Duke Energy CORP - FORM 8-K - EX-99.1 - CONSOLIDATED FINANCIAL STATEMENTS

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8-K - FORM 8-K - Duke Energy CORP	d8k.htm
EX-23.1 - CONSENT OF DELOITTE & TOUCHE LLP FOR PROGRESS ENERGY, INC. - Duke Energy CORP	dex231.htm
EX-99.2 - UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL INFORMATION - Duke Energy CORP	dex992.htm

Exhibit 99.1

CONSOLIDATED FINANCIAL STATEMENTS AS OF AND FOR THE

FISCAL YEAR ENDED DECEMBER 31, 2010 OF PROGRESS ENERGY, INC.

FINANCIAL STATEMENTS

The following financial statements 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, 2010, 2009 and 2008

Consolidated Balance Sheets at December 31, 2010 and 2009

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008

Consolidated Statements of Changes in Total Equity for the Years Ended December 31, 2010, 2009 and 2008

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008

Combined Notes to the Financial Statements for Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a Progress Energy Florida, Inc.

Note 1 – Organization and Summary of Significant Accounting Policies

Note 2 – New Accounting Standards

Note 3 – Divestitures

Note 4 – Property, Plant and Equipment

Note 5 – Receivables

Note 6 – Inventory

Note 7 – Regulatory Matters

Note 8 – Goodwill

Note 9 – Equity

Note 10 – Preferred Stock of Subsidiaries

Note 11 – Debt and Credit Facilities

Note 12 – Investments

Note 13 – Fair Value Disclosures

Note 14 – Income Taxes

Note 15 – Contingent Value Obligations

Note 16 – Benefit Plans

Note 17 – Risk Management Activities and Derivatives Transactions

Note 18 – Related Party Transactions

Note 19 – Financial Information by Business Segment

Note 20 – Other Income and Other Expense

Note 21 – Environmental Matters

Note 22 – Commitments and Contingencies

Note 23 – Condensed Consolidating Statements

Note 24 – Quarterly Financial Data (Unaudited)

Note 25 – Subsequent Event – Merger Agreement

FINANCIAL STATEMENT SCHEDULE ITEM 15

The following financial statement schedule is included herein:

Consolidated Financial Statement Schedule for the Years end December 31, 2010, 2009 and 2008:

Schedule II – Valuation and Qualifying Accounts – Progress Energy, Inc.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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, 2010, 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, 2011, expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2011

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of INCOME


(in millions except per share data) Years ended December 31	2010			2009			2008
Operating revenues	$	10,190		$	9,885		$	9,167

Operating expenses
Fuel used in electric generation		3,300			3,752			3,021
Purchased power		1,279			911			1,299
Operation and maintenance		2,027			1,894			1,820
Depreciation, amortization and accretion		920			986			839
Taxes other than on income		580			557			508
Other		30			13			(3	)

Total operating expenses		8,136			8,113			7,484

Operating income		2,054			1,772			1,683

Other income (expense)
Interest income		7			14			24
Allowance for equity funds used during construction		92			124			122
Other, net		—			6			(17	)

Total other income, net		99			144			129

Interest charges
Interest charges		779			718			679
Allowance for borrowed funds used during construction		(32	)		(39	)		(40	)

Total interest charges, net		747			679			639

Income from continuing operations before income tax		1,406			1,237			1,173
Income tax expense		539			397			395

Income from continuing operations		867			840			778
Discontinued operations, net of tax		(4	)		(79	)		58

Net income		863			761			836
Net income attributable to noncontrolling interests, net of tax		(7	)		(4	)		(6	)

Net income attributable to controlling interests	$	856		$	757		$	830

Average common shares outstanding – basic		291			279			262

Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	2.96		$	2.99		$	2.95
Discontinued operations attributable to controlling interests, net of tax		(0.01	)		(0.28	)		0.22

Net income attributable to controlling interests	$	2.95		$	2.71		$	3.17

Dividends declared per common share	$	2.480		$	2.480		$	2.465

Amounts attributable to controlling interests
Income from continuing operations, net of tax	$	860		$	836		$	773
Discontinued operations, net of tax		(4	)		(79	)		57

Net income attributable to controlling interests	$	856		$	757		$	830

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

PROGRESS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS


(in millions)	December 31, 2010			December 31, 2009
ASSETS
Utility plant
Utility plant in service	$	29,708		$	28,353
Accumulated depreciation		(11,567	)		(11,176	)

Utility plant in service, net		18,141			17,177
Other utility plant, net		220			212
Construction work in progress		2,205			1,790
Nuclear fuel, net of amortization		674			554

Total utility plant, net		21,240			19,733

Current assets
Cash and cash equivalents		611			725
Receivables, net		1,033			800
Inventory		1,226			1,325
Regulatory assets		176			142
Derivative collateral posted		164			146
Income taxes receivable		52			145
Prepayments and other current assets		214			248

Total current assets		3,476			3,531

Deferred debits and other assets
Regulatory assets		2,374			2,179
Nuclear decommissioning trust funds		1,571			1,367
Miscellaneous other property and investments		413			438
Goodwill		3,655			3,655
Other assets and deferred debits		325			333

Total deferred debits and other assets		8,338			7,972

Total assets	$	33,054		$	31,236

CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 293 million and 281 million shares issued and outstanding, respectively	$	7,343		$	6,873
Unearned ESOP shares (0 and 1 million shares, respectively)		—			(12	)
Accumulated other comprehensive loss		(125	)		(87	)
Retained earnings		2,805			2,675

Total common stock equity		10,023			9,449

Noncontrolling interests		4			6

Total equity		10,027			9,455

Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			272
Long-term debt, net		11,864			11,779

Total capitalization		22,257			21,599

Current liabilities
Current portion of long-term debt		505			406
Short-term debt		—			140
Accounts payable		994			835
Interest accrued		216			206
Dividends declared		184			175
Customer deposits		324			300
Derivative liabilities		259			190
Accrued compensation and other benefits		175			167
Other current liabilities		298			239

Total current liabilities		2,955			2,658

Deferred credits and other liabilities
Noncurrent income tax liabilities		1,696			1,196
Accumulated deferred investment tax credits		110			117
Regulatory liabilities		2,635			2,510
Asset retirement obligations		1,200			1,170
Accrued pension and other benefits		1,514			1,339
Derivative liabilities		278			240
Other liabilities and deferred credits		409			407

Total deferred credits and other liabilities		7,842			6,979

Commitments and contingencies (Notes 21 and 22)

Total capitalization and liabilities	$	33,054		$	31,236

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

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CASH FLOWS


(in millions) Years ended December 31	2010			2009			2008
Operating activities
Net income	$	863		$	761		$	836
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		1,083			1,135			957
Deferred income taxes and investment tax credits, net		478			220			411
Deferred fuel (credit) cost		(2	)		290			(333	)
Allowance for equity funds used during construction		(92	)		(124	)		(122	)
Loss (gain) on sales of assets		9			2			(75	)
Pension, postretirement and other employee benefits		198			135			71
Other adjustments to net income		40			134			64
Cash (used) provided by changes in operating assets and liabilities
Receivables		(200	)		26			233
Inventory		98			(99	)		(237	)
Derivative collateral posted		(23	)		200			(340	)
Other assets		(1	)		14			(37	)
Income taxes, net		90			(14	)		(169	)
Accounts payable		125			(26	)		77
Accrued pension and other benefits		(164	)		(285	)		(39	)
Other liabilities		35			(98	)		(79	)

Net cash provided by operating activities		2,537			2,271			1,218

Investing activities
Gross property additions		(2,221	)		(2,295	)		(2,333	)
Nuclear fuel additions		(221	)		(200	)		(222	)
Purchases of available-for-sale securities and other investments		(7,009	)		(2,350	)		(1,590	)
Proceeds from available-for-sale securities and other investments		6,990			2,314			1,534
Other investing activities		61			(1	)		70

Net cash used by investing activities		(2,400	)		(2,532	)		(2,541	)

Financing activities
Issuance of common stock, net		434			623			132
Dividends paid on common stock		(717	)		(693	)		(642	)
Payments of short-term debt with original maturities greater than 90 days		—			(629	)		(176	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		—			—			629
Net (decrease) increase in short-term debt		(140	)		(381	)		496
Proceeds from issuance of long-term debt, net		591			2,278			1,797
Retirement of long-term debt		(400	)		(400	)		(877	)
Cash distributions to noncontrolling interests		(6	)		(6	)		(85	)
Other financing activities		(13	)		14			(26	)

Net cash (used) provided by financing activities		(251	)		806			1,248

Net (decrease) increase in cash and cash equivalents		(114	)		545			(75	)
Cash and cash equivalents at beginning of year		725			180			255

Cash and cash equivalents at end of year	$	611		$	725		$	180

Supplemental disclosures
Cash paid for interest, net of amount capitalized	$	709		$	701		$	612
Cash (received) paid for income taxes		(56	)		87			152
Significant noncash transactions
Accrued property additions		313			252			334
Asset retirement obligation additions and estimate revisions		(36	)		(384	)		14

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

PROGRESS ENERGY, INC.

CONSOLIDATED STATEMENTS of CHANGES in TOTAL EQUITY


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

Balance, December 31, 2007		260	$	6,028	$	(37	)	$	(34	)	$	2,438		$	84		$	8,479
Net income				—		—			—			830			6			836
Other comprehensive loss				—		—			(82	)		—			—			(82	)
Issuance of shares		4		132		—			—			—			—			132
Allocation of ESOP shares				13		12			—			—			—			25
Stock-based compensation expense				33		—			—			—			—			33
Dividends ($2.465 per share)				—		—			—			(646	)		—			(646	)
Distributions to noncontrolling interests				—		—			—			—			(85	)		(85	)
Contributions from noncontrolling interests				—		—			—			—			2			2
Other				—		—			—			—			(1	)		(1	)


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 (Note 2)				—		—			—			—			(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

^(a)

For the year ended December 31, 2010, consolidated net income of $863 million includes $4 million attributable to preferred shareholders of subsidiaries, which is not a component of total equity and is excluded from the table above. For the year ended December 31, 2009, consolidated net income of $761 million includes $4 million attributable to preferred shareholders of subsidiaries, which 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,	2010			2009			2008
Net income	$	863		$	761		$	836
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $4, $4 and $2)		6			6			3
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $2, $3 and $1)		3			4			1
Net unrealized (losses) gains on cash flow hedges (net of tax benefit (expense) of $22, $(10) and $24)		(34	)		16			(37	)
Net unrecognized items for pension and other postretirement benefits (net of tax benefit (expense) of $8, $(1) and $29)		(13	)		2			(49	)
Other (net of tax benefit of $-, $- and $1)		—			1			—

Other comprehensive (loss) income		(38	)		29			(82	)

Comprehensive income		825			790			754
Comprehensive income attributable to noncontrolling interests, net of tax		(7	)		(4	)		(6	)

Comprehensive income attributable to controlling interests	$	818		$	786		$	748

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

PROGRESS ENERGY, INC.

COMBINED 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 public utility holding company headquartered in Raleigh, N.C. As such, we are 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 19 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. Significant 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 12 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 2009 and 2008 have been reclassified to conform to the 2010 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.

In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance that made significant changes to the model for determining who should consolidate a VIE and addressed how often this assessment should be performed. The guidance was effective for us on January 1, 2010 (See Note 2). As a result of the adoption, we and PEC deconsolidated two entities that qualify for low-income housing tax credits under Section 42 of the Internal Revenue Code (the Code) and recognized a $(2) million cumulative effect of change in accounting principle in 2010.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the managing member, and primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the 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 2008 through 2010. No financial or other support has been provided to the VIE during the periods presented.

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


(in millions)	2010		2009
Miscellaneous other property and investments	$	12	$	17
Other assets and deferred debits		1		1
Accounts payable		5		4

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 2008, 2009 and 2010. 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. Customer prepayments are recorded as deferred revenue and recognized as revenues as the services are provided.

FUEL COST DEFERRALS

Fuel expense includes fuel costs and other recoveries that are 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)	2010		2009		2008
Progress Energy	$	345	$	333	$	295
PEC		119		108		102
PEF		226		225		193

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. Certain costs are capitalized in accordance with regulatory treatment. 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. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. 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. The equity funds portion of AFUDC is credited to other income, and the borrowed funds portion 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 4A). 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 7).

Amortization of nuclear fuel costs is computed primarily on the units-of-production method. In the Utilities’ retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC, the SCPSC and the FPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdictions, the provisions for nuclear decommissioning costs are approved by the FERC.

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.

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 7A). 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. Intangible assets are amortized based on the economic benefit of their respective lives.

CHANGE IN ACCOUNTING POLICY REGARDING ANNUAL GOODWILL TESTING DATE

We perform our goodwill impairment tests for the PEC and PEF reporting units at least annually, and more often if events or changes in circumstances indicate it is more likely than not that their carrying values exceed their fair values. Since the adoption of Accounting Standards Codification (ASC) 350, Intangibles – Goodwill and Other, through April 1, 2010, we performed the annual impairment testing of goodwill using April 1 as the testing date. Our annual financial and strategic planning process, including the preparation of long-term cash flow projections, concludes in the fourth quarter of each year. Effective in October 2010, we changed our annual goodwill impairment testing date from April 1 to October 31 to better align our impairment testing procedures with the completion of our financial and strategic planning process. We believe the change is preferable since these long-term cash flow projections are a key component in performing our annual impairment tests of goodwill. During 2010, we tested our goodwill for impairment as of October 31, 2010 and April 1, 2010, and concluded there was no impairment of the carrying value of the goodwill. This change did not accelerate, delay, avoid, or cause a goodwill impairment charge. As it was impracticable to objectively determine operating and valuation estimates for periods prior to October 31, 2010, we have prospectively applied the change in the annual impairment testing date from October 31, 2010.

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 7A).

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 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 17 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. 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. NEW ACCOUNTING STANDARDS

A. CONSOLIDATIONS

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities.” Subsequently, the FASB issued Accounting Standards Update (ASU) 2009-17, “Consolidations (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which codified SFAS No. 167 in the ASC. This guidance made significant changes to the model for determining who should consolidate a VIE, addressed how often this assessment should be performed, required all existing arrangements with VIEs to be evaluated, and was adopted through a cumulative effect of change in accounting principle adjustment. This guidance was effective for us on January 1, 2010. See Note 1C for information regarding our implementation of ASU 2009-17 and its impact on our and the Utilities’ financial position and results of operations.

B. FAIR VALUE MEASUREMENT AND DISCLOSURES

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

3. 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. The accompanying consolidated statements of income reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.

On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky for $71 million in gross cash proceeds. Proceeds from the sale were used for general corporate purposes. During the year ended December 31, 2008, we recorded an after-tax gain of $42 million on the sale of these assets. The accompanying consolidated financial statements reflect the operations 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.

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


(in millions)	2010			2009			2008
Revenues	$	—		$	—		$	17

(Loss) earnings before income taxes and noncontrolling interest	$	(11	)	$	(125	)	$	8
Income tax benefit, including tax credits		5			47			12
Earnings attributable to noncontrolling interests		—			—			(1	)

Net (loss) earnings from discontinued operations attributable to controlling interests		(6	)		(78	)		19
Gain on disposal of discontinued operations, net of income tax expense of $7		—			—			42

(Loss) earnings from discontinued operations attributable to controlling interests	$	(6	)	$	(78	)	$	61

B. COAL MINING BUSINESSES

On March 7, 2008, we sold the remaining operations of subsidiaries engaged in the coal mining business for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. As a result of the sale, during the year ended December 31, 2008, we recorded an after-tax gain of $7 million on the sale of these assets. During the years ended December 31, 2010 and 2009, gains and losses related to post-closing adjustments and pre-divestiture contingencies were not material to our results of operations.

The accompanying consolidated financial statements reflect the coal mining businesses as discontinued operations. Results of discontinued operations for the coal mining businesses for the year ended December 31, 2008 were as follows:


(in millions)	2008
Revenues	$	2

Loss before income taxes	$	(13	)
Income tax benefit		4

Net loss from discontinued operations		(9	)
Gain on disposal of discontinued operations, net of income tax expense of $2		7

Loss from discontinued operations attributable to controlling interests	$	(2	)

C. 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, 2010, 2009 and 2008, gains and losses related to post-closing adjustments and pre-divestiture contingencies of other diversified businesses were not material to our results of operations.

4. 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		2010		2009		2010		2009		2010		2009
Production plant		3-41	$	16,042	$	15,477	$	9,354	$	9,014	$	6,523	$	6,280
Transmission plant		7-75		3,530		3,273		1,626		1,535		1,904		1,738
Distribution plant		13-67		8,715		8,376		4,687		4,499		4,028		3,877
General plant and other		5-35		1,421		1,227		721		684		700		543

Utility plant in service			$	29,708	$	28,353	$	16,388	$	15,732	$	13,155	$	12,438

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 11).

As discussed in Note 7B, PEC intends to retire no later than December 31, 2014, 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. During the fourth quarter of 2010, Progress Energy and PEC reclassified, for all periods, the net carrying value of the four facilities from utility plant in service, net, to other utility plant, net, on the consolidated balance sheets, in accordance with ASC 980-360, Regulated Operations – Property, Plant and Equipment. At December 31, 2010 and 2009, the net carrying value of the four facilities included in other utility plant, net, totaled $172 million and $165 million, respectively. Consistent with current ratemaking treatment, PEC expects to include the four facilities’ remaining net carrying value in rate base after retirement.

AFUDC represents the estimated costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the cost of the plant for certain projects in accordance with the regulatory provisions for each jurisdiction. The equity funds portion of AFUDC is credited to other income, and the borrowed funds portion is credited to interest charges. 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 9.2% in 2010, 2009 and 2008. The composite AFUDC rate for PEF’s electric utility plant was 7.4%, effective beginning April 1, 2010, based on its authorized return on equity (ROE) approved in the base rate case (See Note 7C). Prior to April 1, 2010, the composite AFUDC rate for PEF’s electric utility plant was 8.8%.

Our depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.0%, 2.4% and 2.3% in 2010, 2009 and 2008, respectively. The depreciation provisions related to utility plant were $635 million, $626 million and $578 million in 2010, 2009 and 2008, 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 4C), regulatory approved expenses (See Notes 7 and 21) and Clean Smokestacks Act amortization.

PEC’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.1% for 2010, 2009 and 2008. The depreciation provisions related to utility plant were $338 million, $328 million and $310 million in 2010, 2009 and 2008, 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 4C), regulatory approved expenses (See Note 7B) and Clean Smokestacks Act amortization.

PEF’s depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 1.9% in 2010, and 2.7% in 2009 and 2008. The depreciation provisions related to utility plant were $297 million, $299 million and $268 million in 2010, 2009 and 2008, 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 4C) and regulatory approved expenses (See Note 7C).

During 2010, PEF updated the depreciation rates which were 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 Open Access Transmission Tariff (OATT). The FERC filing requested depreciation rates be applied retroactively to January 1, 2010 whereby if approved, the depreciation rate changes will result in a reduction to the depreciation expense charged to PEF’s OATT customers, beginning June 1, 2011.

Nuclear fuel, net of amortization at December 31, 2010 and 2009, was $674 million and $554 million, respectively, for Progress Energy, $480 million and $396 million, respectively, for PEC and $194 million and $158 million, respectively, for PEF. The amount not yet in service at December 31, 2010 and 2009, was $367 million and $308 million, respectively, for Progress Energy, $199 million and $175 million, respectively, for PEC and $168 million and $133 million, respectively, for PEF. Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE) and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities, was $132 million, $159 million and $145 million for

the years ended December 31, 2010, 2009 and 2008, 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, 2010, 2009 and 2008 was $132 million, $134 million and $115 million, respectively. PEF’s amortization of nuclear fuel costs for the years ended December 31, 2009 and 2008 was $25 million and $30 million, respectively. PEF did not have any amortization of nuclear fuel costs for the year ended December 31, 2010, due to the Crystal River Unit No. 3 (CR3) outage (See Note 7C).

PEF’s construction work in progress related to certain nuclear projects has received regulatory treatment. At December 31, 2010, PEF had $519 million of accelerated recovery of construction work in process, of which $237 million was a component of a nuclear cost-recovery clause regulatory asset. At December 31, 2009, PEF had $451 million of accelerated recovery of construction work in process, of which $274 million was a component of a nuclear cost-recovery clause regulatory asset and $22 million was a component of a deferred fuel regulatory asset. See Note 7C 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:


		Company							Construction
(in millions) Subsidiary	Facility	Ownership Interest			Plant Investment		Accumulated Depreciation		Work in Progress
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		—

2009
PEC	Mayo		83.83	%	$	785	$	282	$	8
PEC	Harris		83.83	%		3,207		1,651		28
PEC	Brunswick		81.67	%		1,681		981		74
PEC	Roxboro Unit 4		87.06	%		686		449		15
PEF	Crystal River Unit 3		91.78	%		900		472		510
PEF	Intercession City Unit P11		66.67	%		23		10		—

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 process for Crystal River Unit 3 is not reduced by the accelerated recovery of qualifying project costs under the FPSC nuclear cost-recovery rule (see Note 7C).

C. ASSET RETIREMENT OBLIGATIONS

At December 31, 2010 and 2009, our asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant, net of accumulated depreciation totaled $90 million and $132 million, respectively. PEC had immaterial asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant at December 31, 2010. Primarily due to the impact of updated cost estimates, as discussed below, at December 31, 2009, PEC had no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant. Primarily due to the impact of updated escalation factors, as discussed below, at December 31, 2010, PEF had no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant. At December 31 2009, PEF’s asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $18 million. At December 31, 2010 and 2009, additional PEF-related asset retirement costs, net of accumulated depreciation, of $90 million and $114 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 $1.571 billion and $1.367 billion at December 31, 2010 and 2009, respectively (See Notes 12 and 13). The fair value of funds set aside in the NDT funds for the nuclear decommissioning liability totaled $1.017 billion and $871 million at December 31, 2010 and 2009, respectively, for PEC and $554 million and $496 million, respectively, for PEF (See Notes 12 and 13). Net NDT unrealized gains are included in regulatory liabilities (See Note 7A).

Progress Energy’s and PEC’s nuclear decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million each in 2010, 2009 and 2008. 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.

Expenses recognized 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, were $87 million, $141 million and $133 million in 2010, 2009 and 2008, respectively. PEC’s related expenses were $122 million, $106 million and $100 million in 2010, 2009 and 2008, respectively. Due to a $60 million cost of removal credit as allowed by the settlement agreement approved by the FPSC (See Note 7C), PEF had income of $35 million in 2010. PEF’s related expenses were $35 million and $33 million in 2009 and 2008, respectively.

The Utilities recognize removal, nonirradiated decommissioning and dismantlement of fossil generation plant costs in regulatory liabilities on the Consolidated Balance Sheets (See Note 7A). At December 31, such costs consisted of:


	Progress Energy				PEC				PEF
(in millions)	2010		2009		2010		2009		2010		2009
Removal costs	$	1,503	$	1,536	$	1,000	$	944	$	503	$	592
Nonirradiated decommissioning costs		233		211		172		150		61		61
Dismantlement costs		121		119		—		—		121		119

Non-ARO cost of removal	$	1,857	$	1,866	$	1,172	$	1,094	$	685	$	772

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 7D for information about the NRC operating licenses held by PEC. Based on updated cost estimates, in 2009 PEC reduced its asset retirement cost net of accumulated depreciation and its ARO liability by approximately $27 million and $390 million, respectively, resulting in no asset retirement costs included in utility plant related to nuclear decommissioning of irradiated plant at December 31, 2009.

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 (See Note 7C). 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. 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 7D 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. In addition, the wholesale accrual on PEF’s reserves for nuclear decommissioning was suspended retroactive to January 2006, 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 $144 million and $143 million at December 31, 2010 and 2009, 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 $26 million and $27 million at December 31, 2010 and 2009, respectively, at PEC and $27 million at December 31, 2010 and 2009 at PEF.

Additionally, PEC and PEF have recognized ARO liabilities related to landfill capping costs. The ARO liabilities related to landfill capping costs were immaterial at December 31, 2010 and 2009, at PEC and $6 million at December 31, 2010 and 2009, 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, 2009	$	1,471		$	1,122		$	349
Accretion expense		83			65			18
Revisions to prior estimates		(384	)		(386	)		2

Asset retirement obligations at December 31, 2009		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

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 $28 million with respect to the primary coverage, $41 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, 2010, PEF has an outstanding claim with NEIL (See Notes 5 and 7C).

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 7C).

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.

5. 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)	2010			2009			2010			2009			2010			2009
Trade accounts receivable	$	651		$	581		$	346		$	291		$	303		$	288
Unbilled accounts receivable		223			193			136			125			87			68
Other receivables		75			44			47			34			12			10
NEIL receivable (See Notes 4 and 7)		119			—			—			—			119			—
Allowance for doubtful receivables		(35	)		(18	)		(10	)		(8	)		(25	)		(10	)

Total receivables, net	$	1,033		$	800		$	519		$	442		$	496		$	356

6. INVENTORY

At December 31 inventory was comprised of:


	Progress Energy				PEC				PEF
(in millions)	2010		2009		2010		2009		2010		2009
Fuel for production	$	542	$	667	$	192	$	304	$	350	$	363
Materials and supplies		676		639		395		366		281		273
Emission allowances		8		18		3		6		5		12
Other		—		1		—		1		—		—

Total inventory	$	1,226	$	1,325	$	590	$	677	$	636	$	648

Materials and supplies amounts above exclude long-term combustion turbine inventory amounts included in other assets and deferred debits on the Consolidated Balance Sheets for Progress Energy of $24 million at December 31, 2009, which was transferred to PEC in 2010 and is included in construction work in progress on the Consolidated Balance Sheets for Progress Energy and PEC at December 31, 2010.

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 $33 million, $5 million and $28 million, respectively, at December 31, 2010. Long-term emission allowances for Progress Energy, PEC and PEF were $39 million, $8 million and $31 million, respectively, at December 31, 2009.

7. REGULATORY MATTERS

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. 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)	2010			2009
Deferred fuel costs – current (Notes 7B and 7C)	$	169		$	105
Nuclear deferral (Notes 7C)		7			37

Total current regulatory assets		176			142

Deferred fuel cost – long-term		—			62
Nuclear deferral (Note 7C)^(a)		178			239
Deferred impact of ARO (Note 4C)^(b)		122			99
Income taxes recoverable through future rates^(c)		302			264
Loss on reacquired debt^(d)		31			35
Postretirement benefits (Note 16)^(e)		1,105			945
Derivative mark-to-market adjustment (Note 17A)^(f)		505			436
DSM / Energy-efficiency deferral (Note 7B)^(g)		57			19
Other		74			80

Total long-term regulatory assets		2,374			2,179

Environmental (Note 7C)		(45	)		(24	)
Deferred energy conservation cost and other current regulatory liabilities		(14	)		(3	)

Total current regulatory liabilities		(59	)		(27	)

Non-ARO cost of removal (Note 4C)^(b)		(1,857	)		(1,866	)
Deferred impact of ARO (Note 4C)^(b)		(143	)		(150	)
Net nuclear decommissioning trust unrealized gains (Note 4C)^(h)		(421	)		(295	)
Storm reserve (Note 7C)⁽ⁱ⁾		(136	)		(136	)
Other		(78	)		(63	)

Total long-term regulatory liabilities		(2,635	)		(2,510	)

Net regulatory liabilities	$	(144	)	$	(216	)

PEC


(in millions)	2010			2009
Deferred fuel costs – current (Notes 7B)	$	71		$	88

Deferred fuel cost – long-term		—			62
Deferred impact of ARO (Note 4C)^(b)		112			92
Income taxes recoverable through future rates^(c)		103			76
Loss on reacquired debt^(d)		13			15
Postretirement benefits (Note 16)^(e)		545			483
Derivative mark-to-market adjustment (Note 17A)^(f)		121			88
DSM / Energy-efficiency deferral (Note 7B)^(g)		57			19
Other		36			38

Total long-term regulatory assets		987			873

Non-ARO cost of removal (Note 4C)^(b)		(1,172	)		(1,094	)
Net nuclear decommissioning trust unrealized gains (Note 4C)^(h)		(267	)		(181	)
Other		(22	)		(18	)

Total long-term regulatory liabilities		(1,461	)		(1,293	)

Net regulatory liabilities	$	(403	)	$	(332	)

PEF


(in millions)	2010			2009
Deferred fuel costs – current (Note 7C)	$	98		$	17
Nuclear deferral (Notes 7C)		7			37

Total current regulatory assets		105			54

Nuclear deferral (Note 7C)^(a)		178			239
Income taxes recoverable through future rates^(c)		199			188
Loss on reacquired debt^(d)		18			20
Postretirement benefits (Note 16)^(e)		560			462
Derivative mark-to-market adjustment (Note 17A)^(f)		384			348
Other		48			50

Total long-term regulatory assets		1,387			1,307

Environmental (Note 7C)		(45	)		(24	)
Deferred energy conservation cost and other current regulatory liabilities		(14	)		(3	)

Total current regulatory liabilities		(59	)		(27	)

Non-ARO cost of removal (Note 4C)^(b)		(685	)		(772	)
Deferred impact of ARO (Note 4C)^(b)		(47	)		(30	)
Net nuclear decommissioning trust unrealized gains (Note 4C)^(h)		(154	)		(114	)
Derivative mark-to-market adjustment (Note 17A)^(f)		(13	)		(20	)
Storm reserve (Note 7C)⁽ⁱ⁾		(136	)		(136	)
Other		(49	)		(31	)

Total long-term regulatory liabilities		(1,084	)		(1,103	)

Net regulatory assets	$	349		$	231

The recovery and amortization periods for these regulatory assets and (liabilities) at December 31, 2010, 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 16).

^(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)	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.

⁽ⁱ⁾	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 rate cases in 1988, the NCUC and the SCPSC each authorized a ROE of 12.75 percent.

COST RECOVERY FILINGS

On November 17, 2010, the NCUC approved three separate PEC cost-recovery filings, all of which were effective December 1, 2010. The NCUC approved PEC’s request for a $170 million decrease in the fuel rate charged to its North Carolina ratepayers, driven by declining fuel prices, which reduced residential electric bills by $5.60 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. The NCUC approved PEC’s request for a $31 million increase in the demand-side management (DSM) and EE rate charged to its North Carolina ratepayers, which increased the residential electric bills by $1.56 per 1,000 kWh for DSM and EE cost recovery. The NCUC approved PEC’s request for a $2 million decrease for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), which decreased the residential electric bills by $0.07 per 1,000 kWh. The net impact of the three filings results in an average reduction in residential electric bills of 3.9 percent. At December 31, 2010, PEC’s North Carolina deferred fuel and DSM / EE balances were $56 million and $49 million, respectively.

On June 23, 2010, the SCPSC approved PEC’s request for a $17 million decrease in the fuel rate charged to its South Carolina ratepayers, driven by declining fuel prices. The decrease was effective July 1, 2010, and decreased residential electric bills by $2.73 per 1,000 kWh for fuel cost recovery. PEC also filed with the SCPSC for an increase in the DSM and EE rate effective July 1, 2010, which was approved on a provisional basis on June 30, 2010, pending review by the South Carolina Office of Regulatory Staff. The net impact of the two filings resulted in an average reduction in residential electric bills of 1.7 percent. We cannot predict the outcome of this matter. At December 31, 2010, PEC’s South Carolina deferred fuel and DSM / EE balances were $15 million and $8 million, respectively.

OTHER MATTERS

On October 13, 2008, the NCUC issued a Certificate of Public Convenience and Necessity allowing PEC to proceed with plans to construct an approximately 600-MW combined cycle dual fuel-capable generating facility at its Richmond County generation site to provide additional generating and transmission capacity to meet the growing energy demands of southern and eastern North Carolina. PEC projects that the generating facility and related transmission will be in service by June 2011.

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 December 1, 2009, PEC filed with the NCUC a plan to retire no later than December 31, 2017, 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 September 13, 2010, PEC filed its 15-year Integrated Resource Plan with the NCUC and SCPSC, which further accelerated the expected retirement schedule of the four coal-fired generating facilities to no later than December 31, 2014. The net carrying value of the four facilities at December 31, 2010, of $172 million is included in other utility plant, net on the Consolidated Balance Sheets. Consistent with ratemaking treatment, PEC will continue to depreciate these plants using the current depreciation lives and rates on file with the NCUC and the SCPSC until PEC completes and files a new depreciation study. The final recovery periods may change in connection with the regulators’ determination of the rate recovery of the remaining net carrying value.

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.

The NCUC and the SCPSC approved proposals to accelerate cost recovery of PEC’s nuclear generating assets beginning January 1, 2000, through 2009. The North Carolina aggregate minimum and maximum amounts of cost recovery were $415 million and $585 million, respectively, with flexibility in the amount of annual depreciation recorded, from none to $150 million per year. Accelerated cost recovery of these assets resulted in additional depreciation expense of $52 million for the year ended December 31, 2008. PEC reached the minimum amount of $415 million of cost recovery by December 31, 2008, and no additional depreciation expense from accelerated cost recovery was subsequently recorded. As a result of the SCPSC’s approval of a 2008 PEC petition, PEC will not be required to recognize the remaining $38 million of accelerated depreciation required to reach the minimum $115 million of cost recovery for the South Carolina jurisdiction, but will record depreciation over the useful lives of the assets. No additional depreciation expense from accelerated cost recovery for the South Carolina jurisdiction was recorded in 2008 or subsequent to the approval.

C. PEF RETAIL RATE MATTERS

BASE RATES

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, 2010, PEF recognized a $60 million reduction in amortization expense pursuant to the settlement agreement. PEF’s applicable cost of removal reserve of $461 million is recorded as a regulatory liability on its December 31, 2010 Balance Sheet. 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, 2010, PEF’s storm damage reserve was $136 million, the amount permitted by the settlement agreement.

On September 14, 2010, the FPSC approved a reduction to PEF’s AFUDC rate, from 8.848 percent to 7.44 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 1, 2010, PEF filed a request with the FPSC to seek approval to decrease the total fuel-cost recovery by $205 million, reducing the residential rate by $6.64 per 1,000 kWh, or 5.2 percent effective January 1, 2011. This decrease is due to decreases of $5.14 per 1,000 kWh for the projected recovery through the Capacity Cost-Recovery Clause (CCRC) and of $1.50 per 1,000 kWh for the projected recovery of fuel costs. The decrease in the CCRC is primarily due to the refund of a prior period over-recovery as a result of higher than expected sales in 2010 and lower anticipated costs associated with PEF’s proposed Levy Units No. 1 and No. 2 Nuclear Power Plants (Levy) in 2011 (See “Levy Nuclear”). The decrease in the projected recovery of fuel costs is due to an expectation of lower 2011 fuel costs and the continued recovery of incremental CR3 replacement power costs through insurance, partially offset by an under-recovery of 2010 fuel costs. On November 2, 2010 and November 30, 2010, the FPSC approved PEF’s CCRC residential rate and fuel rate, respectively. 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”). At December 31, 2010, PEF’s under-recovered deferred fuel balance was $98 million.

On October 25, 2010, the FPSC approved PEF’s motion to establish a separate spin-off docket related to the outage and replacement fuel and power costs associated with the CR3 extended outage (See “CR3 Outage”). This docket will allow the FPSC to evaluate PEF’s actions concerning the concrete delamination and review PEF’s resulting costs associated with the CR3 extended outage. PEF intends to file a petition within 60 days following CR3’s return to service; however, the FPSC has not yet established a case schedule. A hearing is expected later in 2011. We cannot predict the outcome of this matter.

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 combined license (COL) application will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work anticipated in the initial schedule cannot begin until the COL is issued, resulting in a project shift of at least 20 months. Since then, regulatory and economic conditions identified in the 2010 nuclear cost-recovery filing have changed such that major construction activities on the Levy project are being postponed until after the NRC issues the COL, expected in 2013 if the current licensing schedule remains on track. Taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification, we consider Levy to be PEF’s preferred baseload generation option. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility, including comparison to other generation options; DSM and EE programs; and availability and terms of capital financing.

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. PEF will apply for the required license amendment for the third-stage design modification.

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 2014. At December 31, 2010, PEF’s nuclear cost-recovery regulatory asset was $7 million and $178 million, classified as current and noncurrent, respectively.

On October 26, 2010, the FPSC approved PEF’s annual nuclear cost-recovery filing to recover $164 million, which includes recovery of preconstruction, carrying and CCRC-recoverable operations and maintenance (O&M) costs incurred or anticipated to be incurred during 2011, recovery of $60 million of the 2009 deferral in 2011, as well as the estimated true-up of 2010 costs associated with the Levy and CR3 uprate projects. This resulted in a decrease in the nuclear cost-recovery charge of $1.46 per 1,000 kWh for residential customers, beginning with the first January 2011 billing cycle. The FPSC determined the costs associated with Levy were prudent and deferred a determination concerning the prudence of the 2009 CR3 uprate costs until the 2011 nuclear cost-recovery proceeding. The final order was issued on February 2, 2011.

CR3 OUTAGE

In September 2009, CR3 began an outage for normal refueling and maintenance as well as its uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination within the concrete of the outer wall of the containment structure, which has resulted in an extension of the outage. After a comprehensive analysis, we have determined that the concrete delamination at CR3 was caused by redistribution of stresses on the containment wall that occurred when we created an opening to accommodate the replacement of the unit’s steam generators. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. A number of factors affect the return to service date, including regulatory reviews by the NRC and other agencies, emergent work, final engineering designs, testing, weather and other developments.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL as discussed in Note 4D. PEF also maintains insurance coverage through an accidental property damage program, which provides insurance coverage with a $10 million deductible per claim. PEF notified NEIL of the claim related to the CR3 delamination event on October 15, 2009. NEIL has confirmed that the CR3 delamination event is a covered accident. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs.

The following table summarizes the CR3 replacement power and repair costs and recovery through December 31, 2010:


(in millions)	Replacement power costs			Repair costs
Spent to date	$	288		$	150
NEIL proceeds received		(117	)		(64	)
Insurance receivable at December 31, 2010		(54	)		(47	)

Balance for recovery	$	117		$	39

PEF considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. PEF accrued $171 million of replacement power cost reimbursements after the deductible period, which reduced the portion of the deferred fuel regulatory asset related to the extended CR3 outage to $117 million at December 31, 2010. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. PEF requested, and the FPSC approved, the creation of a separate spin-off docket to review the prudence and costs related to the CR3 outage (See “Fuel Cost Recovery”).

We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT COST RECOVERY

On December 30, 2009, the FPSC ordered PEF and other Florida utilities to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. As subsequently revised by the FPSC, PEF’s aggregate conservation goals over the next 10 years were: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). On March 30, 2010, PEF filed a petition for approval of its proposed DSM plan and to authorize cost recovery through the Energy Conservation Cost Recovery Clause (ECCR). On September 14, 2010, the FPSC held an agenda conference to approve PEF’s petition for the DSM plan. The FPSC ruled that while PEF’s proposed DSM plan met the cumulative, 10-year DSM goals set by the FPSC, the plan did not meet the annual DSM goals. On October 4, 2010, the FPSC denied PEF’s petition for the DSM plan, approved PEF’s solar pilot programs, and required PEF to file a revised proposed DSM plan that meets the annual goals set by the FPSC. PEF filed a revised proposed DSM plan on November 29, 2010. An agenda conference has been scheduled by the FPSC for April 5, 2011. We cannot predict the outcome of this matter.

On November 1, 2010, the FPSC approved PEF’s request to increase the ECCR residential rate by $0.29 per 1,000 kWh, or 0.2 percent of the total residential rate, effective January 1, 2011. The increase in the ECCR is primarily due to an increase in conservation program costs, including the costs associated with PEF’s solar pilot, partially offset by a refund of a prior period over-recovery as a result of higher than expected sales in 2010.

OTHER MATTERS

On November 1, 2010, the FPSC approved PEF’s request to decrease the Environmental Cost Recovery Clause (ECRC) by $37 million, reducing the residential rate by $1.02 per 1,000 kWh, or 0.8 percent, effective January 1, 2011. The decrease in the ECRC is primarily due to the 2010 base rate decision, which reduced the clean air project depreciation and return rates, and the refund of a prior period over-recovery as a result of higher than expected sales in 2010. At December 31, 2010, PEF’s over-recovered deferred ECRC was $45 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, 2010, PEF has not recorded any amortization related to the 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. On December 18, 2008, PEF filed an application for a 20-year renewal from the NRC on the operating license for CR3, which would extend the operating license through 2036, if approved. PEF anticipates a decision from the NRC in 2011.

8. 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, 2010 and 2009, 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. As discussed in Note 1D, during 2010 we changed the annual testing date for our annual goodwill impairment tests from April 1 to October 31 of each year. As a result, we performed goodwill impairment tests as of April 1, 2010 and October 31, 2010, and concluded there was no impairment of the carrying value of the goodwill.

9. EQUITY

A. COMMON STOCK

PROGRESS ENERGY

At December 31, 2010 and December 31, 2009, we had 500 million shares of common stock authorized under our charter, of which 293 million and 281 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, 2010, there were no significant restrictions on the use of retained earnings (See Note 11B and Note 25).

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


	2010				2009				2008
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		12.2	$	434		17.5	$	623		3.7	$	132
Issuances under an underwritten public offering^(a)		—		—		14.4		523		—		—
Issuances through 401(k) and/or IPP		11.2		431		2.5		100		3.1		131

^(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, 2010 and December 31, 2009, 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, 2010, there were

no significant restrictions on the use of retained earnings. See Note 11B for additional dividend restrictions related to PEC.

PEF

At December 31, 2010 and December 31, 2009, 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, 2010, there were no significant restrictions on the use of retained earnings. See Note 11B 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 are 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. At December 31, 2010, no ESOP suspense shares were outstanding and the ESOP acquisition loan was repaid.

There were 0.5 million ESOP suspense shares at December 31, 2009 with a fair value of $22 million. ESOP shares allocated to plan participants totaled 13.4 million and 13.0 million at December 31, 2010 and 2009, respectively. 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, with the number of shares determined by dividing compensation cost by the common stock market value at the time of allocation. 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 approximately $12 million, $12 million and $8 million for the years ended December 31, 2010, 2009 and 2008, respectively. At December 31, 2009, we had a long-term note receivable from the 401(k) Trustee related to the purchase of common stock from us in 1989. The balance of the note receivable from the 401(k) Trustee was included in the determination of unearned ESOP common stock, which reduces common stock equity.

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 approximately $43 million, $41 million and $38 million for the years ended December 31, 2010, 2009 and 2008, respectively.

PEC

PEC’s matching costs met with shares released from the ESOP suspense account totaled approximately $8 million, $8 million and $6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Total matching cost was approximately $23 million, $22 million and $21 million for the years ended December 31, 2010, 2009 and 2008, respectively.

PEF

PEF’s matching costs met with shares released from the ESOP suspense account totaled approximately $3 million, $4 million and $2 million for the years ended December 31, 2010, 2009 and 2008, respectively. Total matching cost for both plans was approximately $14 million, $12 million and $11 million for the years ended December 31, 2010, 2009 and 2008, 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.

In 2008, shares issued under the PSSP used only one performance measure. In 2009, the PSSP was redesigned. For 2009 and 2010, shares issued under the revised plan 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. Through December 31, 2010, we issued 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, 2010, 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. Through December 31, 2010, we issued 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, 2010, there were an immaterial number of RSUs outstanding.

The total fair value of RSUs vested during the years ended December 31, 2010, 2009 and 2008, was $24 million, $16 million and $9 million, respectively. No cash was expended to purchase stock to satisfy RSU plan obligations in 2010, 2009 and 2008. The RSUs vested during 2010 had a weighted-average grant date fair value of $43.58.

Our Consolidated Statements of Income included total recognized expense for other stock-based compensation plans of $27 million for the year ended December 31, 2010, with a recognized tax benefit of $11 million. The total expense recognized on our Consolidated Statements of Income for other stock-based compensation plans was $37 million, with a recognized tax benefit of $14 million, and $34 million, with a recognized tax benefit of $13 million, for the years ended December 31, 2009 and 2008, respectively. No compensation cost related to other stock-based compensation plans was capitalized.

At December 31, 2010, unrecognized compensation cost related to nonvested other stock-based compensation plan awards totaled $25 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 $16 million for the year ended December 31, 2010, with a recognized tax benefit of $6 million. The total expense recognized on PEC’s Consolidated Statements of Income for other stock-based compensation plans was $22 million, with a recognized tax benefit of $9 million, and $20 million, with a recognized tax benefit of $8

million, for the years ended December 31, 2009 and 2008, 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 $11 million for the year ended December 31, 2010, with a recognized tax benefit of $4 million. The total expense recognized on PEF’s Statements of Income for other stock-based compensation plans was $14 million, with a recognized tax benefit of $5 million, and $14 million, with a recognized tax benefit of $5 million, for the years ended December 31, 2009 and 2008, 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)	2010		2009		2008
Weighted-average common shares – basic		290.7		279.4		261.6
Net effect of dilutive stock-based compensation plans		0.1		0.1		0.1

Weighted-average shares – fully diluted		290.8		279.5		261.7

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, 1.5 million and 1.6 million stock options outstanding at December 31, 2010, 2009 and 2008, respectively, which were not included in the weighted-average number of shares for computing the fully diluted earnings per share because they were antidilutive.

D. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME

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


	Progress Energy						PEC						PEF
(in millions)	2010			2009			2010			2009			2010			2009
Cash flow hedges	$	(63	)	$	(35	)	$	(33	)	$	(27	)	$	(4	)	$	3
Pension and other postretirement benefits		(62	)		(52	)		—			—			—			—

Total accumulated other comprehensive (loss) income	$	(125	)	$	(87	)	$	(33	)	$	(27	)	$	(4	)	$	3

10. 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 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, 2010 and 2009, 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

11. 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, 2010):


(in millions)			2010			2009
*Parent*
Senior unsecured notes, maturing 2011-2039	6.64	%	$	4,200		$	4,300
Unamortized premium and discount, net				(6	)		(7	)
Current portion of long-term debt				(205	)		(100	)

Long-term debt, net				3,989			4,193


*PEC*
First mortgage bonds, maturing 2011-2038	5.60	%		2,525			2,525
Pollution control obligations, maturing 2017-2024	0.89	%		669			669
Senior unsecured notes, maturing 2012	6.50	%		500			500
Miscellaneous notes	6.00	%		5			21
Unamortized premium and discount, net				(6	)		(6	)
Current portion of long-term debt				—			(6	)

Long-term debt, net				3,693			3,703


*PEF*
First mortgage bonds, maturing 2011-2040	5.82	%		4,100			3,800
Pollution control obligations, maturing 2018-2027	0.52	%		241			241
Medium-term notes, maturing 2028	6.75	%		150			150
Unamortized premium and discount, net				(9	)		(8	)
Current portion of long-term debt				(300	)		(300	)

Long-term debt, net				4,182			3,883

Progress Energy consolidated long-term debt, net			$	11,864		$	11,779


*Florida Progress Funding Corporation (See Note 23)*
Debt to affiliated trust, maturing 2039	7.10	%	$	309		$	309
Unamortized premium and discount, net				(36	)		(37	)

Long-term debt, affiliate			$	273		$	272

On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due 2021. We expect to use net proceeds of $495 million, along with available cash on hand, to retire at maturity 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 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 in November 2009.

On March 25, 2010, PEF issued $250 million of 4.55% First Mortgage Bonds due 2020 and $350 million of 5.65% First Mortgage Bonds due 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, 2010 and 2009, we had committed lines of credit used to support our commercial paper and other short-term borrowings. At December 31, 2010 and December 31, 2009, 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
2010
Parent	Five-year (expiring 5/3/12)^(b)	$	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


2009
Parent	Five-year (expiring 5/3/12)	$	1,130	$	—	$	177	$	953
PEC	Five-year (expiring 6/28/11)		450		—		—		450
PEF	Five-year (expiring 3/28/11)		450		—		—		450

Total credit facilities		$	2,030	$	—	$	177	$	1,853

^(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, 2010 and 2009, the Parent had $31 million and $37 million, respectively, of letters of credit issued, which were supported by the RCA. Additionally, on December 31, 2009, the Parent had $140 million of outstanding commercial paper supported by the RCA.

^(b)	Approximately $22 million of the $500 million will expire May 3, 2011.

On October 15, 2010, PEC and PEF each entered into new $750 million, three-year RCAs with a syndication of 22 financial institutions. The RCAs are used to provide liquidity support for PEC’s and PEF’s issuances of commercial paper and other short-term obligations, and for general corporate purposes. The RCAs will expire on October 15, 2013. The new $750 million RCAs replaced PEC’s and PEF’s $450 million RCAs, which were set to expire on June 28, 2011 and March 28, 2011, respectively. Both $450 million RCAs were terminated effective October 15, 2010. Fees and interest rates under the new RCAs are to be determined based upon the respective credit ratings of PEC’s and PEF’s long-term unsecured senior noncredit-enhanced debt, as rated by Moody’s Investor Services, Inc. (Moody’s) and Standard and Poor’s Rating Services (S&P). The RCAs do not include material adverse change representations for borrowings or financial covenants for interest coverage. See “Covenants and Default Provisions” for additional provisions related to the RCAs.

Also on October 15, 2010, the Parent ratably reduced the size of its $1.130 billion credit facility to $500 million with the existing group of 15 financial institutions. As a result of the changes made on October 15, 2010, our combined credit commitments total $2.000 billion, supported by 24 financial institutions.

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


(in millions)	2010					2009
Parent		—	%	$	—		0.49	%	$	140
PEC		—			—		—			—
PEF		—			—		—			—

Total		—	%	$	—		0.49	%	$	140

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


(in millions)	Progress Energy Consolidated		PEC		PEF
2011	$	1,000	$	—	$	300
2012		950		500		—
2013		830		405		425
2014		300		—		—
2015		1,000		700		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 capital ratio (leverage). At December 31, 2010, 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	%		56	%
PEC		65	%		42	%
PEF		65	%		49	%

^(a)	Indebtedness as defined by the credit agreement includes certain letters of credit 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 long-term debt. Following payment of the Parent’s $700 million March 1, 2011 maturity, $4.000 billion in long-term debt could be subject to acceleration provisions. 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, 2010, the Parent had no shares of preferred stock outstanding. See Note 25 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, 2010, 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, 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, 2010, PEC’s common stock equity was approximately 58.0 percent of total capitalization. At December 31, 2010, 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, 2010, 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, and to 50 percent if common stock equity falls below 20 percent. On December 31, 2010, PEF’s common stock equity was approximately 53.7 percent of total capitalization. At December 31, 2010, none of PEF’s cash dividends or distributions on common stock was restricted.

C. COLLATERALIZED OBLIGATIONS

PEC’s and PEF’s first mortgage bonds 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, 2010, PEC and PEF had a total of $3.194 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 mortgage bonds upon the satisfaction of certain conditions.

D. GUARANTEES OF SUBSIDIARY DEBT

See Note 18 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 17 for a discussion of risk management activities and derivative transactions.

12. INVESTMENTS

A. INVESTMENTS

At December 31, 2010 and 2009, 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)	2010		2009		2010		2009		2010		2009

Nuclear decommissioning trust (See Notes 4C and 13)	$	1,571	$	1,367	$	1,017	$	871	$	554	$	496
Equity method investments^(a)		16		18		3		5		2		2
Cost investments^(b)		5		5		4		4		—		—
Company-owned life insurance^(c)		46		45		37		35		—		—
Benefit investment trusts^(d)		175		191		97		90		37		35

Total	$	1,813	$	1,626	$	1,158	$	1,005	$	593	$	533

^(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 in 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 in 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 in the Consolidated Balance Sheets.

^(d)

Benefit investment trusts are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2010 and 2009, $166 million and $152 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

We evaluate declines in value of investments under the criteria of GAAP. Declines in fair value to below the cost basis judged to be other than temporary on available-for-sale securities 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 13 for additional information. There were no material other-than-temporary impairments in 2010, 2009 or 2008.

13. FAIR VALUE DISCLOSURES

A. DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $12.642 billion and $12.457 billion at December 31, 2010 and 2009, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $14.0 billion and $13.4 billion at December 31, 2010 and 2009, 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 4C). 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
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


2009
Common stock equity	$	839	$	22	$	301
Preferred stock and other equity		16		—		5
Corporate debt		71		1		5
U.S. state and municipal debt		118		2		3
U.S. and foreign government debt		197		1		8
Money market funds and other		161		—		—

Total	$	1,402	$	26	$	322

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 2010 and 2009 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, 2010 and 2009.

The aggregate fair value of investments that related to the December 31, 2010 and 2009 unrealized losses was $195 million and $209 million, respectively.

At December 31, 2010, the fair value of our available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	27
Due after one through five years		223
Due after five through 10 years		126
Due after 10 years		117

Total	$	493

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)	2010		2009		2008
Proceeds	$	6,747	$	2,207	$	1,316
Realized gains		21		26		29
Realized losses		27		87		86

Proceeds were primarily related to NDT funds. 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, 2010 and 2009, our other securities had no investments in a continuous loss position for greater than 12 months.

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $3.693 billion and $3.709 billion at December 31, 2010 and 2009, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.0 billion at December 31, 2010 and 2009.

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 4C). 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
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


2009
Common stock equity	$	545	$	19	$	186
Preferred stock and other equity		10		—		3
Corporate debt		67		1		4
U.S. state and municipal debt		37		—		1
U.S. and foreign government debt		177		1		8
Money market funds and other		35		—		—

Total	$	871	$	21	$	202

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 2010 and 2009 relate to the NDT funds.

The aggregate fair value of investments that related to the December 31, 2010 and 2009 unrealized losses was $104 million and $121 million, respectively.

At December 31, 2010, the fair value of PEC’s available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	14
Due after one through five years		138
Due after five through 10 years		85
Due after 10 years		92

Total	$	329

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)	2010		2009		2008
Proceeds	$	419	$	622	$	587
Realized gains		10		9		12
Realized losses		19		36		48

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, 2010 and 2009, 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 and $4.183 billion at December 31, 2010 and 2009, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $5.0 billion and $4.5 billion at December 31, 2010 and 2009, 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 4C). 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
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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
2009
Common stock equity	$	294	$	3	$	115
Preferred stock and other equity		6		—		2
Corporate debt		4		—		1
U.S. state and municipal debt		80		2		2
U.S. and foreign government debt		13		—		—
Money market funds and other		99		—		—

Total	$	496	$	5	$	120

The aggregate fair value of investments that related to the December 31, 2010 and 2009 unrealized losses was $87 million and $56 million, respectively.

At December 31, 2010, the fair value of PEF’s available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	6
Due after one through five years		85
Due after five through 10 years		41
Due after 10 years		25

Total	$	157

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)	2010		2009		2008
Proceeds	$	6,170	$	1,471	$	610
Realized gains		10		14		16
Realized losses		8		50		36

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, 2010 and 2009, 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, 2010 and 2009. 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
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 funds and other		18		—		—		18

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


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

Total liabilities	$	—	$	512	$	36	$	548


(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Nuclear decommissioning trust funds
Common stock equity	$	839	$	—	$	—	$	839
Preferred stock and other equity		16		—		—		16
Corporate debt		—		71		—		71
U.S. state and municipal debt		—		117		—		117
U.S. and foreign government debt		62		128		—		190
Money market funds and other		1		133		—		134

Total nuclear decommissioning trust funds		918		449		—		1,367
Derivatives
Commodity forward contracts		—		20		—		20
Interest rate contracts		—		19		—		19
Other marketable securities
U.S. state and municipal debt		—		1		—		1
U.S. and foreign government debt		—		7		—		7
Money market funds and other		16		27		—		43

Total assets	$	934	$	523	$	—	$	1,457


Liabilities
Derivatives
Commodity forward contracts	$	—	$	386	$	39	$	425
Contingent value obligations derivatives		—		15		—		15

Total liabilities	$	—	$	401	$	39	$	440

PEC


(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


(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Nuclear decommissioning trust funds
Common stock equity	$	545	$	—	$	—	$	545
Preferred stock and other equity		10		—		—		10
Corporate debt		—		67		—		67
U.S. state and municipal debt		—		37		—		37
U.S. and foreign government debt		52		125		—		177
Money market funds and other		1		34		—		35

Total nuclear decommissioning trust funds		608		263		—		871
Derivatives
Interest rate contracts		—		8		—		8
Other marketable securities		1		—		—		1

Total assets	$	609	$	271	$	—	$	880


Liabilities
Derivatives
Commodity forward contracts	$	—	$	63	$	27	$	90

PEF


(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


(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Nuclear decommissioning trust funds
Common stock equity	$	294	$	—	$	—	$	294
Preferred stock and other equity		6		—		—		6
Corporate debt		—		4		—		4
U.S. state and municipal debt		—		80		—		80
U.S. and foreign government debt		10		3		—		13
Money market funds and other		—		99		—		99

Total nuclear decommissioning trust funds		310		186		—		496
Derivatives
Commodity forward contracts		—		20		—		20
Interest rate contracts		—		5		—		5
Other marketable securities		1		—		—		1

Total assets	$	311	$	211	$	—	$	522


Liabilities
Derivatives
Commodity forward contracts	$	—	$	323	$	12	$	335

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 17 for discussion of risk management activities and derivative transactions.

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

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

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

Transfers in (out) of Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher level for which the inputs to the estimate became less observable or assets and liabilities 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 or 2 during the period other than those reflected in the Level 3 reconciliations. Transfers into and out of each level are measured at the end of the reporting period.

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

PROGRESS ENERGY


(in millions)	2010			2009			2008
Derivatives, net at beginning of period	$	39		$	41		$	(26	)
Total losses (gains), realized and unrealized deferred as regulatory assets and liabilities, net		44			13			102
Transfers (out) in of Level 3, net		(47	)		(15	)		(35	)

Derivatives, net at end of period	$	36		$	39		$	41

PEC


(in millions)	2010			2009			2009
Derivatives, net at beginning of period	$	27		$	22		$	(6	)
Total losses (gains), realized and unrealized deferred as regulatory assets and liabilities, net		27			7			32
Transfers (out) in of Level 3, net		(18	)		(2	)		(4	)

Derivatives, net at end of period	$	36		$	27		$	22

PEF


(in millions)	2010			2009			2008
Derivatives, net at beginning of period	$	12		$	19		$	(20	)
Total losses (gains), realized and unrealized deferred as regulatory assets and liabilities, net		17			6			70
Transfers (out) in of Level 3, net		(29	)		(13	)		(31	)

Derivatives, net at end of period	$	—		$	12		$	19

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

14. 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)	2010			2009
Deferred income tax assets
ARO liability	$	107		$	127
Derivative instruments		204			159
Income taxes refundable through future rates		271			225
Pension and other postretirement benefits		447			508
Other		394			374
Tax credit carry forwards		839			712
Net operating loss carry forwards		105			66
Valuation allowance		(60	)		(55	)

Total deferred income tax assets		2,307			2,116

Deferred income tax liabilities
Accumulated depreciation and property cost differences		(2,439	)		(1,889	)
Income taxes recoverable through future rates		(875	)		(782	)
Other		(386	)		(338	)

Total deferred income tax liabilities		(3,700	)		(3,009	)

Total net deferred income tax liabilities	$	(1,393	)	$	(893	)

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


(in millions)	2010			2009
Current deferred income tax assets, included in prepayments and other current assets	$	156		$	168
Noncurrent deferred income tax assets, included in other assets and deferred debits		34			37
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,583	)		(1,098	)

Total net deferred income tax liabilities	$	(1,393	)	$	(893	)

At December 31, 2010, we had the following tax credit and net operating loss carry forwards:

•

$836 million of federal alternative minimum tax credits that do not expire.

•

$5 million of state income tax credits that will expire during 2013.

•

$105 million of gross federal net operating loss carry forwards that will expire during 2030.

•

$1.6 billion of gross state net operating loss carry forwards that will expire during the period 2011 through 2030.

Valuation allowances have been established due to the uncertainty of realizing certain future state tax benefits. We had a net increase of $5 million in our valuation allowances during 2010.

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 25), 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:


	2010			2009			2008
Effective income tax rate		38.3	%		32.1	%		33.7	%
State income taxes, net of federal benefit		(4.3	)		(3.7	)		(3.8	)
Investment tax credit amortization		0.5			0.8			1.0
Employee stock ownership plan dividends		0.9			1.0			1.0
Domestic manufacturing deduction		—			0.8			0.3
AFUDC equity		1.4			2.2			2.5
Other differences, net		(1.8	)		1.8			0.3

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)	2010			2009			2008
Current
Federal	$	(46	)	$	227		$	38
State		(13	)		41			12

Total current income tax expense (benefit)		(59	)		268			50

Deferred
Federal		542			114			305
State		100			25			49

Total deferred income tax expense		642			139			354

Investment tax credit		(7	)		(10	)		(12	)
Net operating loss carry forward		(37	)		—			(6	)
Beginning-of-the-year valuation allowance change		—			—			9

Total income tax expense	$	539		$	397		$	395

We previously recorded a deferred income tax asset for a state net operating loss carry forward upon the sale of our nonregulated generating facilities and energy marketing and trading operations. During 2008, we recorded an additional deferred income tax asset of $6 million related to the state net operating loss carry forward due to a change in estimate based on 2007 tax return filings. During 2008 we also evaluated this state net operating loss carry forward and recorded a partial valuation allowance of $9 million.

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

•

Taxes related to discontinued operations recorded net of tax for 2010, 2009 and 2008, which are presented separately in Notes 3A through 3C.

•

Taxes related to other comprehensive income recorded net of tax for 2010, 2009 and 2008, which are presented separately in 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 2009 and 2008.

At December 31, 2010, 2009, and 2008, our liability for unrecognized tax benefits was $176 million, $160 million, and $104 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $8 million, $9 million, and $8 million, respectively, at December 31, 2010, 2009, and 2008. The following table presents the changes to unrecognized tax benefits during the years ended December 31:


(in millions)	2010			2009			2008
Unrecognized tax benefits at beginning of period	$	160		$	104		$	93
Gross amounts of increases as a result of tax positions taken in a prior period		10			11			17
Gross amounts of decreases as a result of tax positions taken in a prior period		(4	)		(3	)		(11	)
Gross amounts of increases as a result of tax positions taken in the current period		14			52			8
Gross amounts of decreases as a result of tax positions taken in the current period		(4	)		(4	)		(2	)
Amounts of net increases relating to settlements with taxing authorities		—			—			1
Reduction as a result of a lapse of the applicable statute of limitations		—			—			(2	)

Unrecognized tax benefits at end of period	$	176		$	160		$	104

We and our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Generally our open federal tax years are from 2004 forward, and our open state tax years in our major jurisdictions are from 2003 or 2004 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. We cannot predict when the review will be completed. Although the timing for completion of the IRS review is uncertain, it is reasonably possible that unrecognized tax benefits will decrease by up to approximately $60 million during the 12-month period ending December 31, 2011, due to expected settlements. 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 2010, 2009, and 2008, the net interest expense related to unrecognized tax benefits was $9 million, $9 million, and $4 million, respectively, of which a respective $5 million, $5 million, and $1 million 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 2008, PEF charged the unamortized balance of the regulatory asset to interest expense. During 2010 and 2009, there were no penalties related to unrecognized tax benefits. During 2008, less than $1 million was recorded for penalties related to unrecognized tax benefits. At December 31, 2010, 2009, and 2008, we had accrued $45 million, $36 million, and $27 million, respectively, for interest and penalties, which are 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)	2010			2009
Deferred income tax assets
ARO liability	$	103		$	111
Income taxes refundable through future rates		142			106
Pension and other postretirement benefits		180			254
Other		207			186

Total deferred income tax assets		632			657

Deferred income tax liabilities
Accumulated depreciation and property cost differences		(1,552	)		(1,307	)
Deferred fuel recovery		(29	)		(60	)
Income taxes recoverable through future rates		(421	)		(377	)
Investments		(104	)		(71	)
Other		(6	)		(8	)

Total deferred income tax liabilities		(2,112	)		(1,823	)

Total net deferred income tax liabilities	$	(1,480	)	$	(1,166	)

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


(in millions)	2010			2009
Current deferred income tax assets, included in prepayments and other current assets	$	65		$	42
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,545	)		(1,208	)

Total net deferred income tax liabilities	$	(1,480	)	$	(1,166	)

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


	2010			2009			2008
Effective income tax rate		36.8	%		35.0	%		35.8	%
State income taxes, net of federal benefit		(3.2	)		(2.8	)		(2.7	)
Investment tax credit amortization		0.6			0.7			0.7
Domestic manufacturing deduction		0.4			0.9			0.5
Other differences, net		0.4			1.2			0.7

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)	2010			2009			2008
Current
Federal	$	73		$	192		$	87
State		(8	)		21			7

Total current income tax expense		65			213			94

Deferred
Federal		238			57			181
State		53			13			29

Total deferred income tax expense		291			70			210

Investment tax credit		(6	)		(6	)		(6	)

Total income tax expense	$	350		$	277		$	298

Total income tax expense excluded taxes related to other comprehensive income recorded net of tax for 2010, 2009 and 2008, which are presented separately in 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 $78 million and $38 million at December 31, 2010 and 2009, respectively.

At December 31, 2010, 2009, and 2008, PEC’s liability for unrecognized tax benefits was $74 million, $59 million, and $38 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $4 million, $5 million, and $5 million, respectively, at December 31, 2010, 2009, and 2008. The following table presents the changes to unrecognized tax benefits during the years ended December 31, 2010, 2009, and 2008:


(in millions)	2010			2009			2008
Unrecognized tax benefits at beginning of period	$	59		$	38		$	41
Gross amounts of increases as a result of tax positions taken in a prior period		8			6			5
Gross amounts of decreases as a result of tax positions taken in a prior period		(2	)		(2	)		(10	)
Gross amounts of increases as a result of tax positions taken in the current period		10			17			4
Gross amounts of decreases as a result of tax positions taken in the current period		(1	)		—			(1	)
Amounts of net increases relating to settlements with taxing authorities		—			—			1
Reduction as a result of a lapse of the applicable statute of limitations		—			—			(2	)

Unrecognized tax benefits at end of period	$	74		$	59		$	38

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. Generally PEC’s open federal tax years are from 2004 forward, and PEC’s open state tax years in our major jurisdictions are from 2003 or 2004 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEC cannot predict when the review will be completed. Although the timing for completion of the IRS review is uncertain, it is reasonably possible that unrecognized tax benefits will decrease by up to approximately $10 million during the 12-month period ending December 31, 2011, due to expected settlements. Any potential decrease will not have a material impact on PEC’s results of operations.

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 2010 and 2009, the interest expense recorded related to unrecognized tax benefits was $4 million and $3 million, respectively. During 2008, the interest benefit recorded related to unrecognized tax benefits was $1 million. During 2010, 2009, and 2008, there were no penalties related to unrecognized tax benefits. At December 31, 2010, 2009, and 2008, we had accrued $14 million, $10 million, and $7 million, respectively, for interest and penalties, which are 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)	2010			2009
Deferred income tax assets
Derivative instruments	$	145		$	125
Income taxes refundable through future rates		93			73
Pension and other postretirement benefits		170			163
Reserve for storm damage		52			52
Unbilled revenue		61			48
Other		82			89
Tax credit carry forwards		3			—
Net operating loss carry forwards		9			—

Total deferred income tax assets		615			550

Deferred income tax liabilities
Accumulated depreciation and property cost differences		(874	)		(568	)
Deferred fuel recovery		(65	)		(14	)
Deferred nuclear cost recovery		(94	)		(107	)
Income taxes recoverable through future rates		(454	)		(406	)
Investments		(60	)		(44	)
Other		(18	)		(26	)

Total deferred income tax liabilities		(1,565	)		(1,165	)

Total net deferred income tax liabilities	$	(950	)	$	(615	)

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


(in millions)	2010			2009
Current deferred income tax assets, included in deferred tax assets	$	77		$	115
Noncurrent deferred income tax liabilities, included in noncurrent income tax liabilities		(1,027	)		(730	)

Total net deferred income tax liabilities	$	(950	)	$	(615	)

At December 31, 2010, PEF had the following tax credit and net operating loss carry forwards:

•

$5 million of state income tax credits that will expire during 2013.

•

$22 million of gross federal net operating loss carry forwards that will expire during 2030.

•

$46 million of gross state net operating loss carry forwards that will expire during 2030.

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


	2010			2009			2008
Effective income tax rate		37.9	%		31.1	%		32.0	%
State income taxes, net of federal benefit		(3.2	)		(3.0	)		(3.1	)
Investment tax credit amortization		0.2			0.7			1.1
Domestic manufacturing deduction		—			0.8			0.2
AFUDC equity		0.8			3.4			5.4
Other differences, net		(0.7	)		2.0			(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)	2010			2009			2008
Current
Federal	$	(44	)	$	125		$	39
State		(4	)		20			12

Total current income tax expense (benefit)		(48	)		145			51

Deferred
Federal		293			57			121
State		41			11			15

Total deferred income tax expense		334			68			136

Investment tax credit		(1	)		(4	)		(6	)
Net operating loss carry forward		(9	)		—			—

Total income tax expense	$	276		$	209		$	181

Total income tax expense excluded the following:

•

Taxes related to other comprehensive income recorded net of tax for 2010, 2009 and 2008, which are presented separately in 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 $71 million and $122 million at December 31, 2010 and 2009, respectively.

At December 31, 2010, 2009, and 2008, PEF’s liability for unrecognized tax benefits was $99 million, $98 million, and $62 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $2 million, $3 million, and $2 million, respectively, at December 31, 2010, 2009, and 2008. The following table presents the changes to unrecognized tax benefits during the years ended December 31, 2010, 2009, and 2008:


(in millions)	2010			2009			2008
Unrecognized tax benefits at beginning of period	$	98		$	62		$	55
Gross amounts of increases as a result of tax positions taken in a prior period		2			5			6
Gross amounts of decreases as a result of tax positions taken in a prior period		(1	)		(1	)		(1	)
Gross amounts of increases as a result of tax positions taken in the current period		3			35			3
Gross amounts of decreases as a result of tax positions taken in the current period		(3	)		(3	)		(1	)
Amounts of net increases (decreases) relating to settlements with taxing authorities		—			—			—
Reduction as a result of a lapse of the applicable statute of limitations		—			—			—

Unrecognized tax benefits at end of period	$	99		$	98		$	62

We file consolidated federal and state income tax returns that include PEF. Generally PEF’s open federal tax years are from 2004 forward, and PEF’s open state tax years are from 2003 forward. The IRS is currently examining our federal tax returns for years 2004 through 2005. PEF cannot predict when the review will be completed. Although the timing for completion of the IRS review is uncertain, it is reasonably possible that unrecognized tax benefits will decrease by up to approximately $50 million during the 12-month period ending December 31, 2011, due to expected settlements. 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. During 2008, PEF charged the unamortized balance of the regulatory asset to interest expense on the Statements of Income. Penalties are included in other, net on the Statements of Income. During 2010, 2009, and 2008, interest expense recorded as a regulatory asset was $5 million, $5 million, and $1 million, respectively, and there were no penalties recorded related to unrecognized tax benefits. At December 31, 2010, 2009, and 2008, PEF had accrued $29 million, $24 million, and $19 million, respectively, for interest and penalties, which are included in interest accrued and other assets and deferred debits on the Consolidated Balance Sheets.

15. 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 3A). 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, 2010 and 2009 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 2010 and 2009 was insignificant.

The CVOs are derivatives and are recorded at fair value. The unrealized loss/gain recognized due to changes in fair value is recorded in other, net on the Consolidated Statements of Income (See Note 20). At December 31, 2010 and

2009, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $15 million.

16. 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


	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009			2008
Service cost	$	48		$	42		$	46		$	16		$	7		$	8
Interest cost		140			138			128			45			31			34
Expected return on plan assets		(157	)		(133	)		(170	)		(4	)		(4	)		(6	)
Amortization of actuarial loss^(a)		51			54			8			13			1			1
Other amortization, net ^(a)		6			6			2			5			5			5

Net periodic cost before deferral^(b)	$	88		$	107		$	14		$	75		$	40		$	42

^(a)	Adjusted to reflect PEF’s rate treatment (See Note 16B).

^(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 7C.

PEC


	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009			2008
Service cost	$	19		$	18		$	23		$	5		$	5		$	5
Interest cost		64			64			58			20			16			17
Expected return on plan assets		(77	)		(67	)		(66	)		(2	)		(2	)		(4	)
Amortization of actuarial loss		16			11			6			4			—			—
Other amortization, net		6			6			2			1			1			1

Net periodic cost	$	28		$	32		$	23		$	28		$	20		$	19

PEF


	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009			2008
Service cost	$	22		$	19		$	17		$	10		$	2		$	2
Interest cost		59			56			53			22			13			14
Expected return on plan assets		(68	)		(56	)		(90	)		(2	)		(1	)		(1	)
Amortization of actuarial loss		31			38			1			9			—			1
Other amortization, net		—			—			(1	)		4			3			3

Net periodic cost before deferral^(a)	$	44		$	57		$	(20	)	$	43		$	17		$	19

^(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 2010, 2009 and 2008. The tables also include comparable items that affected regulatory assets of PEC and PEF. For PEC and PEF, 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


	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009		2008
Other comprehensive income (loss)
Recognized for the year
Net actuarial (loss) gain	$	(11	)	$	(1	)	$	(64	)	$	(10	)	$	4	$	(8	)
Other, net		—			—			(6	)		—			—		—
Reclassification adjustments
Net actuarial loss		4			5			1			—			1		—
Other, net		—			—			1			—			1		—
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain		(65	)		10			(735	)		(164	)		64		(73	)
Other, net		—			(3	)		(36	)		—			—		—
Amortized to income^(a)
Net actuarial loss		47			49			7			13			—		1
Other, net		6			6			1			5			4		5

^(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*
	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009		2008
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain	$	(24	)	$	(14	)	$	(308	)	$	(64	)	$	38	$	(66	)
Other, net		—			(2	)		(31	)		—			—		—
Amortized to income
Net actuarial loss		16			11			6			4			—		—
Other, net		6			6			2			1			1		1

PEF


	Pension Benefits									OPEB
(in millions)	2010			2009			2008			2010			2009		2008
Regulatory asset (increase) decrease
Recognized for the year
Net actuarial (loss) gain	$	(41	)	$	24		$	(427	)	$	(100	)	$	26	$	(6	)
Other, net		—			(1	)		(5	)		—			—		—
Amortized to income^(a)
Net actuarial loss		31			38			1			9			—		1
Other, net		—			—			(1	)		4			3		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:


	Pension Benefits									OPEB
	2010			2009			2008			2010			2009			2008
Discount rate		6.00	%		6.30	%		6.20	%		6.05	%		6.20	%		6.20	%
Rate of increase in future compensation
Bargaining		4.50	%		4.25	%		4.25	%		—			—			—
Supplementary plans		5.25	%		5.25	%		5.25	%		—			—			—
Expected long-term rate of return on plan assets		8.75	%		8.75	%		9.00	%		6.60	%		6.80	%		8.10	%

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%, 8.75% and 9.00% for 2010, 2009 and 2008, respectively.

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 2009, primarily due to the uncertainties resulting from the severe capital market deterioration in 2008. 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, 2010 and 2009 are presented in the tables below, with each table followed by related supplementary information.

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Projected benefit obligation at January 1	$	2,422		$	2,234		$	543		$	608
Service cost		48			42			16			7
Interest cost		140			138			45			31
Settlements		—			(9	)		—			—
Benefit payments		(129	)		(124	)		(44	)		(40	)
Plan amendment		1			3			—			—
Actuarial loss (gain)		127			138			173			(63	)

Obligation at December 31		2,609			2,422			733			543
Fair value of plan assets at December 31		1,891			1,673			33			55

Funded status	$	(718	)	$	(749	)	$	(700	)	$	(488	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $2.609 billion and $2.422 billion at December 31, 2010 and 2009, respectively. Those plans had accumulated benefit obligations totaling $2.563 billion and $2.378 billion at December 31, 2010 and 2009, respectively, and plan assets of $1.891 billion and $1.673 billion at December 31, 2010 and 2009, respectively.

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


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Current liabilities	$	(10	)	$	(9	)	$	(22	)	$	—
Noncurrent liabilities		(708	)		(740	)		(678	)		(488	)

Funded status	$	(718	)	$	(749	)	$	(700	)	$	(488	)

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)	2010		2009		2010		2009
Recognized in accumulated other comprehensive loss
Net actuarial loss (gain)	$	90	$	83	$	5	$	(5	)
Other, net		9		10		1		—
Recognized in regulatory assets, net
Net actuarial loss		824		806		183		32
Other, net		55		59		9		14

Total not yet recognized as a component of net periodic cost^(a)	$	978	$	958	$	198	$	41

^(a)	All components are adjusted to reflect PEF’s rate treatment (See Note 16B).

The following table presents the amounts we expect to recognize as components of net periodic cost in 2011:


(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss^(a)	$	58	$	12
Amortization of other, net^(a)		7		5

^(a)	Adjusted to reflect PEF’s rate treatment (See Note 16B).

PEC


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Projected benefit obligation at January 1	$	1,120		$	1,025		$	282		$	312
Service cost		19			18			5			5
Interest cost		64			64			20			16
Plan amendment		—			2			—			—
Benefit payments		(56	)		(50	)		(19	)		(17	)
Actuarial loss (gain)		41			61			64			(34	)

Obligation at December 31		1,188			1,120			352			282
Fair value of plan assets at December 31		884			749			—			21

Funded status	$	(304	)	$	(371	)	$	(352	)	$	(261	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $1.188 billion and $1.120 billion at December 31, 2010 and 2009, respectively. Those plans had accumulated benefit obligations totaling $1.184 billion and $1.116 billion at December 31, 2010 and 2009, respectively, and plan assets of $884 million and $749 million at December 31, 2010 and 2009, respectively.

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


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Current liabilities	$	(2	)	$	(2	)	$	(19	)	$	—
Noncurrent liabilities		(302	)		(369	)		(333	)		(261	)

Funded status	$	(304	)	$	(371	)	$	(352	)	$	(261	)

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)	2010		2009		2010		2009
Recognized in regulatory assets
Net actuarial loss	$	418	$	410	$	76	$	16
Other, net		49		54		2		3

Total not yet recognized as a component of net periodic cost	$	467	$	464	$	78	$	19

The following table presents the amounts PEC expects to recognize as components of net periodic cost in 2011:


(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss	$	23	$	4
Amortization of other, net		6		1

PEF


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Projected benefit obligation at January 1	$	992		$	914		$	219		$	248
Service cost		22			19			10			2
Interest cost		59			56			22			13
Plan amendment		1			—			—			—
Benefit payments		(58	)		(58	)		(23	)		(20	)
Actuarial loss (gain)		71			61			98			(24	)

Obligation at December 31		1,087			992			326			219
Fair value of plan assets at December 31		871			794			33			32

Funded status	$	(216	)	$	(198	)	$	(293	)	$	(187	)

All defined benefit pension plans had accumulated benefit obligations in excess of plan assets, with projected benefit obligations totaling $1.087 billion and $992 million at December 31, 2010 and 2009, respectively. Those plans had accumulated benefit obligations totaling $1.049 billion and $957 million at December 31, 2010 and 2009, respectively, and plan assets of $871 million and $794 million at December 31, 2010 and 2009, respectively.

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


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Current liabilities	$	(3	)	$	(3	)	$	—		$	—
Noncurrent liabilities		(213	)		(195	)		(293	)		(187	)

Funded status	$	(216	)	$	(198	)	$	(293	)	$	(187	)

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)	2010		2009		2010		2009
Recognized in regulatory assets, net
Net actuarial loss	$	406	$	396	$	107	$	16
Other, net		6		5		7		11

Total not yet recognized as a component of net periodic cost	$	412	$	401	$	114	$	27

The following table presents the amounts PEF expects to recognize as components of net periodic cost in 2011:


(in millions)	Pension Benefits		OPEB
Amortization of actuarial loss	$	31	$	7
Amortization of other, net		—		4

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


	Pension Benefits						OPEB
	2010			2009			2010			2009
Discount rate		5.65	%		6.00	%		5.75	%		6.05	%
Rate of increase in future compensation
Bargaining		4.50	%		4.50	%		—			—
Supplementary plans		5.25	%		5.25	%		—			—
Initial medical cost trend rate for pre-Medicare Act benefits		—			—			8.50	%		8.50	%
Initial medical cost trend rate for post-Medicare Act benefits		—			—			8.50	%		8.50	%
Ultimate medical cost trend rate		—			—			5.00	%		5.00	%
Year ultimate medical cost trend rate is achieved		—			—			2017			2016

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		$	2
Effect on postretirement benefit obligation		46			22			20
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 for 2010 include contributions directly to pension plan assets of $129 million, $95 million and $34 million, respectively, and for 2009 include contributions directly to pension plan assets of $222 million, $163 million and $58 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 15 percent of gross benefit payments for Progress Energy, 21 percent for PEC and 10 percent for PEF. The OPEB benefit payments are also reduced by prescription drug-related federal subsidies received. In 2010, the subsidies totaled $3 million for us, $1 million for PEC and $2 million for PEF. In 2009, the subsidies totaled $3 million for us, $1 million for PEC and $1 million for PEF.

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

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Fair value of plan assets January 1	$	1,673		$	1,285		$	55		$	52
Actual return on plan assets		208			279			2			9
Benefit payments, including settlements		(129	)		(133	)		(44	)		(40	)
Employer contributions		139			242			20			34

Fair value of plan assets at December 31	$	1,891		$	1,673		$	33		$	55

PEC


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Fair value of plan assets January 1	$	749		$	521		$	21		$	22
Actual return on plan assets		94			113			2			5
Benefit payments		(56	)		(50	)		(19	)		(17	)
Employer contributions (reimbursements)		97			165			(4	)		11

Fair value of plan assets at December 31	$	884		$	749		$	—		$	21

PEF


	Pension Benefits						OPEB
(in millions)	2010			2009			2010			2009
Fair value of plan assets January 1	$	794		$	650		$	32		$	27
Actual return on plan assets		98			141			1			3
Benefit payments		(58	)		(58	)		(23	)		(20	)
Employer contributions		37			61			23			22

Fair value of plan assets at December 31	$	871		$	794		$	33		$	32

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 rolling 10-year annual return of 6 percent over the rate of inflation. The current target pension asset allocations are 40 percent domestic equity, 20 percent international equity, 25 percent domestic fixed income, 10 percent private equity and timber and 5 percent 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. International equity includes investments in foreign stocks in both developed and emerging market countries, using a mix of value and growth based investment strategies. Domestic fixed income primarily includes domestic investment grade fixed income investments. A substantial portion of OPEB plan assets are managed with pension assets. The remaining 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 of our pension plan assets at December 31, 2010 and 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	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
Interest rate swaps and other investments		—		4		—		4

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


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Cash and cash equivalents	$	1	$	96	$	—	$	97
Domestic equity securities		263		1		—		264
Private equity securities		—		—		122		122
Corporate bonds		—		67		—		67
U.S. state and municipal debt		—		4		—		4
U.S. and foreign government debt		25		95		—		120
Mortgage backed securities		—		22		—		22
Commingled funds		—		888		—		888
Hedge funds		—		47		2		49
Timber investments		—		—		14		14
Interest rate swaps and other investments		—		56		—		56

Total assets	$	289	$	1,276	$	138	$	1,703

Liabilities
Foreign currency contracts		5		—		—		5
Interest rate swaps and other investments		—		25		—		25

Total liabilities		5		25		—		30

Fair value of plan assets	$	284	$	1,251	$	138	$	1,673

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

The following table sets forth the fair value hierarchy of our other postretirement plan assets at December 31, 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	Other Postretirement Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Cash and cash equivalents	$	—	$	1	$	—	$	1
Domestic equity securities		4		—		—		4
Corporate bonds		—		1		—		1
U.S. state and municipal debt		—		32		—		32
U.S. and foreign government debt		—		2		—		2
Commingled funds		—		13		—		13
Hedge funds		—		1		—		1
Interest rate swaps and other investments		—		1		—		1

Fair value of plan assets	$	4	$	51	$	—	$	55

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
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


(in millions)	Private Equity Securities			Hedge Funds		Timber Investments			Total
2009
Balance at January 1	$	111		$	2	$	18		$	131
Net realized and unrealized (losses)^(a)		(10	)		—		(4	)		(14	)
Purchases, sales and distributions, net		21			—		—			21

Balance at December 31	$	122		$	2	$	14		$	138

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

PEC

The following table sets forth by level within the fair value hierarchy of PEC’s pension plan assets at December 31, 2010 and 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	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
Interest rate swaps and other investments		—		1		—		1

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


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Cash and cash equivalents	$	—	$	43	$	—	$	43
Domestic equity securities		118		—		—		118
Private equity securities		—		—		55		55
Corporate bonds		—		30		—		30
U.S. state and municipal debt		—		2		—		2
U.S. and foreign government debt		11		43		—		54
Mortgage backed securities		—		10		—		10
Commingled funds		—		398		—		398
Hedge funds		—		21		1		22
Timber investments		—		—		6		6
Interest rate swaps and other investments		—		24		—		24

Total assets	$	129	$	571	$	62	$	762

Liabilities
Foreign currency contracts		2		—		—		2
Interest rate swaps and other investments		—		11		—		11

Total liabilities		2		11		—		13

Fair value of plan assets	$	127	$	560	$	62	$	749

The following table sets forth the fair value hierarchy of our other postretirement plan assets at December 31, 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	Other Postretirement Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Cash and cash equivalents	$	—	$	1	$	—	$	1
Domestic equity securities		4		—		—		4
Corporate bonds		—		1		—		1
U.S. and foreign government debt		—		2		—		2
Commingled funds		—		12		—		12
Hedge funds		—		1		—		1

Fair value of plan assets	$	4	$	17	$	—	$	21

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
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


(in millions)	Private Equity Securities			Hedge Funds		Timber Investments			Total
2009
Balance at January 1	$	49		$	1	$	8		$	58
Net realized and unrealized (losses)^(a)		(4	)		—		(2	)		(6	)
Purchases, sales and distributions, net		10			—		—			10

Balance at December 31	$	55		$	1	$	6		$	62

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

PEF

The following table sets forth by level within the fair value hierarchy of PEF’s pension assets at December 31, 2010 and 2009. See Note 13 for detailed information regarding the fair value hierarchy.


	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
Interest rate swaps and other investments		—		2		—		2

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


	Pension Benefit Plan Assets
(in millions)	Level 1		Level 2		Level 3		Total
2009
Assets
Cash and cash equivalents	$	—	$	46	$	—	$	46
Domestic equity securities		125		—		—		125
Private equity securities		—		—		58		58
Corporate bonds		—		32		—		32
U.S. state and municipal debt		—		2		—		2
U.S. and foreign government debt		12		45		—		57
Mortgage backed securities		—		10		—		10
Commingled funds		—		421		—		421
Hedge funds		—		22		1		23
Timber investments		—		—		7		7
Interest rate swaps and other investments		—		26		—		26

Total assets	$	137	$	604	$	66	$	807

Liabilities
Foreign currency contracts		2		—		—		2
Interest rate swaps and other investments		—		11		—		11

Total liabilities		2		11		—		13

Fair value of plan assets	$	135	$	593	$	66	$	794

PEF’s other postretirement benefit plan assets had a fair value of $33 million and $32 million, which consisted of U.S. state and municipal assets classified as Level 2 in the fair value hierarchy at December 31, 2010 and 2009, 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
2010
Balance at January 1	$	58		$	1	$	7		$	66
Net realized and unrealized (losses)^(a)		3			—		(1	)		2
Purchases, sales and distributions, net		7			—		(1	)		6

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


(in millions)	Private Equity Securities			Hedge Funds		Timber Investments			Total
2009
Balance at January 1	$	53		$	1	$	9		$	63
Net realized and unrealized (losses)^(a)		(5	)		—		(2	)		(7	)
Purchases, sales and distributions, net		10			—		—			10

Balance at December 31	$	58		$	1	$	7		$	66

^(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 2011, we expect to make contributions of $300 million-$400 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 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $168, $176, $178, $189, $193 and $1,016, respectively. The expected benefit payments for the OPEB plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $45, $48, $51, $53, $56 and $306, 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 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $4, $5, $5, $6, $6 and $43, respectively.

In 2011, PEC expects to make contributions of $200 million-$250 million directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $86, $90, $89, $95, $96 and $476, respectively. The expected benefit payments for the OPEB plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $20, $22, $24, $26, $27 and $152, 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 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $2, $2, $3, $3, $3 and $22, respectively.

In 2011, PEF expects to make contributions of $100 million-$150 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 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $62, $65, $67, $69, $73 and $411, respectively. The expected benefit payments for the OPEB plan for 2011 through 2015 and in total for 2016 through 2020, in millions, are approximately $22, $22, $23, $24, $25 and $132, 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 2011 through 2015 and in total for 2016 through 2020, 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 has been 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 16A is adjusted as appropriate to reflect PEF’s rate treatment.

17. 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 13B 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 2011 and 2012. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled (See Note 7A). 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 $164 million and $146 million on the Progress Energy Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. At December 31, 2010, Progress Energy had 259.9 million MMBtu notional of natural gas and 20.2 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 and $7 million on the PEC Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. At December 31, 2010, PEC had 64.0 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 $140 million and $139 million on the PEF Balance Sheets at December 31, 2010 and 2009, respectively. At December 31, 2010, PEF had 195.9 million MMBtu notional of natural gas and 20.2 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, 2010, all open interest rate hedges will reach their mandatory termination dates within three years. 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. It is expected that in the next twelve months losses of $7 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $4 million at PEC. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in 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, 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, 2008, including amounts related to terminated hedges, we had $56 million of after-tax losses, including $35 million of after-tax losses at PEC, recorded in accumulated other comprehensive income related to forward starting swaps.

At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. During January 2011, Progress Energy terminated $300 million notional of forward starting swaps in conjunction with the issuance of debt (See Note 11A).

At December 31, 2009, Progress Energy had $325 million notional of open forward starting swaps, including $100 million at PEC and $75 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, 2010 and 2009, 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 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 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 at December 31, 2010, is $446 million, for which Progress Energy has posted collateral of $164 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at December 31, 2010, Progress Energy would have been required to post an additional $282 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 at December 31, 2010 is $118 million, 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 were triggered at December 31, 2010, PEC would have been required to post an additional $94 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 at December 31, 2010 is $328 million, for which PEF has posted collateral of $140 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on December 31, 2010, PEF would have been required to post an additional $188 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 (in millions)	2010				2009
Instrument / Balance sheet location (in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets	$	1			$	5
Other assets and deferred debits		3				14
Derivative liabilities, current			$	32			$	—
Derivative liabilities, long-term				7				—

Total derivatives designated as hedging instruments		4		39		19		—


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		11				11
Other assets and deferred debits		4				9
Derivative liabilities, current				226				189
Derivative liabilities, long-term				268				236
CVOs^(b)
Other liabilities and deferred credits				15				15

Fair value of derivatives not designated as hedging instruments		15		509		20		440
Fair value loss transition adjustment^(c)
Derivative liabilities, current				1				1
Derivative liabilities, long-term				3				4

Total derivatives not designated as hedging instruments		15		513		20		445

Total derivatives	$	19	$	552	$	39	$	445

^(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 (See Note 15).

^(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 (in millions)	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)
Instrument (in millions)	2010			2009		2008			2010			2009			2008			2010		2009			2008
Commodity cash flow derivatives	$	—		$	1	$	(2	)	$	—		$	—		$	—		$	—	$	—		$	—
Interest rate derivatives^{(c) (d)}		(34	)		15		(35	)		(6	)		(6	)		(3	)		3		(3	)		1

Total	$	(34	)	$	16	$	(37	)	$	(6	)	$	(6	)	$	(3	)	$	3	$	(3	)	$	1

^(a)	Effective portion.

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

^(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.

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

Derivatives Not Designated as Hedging Instruments


Instrument (in millions)	Realized Gain or (Loss)^(a)								Unrealized Gain or (Loss)^(b)
Instrument (in millions)	2010			2009			2008		2010			2009			2008
Commodity derivatives^(a)	$	(324	)	$	(659	)	$	174	$	(398	)	$	(387	)	$	(653	)

^(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 (in millions)	Amount of Gain or (Loss) Recognized in Income on Derivatives
Instrument (in millions)	2010		2009		2008
Commodity derivatives^(a)	$	—	$	1	$	(3	)
Fair value loss transition adjustment^(a)		1		2	$	3
CVOs^(a)		—		19		—

Total	$	1	$	22	$	—

^(a)	Amounts recorded in 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 (in millions)	2010				2009
Instrument / Balance sheet location (in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Other assets and deferred debits	$	3			$	8
Derivative liabilities, current			$	7			$	—
Other liabilities and deferred credits				4				—

Total derivatives designated as hedging instruments		3		11		8		—


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		1				—
Other assets and deferred debits		1				—
Derivative liabilities, current				45				28
Other liabilities and deferred credits				78				62

Fair value of derivatives not designated as hedging instruments		2		123		—		90
Fair value loss transition adjustment^(b)
Derivative liabilities, current				1				1
Other liabilities and deferred credits				3				4

Total derivatives not designated as hedging instruments		2		127		—		95

Total derivatives	$	5	$	138	$	8	$	95

^(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 (in millions)	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)
Instrument (in millions)	2010			2009		2008			2010			2009			2008			2010		2009			2008
Commodity cash flow derivatives	$	—		$	—	$	(1	)	$	—		$	—		$	—		$	—	$	—		$	—
Interest rate derivatives^{(c) (d)}		(10	)		5		(25	)		(4	)		(3	)		(1	)		—		(2	)		—

Total	$	(10	)	$	5	$	(26	)	$	(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 in the Consolidated Statements of Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments


Instrument (in millions)	Realized Gain or (Loss)^(a)								Unrealized Gain or (Loss)^(b)
Instrument (in millions)	2010			2009			2008		2010			2009			2008
Commodity derivatives	$	(46	)	$	(76	)		2	$	(77	)	$	(68	)	$	(110	)

^(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 (in millions)	Amount of Gain or (Loss) Recognized in Income on Derivatives
Instrument (in millions)	2010		2009		2008
Commodity derivatives^(a)	$	—	$	1	$	(3	)
Fair value loss transition adjustment^(a)		1		2	$	3

Total	$	1	$	3	$	—

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

PEF

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


Instrument / Balance sheet location (in millions)	2010				2009
Instrument / Balance sheet location (in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Prepayments and other current assets	$	—			$	5
Derivative liabilities, current			$	7			$	—

Total derivatives designated as hedging instruments		—		7		5		—


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		10				11
Other assets and deferred debits		3				9
Derivative liabilities, current				181				161
Derivative liabilities, long-term				190				174

Total derivatives not designated as hedging instruments		13		371		20		335

Total derivatives	$	13	$	378	$	25	$	335

^(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 (in millions)	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)
Instrument (in millions)	2010			2009		2008			2010		2009		2008		2010		2009		2008
Commodity cash flow derivatives	$	—		$	1	$	(1	)	$	—	$	—	$	—	$	—	$	—	$	—
Interest rate derivatives^{(c) (d)}		(7	)		3		8			—		—		—		—		—		1

Total	$	(7	)	$	4	$	7		$	—	$	—	$	—	$	—	$	—	$	1

^(a)	Effective portion.

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

^(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.

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

Derivatives Not Designated as Hedging Instruments


Instrument (in millions)	Realized Gain or (Loss)^(a)								Unrealized Gain or (Loss)^(b)
Instrument (in millions)	2010			2009			2008		2010			2009			2008
Commodity derivatives	$	(278	)	$	(583	)	$	172	$	(321	)	$	(319	)	$	(543	)

^(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.

18. RELATED PARTY TRANSACTIONS

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, 2010, the Parent had issued $473 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 2010, 2009 and 2008 to PEC amounted to $176 million, $170 million and $194 million, respectively, and services provided to PEF were $156 million, $147 million and $160 million, respectively. During 2010, PESC transferred a $24 million combustion turbine to PEC at cost (See Note 6).

PEC and PEF also provide and receive goods and services at cost. Goods and services provided by PEC to PEF during 2010, 2009 and 2008 amounted to $43 million, $36 million and $44 million, respectively. Goods and services provided by PEF to PEC during 2010, 2009 and 2008 amounted to $18 million, $12 million and $12 million, respectively.

PEC and PEF participate in an internal money pool, operated by Progress Energy, 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 0.30%, 0.74% and 3.29% for the years ended December 31, 2010, 2009 and 2008, respectively. Amounts payable to the money pool are included in notes payable to affiliated companies on the Balance Sheets. PEC and PEF recorded insignificant interest expense related to the money pool for all the years presented.

PEC and its wholly owned subsidiaries and PEF have entered into the Tax Agreement with the Parent (See Note 14).

19. 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, 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 (loss)		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 (loss)		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


At and for the year ended December 31, 2008
Revenues
Unaffiliated	$	4,429	$	4,730	$	8		$	—		$	9,167
Intersegment		—		1		361			(362	)		—

Total revenues		4,429		4,731		369			(362	)		9,167

Depreciation, amortization and accretion		518		306		15			—			839
Interest income		12		9		38			(35	)		24
Total interest charges, net		207		208		259			(35	)		639
Income tax expense (benefit)^(a)		298		181		(87	)		—			392
Ongoing Earnings (loss)		531		383		(138	)		—			776
Total assets		13,165		12,471		17,483			(13,246	)		29,873
Capital and investment expenditures		939		1,601		33			(13	)		2,560

^(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 is computed as GAAP net income attributable to controlling interests after excluding discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Management has identified the following Ongoing Earnings adjustments: CVO mark-to-market adjustments because we are unable to predict changes in their fair value 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 has determined that impairments, charges (and subsequent adjustments, if any) recognized for the retirement of generating units prior to the end of their estimated useful lives, cumulative prior period adjustments, net valuation allowances and operating results of discontinued operations are not representative of our ongoing operations and should be excluded 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)	2010			2009			2008
Ongoing Earnings	$	889		$	846		$	776
CVO mark-to-market (Note 15)		—			19			—
Impairment, net of tax benefit of $4 and $1		(6	)		(2	)		—
Plant retirement adjustment, net of tax benefit of $1 and $11		(1	)		(17	)		—
Change in tax treatment of the Medicare Part D subsidy (Note 16)		(22	)		—			—
Cumulative prior period adjustment related to certain employee life insurance benefits, net of tax benefit of $7		—			(10	)		—
Valuation allowance and related net operating loss carry forward		—			—			(3	)
Continuing income attributable to noncontrolling interests, net of tax		7			4			5

Income from continuing operations		867			840			778
Discontinued operations, net of tax		(4	)		(79	)		58
Net income attributable to noncontrolling interests, net of tax		(7	)		(4	)		(6	)

Net income attributable to controlling interests	$	856		$	757		$	830

20. OTHER INCOME AND OTHER EXPENSE

Other income and expense includes interest income; AFUDC equity, which represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets; and other, net. The components of other, net as shown on the accompanying Statements of Income are presented below. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities.

PROGRESS ENERGY


(in millions)	2010			2009			2008
Nonregulated energy and delivery services income, net	$	10		$	17		$	17
CVOs unrealized gain, net (Note 15)		—			19			—
Investment gains (losses), net		9			(9	)		(13	)
Donations		(23	)		(20	)		(25	)
Other, net		4			(1	)		4

Other, net	$	—		$	6		$	(17	)

PEC


(in millions)	2010			2009			2008
Nonregulated energy and delivery services income, net	$	—		$	6		$	11
Investment gains (losses), net		2			(21	)		—
Donations		(9	)		(10	)		(14	)
Other, net		7			7			7

Other, net	$	—		$	(18	)	$	4

PEF


(in millions)	2010			2009			2008
Nonregulated energy and delivery services income, net	$	11		$	11		$	8
Donations		(13	)		(10	)		(11	)
Investment gains, net		4			7			(9	)
Other, net		(3	)		(3	)		2

Other, net	$	(1	)	$	5		$	(10	)

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 provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the United States Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Note 7). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.

The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities’ coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. On June 21, 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in late 2011 or 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and

additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M 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 were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PROGRESS ENERGY


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2009	$	22		$	20		$	42
Amount accrued for environmental loss contingencies^(a)		8			13			21
Expenditures for environmental loss contingencies^(a)		(10	)		(18	)		(28	)

Balance, December 31, 2010^(b)	$	20		$	15		$	35


Balance, December 31, 2008	$	31		$	22		$	53
Amount accrued for environmental loss contingencies^(a)		3			13			16
Expenditures for environmental loss contingencies^(a)		(12	)		(15	)		(27	)

Balance, December 31, 2009^(b)	$	22		$	20		$	42

^(a)

Amounts accrued and expenditures are for the years ended December 31. For the year ended December 31, 2008, we accrued $8 million for the remediation of MGP and other sites and $17 million for the remediation of distribution and substation transformers. For the year ended December 31, 2008, we spent $8 million for the remediation of MGP and other sites and $28 million for the remediation of distribution and substation transformers.

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

PEC


(in millions)	MGP and Other Sites
Balance, December 31, 2009	$	13
Amount accrued for environmental loss contingencies^(a)		3
Expenditures for environmental loss contingencies^(a)		(4	)

Balance, December 31, 2010^(b)	$	12


Balance, December 31, 2008	$	16
Amount accrued for environmental loss contingencies^(a)		3
Expenditures for environmental loss contingencies^(a)		(6	)

Balance, December 31, 2009^(b)	$	13

^(a)	Amounts accrued and expenditures are for the years ended December 31. For the year ended December 31, 2008, PEC accrued and spent approximately $8 million.

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

Balance, December 31, 2010^(b)	$	8		$	15		$	23


Balance, December 31, 2008	$	15		$	22		$	37
Amount accrued for environmental loss contingencies^(a)		—			13			13
Expenditures for environmental loss contingencies^(a)		(6	)		(15	)		(21	)

Balance, December 31, 2009^(b)	$	9		$	20		$	29

^(a)	Amounts accrued and expenditures are for the years ended December 31. For the year ended December 31, 2008, PEF accrued approximately $17 million and spent approximately $28 million, which primarily related to distribution and substation transformers.

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

PROGRESS ENERGY

In addition to the Utilities’ sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 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, 2010 and December 31, 2009, PEC’s recorded liability for the site was approximately $5 million and $4 million, respectively. 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 also set a trial date for May 7, 2012. On June 15, 2010, the court entered a case management order and discovery is proceeding. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. In 2009, PEC and several of the other participating PRPs at the Ward site submitted a letter containing a good faith response to the EPA’s special notice letter. Another group of PRPs separately submitted a good faith response, which the EPA advised would be used to negotiate implementation of the required actions. The other PRPs’ good faith response was subsequently withdrawn. Discussions among representatives of certain PRPs, including PEC, and the EPA are ongoing. Although a loss is considered probable, an agreement among the PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.

PEF

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

PEF has received approval from the FPSC for recovery through the 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. At December 31, 2010 and December 31, 2009, PEF has recorded a regulatory asset for the probable recovery of costs through the ECRC related to the sites included under the agreement with the FDEP.

B. AIR AND WATER QUALITY

At December 31, 2010 and 2009, we were subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury regulation. PEC’s environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions have been placed in service. PEF’s CAIR projects have been placed in service.

In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court’s prior opinion. On August 2, 2010, the EPA published the proposed Transport Rule, which is the regulatory program that will replace the CAIR when finalized. The proposed Transport Rule contains new emissions trading programs for nitrogen oxides (NOx) and sulfur dioxide (SO₂) emissions as well as more stringent overall emissions targets. The EPA plans to finalize the Transport Rule in the spring of 2011. Due to significant investments in NOx and SO₂ emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are well positioned to comply with the Transport Rule. The outcome of the EPA’s rulemaking cannot be predicted. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, the current implementation of the CAIR continues to fulfill best available retrofit technology (BART) for NOx and SO₂

for BART-affected units under the CAVR. Should this determination change as the Transport Rule is promulgated, CAVR compliance eventually may require consideration of NOx and SO₂ emissions in addition to particulate matter emissions for BART-eligible units.

In 2008, the D.C. Court of Appeals vacated the CAMR. As a result, the EPA subsequently announced that it will develop a maximum achievable control technology (MACT) standard. The United States District Court for the District of Columbia has issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. In addition, North Carolina adopted a state-specific requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of these decisions. The outcome of this matter cannot be predicted.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5). The CR4 project was placed in service in May 2010 and the CR5 project was placed in service in December 2009. 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 7C, PEF identified in its 2010 nuclear cost-recovery filing regulatory and economic conditions causing schedule shifts such that major construction activities are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

The EPA is continuing to record allowance allocations under the CAIR NOx trading program, in some cases for years beyond the estimated 2011 finalization of the Transport Rule. The EPA’s continued recording of CAIR NOx allowance allocations does not guarantee that allowances will continue to be usable for compliance after a replacement rule is finalized or that they will continue to have value in the future. SO₂ emission allowances will be utilized to comply with existing Clean Air Act requirements. PEF’s CAIR expenses, including NOx allowance inventory expense, are recoverable through the ECRC. At December 31, 2010 and 2009, PEC had approximately $8 million and $13 million, respectively, in SO₂ emission allowances and an immaterial amount of NOx emission allowances. At December 31, 2010 and 2009, PEF had approximately $5 million and $7 million, respectively, in SO₂ emission allowances and approximately $28 million and $36 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, 2010, the following tables reflect contractual cash obligations and other commercial commitments in the respective periods in which they are due:

Progress Energy


(in millions)	2011		2012		2013		2014		2015		Thereafter		Total
Fuel^(a)	$	2,407	$	2,365	$	1,985	$	1,441	$	1,224	$	6,719	$	16,141
Purchased power		475		457		440		382		389		3,461		5,604
Construction obligations^(a)		507		230		122		51		55		14		979
Other purchase obligations		122		72		66		41		69		697		1,067

Total	$	3,511	$	3,124	$	2,613	$	1,915	$	1,737	$	10,891	$	23,791


*PEC*
(in millions)	2011		2012		2013		2014		2015		Thereafter		Total
Fuel	$	1,269	$	1,202	$	1,130	$	846	$	816	$	2,764	$	8,027
Purchased power		98		80		73		68		69		427		815
Construction obligations		450		199		75		8		—		—		732
Other purchase obligations		39		25		15		19		39		303		440

Total	$	1,856	$	1,506	$	1,293	$	941	$	924	$	3,494	$	10,014


*PEF*
(in millions)	2011		2012		2013		2014		2015		Thereafter		Total
Fuel^(a)	$	1,138	$	1,163	$	855	$	595	$	408	$	3,955	$	8,114
Purchased power		377		377		367		314		320		3,034		4,789
Construction obligations^(a)		57		31		47		43		55		14		247
Other purchase obligations		59		39		48		22		30		394		592

Total	$	1,631	$	1,610	$	1,317	$	974	$	813	$	7,397	$	13,742

^(a)

PEF signed an engineering, procurement and construction (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 $2.890 billion, $2.921 billion and $3.078 billion for 2010, 2009 and 2008, respectively. PEC’s total purchases under these commitments for its generating plants were $1.489 billion, $1.527 billion and $1.446 billion in 2010, 2009 and 2008, respectively. PEF’s purchases totaled $1.401 billion, $1.394 billion and $1.632 billion in 2010, 2009 and 2008, 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 for the planned Levy nuclear units. The construction schedule and startup dates were subsequently revised. (See discussion following under “Construction Obligations.”) This approximately $400 million contract (for fuel plus related core components), which is excluded from the previous table, is for the period from 2019 through 2033, and contains exit provisions with termination fees that vary based on the circumstance.

Both PEC and PEF have ongoing purchased power contracts, including renewable energy contracts, with certain co-generators, primarily qualified facilities (QFs), with expiration dates ranging from 2011 to 2030. These purchased power contracts generally provide for capacity and energy payments or bundled capacity and energy payments.

PEC executed two long-term tolling agreements for the purchase of all of the power generated from Broad River LLC’s Broad River facility. One agreement provides for the purchase of approximately 500 MW of capacity through May 2021 with average minimum annual payments of approximately $24 million, primarily representing capital-related capacity costs. The second agreement provides for the additional purchase of approximately 335 MW of capacity through February 2022 with average annual payments of approximately $24 million representing capital-related capacity costs. Total purchases for both capacity and energy under the Broad River LLC’s Broad River facility agreements amounted to $115 million, $46 million and $44 million in 2010, 2009 and 2008, respectively.

In 2007, PEC executed long-term agreements for the purchase of power from Southern Power Company. The agreements provide for firm unit capacity and energy purchases of 305 MW (68 percent of net output) for 2010, 310 MW (30 percent of net output) for 2011 and 150 MW (33 percent of net output) annually thereafter through 2019. Estimated payments for capacity under the agreements are approximately $25 million for 2011 and $12 million

annually thereafter through 2019. Total purchases for both capacity and energy under the agreements were $92 million in 2010.

PEC has various pay-for-performance contracts with QFs, including renewable energy, for approximately 31 MW of firm capacity expiring at various times through 2030. 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. Payments made under these contracts were $8 million, $24 million and $55 million in 2010, 2009 and 2008, respectively.

PEF has firm contracts for approximately 657 MW of purchased power with other utilities, including a contract with Southern Company for approximately 424 MW (25 percent of net output) of purchased power annually, which started in 2010 and extends into 2016. A contract with Southern Company for approximately 414 MW (12 percent of net output) of purchased power ended in 2010. Total purchases, for both energy and capacity, under agreements with other utilities amounted to $189 million, $149 million and $178 million for 2010, 2009 and 2008, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $64 million, $53 million, $46 million, $65 million and $65 million for 2011 through 2015, respectively, and $24 million payable thereafter.

PEF has ongoing purchased power contracts with certain QFs for 682 MW of firm capacity with expiration dates ranging from 2011 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. Total capacity and energy payments made under these contracts amounted to $469 million, $435 million and $440 million for 2010, 2009 and 2008, respectively. Minimum expected future capacity payments under these contracts are $300 million, $313 million, $309 million, $238 million and $244 million for 2011 through 2015, respectively, and $3.006 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.

In 2009, PEC executed a long-term coal transportation agreement by combining, amending and restating previous agreements with Norfolk Southern Railroad. This agreement will support PEC’s coal supply needs through June 2020. Expected future transportation payments under this agreement are $223 million, $235 million, $224 million, $213 million and $218 million for 2011 through 2015, respectively, with approximately $1.322 billion payable thereafter. Coal transportation expenses under these agreements were approximately $231 million and $283 million for 2010 and 2009, respectively. PEC’s state utility commissions allow fuel-related costs to be recovered through fuel cost-recovery clauses.

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 May 2011 through May 2033. The estimated total cost to PEC associated with these agreements is approximately $2.042 billion, approximately $426 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 approximately 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.

In April 2008, (and as amended in February 2009), PEF entered into a conditional contract with a pipeline entity for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with this agreement is estimated to be approximately $890 million. In addition to this contract, PEF has entered into additional gas transportation arrangements for the period from 2011 through 2036. The total current notional cost of these additional agreements is estimated to be approximately $281 million. All of these contracts are subject to conditions precedent, including the completion and commencement of operation of necessary related interstate natural gas pipeline system expansions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEF’s fuel commitments.

CONSTRUCTION OBLIGATIONS

We have purchase obligations related to various capital construction projects. Our total payments under these contracts were $703 million, $818 million and $1.018 billion for 2010, 2009 and 2008, 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 $555 million, $199 million and $140 million for 2010, 2009 and 2008, respectively. Payments for 2010 primarily relate to construction of generating facilities at our sites in Richmond County, N.C., Wayne County, N.C., and New Hanover County, N.C., as discussed in Note 7B.

PEF made payments of $63 million, $243 million and $117 million for 2010, 2009 and 2008, respectively, toward long lead equipment and engineering related to the Levy EPC. Additionally, PEF has other construction obligations related to various capital projects including new generation, transmission and environmental compliance. Total payments under PEF’s other construction-related contracts were $84 million, $376 million and $761 million for 2010, 2009 and 2008, respectively.

The future construction obligations presented in the previous tables for Progress Energy and PEF exclude the 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 7C in PEF’s 2010 nuclear cost-recovery filing, 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 combined license (COL) application will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work anticipated in the initial schedule cannot begin until the COL is issued, resulting in a project shift of at least 20 months. Since then, regulatory and economic conditions identified in the 2010 nuclear cost-recovery filing have changed such that major construction activities on the Levy project are being postponed until after the NRC issues the COL, 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. Prior to the 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 the timing of when those obligations will be satisfied or the magnitude of any change. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items, which have total remaining estimated payments and associated escalations of approximately $1.250 billion included in the previously discussed $8.608 billion. PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. In its April 30, 2010 nuclear cost-recovery filing, PEF included for rate-making purposes a point estimate of potential Levy disposition fees and charges of $50 million, subject to true-up. However, the amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed. 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 Richmond County, N.C., 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 $124 million, $56 million and $110 million for 2010, 2009 and 2008, respectively.

PEC has various other purchase obligations, including obligations for parts and equipment, limestone supply and fleet vehicles. Total purchases under these contracts were $55 million, $14 million and $18 million for 2010, 2009 and 2008, respectively.

On October 1, 2010, PEC entered into long-term service agreements for its Richmond County, N.C., Wayne County, N.C., and New Hanover County, N.C., generating facilities, covering projected maintenance events for each facility through 2033, 2028 and 2029, respectively. The total cost to PEC associated with these agreements is estimated to be approximately $379 million over the term of the agreements. Expected future payments under these agreements are $6 million, $7 million, $11 million, $16 million and $36 million for 2011 through 2015, respectively, with approximately $303 million payable thereafter. Total purchases under these agreements were not material for 2010.

Among PEF’s other purchase obligations, PEF has long-term service agreements for the Hines Energy Complex and the Bartow Plant, emission obligations and fleet vehicles. Total payments under these contracts were $35 million, $22 million and $58 million for 2010, 2009 and 2008, respectively. Future obligations are primarily comprised of the long-term service agreements.

B. LEASES

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates. 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 totaled $39 million, $37 million and $38 million for 2010, 2009 and 2008, respectively. Our purchased power expense under agreements classified as operating leases was approximately $61 million, $11 million and $152 million in 2010, 2009 and 2008, respectively.

PEC’s rent expense under operating leases totaled $25 million, $26 million and $26 million during 2010, 2009 and 2008, respectively. These amounts include rent expense allocated from PESC to PEC of $5 million in 2010, 2009 and 2008. Purchased power expense under agreements classified as operating leases was approximately $38 million, $11 million and $9 million in 2010, 2009 and 2008, respectively.

PEF’s rent expense under operating leases totaled $14 million, $11 million and $11 million during 2010, 2009 and 2008, respectively. These amounts include rent expense allocated from PESC to PEF of $3 million in 2010, 2009 and 2008. Purchased power expense under agreements classified as operating leases was approximately $23 million and $142 million in 2010 and 2008, respectively. PEF had no purchased power expense under operating lease agreements for 2009.

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


	Progress Energy						PEC						PEF
(in millions)	2010			2009			2010			2009			2010			2009
Buildings	$	267		$	267		$	30		$	30		$	237		$	237
Less: Accumulated amortization		(46	)		(37	)		(17	)		(15	)		(29	)		(22	)

Total	$	221		$	230		$	13		$	15		$	208		$	215

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, $26 million and $26 million for 2010, 2009 and 2008, respectively, which was primarily comprised of PEF’s capital lease expense of $23 million, $24 million and $24 million for 2010, 2009 and 2008, respectively.

At December 31, 2010, minimum annual payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable operating and capital leases were:


	Progress Energy					PEC					PEF
(in millions)	Capital			Operating		Capital			Operating		Capital			Operating
2011	$	28		$	37	$	2		$	23	$	26		$	10
2012		28			55		2			22		26			30
2013		36			80		10			43		26			35
2014		26			78		—			42		26			34
2015		25			77		—			43		25			33
Thereafter		227			866		6			515		221			350

Minimum annual payments		370			1,193		20			688		350			492

Less amount representing imputed interest		(149	)				(7	)				(142	)

Total	$	221		$	1,193	$	13		$	688	$	208		$	492

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 in the Consolidated Statements of Income.

In 2008, PEC entered into a 336-MW (100 percent of net output) tolling purchased power agreement, which is classified as an operating lease. The agreement calls for an approximately $18 million initial minimum payment with minimum annual payments from 2013 through 2032 escalating at a rate of 2.5 percent, for a total of approximately $460 million.

In 2009, PEC entered into a 240-MW (100 percent of net output) tolling purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $10 million from July 2012 through September 2017, for a total of approximately $52 million.

In 2007, PEF entered into a 632-MW (100 percent of net output) tolling purchased power agreement, which is classified as an operating lease. The agreement calls for minimum annual payments of approximately $28 million from June 2012 through May 2027, for a total of approximately $420 million.

In 2005, PEF entered into an agreement for a capital lease for a building completed during 2006. The lease term expires March 2047 and 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 lease, approximately $51 million of rental expense will be recorded in the Statements of Income.

In 2006, PEF extended the terms of a 517-MW (100 percent of net output) tolling agreement for purchased power, which is classified as a capital lease of the related plant, for an additional 10 years. The agreement calls for minimum annual payments of approximately $21 million from April 2007 through April 2024, for a total of approximately $348 million.

The Utilities are lessors of electric poles, streetlights and other facilities. PEC’s minimum rentals receivable under noncancelable leases were $11 million for 2011 and none thereafter. PEC’s rents received are contingent upon usage and totaled $33 million, $34 million, $33 million for 2010, 2009 and 2008, respectively. PEF’s rents received are based on a fixed minimum rental where price varies by type of equipment or contingent usage and totaled $85 million, $84 million and $81 million for 2010, 2009 and 2008, respectively. PEF’s minimum rentals receivable under noncancelable leases are not material for 2011 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,

2010, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Balance Sheets.

At December 31, 2010, 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, 2010, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $307 million, including $31 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. At December 31, 2010 and 2009, we had recorded liabilities related to guarantees and indemnifications to third parties of approximately $31 million and $34 million, respectively. These amounts included $6 million and $7 million for PEF at December 31, 2010 and 2009, respectively. During the year ended December 31, 2010, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

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

ENVIRONMENTAL

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

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 United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities on or before January 31, 1998. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. The Utilities have asserted nearly $91 million in damages incurred between January 31, 1998, and December 31, 2005, the time period set by the court for damages in this case. The Utilities may file subsequent damage claims as they incur additional costs.

In 2008, the Utilities received a ruling from the United States Court of Federal Claims awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. A request for reconsideration filed by the United States Department of Justice resulted in an immaterial reduction of the award. Substantially all of the award relates to costs incurred by PEC. On August 15, 2008, the Department of Justice appealed the United States Court of Federal Claims ruling to the D.C. Court of Appeals. On July 21, 2009, the D.C. Court of Appeals vacated and remanded the calculation of damages back to the Trial Court but affirmed the portion of damages awarded that were directed to overhead costs and other indirect expenses. The Department of Justice requested a rehearing en banc but the D.C. Court of Appeals denied the motion on November 3, 2009. In the event that the Utilities recover damages in this matter, such recovery will primarily offset capital assets and therefore is not expected to have a material impact on the Utilities’ results of operations. However, the Utilities cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000 (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); 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. 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. On December 17, 2010, we filed our initial appellate brief. 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.

NOTICE OF VIOLATION

On April 29, 2009, the EPA issued a notice of violation and opportunity to show cause with respect to a 16,000-gallon oil spill at one of PEC’s substations in 2007. The notice of violation did not include specified sanctions sought. Subsequently, the EPA notified PEC that the agency was seeking monetary sanctions that are de minimus to our and PEC’s results of operations or financial condition. PEC has entered into consent agreements with the EPA resolving all issues and requiring de minimus payment of penalties and performance.

FLORIDA NUCLEAR COST RECOVERY

On February 8, 2010, a lawsuit was filed against PEF in state circuit court in Sumter County, Fla., alleging that the Florida nuclear cost-recovery statute (Section 366.93, Florida Statutes) violates the Florida Constitution, and seeking a refund of all monies collected by PEF pursuant to that statute with interest. The complaint also requests that the court grant class action status to the plaintiffs. On April 6, 2010, PEF filed a motion to dismiss the complaint. The trial judge issued an order on May 3, 2010, dismissing the complaint. The plaintiffs filed an amended complaint on June 1, 2010. PEF believes the lawsuit is without merit and filed a motion to dismiss the amended complaint on July 12, 2010. On October 1, 2010, the plaintiffs filed an appeal of the trial court’s order dismissing the complaint. Initial and reply briefs have been filed by the appellants and PEF. The appellants filed their response brief on January 25, 2011. We cannot predict the outcome of this matter.

OTHER LITIGATION MATTERS

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

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, 2010, 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 11B, 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.

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

100

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

101

Condensed Consolidating Statement of Income

Year ended December 31, 2008


(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	4,738		$	4,429		$	—		$	9,167
Affiliate revenues		—			—			361			(361	)		—

Total operating revenues		—			4,738			4,790			(361	)		9,167

Operating expenses
Fuel used in electric generation		—			1,675			1,346			—			3,021
Purchased power		—			953			346			—			1,299
Operation and maintenance		3			813			1,346			(342	)		1,820
Depreciation, amortization and accretion		—			306			533			—			839
Taxes other than on income		—			309			207			(8	)		508
Other		—			1			(4	)		—			(3	)

Total operating expenses		3			4,057			3,774			(350	)		7,484

Operating (loss) income		(3	)		681			1,016			(11	)		1,683

Other income (expense)
Interest income		11			9			16			(12	)		24
Allowance for equity funds used during construction		—			95			27			—			122
Other, net		—			(18	)		(4	)		5			(17	)

Total other income, net		11			86			39			(7	)		129

Interest charges
Interest charges		201			263			227			(12	)		679
Allowance for borrowed funds used during construction		—			(28	)		(12	)		—			(40	)

Total interest charges, net		201			235			215			(12	)		639

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(193	)		532			840			(6	)		1,173
Income tax (benefit) expense		(85	)		172			306			2			395
Equity in earnings of consolidated subsidiaries		941			—			—			(941	)		—

Income from continuing operations		833			360			534			(949	)		778
Discontinued operations, net of tax		(3	)		61			—			—			58

Net income		830			421			534			(949	)		836
Net income attributable to noncontrolling interests, net of tax		—			(6	)		—			—			(6	)

Net income attributable to controlling interests	$	830		$	415		$	534		$	(949	)	$	830

102

Condensed Consolidating Balance Sheet

December 31, 2010


(in millions)	Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	10,189	$	10,961	$	90		$	21,240

Current assets
Cash and cash equivalents		110		270		231		—			611
Receivables, net		—		497		536		—			1,033
Notes receivable from affiliated companies		14		48		115		(177	)		—
Regulatory assets		—		105		71		—			176
Derivative collateral posted		—		140		24		—			164
Income taxes receivable		14		1		90		(53	)		52
Prepayments and other current assets		16		750		894		(220	)		1,440

Total current assets		154		1,811		1,961		(450	)		3,476

Deferred debits and other assets
Investment in consolidated subsidiaries		14,316		—		—		(14,316	)		—
Regulatory assets		—		1,387		987		—			2,374
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		554		1,017		—			1,571
Other assets and deferred debits		75		238		894		(469	)		738

Total deferred debits and other assets		14,391		2,179		2,898		(11,130	)		8,338

Total assets	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,023	$	4,957	$	5,686	$	(10,643	)	$	10,023
Noncontrolling interests		—		4		—		—			4

Total equity		10,023		4,961		5,686		(10,643	)		10,027

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		—		(36	)		273
Long-term debt, net		3,989		4,182		3,693		—			11,864

Total capitalization		14,012		9,486		9,438		(10,679	)		22,257

Current liabilities
Current portion of long-term debt		205		300		—		—			505
Notes payable to affiliated companies		—		175		3		(178	)		—
Derivative liabilities		18		188		53		—			259
Other current liabilities		278		1,002		1,184		(273	)		2,191

Total current liabilities		501		1,665		1,240		(451	)		2,955

Deferred credits and other liabilities
Noncurrent income tax liabilities		3		528		1,608		(443	)		1,696
Regulatory liabilities		—		1,084		1,461		90			2,635
Other liabilities and deferred credits		29		1,416		2,073		(7	)		3,511

Total deferred credits and other liabilities		32		3,028		5,142		(360	)		7,842

Total capitalization and liabilities	$	14,545	$	14,179	$	15,820	$	(11,490	)	$	33,054

103

Condensed Consolidating Balance Sheet

December 31, 2009


(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	9,733	$	9,886	$	114		$	19,733

Current assets
Cash and cash equivalents		606		72		47		—			725
Receivables, net		—		358		442		—			800
Notes receivable from affiliated companies		30		46		303		(379	)		—
Regulatory assets		—		54		88		—			142
Derivative collateral posted		—		139		7		—			146
Income taxes receivable		5		97		50		(7	)		145
Prepayments and other current assets		14		800		935		(176	)		1,573

Total current assets		655		1,566		1,872		(562	)		3,531

Deferred debits and other assets
Investment in consolidated subsidiaries		13,348		—		—		(13,348	)		—
Regulatory assets		—		1,307		873		(1	)		2,179
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		496		871		—			1,367
Other assets and deferred debits		166		202		923		(520	)		771

Total deferred debits and other assets		13,514		2,005		2,667		(10,214	)		7,972

Total assets	$	14,169	$	13,304	$	14,425	$	(10,662	)	$	31,236

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	9,449	$	4,590	$	5,085	$	(9,675	)	$	9,449
Noncontrolling interests		—		3		3		—			6

Total equity		9,449		4,593		5,088		(9,675	)		9,455

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		115		(152	)		272
Long-term debt, net		4,193		3,883		3,703		—			11,779

Total capitalization		13,642		8,819		8,965		(9,827	)		21,599

Current liabilities
Current portion of long-term debt		100		300		6		—			406
Short-term debt		140		—		—		—			140
Notes payable to affiliated companies		—		376		3		(379	)		—
Derivative liabilities		—		161		29		—			190
Other current liabilities		261		941		902		(182	)		1,922

Total current liabilities		501		1,778		940		(561	)		2,658

Deferred credits and other liabilities
Noncurrent income tax liabilities		—		320		1,258		(382	)		1,196
Regulatory liabilities		—		1,103		1,293		114			2,510
Other liabilities and deferred credits		26		1,284		1,969		(6	)		3,273

Total deferred credits and other liabilities		26		2,707		4,520		(274	)		6,979

Total capitalization and liabilities	$	14,169	$	13,304	$	14,425	$	(10,662	)	$	31,236

104

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	)
Cash distributions to noncontrolling interest		—			(3	)		—			(3	)		(6	)
Changes in advances from affiliated companies		—			(201	)		—			201			—
Contributions from parent		—			33			152			(185	)		—
Other financing activities		—			(11	)		(130	)		128			(13	)

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

105

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 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	)
Cash distributions to noncontrolling interests		—			(3	)		—			(3	)		(6	)
Changes in advances from affiliated companies		—			170			—			(170	)		—
Contributions from parent		—			653			49			(702	)		—
Other financing activities		(2	)		(9	)		12			13			14

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

106

Condensed Consolidating Statement of Cash Flows

Year ended December 31, 2008


(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash (used) provided by operating activities	$	(90	)	$	221		$	1,114		$	(27	)	$	1,218

Investing activities
Gross property additions		—			(1,553	)		(794	)		14			(2,333	)
Nuclear fuel additions		—			(43	)		(179	)		—			(222	)
Proceeds from sales of assets to affiliated companies		—			12			—			(12	)		—
Purchases of available-for-sale securities and other investments		(7	)		(783	)		(800	)		—			(1,590	)
Proceeds from available-for-sale securities and other investments		—			788			746			—			1,534
Changes in advances to affiliated companies		123			105			8			(236	)		—
Return of investment in consolidated subsidiaries		20			10			—			(30	)		—
Contributions to consolidated subsidiaries		(101	)		—			—			101			—
Other investing activities		—			57			13			—			70

Net cash provided (used) by investing activities		35			(1,407	)		(1,006	)		(163	)		(2,541	)

Financing activities
Issuance of common stock, net		132			—			—			—			132
Dividends paid on common stock		(642	)		—			—			—			(642	)
Dividends paid to parent		—			(33	)		—			33			—
Dividends paid to parent in excess of retained earnings		—			—			(20	)		20			—
Payments of short-term debt with original maturities greater than 90 days		(176	)		—			—			—			(176	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		629			—			—			—			629
Net increase in short-term debt		15			371			110			—			496
Proceeds from issuance of long-term debt, net		—			1,475			322			—			1,797
Retirement of long-term debt		—			(577	)		(300	)		—			(877	)
Cash distributions to noncontrolling interests		—			(85	)		(10	)		10			(85	)
Changes in advances from affiliated companies		—			(21	)		(215	)		236			—
Contributions from parent		—			85			29			(114	)		—
Other financing activities		—			1			(32	)		5			(26	)

Net cash (used) provided by financing activities		(42	)		1,216			(116	)		190			1,248

Net (decrease) increase in cash and cash equivalents		(97	)		30			(8	)		—			(75	)
Cash and cash equivalents at beginning of year		185			43			27			—			255

Cash and cash equivalents at end of year	$	88		$	73		$	19		$	—		$	180

107

24. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data was as follows:

Progress Energy


(in millions except per share data)	First		Second		Third		Fourth
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
2009
Operating revenues	$	2,442	$	2,312	$	2,824	$	2,307
Operating income		393		379		676		324
Income from continuing operations		183		175		350		132
Net income		183		174		248		156
Net income attributable to controlling interests		182		174		247		154
Common stock data
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax		0.66		0.62		1.24		0.46
Net income attributable to controlling interests		0.66		0.62		0.88		0.55
Dividends declared per common share		0.620		0.620		0.620		0.620
Market price per share
High		40.85		38.20		40.05		42.20
Low		31.35		33.50		35.97		36.67

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 2009, we recognized $102 million of expense from discontinued operations attributable to controlling interests, net of tax, primarily related to a jury delivering a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates previously engaged in coal-based solid synthetic fuels operations. In the fourth quarter of 2009, we recognized $25 million of earnings from discontinued operations primarily related to the tax benefits associated with the payment of the judgment. See Note 22D for additional information.

During the fourth quarter of 2009, we recorded a cumulative prior period adjustment related to certain employee life insurance benefits. The impact of this adjustment decreased total other income, net, by $17 million and decreased net income attributable to controlling interests by $10 million. The prior period adjustment is not material to 2009 or previously issued financial statements.

108

PEC

Summarized quarterly financial data was as follows:


(in millions)	First		Second		Third		Fourth
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
2009
Operating revenues	$	1,178	$	1,076	$	1,307	$	1,066
Operating income		249		182		367		168
Net income		128		94		208		84
Net income attributable to controlling interests		128		95		208		85

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.

During the fourth quarter of 2009, PEC recorded a cumulative prior period adjustment related to certain employee life insurance benefits. The impact of this adjustment decreased total other income, net, by $16 million and decreased net income attributable to controlling interests by $10 million. The prior period adjustment is not material to 2009 or previously issued financial statements.

PEF

Summarized quarterly financial data was as follows:


(in millions)	First		Second		Third		Fourth
2010
Operating revenues	$	1,270	$	1,252	$	1,543	$	1,189
Operating income		222		244		344		149
Net income		102		119		180		52
2009
Operating revenues	$	1,262	$	1,234	$	1,516	$	1,239
Operating income		140		195		314		153
Net income		89		119		177		77

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.

109

25. SUBSEQUENT EVENT – 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 continue as a wholly owned subsidiary of Duke Energy.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The Merger Agreement contemplates a reverse stock split of Duke Energy stock, effective immediately prior to the Merger. The board of directors of Duke Energy has approved a reverse stock split, at a ratio of 1-for-2 or 1-for-3, to be determined by the board of directors of Duke Energy after consultation with Progress Energy, which is subject to approval by the shareholders of Duke Energy and would be effective prior to the Merger. Accordingly, the 2.6125 exchange ratio for Progress Energy common shares, options and equity awards will be adjusted based on Duke Energy’s reverse stock split.

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 of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission, the SCPSC, the FPSC, the Indiana Utility Regulatory Commission, and the Ohio Public Utilities Commission.

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

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

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

Progress Energy shareholders have filed class action lawsuits in the state and federal courts in North Carolina against Progress Energy and each of the members of Progress Energy’s board of directors. The lawsuits seek to prohibit the Merger and, in some cases, seek damages in the event that the Merger is completed. Progress Energy intends to vigorously defend against these claims. We cannot predict the outcome of this matter.

Further information concerning the proposed merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4 to be filed by us with the SEC in connection with the Merger.

110

FINANCIAL STATEMENT SCHEDULE

Financial Statement Schedule Filed:

Consolidated Financial Statement Schedule for the Years Ended December 31, 2010, 2009 and 2008:

Schedule II – Valuation and Qualifying Accounts – Progress Energy, Inc.

PROGRESS ENERGY, INC.

Schedule II - Valuation and Qualifying Accounts

For the Years Ended December 31

(in millions)


Description	Balance at Beginning of Period		Additions Charged to Expenses		Other Additions			Deductions^(a)			Balance at End of Period

Valuation and qualifying accounts deducted on the balance sheet from the related assets:

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

2008
Uncollectible accounts	$	29	$	24	$	—		$	(35	)	$	18
Fossil fuel plants dismantlement reserve		144		1		—			—			145
Nuclear refueling outage reserve		2		12		—			—			14
Deferred tax asset valuation allowance		79		12		—			(36	)		55

^(a)	Deductions from valuation accounts represent write-offs, net of recoveries, or the release of valuation allowances.

^(b)	Includes $18 million related to other non-customer 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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the internal control over financial reporting of Progress Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and consolidated financial statement schedule as of and for the year ended December 31, 2010 of the Company, and our report dated February 28, 2011, expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina

February 28, 2011

113

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