	73	$	5		$	154


(in millions)	Private Equity Securities		Hedge Funds		Timber Investments			Total
2010
Balance at January 1	$	55	$	1	$	6		$	62
Net realized and unrealized gains (losses)^(a)		4		—		(1	)		3
Purchases, sales and distributions, net		10		—		—			10

Balance at December 31	$	69	$	1	$	5		$	75

^(a)	Substantially all amounts relate to investments held at December 31.

PEF

The following table sets forth by level within the fair value hierarchy PEF’s pension assets at December 31, 2011 and 2010. See Note 14 for detailed information regarding the fair value hierarchy.


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2011
Assets
Cash and cash equivalents	$	36	$	15	$	—	$	51
International equity securities		21		—		—		21
Domestic equity securities		117		—		—		117
Private equity securities		—		—		68		68
Corporate bonds		—		180		—		180
U.S. state and municipal debt		—		19		—		19
U.S. and foreign government debt		109		45		—		154
Commingled funds		—		217		—		217
Hedge funds		—		70		65		135
Timber investments		—		—		5		5
Other investments		—		2		—		2

Fair value of plan assets	$	283	$	548	$	138	$	969


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2010
Assets
Cash and cash equivalents	$	—	$	43	$	—	$	43
International equity securities		18		—		—		18
Domestic equity securities		132		—		—		132
Private equity securities		—		—		68		68
Corporate bonds		—		99		—		99
U.S. state and municipal debt		—		9		—		9
U.S. and foreign government debt		66		14		—		80
Commingled funds		—		391		—		391
Hedge funds		—		23		1		24
Timber investments		—		—		5		5
Other investments		—		2		—		2

Fair value of plan assets	$	216	$	581	$	74	$	871

PEF’s other postretirement benefit plan assets had a fair value of $37 million and $33 million, which consisted of U.S. state and municipal assets classified as Level 2 in the fair value hierarchy at December 31, 2011 and 2010, respectively.

A reconciliation of changes in the fair value of PEF’s pension plan assets classified as Level 3 in the fair value hierarchy for the years ended December 31 follows:


(in millions)	Private Equity Securities		Hedge Funds		Timber Investments		Total
2011
Balance at January 1	$	68	$	1	$	5	$	74
Net realized and unrealized gains^(a)		—		2		—		2
Transfers in		—		23		—		23
Purchases, sales and distributions, net		—		39		—		39


Balance at December 31	$	68	$	65	$	5	$	138


(in millions)	Private Equity Securities		Hedge Funds		Timber Investments			Total
2010
Balance at January 1	$	58	$	1	$	7		$	66
Net realized and unrealized gains (losses)^(a)		3		—		(1	)		2
Purchases, sales and distributions, net		7		—		(1	)		6

Balance at December 31	$	68	$	1	$	5		$	74

^(a)	Substantially all amounts relate to investments held at December 31.

For Progress Energy, PEC and PEF, the determination of the fair values of pension and postretirement plan assets incorporates various factors required under GAAP. The assets of the plan include exchange traded securities (classified within Level 1) and other marketable debt and equity securities, most of which are valued using Level 1 inputs for similar instruments, and are classified within Level 2 investments.

Most over-the-counter investments are valued using observable inputs for similar instruments or prices from similar transactions and are classified as Level 2. Over-the-counter investments where significant unobservable inputs are used, such as financial pricing models, are classified as Level 3 investments.

Investments in private equity are valued using observable inputs, when available, and also include comparable market transactions, income and cost basis valuation techniques. The market approach includes using comparable market transactions or values. The income approach generally consists of the net present value of estimated future cash flows, adjusted as appropriate for liquidity, credit, market and/or other risk factors. Private equity investments are classified as Level 3 investments.

Investments in commingled funds are not publically traded, but the underlying assets held in these funds are traded in active markets and the prices for these assets are readily observable. Holdings in commingled funds are classified as Level 2 investments.

Hedge funds are based primarily on the net asset values and other financial information provided by management of the private investment funds. Hedge funds are classified as Level 2 if the plan is able to redeem the investment with the investee at net asset value as of the measurement date, or at a later date within a reasonable period of time. Hedge funds are classified as Level 3 if the investment cannot be redeemed at net asset value or it cannot be determined when the fund will be redeemed.

Investments in timber are valued primarily on valuations prepared by independent property appraisers. These appraisals are based on cash flow analysis, current market capitalization rates, recent comparable sales transactions, actual sales negotiations and bona fide purchase offers. Inputs include the species, age, volume and condition of timber stands growing on the land; the location, productivity, capacity and accessibility of the timber tracts; current and expected log prices; and current local prices for comparable investments. Timber investments are classified as Level 3 investments.

CONTRIBUTION AND BENEFIT PAYMENT EXPECTATIONS

In 2012, we expect to make contributions of $125 million-$225 million directly to pension plan assets and $1 million of discretionary contributions directly to the OPEB plan assets. The expected benefit payments for the pension benefit plan for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $182, $185, $193, $198, $200 and $1,046, respectively. The expected benefit payments for the OPEB plan for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $47, $50, $53, $56, $58 and $318, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from our assets. The benefit payment amounts reflect our net cost after any participant contributions and do not reflect reductions for expected prescription drug-related federal subsidies. The expected

federal subsidies for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $4, $5, $5, $6, $7 and $44, respectively.

In 2012, PEC expects to make contributions of $60 million-$110 million directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $94, $94, $99, $99, $97 and $479, respectively. The expected benefit payments for the OPEB plan for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $21, $23, $25, $26, $28 and $158, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from PEC assets. The benefit payment amounts reflect the net cost to PEC after any participant contributions and do not reflect reductions for expected prescription drug-related federal subsidies. The expected federal subsidies for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $2, $2, $3, $3, $3 and $23, respectively.

In 2012, PEF expects to make contributions of $65 million-$115 million directly to pension plan assets and expects to make $1 million of discretionary contributions to OPEB plan assets. The expected benefit payments for the pension benefit plan for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $64, $67, $70, $73, $76 and $430, respectively. The expected benefit payments for the OPEB plan for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $23, $24, $25, $25, $26 and $137, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from PEF’s assets. The benefit payment amounts reflect the net cost to PEF after any participant contributions and do not reflect reductions for expected prescription drug-related federal subsidies. The expected federal subsidies for 2012 through 2016 and in total for 2017 through 2021, in millions, are approximately $2, $2, $2, $3, $3 and $17, respectively.

The Patient Protection and Affordable Care Act (PPACA) and the related Health Care and Education Reconciliation Act, which made various amendments to the PPACA, were enacted in March 2010. The PPACA contains a provision that changes the tax treatment related to a federal subsidy available to sponsors of retiree health benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to the benefits under Medicare Part D. The subsidy is known as the Retiree Drug Subsidy. Employers are not currently taxed on the Retiree Drug Subsidy payments they receive. However, as a result of the PPACA as amended, Retiree Drug Subsidy payments will effectively become taxable in tax years beginning after December 31, 2012, by requiring the amount of the subsidy received to be offset against the employer’s deduction for health care expenses. Under GAAP, changes in tax law are accounted for in the period of enactment. Accordingly, an additional tax expense of $22 million for us, including $12 million for PEC and $10 million for PEF, was recognized during the year ended December 31, 2010.

B.	FLORIDA PROGRESS ACQUISITION

During 2000, we completed our acquisition of Florida Progress. Florida Progress’ pension and OPEB liabilities, assets and net periodic costs are reflected in the above information as appropriate. Certain of Florida Progress’ nonbargaining unit benefit plans were merged with our benefit plans effective January 1, 2002.

PEF continues to recover qualified plan pension costs and OPEB costs in rates as if the acquisition had not occurred. The information presented in Note 17A is adjusted as appropriate to reflect PEF’s rate treatment.

18.

RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

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

nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations.

See Note 14B for information about the fair value of derivatives.

A.	COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value.

ECONOMIC DERIVATIVES

Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions.

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 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 (See Note 8A). After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

Certain hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $147 million and $164 million on the Progress Energy Consolidated Balance Sheets at December 31, 2011 and 2010, respectively. At December 31, 2011, Progress Energy had 380.0 million MMBtu notional of natural gas and 10.3 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $24 million on the PEC Consolidated Balance Sheets at December 31, 2011 and 2010. At December 31, 2011, PEC had 111.4 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases.

PEF’s cash collateral asset included in derivative collateral posted was $123 million and $140 million on the PEF Balance Sheets at December 31, 2011 and 2010, respectively. At December 31, 2011, PEF had 268.6 million MMBtu notional of natural gas and 10.3 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

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

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps, and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. The notional amounts of

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

CASH FLOW HEDGES

At December 31, 2011, all open interest rate hedges will reach their mandatory termination dates within two years. 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 other comprehensive loss related to forward starting swaps. It is expected that in the next 12 months losses of $12 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities and changes in market value of currently open forward starting swaps.

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

At December 31, 2009, including amounts related to terminated hedges, we had $35 million of after-tax losses, including $27 million of after-tax losses at PEC and $3 million of after-tax gains at PEF, recorded in accumulated other comprehensive income related to forward starting swaps.

At December 31, 2011, Progress Energy had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

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

FAIR VALUE HEDGES

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

C.	CONTINGENT FEATURES

Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company’s credit rating with Moody’s, 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 $489 million at December 31, 2011, for which Progress Energy has posted collateral of $147 million in the normal course of business. If the credit risk-related contingent features underlying these agreements had been triggered at December 31, 2011, Progress Energy would have been required to post an additional $342 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 $152 million at December 31, 2011, for which PEC has posted collateral of $24 million in the normal course of business. If the credit risk-related contingent features underlying these agreements had been triggered at December 31, 2011, PEC would have been required to post an additional $128 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 $337 million at December 31, 2011, for which PEF has posted collateral of $123 million in the normal course of business. If the credit risk-related contingent features underlying these agreements had been triggered on December 31, 2011, PEF would have been required to post an additional $214 million of collateral with its counterparties.

D.	DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

The following table presents the fair value of derivative instruments at December 31:


Instrument / Balance sheet location	2011				2010
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	2			$	—
Derivative liabilities, long-term				1				—
Interest rate derivatives
Prepayments and other current assets	$	—			$	1
Other assets and deferred debits		—				3
Derivative liabilities, current				76				32
Derivative liabilities, long-term				17				7

Total derivatives designated as hedging instruments		—		96		4		39


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		5				11
Other assets and deferred debits		—				4
Derivative liabilities, current				357				226
Derivative liabilities, long-term				332				268
CVOs^(b)
Other current liabilities				14				—
Other liabilities and deferred credits				—				15

Fair value of derivatives not designated as hedging instruments		5		703		15		509
Fair value loss transition adjustment^(c)
Derivative liabilities, current				1				1
Derivative liabilities, long-term				2				3

Total derivatives not designated as hedging instruments		5		706		15		513

Total derivatives	$	5	$	802	$	19	$	552

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

^(b)	The Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000. In 2011, we purchased 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer. (See Note 16)

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

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Income for the years ended December 31:

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)								Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)									Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2011			2010			2009		2011			2010			2009			2011			2010		2009
Commodity cash flow derivatives^(c)	$	(2	)	$	—		$	1	$	—		$	—		$	—		$	—		$	—	$	—
Interest rate derivatives^{(d) (e)}		(85	)		(34	)		15		(8	)		(6	)		(6	)		(3	)		3		(3	)

Total	$	(87	)	$	(34	)	$	16	$	(8	)	$	(6	)	$	(6	)	$	(3	)	$	3	$	(3	)

^(a)	Effective portion.

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

^(c)	Amounts recorded on the Consolidated Statements of Income are classified in fuel used in electric generation.

^(d)	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.

^(e)	Amounts recorded on the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)									Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2009			2011			2010			2009
Commodity derivatives^(a)	$	(297	)	$	(324	)	$	(659	)	$	(502	)	$	(398	)	$	(387	)

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

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


Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2011			2010		2009
Commodity derivatives^(a)	$	—		$	—	$	1
Fair value loss transition adjustment^(a)		1			1		2
CVOs^(a)		(59	)		—		19

Total	$	(58	)	$	1	$	22

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

PEC

The following table presents the fair value of derivative instruments at December 31:


Instrument / Balance sheet location	2011				2010
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Other assets and deferred debits	$	—			$	3
Derivative liabilities, current			$	38			$	7
Other liabilities and deferred credits				9				4

Total derivatives designated as hedging instruments		—		47		3		11


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		—				1
Other assets and deferred debits		—				1
Derivative liabilities, current				91				45
Other liabilities and deferred credits				110				78

Fair value of derivatives not designated as hedging instruments		—		201		2		123
Fair value loss transition adjustment^(b)
Derivative liabilities, current				1				1
Other liabilities and deferred credits				2				3

Total derivatives not designated as hedging instruments		—		204		2		127

Total derivatives	$	—	$	251	$	5	$	138

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

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

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Income for the years ended December 31:

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)								Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)									Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2011			2010			2009		2011			2010			2009			2011			2010		2009
Interest rate derivatives^{(c) (d)}	$	(43	)	$	(10	)	$	5	$	(5	)	$	(4	)	$	(3	)	$	(1	)	$	—	$	(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 on the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)									Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2009			2011			2010			2009
Commodity derivatives	$	(60	)	$	(46	)	$	(76	)	$	(140	)	$	(77	)	$	(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)	2011		2010		2009
Commodity derivatives^(a)	$	—	$	—	$	1
Fair value loss transition adjustment^(a)		1		1		2

Total	$	1	$	1	$	3

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

PEF

The following table presents the fair value of derivative instruments at December 31:


Instrument / Balance sheet location	2011				2010
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	2			$	—
Derivative liabilities, long-term				1				—
Interest rate derivatives
Derivative liabilities, current				—				7
Derivative liabilities, long-term				8				—

Total derivatives designated as hedging instruments				11				7


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	5			$	10
Other assets and deferred debits		—				3
Derivative liabilities, current				266				181
Derivative liabilities, long-term				222				190

Total derivatives not designated as hedging instruments		5		488		13		371

Total derivatives	$	5	$	499	$	13	$	378

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

The following tables present the effect of derivative instruments on the Statements of Comprehensive Income and the Statements of Income for the years ended December 31:

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)								Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2011			2010			2009		2011		2010		2009		2011		2010		2009
Commodity cash flow derivatives^(c)	$	(2	)	$	—		$	1	$	—	$	—	$	—	$	—	$	—	$	—
Interest rate derivatives^{(d) (e)}		(21	)		(7	)		3		—		—		—		—		—		—

Total	$	(23	)	$	(7	)	$	4	$	—	$	—	$	—	$	—	$	—	$	—

^(a)	Effective portion.

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

^(c)	Amounts recorded on the Statements of Income are classified in fuel used in electric generation.

^(d)	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.

^(e)	Amounts recorded on the Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)									Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2009			2011			2010			2009
Commodity derivatives	$	(237	)	$	(278	)	$	(583	)	$	(362	)	$	(321	)	$	(319	)

^(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.

19.

RELATED PARTY TRANSACTIONS

There were no material related party transactions in which we or any of our subsidiaries were or will be a participant and in which any of our directors, executive officers or any of their immediate family members had a direct or indirect material interest. Transactions between affiliated companies are further discussed below.

As a part of normal business, we enter into various agreements providing financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees may include performance obligations under power supply agreements, transmission agreements, gas agreements, fuel procurement agreements, trading operations and cash management. Our guarantees also include standby letters of credit and surety bonds. At December 31, 2011, the Parent had issued $453 million of guarantees for future financial or performance assurance on behalf of its subsidiaries. This includes $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries (See Note 23). We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included on the Consolidated Balance Sheets.

Our subsidiaries provide and receive services, at cost, to and from the Parent and its subsidiaries, in accordance with agreements approved by the SEC pursuant to Section 13(b) of the Public Utility Holding Company Act of 1935. The

repeal of the Public Utility Holding Company Act of 1935 effective February 8, 2006, and subsequent regulation by the FERC did not change our current intercompany services. Services include purchasing, human resources, accounting, legal, transmission and delivery support, engineering materials, contract support, loaned employees payroll costs, construction management and other centralized administrative, management and support services. The costs of the services are billed on a direct-charge basis, whenever possible, and on allocation factors for general costs that cannot be directly attributed. Billings from affiliates are capitalized or expensed depending on the nature of the services rendered. Amounts receivable from and/or payable to affiliated companies for these services are included in receivables from affiliated companies and payables to affiliated companies on the Balance Sheets.

PESC provides the majority of the affiliated goods and services under the approved agreements. Goods and services provided by PESC during 2011, 2010 and 2009 to PEC amounted to $203 million, $176 million and $170 million, respectively, and services provided to PEF were $160 million, $156 million and $147 million, respectively. During 2010, PESC transferred a $24 million combustion turbine to PEC at cost.

PEC and PEF also provide and receive goods and services at cost. Goods and services provided by PEC to PEF during 2011, 2010 and 2009 amounted to $57 million, $43 million and $36 million, respectively. Goods and services provided by PEF to PEC during 2011, 2010 and 2009 amounted to $12 million, $18 million and $12 million, respectively.

PEC and PEF participate in an internal money pool, administered by PESC, to more effectively utilize cash resources and to reduce outside short-term borrowings. The money pool is also used to settle intercompany balances. The weighted-average interest rate for the money pool was 0.32%, 0.30% and 0.74% for the years ended December 31, 2011, 2010 and 2009, respectively. Amounts payable to the money pool are included in notes payable to affiliated companies on the Balance Sheets. PEC and PEF recorded minimal interest expense related to the money pool for all the years presented.

PEC and each of its wholly owned subsidiaries and PEF have entered into the Tax Agreement with the Parent (See Note 15).

20.

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 the following tables, capital and investment expenditures include property additions, acquisitions of nuclear fuel and other capital investments.


(in millions)	PEC		PEF		Corporate and Other			Eliminations			Total
At and for the year ended December 31, 2011
Revenues
Unaffiliated	$	4,528	$	4,367	$	12		$	—		$	8,907
Intersegment		—		2		272			(274	)		—

Total revenues		4,528		4,369		284			(274	)		8,907

Depreciation, amortization and accretion		514		169		18			—			701
Interest income		1		1		22			(22	)		2
Total interest charges, net		184		239		324			(22	)		725
Income tax expense (benefit)^(a)		268		311		(99	)		—			480
Ongoing Earnings		541		530		(200	)		—			871
Total assets		16,102		14,484		20,926			(16,453	)		35,059
Capital and investment expenditures		1,423		710		17			—			2,150


At and for the year ended December 31, 2010
Revenues
Unaffiliated	$	4,922	$	5,252	$	16		$	—		$	10,190
Intersegment		—		2		248			(250	)		—

Total revenues		4,922		5,254		264			(250	)		10,190

Depreciation, amortization and accretion		479		426		15			—			920
Interest income		3		1		31			(28	)		7
Total interest charges, net		186		258		331			(28	)		747
Income tax expense (benefit)^(a)		342		267		(87	)		—			522
Ongoing Earnings		618		462		(191	)		—			889
Total assets		14,899		14,056		21,110			(17,011	)		33,054
Capital and investment expenditures		1,382		991		33			(24	)		2,382


At and for the year ended December 31, 2009
Revenues
Unaffiliated	$	4,627	$	5,249	$	9		$	—		$	9,885
Intersegment		—		2		234			(236	)		—

Total revenues		4,627		5,251		243			(236	)		9,885

Depreciation, amortization and accretion		470		502		14			—			986
Interest income		5		4		38			(33	)		14
Total interest charges, net		195		231		286			(33	)		679
Income tax expense (benefit)^(a)		295		209		(88	)		—			416
Ongoing Earnings		540		460		(154	)		—			846
Total assets		13,502		13,100		20,538			(15,904	)		31,236
Capital and investment expenditures		962		1,532		21			(12	)		2,503

^(a)	Income tax expense (benefit) excludes the tax impact of Ongoing Earnings adjustments.

Management uses the non-GAAP financial measure “Ongoing Earnings” as a performance measure to evaluate the results of our segments and operations. Ongoing Earnings as presented here may not be comparable to similarly titled measures used by other companies. 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: CVO mark-to-market adjustments because we are unable to predict changes in their fair value; CR3 indemnification charge (and subsequent adjustments, if any) for estimated future years’ joint owner replacement power costs (through the expiration of the indemnification provisions of the joint owner agreement) because GAAP requires that the charge be accounted for in the period in which it becomes probable and estimable rather than the periods to which it relates; and the impact from changes in the tax treatment of the Medicare Part D subsidy because GAAP requires that the impact of the tax law change be accounted for in the period of enactment rather than the affected tax year. Additionally, management does not consider impairments, charges (and subsequent adjustments, if any) recognized for the retirement of generating units prior to the end of their estimated useful lives, merger and integration costs, cumulative prior period adjustments, operating results of discontinued operations and the amount to be refunded to customers through the fuel clause included in the terms of the 2012 settlement agreement 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 for the years ended December 31 follow:


(in millions)	2011			2010			2009
Ongoing Earnings	$	871		$	889		$	846
CVO mark-to-market, net of tax benefit of $14 and $- (Note 16)		(45	)		—			19
Impairment, net of tax benefit of $1, $4 and $1		(2	)		(6	)		(2	)
Merger and integration costs, net of tax benefit of $17 (Note 2)		(46	)		—			—
CR3 indemnification charge, net of tax benefit of $13 (Note 22C)		(20	)		—			—
Plant retirement charge, net of tax benefit of $1, $1 and $11		(1	)		(1	)		(17	)
Amount to be refunded to customers, net of tax benefit of $111 (Note 8C)		(177	)		—			—
Change in tax treatment of the Medicare Part D subsidy (Note 17)		—			(22	)		—
Cumulative prior period adjustment related to certain employee life insurance benefits, net of tax benefit of $7		—			—			(10	)
Continuing income attributable to noncontrolling interests, net of tax		7			7			4

Income from continuing operations		587			867			840
Discontinued operations, net of tax		(5	)		(4	)		(79	)
Net income attributable to noncontrolling interests, net of tax		(7	)		(7	)		(4	)

Net income attributable to controlling interests	$	575		$	856		$	757

21.

ENVIRONMENTAL MATTERS

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

A.	HAZARDOUS AND SOLID WASTE

The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion 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 June 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 design and performance standards for coal combustion residuals management facilities and regulate disposal of coal combustion residuals 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 residuals that are recycled. A final rule is expected in late 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

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

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

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which are 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, 2008	$	31		$	22		$	53
Amount accrued for environmental loss contingencies		3			13			16
Expenditures for environmental loss contingencies		(12	)		(15	)		(27	)

Balance, December 31, 2009^(a)		22			20			42
Amount accrued for environmental loss contingencies		8			13			21
Expenditures for environmental loss contingencies		(10	)		(18	)		(28	)

Balance, December 31, 2010^(a)		20			15			35
Amount accrued for environmental loss contingencies		2			8			10
Expenditures for environmental loss contingencies		(5	)		(17	)		(22	)

Balance, December 31, 2011^(a)	$	17		$	6		$	23

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

PEC


(in millions)	MGP and Other Sites
Balance, December 31, 2008	$	16
Amount accrued for environmental loss contingencies		3
Expenditures for environmental loss contingencies		(6	)

Balance, December 31, 2009^(a)		13
Amount accrued for environmental loss contingencies		3
Expenditures for environmental loss contingencies		(4	)

Balance, December 31, 2010^(a)		12
Amount accrued for environmental loss contingencies		1
Expenditures for environmental loss contingencies		(2	)

Balance, December 31, 2011^(a)	$	11

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

PEF


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2008	$	15		$	22		$	37
Amount accrued for environmental loss contingencies		—			13			13
Expenditures for environmental loss contingencies		(6	)		(15	)		(21	)

Balance, December 31, 2009^(a)		9			20			29
Amount accrued for environmental loss contingencies		5			13			18
Expenditures for environmental loss contingencies		(6	)		(18	)		(24	)

Balance, December 31, 2010^(a)		8			15			23
Amount accrued for environmental loss contingencies		1			8			9
Expenditures for environmental loss contingencies		(3	)		(17	)		(20	)

Balance, December 31, 2011^(a)	$	6		$	6		$	12

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

PROGRESS ENERGY

In addition to the Utilities’ sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 22C).

PEC

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

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. (Ward) site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At December 31, 2011 and December 31, 2010, PEC’s recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. On March 24, 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. The court 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 will be completed by May 2012. Meanwhile, proceedings with respect to the other defendants have been stayed. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for 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. It is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.

PEF

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

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed all distribution transformer sites and all substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M costs 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 impacting 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 and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx and SO₂ for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the CAIR.

In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it would develop maximum achievable control technology (MACT) standards. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants. On February 16, 2012, the EPA published the final MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT). The rule will become effective on April 16, 2012. Compliance is due in three years with provisions for a one-year extension from state agencies on a case-by-case basis. The EGU MACT contains stringent emission limits for mercury, non-mercury metals and acid gases from coal-fired units and hazardous air pollutant metals, acid gases and hydrogen fluoride from oil-fired units. 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 emissions controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the EGU MACT. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the EGU MACT. We are continuing to evaluate the impacts of the EGU MACT on the Utilities. We anticipate that compliance with the EGU MACT 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, 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 U.S. Court of Appeals for the District of Columbia (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, slated 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 which PEC and PEF are members of, 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 has been scheduled for 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 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. Under the CSAPR, Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO₂ emissions controls and fleet modernization projects completed or under way, we believe 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 Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 8B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

We account for emission allowances as inventory using the average cost method. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO₂ trading program. NOx and SO₂ emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs. SO₂ emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. NOx allowances cannot be utilized to comply with other requirements. 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. At December 31, 2011 and December 31, 2010, PEC had an immaterial amount of NOx emission allowances. At December 31, 2011 and December 31, 2010, PEF had approximately $22 million and $28 million, respectively, in NOx emission allowances.

22.

COMMITMENTS AND CONTINGENCIES

A.	PURCHASE OBLIGATIONS

In most cases, our purchase obligation contracts contain provisions for price adjustments, minimum purchase levels and other financial commitments. The commitment amounts presented below are estimates and therefore will likely differ from actual purchase amounts. At December 31, 2011, the following tables reflect contractual cash obligations and other commercial commitments in the respective periods in which they are due:


*Progress Energy*

(in millions)	2012		2013		2014		2015		2016		Thereafter		Total
Fuel^(a)	$	2,324	$	2,053	$	1,644	$	1,460	$	1,182	$	6,437	$	15,100
Purchased power		459		440		381		391		373		3,104		5,148
Construction obligations^(a)		331		216		35		23		4		10		619
Other purchase obligations		153		100		69		61		71		603		1,057

Total	$	3,267	$	2,809	$	2,129	$	1,935	$	1,630	$	10,154	$	21,924


*PEC*

(in millions)	2012		2013		2014		2015		2016		Thereafter		Total
Fuel	$	1,173	$	970	$	760	$	718	$	626	$	1,864	$	6,111
Purchased power		79		70		64		70		68		376		727
Construction obligations		277		114		25		19		—		—		435
Other purchase obligations		77		44		47		30		38		242		478

Total	$	1,606	$	1,198	$	896	$	837	$	732	$	2,482	$	7,751


*PEF*

(in millions)	2012		2013		2014		2015		2016		Thereafter		Total
Fuel^(a)	$	1,151	$	1,083	$	884	$	742	$	556	$	4,573	$	8,989
Purchased power		380		370		317		321		305		2,728		4,421
Construction obligations^(a)		54		102		10		4		4		10		184
Other purchase obligations		64		48		22		31		33		361		559

Total	$	1,649	$	1,603	$	1,233	$	1,098	$	898	$	7,672	$	14,153

^(a)

PEF signed an EPC agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two approximately 1,100-MW Westinghouse AP1000 nuclear units planned for construction at Levy. Due to uncertainty regarding the ultimate magnitude and timing of obligations under the EPC agreement and the Levy nuclear fabrication contract, the table includes only the obligations related to the selected components of long lead time equipment as discussed under “Fuel and Purchased Power” and “Construction Obligations.”

FUEL AND PURCHASED POWER

Through our subsidiaries, we have entered into various long-term contracts for coal, oil, gas and nuclear fuel as well as transportation agreements for the related fuel. Our purchases under these commitments were $2.697 billion, $2.890 billion and $2.921 billion for 2011, 2010 and 2009, respectively. PEC’s purchases were $1.398 billion, $1.489 billion and $1.527 billion in 2011, 2010 and 2009, respectively. PEF’s purchases were $1.299 billion, $1.401 billion and $1.394 billion in 2011, 2010 and 2009, respectively. Essentially all fuel and certain purchased power costs incurred by PEC and PEF are eligible for recovery through their respective cost-recovery clauses.

In December 2008, PEF entered into a nuclear fuel fabrication contract that contained exit provisions with termination fees for the planned Levy nuclear units. Due to revisions in the construction schedule and startup dates the nuclear fuel fabrication contract was terminated during 2011. (See discussion following under “Construction Obligations.”)

Both PEC and PEF have ongoing purchased power contracts, including renewable energy contracts, with other utilities, certain co-generators and qualified facilities (QFs), with expiration dates ranging from 2012 to 2032. These purchased power contracts generally provide for capacity and energy payments or bundled capacity and energy payments. In addition, both PEC and PEF have various contracts to secure transmission rights. Our purchases under purchased power contracts, including transmission costs, were $925 million, $907 million and $756 million for 2011, 2010 and 2009, respectively. PEC’s purchases, including transmission costs, were $253 million, $239 million and $171 million in 2011, 2010 and 2009, respectively. PEF’s purchases, including transmission costs, were $672 million, $668 million and $585 million in 2011, 2010 and 2009, respectively.

PEC has executed certain firm contracts for approximately 985 MW of purchased power with other utilities, including tolling contracts, with expiration dates ranging from 2019 to 2022 and representing between 33 percent and 100 percent of plant net output. Minimum purchases under these contracts included in the previous table, representing capital-related capacity costs, are approximately $51 million, $52 million, $53 million, $60 million and $60 million for 2012 through 2016, respectively, and $271 million payable thereafter.

PEC has various pay-for-performance contracts with QFs, including renewable energy, for approximately 81 MW of firm capacity expiring at various times through 2032. In most cases, these contracts account for 100 percent of the net generating capacity of each of the facilities. Payments for both capacity and energy are contingent upon the QFs’ ability to generate and, therefore, are not included in the previous table.

PEC has entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs. Certain agreements are for the period from July 2012 through May 2033. The estimated total cost to PEC associated with these agreements is approximately $1.510 billion, approximately $380 million of which will be classified as a capital lease. Due to the conditions of the capital lease agreement, the capital lease will not be recorded on PEC’s balance sheet until mid-2012. The transactions are subject to several conditions precedent, including various state regulatory approvals, the completion and commencement of operation of necessary related interstate and intrastate natural gas pipeline system expansions and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEC’s fuel commitments or in PEC’s capital lease assets or obligations.

PEF has executed certain firm contracts for approximately 499 MW of purchased power with other utilities with expiration dates ranging from 2012 to 2016 and representing between 12 percent and 25 percent of plant net output. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $53 million, $46 million, $65 million, $65 million and $27 million for 2012 through 2016, respectively.

PEF has ongoing purchased power contracts with certain QFs for 682 MW of firm capacity with expiration dates ranging from 2012 to 2025. Energy payments are based on the actual power taken under these contracts. Capacity payments are subject to the QFs meeting certain contract performance obligations. In most cases, these contracts account for 100 percent of the net generating capacity of each of the facilities. All ongoing commitments have been approved by the FPSC. Minimum expected future capacity payments under these contracts are $313 million, $309 million, $238 million, $244 million and $273 million for 2012 through 2016, respectively, and $2.728 billion payable thereafter. The FPSC allows the capacity payments to be recovered through a capacity cost-recovery clause, which is similar to, and works in conjunction with, energy payments recovered through the fuel cost-recovery clause.

CONSTRUCTION OBLIGATIONS

We have purchase obligations related to various capital construction projects. Our total payments under these contracts were $507 million, $703 million and $818 million for 2011, 2010 and 2009, respectively.

PEC has purchase obligations related to various capital projects including new generation and transmission obligations. Total payments under PEC’s construction-related contracts were $460 million, $555 million and $199 million for 2011, 2010 and 2009, respectively. Payments for 2011 primarily relate to construction of generating facilities at our sites in Wayne County, N.C., and New Hanover County, N.C., as discussed in Note 8B.

PEF has purchase obligations related to capital projects including Levy and various new generation, transmission and environmental compliance projects. Total payments under PEF’s construction-related contracts were $47 million, $147 million and $619 million for 2011, 2010 and 2009, respectively, including $6 million, $63 million and $243 million for 2011, 2010 and 2009, respectively, toward long lead equipment and engineering related to the Levy EPC.

The future construction obligations presented in the previous tables for Progress Energy and PEF exclude PEF’s Levy EPC agreement. The EPC agreement includes provisions for termination. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. As discussed in Note 8C, in 2010 PEF identified a schedule shift in the Levy project, and major construction activities on Levy have been postponed until after the NRC issues the COL for the plants, which is expected in 2013 if the current licensing schedule remains on track. We executed an amendment to the EPC agreement in 2010 due to the schedule shifts. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF completed vendor negotiations in July 2011 to continue or suspend purchase orders for long lead time equipment without material fees or charges. Prior to the EPC amendment, estimated payments and associated escalations were $8.608 billion for the multi-year contract and did not assume any joint ownership. Because we have executed an amendment to the EPC agreement and anticipate negotiating additional amendments upon receipt of the COL, we cannot currently predict when those obligations will be satisfied or the magnitude of any change. PEF has continued with selected components of long lead time equipment. Work was suspended on the remaining long lead time equipment items, which have total remaining estimated payments and associated escalations of approximately $1.250 billion included in the previously discussed $8.608 billion. We cannot predict the outcome of this matter.

OTHER PURCHASE OBLIGATIONS

We have various other contractual obligations primarily related to PESC service contracts for operational services, PEC service agreements related to its Smith Energy Complex, Wayne County, N.C., and New Hanover County, N.C., generating facilities, and PEF service agreements related to the Hines Energy Complex and the Bartow Plant. Our payments under these agreements were $151 million, $124 million and $56 million for 2011, 2010 and 2009, respectively.

PEC has various other purchase obligations, including obligations for long-term service agreements, parts and equipment, limestone supply and fleet vehicles. Total purchases under these contracts were $73 million, $55 million and $14 million for 2011, 2010 and 2009, respectively.

PEF has various other purchase obligations, including long-term service agreements for the Hines Energy Complex and the Bartow Plant. Total payments under these contracts were $54 million, $35 million and $22 million for 2011, 2010 and 2009, respectively. Future obligations are primarily comprised of the long-term service agreements.

B.	LEASES

We and the Utilities lease office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates. Additionally, the Utilities have entered into certain purchased power agreements, which are classified as leases. Some rental payments for transportation equipment include minimum rentals plus contingent rentals based on mileage. These contingent rentals are not significant.

Our rent expense under operating leases other than for purchased power totaled $42 million, $39 million and $37 million for 2011, 2010 and 2009, respectively. Our purchased power expense under agreements classified as operating leases was approximately $62 million, $61 million and $11 million in 2011, 2010 and 2009, respectively.

In 2003, we entered into an operating lease for a building for which minimum annual rental payments are approximately $7 million. The lease term expires July 2035 and provides for no rental payments during the last 15 years of the lease, during which period $53 million of rental expense will be recorded on the Consolidated Statements of Income. See Note 2 regarding our exit plan to vacate and sublease this building.

PEC’s rent expense under operating leases other than for purchased power totaled $26 million, $25 million and $26 million during 2011, 2010 and 2009, respectively. These amounts include rent expense allocated from PESC to PEC of $5 million in 2011, 2010 and 2009.

PEC has entered into purchased power agreements that are classified as operating leases. These agreements, which have total minimum payments of approximately $512 million and expire through 2032, primarily relate to two tolling agreements for purchased power of approximately 576 MW (100 percent of net output). Purchased power expense under agreements classified as operating leases was approximately $62 million, $38 million and $11 million in 2011, 2010 and 2009, respectively.

PEF’s rent expense under operating leases other than for purchased power totaled $15 million, $14 million and $11 million during 2011, 2010 and 2009, respectively. These amounts include rent expense allocated from PESC to PEF of $4 million in 2011 and $3 million in 2010 and 2009.

PEF has entered into a purchased power tolling agreement that is classified as an operating lease. This agreement for approximately 640 MW (100 percent of net output) has minimum annual payments beginning in June 2012 and expires in 2027 with total minimum payments of approximately $421 million. Purchased power expense under agreements classified as operating leases was approximately $23 million in 2010. PEF had no purchased power expense under operating lease agreements in 2011 and 2009.

PEF has a capital lease for a building and one tolling agreement for purchased power, which is classified as a capital lease of the related plant. PEF entered into the agreement for the building in 2005 and the lease term expires in 2047. The agreement for the building provides for minimum annual payments from 2007 through 2026 and no payments from 2027 through 2047. The minimum annual payments are approximately $5 million, for a total of approximately $103 million. During the last 20 years of the building lease, approximately $51 million of rental expense will be recorded on the Statements of Income. The 517-MW (100 percent of net output) tolling agreement for purchased power has minimum annual payments of approximately $21 million from 2007 through 2024, for a total of approximately $348 million.

Assets recorded under capital leases, including plant related to purchased power agreements, at December 31, consisted of:


	Progress Energy						PEC						PEF
(in millions)	2011			2010			2011			2010			2011			2010
Buildings	$	267		$	267		$	30		$	30		$	237		$	237
Less: Accumulated amortization		(56	)		(46	)		(18	)		(17	)		(38	)		(29	)

Total	$	211		$	221		$	12		$	13		$	199		$	208

Consistent with the ratemaking treatment for capital leases, capital lease expenses are charged to the same accounts that would be used if the leases were operating leases. Thus, our and the Utilities’ capital lease expense is generally included in O&M or purchased power expense. Our capital lease expense totaled $25 million, $25 million and $26 million for 2011, 2010 and 2009, respectively, which was primarily comprised of PEF’s capital lease expense of $23 million, $23 million and $24 million for 2011, 2010 and 2009, respectively.

At December 31, 2011, minimum annual payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable operating and capital leases were:

		Operating		Operating		Operating		Operating		Operating		Operating
	Progress Energy				PEC				PEF
(in millions)	Capital		Operating		Capital		Operating		Capital		Operating
2012	$	28	$	61	$	2	$	28	$	26	$	27
2013		36		85		10		43		26		36
2014		26		82		—		42		26		35
2015		26		79		—		43		26		34
2016		25		79		—		43		25		34

		Operating			Operating		Operating			Operating		Operating			Operating
Thereafter		201			791		6			472		195			318

Minimum annual payments		342			1,177		18			671		324			484
Less amount representing imputed interest		(131	)				(6	)				(125	)

Total	$	211		$	1,177	$	12		$	671	$	199		$	484

The Utilities are lessors of electric poles, streetlights and other facilities. PEC’s rents received are primarily contingent upon usage and totaled $35 million, $33 million, and $34 million for 2011, 2010 and 2009, respectively. PEC’s minimum rentals receivable under noncancelable leases are $12 million for 2012 and none thereafter. PEF’s rents received are based on a fixed minimum rental where price varies by type of equipment or contingent usage and totaled $86 million, $85 million and $84 million for 2011, 2010 and 2009, respectively. PEF’s minimum rentals receivable under noncancelable leases are not material for 2012 and thereafter.

C.	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 December 31, 2011, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included on the accompanying Balance Sheets.

At December 31, 2011, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At December 31, 2011, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $337 million, including $61 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. As part of settlement agreements entered into in 2002, PEF is responsible for providing the joint owners of CR3 a specified amount of generating capacity through the expiration of the indemnification provisions of the joint owner agreement in 2013. Due to the CR3 outage (See Note 8C), PEF has been unable to meet the required generating capacity and has provided replacement power from other generation sources or purchased power. During the year ended December 31, 2011, we and PEF recorded indemnification charges totaling $48 million for estimated joint owner replacement power costs for 2011 and future years, and provided replacement power totaling $21 million. At December 31, 2011 and 2010, we had recorded liabilities related to guarantees and indemnifications to third parties of $63 million and $31 million, respectively. These amounts included $37 million and $6 million for PEF at December 31, 2011 and 2010, respectively. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 23).

D.	OTHER COMMITMENTS AND CONTINGENCIES

MERGER

During January and February 2011, Progress Energy and its directors were named as defendants in 11 purported class action lawsuits with 10 lawsuits brought in the Superior Court, Wake County, N.C., and one lawsuit filed in the United States District Court for the Eastern District of North Carolina, each in connection with the Merger (we refer to these lawsuits as the “actions”). The complaints in the actions alleged, among other things, that the Merger Agreement was the product of breaches of fiduciary duty by the individual defendants, in that it allegedly did not provide for full and fair value for Progress Energy’s shareholders; that the Merger Agreement contained coercive deal protection measures; and that the Merger Agreement and the Merger were approved as a result, allegedly, of

improper self-dealing by certain defendants who would receive certain alleged employment compensation benefits and continued employment pursuant to the Merger Agreement. The complaints in the actions also alleged that Progress Energy aided and abetted the individual defendants’ alleged breaches of fiduciary duty. As relief, the plaintiffs in the actions sought, among other things, to enjoin completion of the Merger.

Additionally, the complaint in the federal action was amended in early April 2011 to include allegations that the defendants violated federal securities laws in connection with statements contained in the registration statement filed on Form S-4 by Duke Energy related to the Merger (the Registration Statement).

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

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

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

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

On July 11, 2011, solely to avoid the costs, risks and uncertainties inherent in litigation and to allow its shareholders to vote on the proposals required in connection with the Merger at its special meeting of its shareholders, Progress Energy entered into a memorandum of understanding with plaintiffs in the consolidated state court actions and other named defendants to settle the consolidated action and all related claims that were or could have been asserted in other actions, subject to court approval. The details of the settlement were set forth in a notice sent to Progress Energy’s shareholders of record that were members of the class as of July 5, 2011.

On November 29, 2011, the court entered a final order and judgment approving the settlement as fair, reasonable and adequate and awarded legal fees and expenses to plaintiffs’ counsel of $550,000. The court dismissed the action with prejudice and released and fully discharged all claims, including federal claims, which had been or could be in the future asserted in the action or in any court, tribunal or proceeding. On December 8, 2011, the federal action was voluntarily dismissed.

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 21).

Hurricane Katrina

In May 2011, PEC and PEF were named in a class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claim that PEC and PEF, along with numerous other utility, oil, coal and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that

defendants’ greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. We believe the plaintiffs’ claim is without merit; however, we cannot predict the outcome of this matter.

Water Discharge Permit

On October 5, 2011, Earthjustice, on behalf of the Sierra Club and Florida Wildlife Federation, filed a petition seeking review of the water discharge permit issued to CR1, CR2 and CR3 raising a number of technical and legal issues with respect to the permit. A settlement has been tentatively reached providing for the withdrawal of the petition and issuance of a revised water discharge permit identical in form to the one under appeal but with an 18 month term. The current permit has a five year term. The settlement, if finalized, will fully resolve the current dispute. We cannot predict the outcome of this matter.

SPENT NUCLEAR FUEL MATTERS

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

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities on or before January 31, 1998. The Utilities have asserted over $90 million in damages incurred between January 31, 1998, and December 31, 2005, the time period set by the court for damages in this case.

On June 14, 2011, the judge in the U.S. Court of Federal Claims issued a ruling to award the Utilities substantially all their asserted damages. In September 2011, after the government dismissed its notice of appeal, the judgment became final. As a result, in September 2011, PEC recorded the $92 million award as an offset for past spent fuel storage costs incurred, of which $27 million was O&M expense. PEC received the cash award in January 2012.

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. The Utilities may file subsequent damage claims as they incur additional costs. We cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000 (the Asset Purchase Agreement), by and among U.S. Global, LLC (Global); Earthco; certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the expiration of the Section 29 tax credit program on December 31, 2007, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

The jury awarded Global $78 million. On October 23, 2009, Global filed a motion to assess prejudgment interest on the award. On November 20, 2009, the court granted the motion and assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. On December 18, 2009, we appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we

made a $154 million payment, which represents payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument was held on September 27, 2011. We cannot predict the outcome of this matter.

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

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

CLAIM OF HOLDER OF CONTINGENT VALUE OBLIGATIONS

On June 10, 2011, Davidson Kempner Partners, M.H. Davidson & Co., Davidson Kempner Institutional Partners, L.P., and Davidson Kempner International, Ltd. (jointly, Davidson Kempner) filed a lawsuit against us in the Supreme Court of the State of New York, County of New York. Davidson Kempner is a holder of CVOs (See Note 16) and alleged that we improperly deducted escrow deposits in 2005 in determining net after-tax cash flow under the agreement governing the CVOs and that by taking this position, we breached our obligation under the agreement to exercise good faith and fair dealing. The plaintiffs alleged that this breach caused injury to the holders of CVOs in the approximate amount of $42 million. The plaintiffs requested declaratory judgment to require that we deduct the escrowed payments in 2006.

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

OTHER LITIGATION MATTERS

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

23.

CONDENSED CONSOLIDATING STATEMENTS

Presented below are the Condensed Consolidating Statements of Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In September 2005, we issued our guarantee of certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are in addition to the previously issued guarantees of our wholly owned subsidiary, Florida Progress.

The Trust, a finance subsidiary, was established in 1999 for the sole purpose of issuing $300 million of 7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A (Preferred Securities), and using the proceeds thereof to purchase from Funding Corp. $300 million of 7.10% Junior Subordinated Deferrable Interest Notes due

2039 (Subordinated Notes). The Trust has no other operations and its sole assets are the Subordinated Notes and Notes Guarantee (as discussed below). Funding Corp. is a wholly owned subsidiary of Florida Progress and was formed for the sole purpose of providing financing to Florida Progress and its subsidiaries. Funding Corp. does not engage in business activities other than such financing and has no independent operations. Since 1999, Florida Progress has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes. In addition, Florida Progress guaranteed the payment of all distributions related to the Preferred Securities required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (the Preferred Securities Guarantee). The two guarantees considered together constitute a full and unconditional guarantee by Florida Progress of the Trust’s obligations under the Preferred Securities. The Preferred Securities and the Preferred Securities Guarantee are listed on the New York Stock Exchange.

The Subordinated Notes may be redeemed at the option of Funding Corp. at par value plus accrued interest through the redemption date. The proceeds of any redemption of the Subordinated Notes will be used by the Trust to redeem proportional amounts of the Preferred Securities and common securities in accordance with their terms. Upon liquidation or dissolution of Funding Corp., holders of the Preferred Securities would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. The annual interest expense related to the Subordinated Notes is reflected in the Consolidated Statements of Income.

We have guaranteed the payment of all distributions related to the Trust’s Preferred Securities. At December 31, 2011, the Trust had outstanding 12 million shares of the Preferred Securities with a liquidation value of $300 million. Our guarantees are joint and several, full and unconditional, and are in addition to the joint and several, full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances, and as disclosed in Note 12B, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a variable-interest entity 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.

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-K. 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.

100

Condensed Consolidating Statement of Income

Year ended December 31, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	4,379		$	4,528		$	—		$	8,907
Affiliate revenues		—			—			272			(272	)		—

Total operating revenues		—			4,379			4,800			(272	)		8,907

Operating expenses
Fuel used in electric generation		—			1,506			1,387			—			2,893
Purchased power		—			778			315			—			1,093
Operation and maintenance		10			881			1,407			(262	)		2,036
Depreciation, amortization and accretion		—			169			532			—			701
Taxes other than on income		—			350			218			(6	)		562
Other		—			(1	)		35			—			34

Total operating expenses		10			3,683			3,894			(268	)		7,319

Operating (loss) income		(10	)		696			906			(4	)		1,588

Other income (expense)
Interest income		—			1			2			(1	)		2
Allowance for equity funds used during construction		—			32			71			—			103
Other, net		(61	)		5			(4	)		2			(58	)

Total other (expense) income, net		(61	)		38			69			1			47

Interest charges
Interest charges		279			276			205			—			760
Allowance for borrowed funds used during construction		—			(14	)		(21	)		—			(35	)

Total interest charges, net		279			262			184			—			725

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(350	)		472			791			(3	)		910
Income tax (benefit) expense		(127	)		170			275			5			323
Equity in earnings of consolidated subsidiaries		798			—			—			(798	)		—

Income from continuing operations		575			302			516			(806	)		587
Discontinued operations, net of tax		—			(3	)		(2	)		—			(5	)

Net income		575			299			514			(806	)		582
Net income attributable to noncontrolling interests, net of tax		—			(4	)		—			(3	)		(7	)

Net income attributable to controlling interests	$	575		$	295		$	514		$	(809	)	$	575

101

Condensed Consolidating Statement of Income

Year ended December 31, 2010


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	5,268		$	4,922		$	—		$	10,190
Affiliate revenues		—			—			248			(248	)		—

Total operating revenues		—			5,268			5,170			(248	)		10,190

Operating expenses
Fuel used in electric generation		—			1,614			1,686			—			3,300
Purchased power		—			977			302			—			1,279
Operation and maintenance		7			912			1,345			(237	)		2,027
Depreciation, amortization and accretion		—			426			494			—			920
Taxes other than on income		—			362			225			(7	)		580
Other		—			17			13			—			30

Total operating expenses		7			4,308			4,065			(244	)		8,136

Operating (loss) income		(7	)		960			1,105			(4	)		2,054

Other income (expense)
Interest income		7			2			5			(7	)		7
Allowance for equity funds used during construction		—			28			64			—			92
Other, net		(1	)		1			(3	)		3			—

Total other income, net		6			31			66			(4	)		99

Interest charges
Interest charges		282			293			211			(7	)		779
Allowance for borrowed funds used during construction		—			(13	)		(19	)		—			(32	)

Total interest charges, net		282			280			192			(7	)		747

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(283	)		711			979			(1	)		1,406
Income tax (benefit) expense		(111	)		267			378			5			539

Equity in earnings of consolidated subsidiaries		1,027			—			—			(1,027	)		—

Income from continuing operations		855			444			601			(1,033	)		867
Discontinued operations, net of tax		1			(1	)		(4	)		—			(4	)

Net income		856			443			597			(1,033	)		863
Net (income) loss attributable to noncontrolling interests, net of tax		—			(4	)		1			(4	)		(7	)

Net income attributable to controlling interests	$	856		$	439		$	598		$	(1,037	)	$	856

102

Condensed Consolidating Statement of Income

Year ended December 31, 2009


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	5,259		$	4,626		$	—		$	9,885
Affiliate revenues		—			—			235			(235	)		—

Total operating revenues		—			5,259			4,861			(235	)		9,885

Operating expenses
Fuel used in electric generation		—			2,072			1,680			—			3,752
Purchased power		—			682			229			—			911
Operation and maintenance		8			839			1,269			(222	)		1,894
Depreciation, amortization and accretion		—			502			484			—			986
Taxes other than on income		—			347			216			(6	)		557
Other		—			13			—			—			13

Total operating expenses		8			4,455			3,878			(228	)		8,113

Operating (loss) income		(8	)		804			983			(7	)		1,772

Other income (expense)
Interest income		10			5			9			(10	)		14
Allowance for equity funds used during construction		—			91			33			—			124
Other, net		18			6			(22	)		4			6

Total other income, net		28			102			20			(6	)		144

Interest charges
Interest charges		233			280			215			(10	)		718
Allowance for borrowed funds used during construction		—			(27	)		(12	)		—			(39	)

Total interest charges, net		233			253			203			(10	)		679

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(213	)		653			800			(3	)		1,237
Income tax (benefit) expense		(93	)		200			286			4			397
Equity in earnings of consolidated subsidiaries		875			—			—			(875	)		—

Income from continuing operations		755			453			514			(882	)		840
Discontinued operations, net of tax		2			(43	)		(38	)		—			(79	)

Net income		757			410			476			(882	)		761
Net (income) loss attributable to noncontrolling interests, net of tax		—			(3	)		2			(3	)		(4	)

Net income attributable to controlling interests	$	757		$	407		$	478		$	(885	)	$	757

103

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

104

Condensed Consolidating Balance Sheet

December 31, 2010


(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	10,189	$	10,961	$	90		$	21,240

Current assets
Cash and cash equivalents		110		270		231		—			611
Receivables, net		—		497		536		—			1,033
Notes receivable from affiliated companies		14		48		115		(177	)		—
Regulatory assets		—		105		71		—			176
Derivative collateral posted		—		140		24		—			164
Prepayments and other current assets		30		751		984		(273	)		1,492

Total current assets		154		1,811		1,961		(450	)		3,476

Deferred debits and other assets
Investment in consolidated subsidiaries		14,316		—		—		(14,316	)		—
Regulatory assets		—		1,387		987		—			2,374
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		554		1,017		—			1,571
Other assets and deferred debits		75		238		894		(469	)		738

Total deferred debits and other assets		14,391		2,179		2,898		(11,130	)		8,338

Total assets	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,023	$	4,957	$	5,686	$	(10,643	)	$	10,023
Noncontrolling interests		—		4		—		—			4

Total equity		10,023		4,961		5,686		(10,643	)		10,027

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		—		(36	)		273
Long-term debt, net		3,989		4,182		3,693		—			11,864

Total capitalization		14,012		9,486		9,438		(10,679	)		22,257

Current liabilities
Current portion of long-term debt		205		300		—		—			505
Notes payable to affiliated companies		—		175		3		(178	)		—
Derivative liabilities		18		188		53		—			259
Other current liabilities		278		1,002		1,184		(273	)		2,191

Total current liabilities		501		1,665		1,240		(451	)		2,955

Deferred credits and other liabilities
Noncurrent income tax liabilities		3		528		1,608		(443	)		1,696
Regulatory liabilities		—		1,084		1,461		90			2,635
Other liabilities and deferred credits		29		1,416		2,073		(7	)		3,511

Total deferred credits and other liabilities		32		3,028		5,142		(360	)		7,842

Total capitalization and liabilities	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054

105

Condensed Consolidating Statement of Cash Flows

Year ended December 31, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	756		$	706		$	1,251		$	(1,098	)	$	1,615

Investing activities
Gross property additions		—			(818	)		(1,248	)		—			(2,066	)
Nuclear fuel additions		—			(15	)		(211	)		—			(226	)
Purchases of available-for-sale securities and other investments		—			(4,438	)		(579	)		—			(5,017	)
Proceeds from available-for-sale securities and other investments		—			4,441			529			—			4,970
Changes in advances to affiliated companies		(38	)		48			(104	)		94			—
Contributions to consolidated subsidiaries		(11	)		—			—			11			—
Other investing activities		(24	)		121			29			1			127

Net cash used by investing activities		(73	)		(661	)		(1,584	)		106			(2,212	)

Financing activities
Issuance of common stock, net		53			—			—			—			53
Dividends paid on common stock		(734	)		—			—			—			(734	)
Dividends paid to parent		—			(513	)		(585	)		1,098			—
Net decrease in short-term debt		250			233			185			(1	)		667
Proceeds from issuance of long-term debt, net		495			296			495			—			1,286
Retirement of long-term debt		(700	)		(300	)		—			—			(1,000	)
Changes in advances from affiliated companies		—			63			31			(94	)		—
Contributions from parent		—			10			1			(11	)		—
Other financing activities		(40	)		(12	)		(4	)		—			(56	)

Net cash (used) provided by financing activities		(676	)		(223	)		123			992			216

Net increase (decrease) in cash and cash equivalents		7			(178	)		(210	)		—			(381	)
Cash and cash equivalents at beginning of year		110			270			231			—			611

Cash and cash equivalents at end of year	$	117		$	92		$	21		$	—		$	230

106

Condensed Consolidating Statement of Cash Flows

Year ended December 31, 2010


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	16		$	1,181		$	1,562		$	(222	)	$	2,537

Investing activities
Gross property additions		—			(1,014	)		(1,231	)		24			(2,221	)
Nuclear fuel additions		—			(38	)		(183	)		—			(221	)
Purchases of available-for-sale securities and other investments		—			(6,391	)		(618	)		—			(7,009	)
Proceeds from available-for-sale securities and other investments		—			6,395			595			—			6,990
Changes in advances to affiliated companies		15			(2	)		188			(201	)		—
Return of investment in consolidated subsidiaries		54			—			—			(54	)		—
Contributions to consolidated subsidiaries		(171	)		—			—			171			—
Other investing activities		113			60			3			(115	)		61

Net cash provided (used) by investing activities		11			(990	)		(1,246	)		(175	)		(2,400	)

Financing activities
Issuance of common stock, net		434			—			—			—			434
Dividends paid on common stock		(717	)		—			—			—			(717	)
Dividends paid to parent		—			(102	)		(100	)		202			—
Dividends paid to parent in excess of retained earnings		—			—			(54	)		54			—
Net decrease in short-term debt		(140	)		—			—			—			(140	)
Proceeds from issuance of long-term debt, net		—			591			—			—			591
Retirement of long-term debt		(100	)		(300	)		—			—			(400	)
Changes in advances from affiliated companies		—			(201	)		—			201			—
Contributions from parent		—			33			152			(185	)		—
Other financing activities		—			(14	)		(130	)		125			(19	)

Net cash (used) provided by financing activities		(523	)		7			(132	)		397			(251	)

Net (decrease) increase in cash and cash equivalents		(496	)		198			184			—			(114	)
Cash and cash equivalents at beginning of year		606			72			47			—			725

Cash and cash equivalents at end of year	$	110		$	270		$	231		$	—		$	611

107

Condensed Consolidating Statement of Cash Flows

Year ended December 31, 2009


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	108		$	1,079		$	1,282		$	(198	)	$	2,271

Investing activities
Gross property additions		—			(1,449	)		(858	)		12			(2,295	)
Nuclear fuel additions		—			(78	)		(122	)		—			(200	)
Proceeds from sales of assets to affiliated companies		—			—			11			(11	)		—
Purchases of available-for-sale securities and other investments		—			(1,548	)		(802	)		—			(2,350	)
Proceeds from available-for-sale securities and other investments		—			1,558			756			—			2,314
Changes in advances to affiliated companies		4			(2	)		(172	)		170			—
Return of investment in consolidated subsidiaries		12			—			—			(12	)		—
Contributions to consolidated subsidiaries		(688	)		—			—			688			—
Other investing activities		—			—			(1	)		—			(1	)

Net cash used by investing activities		(672	)		(1,519	)		(1,188	)		847			(2,532	)

Financing activities
Issuance of common stock, net		623			—			—			—			623
Dividends paid on common stock		(693	)		—			—			—			(693	)
Dividends paid to parent		—			(1	)		(200	)		201			—
Dividends paid to parent in excess of retained earnings		—			—			(12	)		12			—
Payments of short-term debt with original maturities greater than 90 days		(629	)		—			—			—			(629	)
Net increase (decrease) in short-term debt		100			(371	)		(110	)		—			(381	)
Proceeds from issuance of long-term debt, net		1,683			—			595			—			2,278
Retirement of long-term debt		—			—			(400	)		—			(400	)
Changes in advances from affiliated companies		—			170			—			(170	)		—
Contributions from parent		—			653			49			(702	)		—
Other financing activities		(2	)		(12	)		12			10			8

Net cash provided (used) by financing activities		1,082			439			(66	)		(649	)		806

Net increase (decrease) in cash and cash equivalents		518			(1	)		28			—			545
Cash and cash equivalents at beginning of year		88			73			19			—			180

Cash and cash equivalents at end of year	$	606		$	72		$	47		$	—		$	725

108

24.

QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data was as follows:

Progress Energy


(in millions except per share data)	First		Second		Third		Fourth
2011
Operating revenues	$	2,167	$	2,256	$	2,747	$	1,737
Operating income		451		428		690		19
Income (loss) from continuing operations		187		180		293		(73	)
Net income (loss)		185		178		293		(74	)
Net income (loss) attributable to controlling interests		184		176		291		(76	)
Common stock data
Basic and diluted earnings per common share
Income (loss) from continuing operations attributable to controlling interests, net of tax		0.63		0.60		0.98		(0.25	)
Net income (loss) attributable to controlling interests		0.62		0.60		0.98		(0.25	)
Dividends declared per common share		0.620		0.620		0.620		0.259
Market price per share
High		46.83		49.03		52.42		56.33
Low		42.55		45.20		42.05		49.37
2010
Operating revenues	$	2,535	$	2,372	$	2,962	$	2,321
Operating income		494		440		753		367
Income from continuing operations		191		181		365		130
Net income		190		180		365		128
Net income attributable to controlling interests		190		180		361		125
Common stock data
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax		0.67		0.62		1.23		0.43
Net income attributable to controlling interests		0.67		0.62		1.23		0.42
Dividends declared per common share		0.620		0.620		0.620		0.620
Market price per share
High		41.35		40.69		44.82		45.61
Low		37.04		37.13		38.96		43.08

In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Typically, weather conditions in our service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to our customers. As a result, our overall operating results may fluctuate substantially on a seasonal basis.

In the third quarter of 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement. As a result, we recognized $50 million of expense, net of tax, related to the change in the CVOs’ fair market value. See Note 16 for additional information.

During the fourth quarter of 2011, we recorded $288 million to be refunded to customers through the fuel clause in accordance with the 2012 settlement agreement. This was recognized as a reduction in operating revenues. See Note 8C for additional information.

109

PEC

Summarized quarterly financial data was as follows:


(in millions)	First		Second		Third		Fourth
2011
Operating revenues	$	1,133	$	1,060	$	1,332	$	1,003
Operating income		228		192		329		136
Net income		131		107		199		79
Net income attributable to controlling interests		131		107		199		79
2010
Operating revenues	$	1,263	$	1,117	$	1,414	$	1,128
Operating income		266		196		402		207
Net income		136		111		236		119
Net income attributable to controlling interests		138		112		234		119

In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Typically, weather conditions in PEC’s service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to its customers. As a result, its overall operating results may fluctuate substantially on a seasonal basis.

PEF

Summarized quarterly financial data was as follows:


(in millions)	First		Second		Third		Fourth
2011
Operating revenues	$	1,032	$	1,193	$	1,414	$	730
Operating income (loss)		216		234		361		(113	)
Net income (loss)		102		113		203		(104	)
2010
Operating revenues	$	1,270	$	1,252	$	1,543	$	1,189
Operating income		222		244		344		149
Net income		102		119		180		52

In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. Typically, weather conditions in PEF’s service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to its customers. As a result, its overall operating results may fluctuate substantially on a seasonal basis.

During the fourth quarter of 2011, PEF recorded $288 million to be refunded to customers through the fuel clause in accordance with the 2012 settlement agreement. This was recognized as a reduction in operating revenues. See Note 8C for additional information.

PROGRESS ENERGY, INC.

Schedule II - Valuation and Qualifying Accounts

For the Years Ended December 31, 2011, 2010 and 2009

(in millions)


Description	Balance at Beginning of Period		Additions Charged to Expenses		Charged to Other Accounts			Deductions(a)			Balance at End of Period

Valuation and qualifying accounts deducted on the balance sheet from the related assets:
2011
Uncollectible accounts	$	35	$	10	$	1		$	(19	)(b)	$	27
Inventory valuation(c)		17		2		—			(2	)		17
Fossil fuel plants dismantlement reserve		144		4		—			—			148
Nuclear refueling outage reserve		15		5		—			—			20
Deferred tax asset valuation allowance		60		11		—			—			71

2010
Uncollectible accounts	$	18	$	18	$	24	(b)	$	(25	)	$	35
Inventory valuation(c)		14		3		—			—			17
Fossil fuel plants dismantlement reserve		143		4		—			(3	)		144
Nuclear refueling outage reserve		5		13		—			(3	)		15
Deferred tax asset valuation allowance		55		5		—			—			60

2009
Uncollectible accounts	$	18	$	32	$	—		$	(32	)	$	18
Inventory valuation(c)		—		14		—			—			14
Fossil fuel plants dismantlement reserve		145		1		—			(3	)		143
Nuclear refueling outage reserve		14		18		—			(27	)		5
Deferred tax asset valuation allowance		55		—		—			—			55

(a)	Deductions from valuation accounts represent write-offs, net of recoveries, or the release of valuation allowances.

(b)	Includes $6 million deduction in 2011 and $18 million charge in 2010 related to other noncustomer receivables.

(c)	Relates to the impact of PEC’s decision to retire 11 coal-fired units prior to the end of their estimated useful lives.

110

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