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

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EX-99.2 - UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION - Duke Energy CORP	d253570dex992.htm
8-K - FORM 8-K - Duke Energy CORP	d253570d8k.htm

Exhibit 99.1

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

September 30, 2011

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME


	Three months ended September 30						Nine months ended September 30
(in millions except per share data)	2011			2010			2011			2010
Operating revenues	$	2,747		$	2,962		$	7,170		$	7,869

Operating expenses
Fuel used in electric generation		844			935			2,236			2,574
Purchased power		349			418			898			996
Operation and maintenance		487			474			1,491			1,459
Depreciation, amortization and accretion		175			201			508			680
Taxes other than on income		163			161			437			448
Other		39			20			31			25

Total operating expenses		2,057			2,209			5,601			6,182

Operating income		690			753			1,569			1,687

Other income (expense)
Interest income		1			3			2			6
Allowance for equity funds used during construction		22			22			77			68
Other, net		(70	)		(5	)		(60	)		(5	)

Total other (expense) income, net		(47	)		20			19			69

Interest charges
Interest charges		180			197			568			587
Allowance for borrowed funds used during construction		(8	)		(8	)		(26	)		(24	)

Total interest charges, net		172			189			542			563

Income from continuing operations before income tax		471			584			1,046			1,193
Income tax expense		178			219			386			456

Income from continuing operations before cumulative effect of change in accounting principle		293			365			660			737
Discontinued operations, net of tax		—			(2	)		(4	)		(2	)
Cumulative effect of change in accounting principle, net of tax		—			2			—			—

Net income		293			365			656			735
Net income attributable to noncontrolling interests, net of tax		(2	)		(4	)		(5	)		(4	)

Net income attributable to controlling interests	$	291		$	361		$	651		$	731

Average common shares outstanding – basic		296			294			296			289

Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	0.98		$	1.23		$	2.22		$	2.53
Discontinued operations attributable to controlling interests, net of tax		—			—			(0.02	)		—

Net income attributable to controlling interests	$	0.98		$	1.23		$	2.20		$	2.53

Dividends declared per common share	$	0.620		$	0.620		$	1.860		$	1.860

Amounts attributable to controlling interests
Income from continuing operations, net of tax	$	291		$	363		$	655		$	733
Discontinued operations, net of tax		—			(2	)		(4	)		(2	)

Net income attributable to controlling interests	$	291		$	361		$	651		$	731

See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


(in millions)	September 30, 2011			December 31, 2010
ASSETS
Utility plant
Utility plant in service	$	30,729		$	29,708
Accumulated depreciation		(11,905	)		(11,567	)

Utility plant in service, net		18,824			18,141
Other utility plant, net		222			220
Construction work in progress		2,233			2,205
Nuclear fuel, net of amortization		736			674

Total utility plant, net		22,015			21,240

Current assets
Cash and cash equivalents		103			611
Receivables, net		1,207			1,033
Inventory		1,376			1,226
Regulatory assets		180			176
Derivative collateral posted		112			164
Deferred tax assets		285			156
Prepayments and other current assets		162			110

Total current assets		3,425			3,476

Deferred debits and other assets
Regulatory assets		2,333			2,374
Nuclear decommissioning trust funds		1,512			1,571
Miscellaneous other property and investments		410			413
Goodwill		3,655			3,655
Other assets and deferred debits		327			325

Total deferred debits and other assets		8,237			8,338

Total assets	$	33,677		$	33,054

CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 295 million and 293 million shares issued and outstanding, respectively	$	7,414		$	7,343
Accumulated other comprehensive loss		(207	)		(125	)
Retained earnings		2,905			2,805

Total common stock equity		10,112			10,023

Noncontrolling interests		3			4

Total equity		10,115			10,027

Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		11,717			11,864

Total capitalization		22,198			22,257

Current liabilities
Current portion of long-term debt		950			505
Short-term debt		45			—
Accounts payable		895			994
Interest accrued		184			216
Dividends declared		185			184
Customer deposits		339			324
Derivative liabilities		303			259
Accrued compensation and other benefits		140			175
Other current liabilities		507			298

Total current liabilities		3,548			2,955

Deferred credits and other liabilities
Noncurrent income tax liabilities		2,310			1,696
Accumulated deferred investment tax credits		104			110
Regulatory liabilities		2,326			2,635
Asset retirement obligations		1,253			1,200
Accrued pension and other benefits		1,226			1,514
Derivative liabilities		255			278
Other liabilities and deferred credits		457			409

Total deferred credits and other liabilities		7,931			7,842

Commitments and contingencies (Notes 14 and 15)

Total capitalization and liabilities	$	33,677		$	33,054

See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS


(in millions) Nine months ended September 30	2011			2010
Operating activities
Net income	$	656		$	735
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		632			804
Deferred income taxes and investment tax credits, net		430			263
Deferred fuel credit		(11	)		(37	)
Allowance for equity funds used during construction		(77	)		(68	)
Other adjustments to net income		202			197
Cash (used) provided by changes in operating assets and liabilities
Receivables		(93	)		(252	)
Inventory		(152	)		111
Derivative collateral posted		52			(83	)
Other assets		(19	)		(25	)
Income taxes, net		20			213
Accounts payable		(40	)		45
Accrued pension and other benefits		(359	)		(162	)
Other liabilities		63			163

Net cash provided by operating activities		1,304			1,904

Investing activities
Gross property additions		(1,535	)		(1,643	)
Nuclear fuel additions		(134	)		(164	)
Purchases of available-for-sale securities and other investments		(4,536	)		(5,927	)
Proceeds from available-for-sale securities and other investments		4,509			5,915
Insurance proceeds		78			18
Other investing activities		43			(3	)

Net cash used by investing activities		(1,575	)		(1,804	)

Financing activities
Issuance of common stock, net		42			419
Dividends paid on common stock		(550	)		(535	)
Net increase (decrease) in short-term debt		45			(140	)
Proceeds from issuance of long-term debt, net		1,286			591
Retirement of long-term debt		(1,000	)		(400	)
Other financing activities		(60	)		(69	)

Net cash used by financing activities		(237	)		(134	)

Net decrease in cash and cash equivalents		(508	)		(34	)
Cash and cash equivalents at beginning of period		611			725

Cash and cash equivalents at end of period	$	103		$	691

Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	253		$	255

See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

INDEX TO APPLICABLE COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS BY REGISTRANT

Each of the following combined notes to the unaudited condensed interim financial statements of the Progress Registrants are applicable to Progress Energy, Inc. but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF. The notes that are not listed below for PEC or PEF are not, and shall not be deemed to be, part of PEC’s or PEF’s financial statements contained herein.


Registrant	Applicable Notes

PEC		1 through 9, 11, 12, 14 and 15

PEF		1 through 9, 11, 12, 14 and 15

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.	ORGANIZATION

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

PROGRESS ENERGY

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

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 13 for further information about our segments.

PEC

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

PEF

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

B.	BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2010 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2010 (2010 Form 10-K).

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants’ financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods.

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

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

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

The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the Statements of Income were as follows:


	Three months ended September 30				Nine months ended September 30
(in millions)	2011		2010		2011		2010
Progress Energy	$	96	$	101	$	245	$	265
PEC		33		34		86		91
PEF		63		67		159		174

C.	CONSOLIDATION OF VARIABLE INTEREST ENTITIES

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

PROGRESS ENERGY

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

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


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

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

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

PEC

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

PEF

PEF has no significant variable interests in VIEs.

2.	MERGER AGREEMENT

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

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

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

Shareholder Approval

•

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

Federal Regulatory Approvals

•

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

•

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

•

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

•

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

•

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

State Regulatory Approvals

•

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

these applications on September 20-22, 2011, and proposed orders and/or briefs must be filed by November 14, 2011.

•

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

•

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

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

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

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

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

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

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

3.	NEW ACCOUNTING STANDARDS

FAIR VALUE MEASUREMENT AND DISCLOSURES

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

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

GOODWILL IMPAIRMENT TESTING

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

4.	REGULATORY MATTERS

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

A.	PEC RETAIL RATE MATTERS

COST RECOVERY FILINGS

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

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

OTHER MATTERS

Construction of Generating Facilities

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

Planned Retirements of Generating Facilities

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

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

B.	PEF RETAIL RATE MATTERS

CR3 OUTAGE

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

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

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

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

developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments.

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

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

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


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

Balance for recovery	$	133	^(a)	$	45

^(a)

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

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

On October 25, 2010, the FPSC approved PEF’s motion to establish a separate spin-off docket to review the prudence and costs related to the outage and replacement fuel and power costs associated with the CR3 extended

outage. This docket will allow the FPSC to evaluate PEF’s actions concerning the concrete delamination and review PEF’s resulting costs associated with the extended outage. On June 27, 2011, PEF filed an updated status report with the NRC and FPSC regarding the CR3 outage. The FPSC held subsequent status conferences regarding the CR3 outage on July 14, 2011, and August 8, 2011.

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

We cannot predict the outcome of these matters.

COST OF REMOVAL RESERVE

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

FUEL COST RECOVERY

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

NUCLEAR COST RECOVERY

Levy Nuclear

Major construction activities on Levy have been postponed until after the NRC issues the combined license (COL) for the plants, which is expected in 2013 if the current licensing schedule remains on track. Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification;

public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF’s preferred baseload generation option.

CR3 Uprate

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

Cost Recovery

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

DEMAND-SIDE MANAGEMENT

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

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

OTHER MATTERS

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

5.	EQUITY AND COMPREHENSIVE INCOME

A.	EARNINGS PER COMMON SHARE

There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2011

and 2010. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial.

B.	RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of a subsidiary and a VIE (See Note 1C).

The following table presents changes in total equity for the year to date:


(in millions)	Total Common Stock Equity			Noncontrolling Interests			Total Equity
Balance, December 31, 2010	$	10,023		$	4		$	10,027
Net income^(a)		651			2			653
Other comprehensive loss		(82	)		—			(82	)
Issuance of shares through offerings and stock-based compensation plans (See Note 5D)		70			—			70
Dividends declared		(550	)		—			(550	)
Distributions to noncontrolling interests		—			(3	)		(3	)

Balance, September 30, 2011	$	10,112		$	3		$	10,115


Balance, December 31, 2009	$	9,449		$	6		$	9,455
Cumulative effect of change in accounting principle		—			(2	)		(2	)
Net income^(a)		731			1			732
Other comprehensive loss		(77	)		—			(77	)
Issuance of shares through offerings and stock-based compensation plans (See Note 5D)		461			—			461
Dividends declared		(543	)		—			(543	)
Distributions to noncontrolling interests		—			(2	)		(2	)

Balance, September 30, 2010	$	10,021		$	3		$	10,024

^(a)

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

PEC

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

PEF

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

C.	COMPREHENSIVE INCOME

PROGRESS ENERGY


	Three months ended September 30
(in millions)	2011			2010
Net income	$	293		$	365
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $1)		2			1
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $1 and $-)		2			1
Net unrealized losses on cash flow hedges (net of tax benefit of $44 and $19)		(69	)		(30	)
Net unrecognized items on pension and other postretirement benefits (net of tax benefit of $2)		—			(4	)
Other (net of tax expense of $-)		—			(1	)

Other comprehensive loss		(65	)		(33	)

Comprehensive income		228			332
Comprehensive income attributable to noncontrolling interests		(2	)		(4	)

Comprehensive income attributable to controlling interests	$	226		$	328


	Nine months ended September 30
(in millions)	2011			2010
Net income	$	656		$	735
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $3 and $3)		5			4
Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $3 and $1)		4			3
Net unrealized losses on cash flow hedges (net of tax benefit of $53 and $51)		(83	)		(80	)
Net unrecognized items on pension and other postretirement benefits (net of tax benefit of $5 and $2)		(8	)		(4	)

Other comprehensive loss		(82	)		(77	)

Comprehensive income		574			658
Comprehensive income attributable to noncontrolling interests		(5	)		(4	)

Comprehensive income attributable to controlling interests	$	569		$	654

PEC


	Three months ended September 30
(in millions)	2011			2010
Net income	$	199		$	236
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $1 and $1)		1			1
Net unrealized losses on cash flow hedges (net of tax benefit of $23 and $7)		(35	)		(10	)

Other comprehensive loss		(34	)		(9	)

Comprehensive income		165			227
Comprehensive income attributable to noncontrolling interests		—			(2	)

Comprehensive income attributable to controlling interests	$	165		$	225


	Nine months ended September 30
(in millions)	2011			2010
Net income	$	437		$	483
Other comprehensive income (loss)
Reclassification adjustments included in net income
Change in cash flow hedges (net of tax expense of $2 and $2)		3			3
Net unrealized losses on cash flow hedges (net of tax benefit of $26 and $17)		(40	)		(26	)

Other comprehensive loss		(37	)		(23	)

Comprehensive income		400			460
Comprehensive loss attributable to noncontrolling interests		—			1

Comprehensive income attributable to controlling interests	$	400		$	461

PEF


	Three months ended September 30
(in millions)	2011			2010
Net income	$	203		$	180
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $11 and $3)		(17	)		(6	)

Other comprehensive loss		(17	)		(6	)

Comprehensive income	$	186		$	174


	Nine months ended September 30
(in millions)	2011			2010
Net income	$	418		$	401
Other comprehensive loss
Net unrealized losses on cash flow hedges (net of tax benefit of $14 and $10)		(22	)		(16	)

Other comprehensive loss		(22	)		(16	)

Comprehensive income	$	396		$	385

D.	COMMON STOCK

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

The following table presents information for our common stock issuances:


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

6.	PREFERRED STOCK OF SUBSIDIARIES

All of our preferred stock was issued by the Utilities. The preferred stock is considered temporary equity due to certain provisions that could require us to redeem the preferred stock for cash. In the event dividends payable on PEC or PEF preferred stock are in default for an amount equivalent to or exceeding four quarterly dividend payments, the holders of the preferred stock are entitled to elect a majority of PEC’s or PEF’s respective board of directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities’ respective board of directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share plus any accumulated unpaid dividends except for PEF’s 4.75%, $100 par value class, which does not have a liquidation preference. Each holder of PEC’s preferred stock is entitled to one vote. The holders of PEF’s preferred stock have no right to vote except for certain circumstances involving dividends payable on preferred stock that are in default or certain matters affecting the rights and preferences of the preferred stock.

7.	DEBT AND CREDIT FACILITIES

Material changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2010, are as follows.

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

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

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

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

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

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

8.	FAIR VALUE DISCLOSURES

A.	DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

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

December 31, 2010, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities’ nuclear plants as discussed in Note 4C of the 2010 Form 10-K. Nuclear decommissioning trust (NDT) funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, we hold other debt investments in certain benefit trusts classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2011
Common stock equity	$	925	$	41	$	313
Preferred stock and other equity		50		1		8
Corporate debt		90		1		6
U.S. state and municipal debt		121		2		6
U.S. and foreign government debt		289		—		17
Money market funds and other		89		—		2

Total	$	1,564	$	45	$	352


December 31, 2010
Common stock equity	$	1,021	$	13	$	408
Preferred stock and other equity		28		—		11
Corporate debt		90		—		6
U.S. state and municipal debt		132		4		3
U.S. and foreign government debt		264		2		10
Money market funds and other		52		—		1

Total	$	1,587	$	19	$	439

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

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

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


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

Total	$	514

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


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

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

PEC

DEBT

The carrying amount of PEC’s long-term debt, including current maturities, was $4.193 billion and $3.693 billion at September 30, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.7 billion and $4.0 billion at September 30, 2011 and December 31, 2010, respectively.

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC’s nuclear plants as discussed in Note 4C of the 2010 Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value.

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2011
Common stock equity	$	599	$	27	$	198
Preferred stock and other equity		15		1		5
Corporate debt		72		1		5
U.S. state and municipal debt		53		—		3
U.S. and foreign government debt		213		—		16
Money market funds and other		41		—		1

Total	$	993	$	29	$	228


December 31, 2010
Common stock equity	$	652	$	10	$	256
Preferred stock and other equity		14		—		6
Corporate debt		72		—		5
U.S. state and municipal debt		51		1		1
U.S. and foreign government debt		199		1		9
Money market funds and other		42		—		1


Total	$	1,030	$	12	$	278

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

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

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


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

Total	$	349

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


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

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

PEF

DEBT

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

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF’s nuclear plant as discussed in Note 4C of the 2010 Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2011
Common stock equity	$	326	$	14	$	115
Preferred stock and other equity		35		—		3
Corporate debt		18		—		1
U.S. state and municipal debt		68		2		3
U.S. and foreign government debt		76		—		1
Money market funds and other		41		—		1

Total	$	564	$	16	$	124


December 31, 2010
Common stock equity	$	369	$	3	$	152
Preferred stock and other equity		14		—		5
Corporate debt		14		—		1
U.S. state and municipal debt		81		3		2
U.S. and foreign government debt		62		1		1
Money market funds and other		10		—		—

Total	$	550	$	7	$	161

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

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

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


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

Total	$	165

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


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

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

B.	FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, our and the Utilities’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PROGRESS ENERGY


(in millions)	Level 1		Level 2		Level 3		Total
September 30, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	925	$	—	$	—	$	925
Preferred stock and other equity		23		27		—		50
Corporate debt		—		90		—		90
U.S. state and municipal debt		1		118		—		119
U.S. and foreign government debt		100		188		—		288
Money market funds and other		—		40		—		40

Total nuclear decommissioning trust funds		1,049		463		—		1,512
Derivatives
Commodity forward contracts		—		7		—		7
Other marketable securities
Money market and other		18		7		—		25

Total assets	$	1,067	$	477	$	—	$	1,544


Liabilities
Derivatives
Commodity forward contracts	$	—	$	426	$	43	$	469
Interest rate contracts		—		86		—		86
Contingent value obligations		—		—		74		74

Total liabilities	$	—	$	512	$	117	$	629


(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,021	$	—	$	—	$	1,021
Preferred stock and other equity		22		6		—		28
Corporate debt		—		86		—		86
U.S. state and municipal debt		—		132		—		132
U.S. and foreign government debt		79		182		—		261
Money market funds and other		1		42		—		43

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

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


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

Total liabilities	$	—	$	512	$	36	$	548

PEC


(in millions)	Level 1		Level 2		Level 3		Total
September 30, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	599	$	—	$	—	$	599
Preferred stock and other equity		15		—		—		15
Corporate debt		—		72		—		72
U.S. state and municipal debt		1		52		—		53
U.S. and foreign government debt		89		124		—		213
Money market funds and other		—		40		—		40

Total nuclear decommissioning trust funds		704		288		—		992
Other marketable securities		3		—		—		3

Total assets	$	707	$	288	$	—	$	995


Liabilities
Derivatives
Commodity forward contracts	$	—	$	92	$	42	$	134
Interest rate contracts		—		43		—		43

Total liabilities	$	—	$	135	$	42	$	177


(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	652	$	—	$	—	$	652
Preferred stock and other equity		14		—		—		14
Corporate debt		—		72		—		72
U.S. state and municipal debt		—		51		—		51
U.S. and foreign government debt		76		123		—		199
Money market funds and other		1		28		—		29

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

Total assets	$	747	$	279	$	—	$	1,026


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

Total liabilities	$	—	$	98	$	36	$	134

PEF


(in millions)	Level 1		Level 2		Level 3		Total
September 30, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	326	$	—	$	—	$	326
Preferred stock and other equity		8		27		—		35
Corporate debt		—		18		—		18
U.S. state and municipal debt		—		66		—		66
U.S. and foreign government debt		11		64		—		75

Total nuclear decommissioning trust funds		345		175		—		520
Derivatives
Commodity forward contracts		—		7		—		7
Other marketable securities		1		—		—		1

Total assets	$	346	$	182	$	—	$	528


Liabilities
Derivatives
Commodity forward contracts	$	—	$	334	$	1	$	335
Interest rate contracts		—		8		—		8

Total liabilities	$	—	$	342	$	1	$	343


(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2010
Assets
Nuclear decommissioning trust funds
Common stock equity	$	369	$	—	$	—	$	369
Preferred stock and other equity		8		6		—		14
Corporate debt		—		14		—		14
U.S. state and municipal debt		—		81		—		81
U.S. and foreign government debt		3		59		—		62
Money market funds and other		—		14		—		14

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

Total assets	$	381	$	187	$	—	$	568


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

Total liabilities	$	—	$	378	$	—	$	378

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

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within

Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 12 for discussion of risk management activities and derivative transactions.

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

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

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

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

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

PROGRESS ENERGY


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

Derivatives, net at end of period	$	117	$	85	$	117	$	85

PEC


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

Derivatives, net at end of period	$	42	$	55	$	42	$	55

PEF


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

Derivatives, net at end of period	$	1	$	30	$	1	$	30

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

9.	INCOME TAXES

PROGRESS ENERGY

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

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

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

PEC

We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. PEC’s federal tax years are open for examination from 2007 forward, and PEC’s open state tax years in our major jurisdictions are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns.

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

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

PEF

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

At September 30, 2011 and December 31, 2010, PEF’s liability for unrecognized tax benefits was $87 million and $99 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $2 million at September 30, 2011.

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

10.

CONTINGENT VALUE OBLIGATIONS

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

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

11.

BENEFIT PLANS

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

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

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2011			2010			2011		2010
Service cost	$	13		$	12		$	3	$	3
Interest cost		35			35			10		13
Expected return on plan assets		(45	)		(40	)		—		(1	)
Amortization of actuarial loss^(a)		16			13			3		6
Other amortization, net ^(a)		2			2			1		1

Net periodic cost	$	21		$	22		$	17	$	22

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

PEC


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

Net periodic cost	$	6		$	6		$	8	$	10

PEF


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

Net periodic cost	$	10		$	12		$	8	$	11

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

PROGRESS ENERGY


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

Net periodic cost	$	63		$	65		$	50		$	43

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

PEC


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

Net periodic cost	$	18		$	20		$	23	$	21

PEF


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

Net periodic cost	$	29		$	32		$	24		$	19

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

As a result of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act, which were enacted in March 2010, we recognized an additional tax expense of $22 million,

including $12 million for PEC and $10 million for PEF, during the nine months ended September 30, 2010. See Note 16A in the 2010 Form 10-K.

12.

RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations.

A.	COMMODITY DERIVATIVES

GENERAL

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

ECONOMIC DERIVATIVES

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

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2011 and 2012. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

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

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $112 million and $164 million on the Progress Energy Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, Progress Energy had 339.4 million MMBtu notional of natural gas and 12.3 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases.

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

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

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

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates.

CASH FLOW HEDGES

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

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

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

FAIR VALUE HEDGES

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

C.	CONTINGENT FEATURES

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

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

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

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

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

D.	DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

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


Instrument / Balance sheet location	September 30, 2011				December 31, 2010
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	1			$	—
Interest rate derivatives
Prepayments and other current assets	$	—			$	1
Other assets and deferred debits		—				3
Derivative liabilities, current				70				32
Derivative liabilities, long-term				16				7

Total derivatives designated as hedging instruments		—		87		4		39


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		6				11
Other assets and deferred debits		1				4
Derivative liabilities, current				231				226
Derivative liabilities, long-term				237				268
CVOs^(b)
Other current liabilities				74				—
Other liabilities and deferred credits				—				15

Fair value of derivatives not designated as hedging instruments		7		542		15		509
Fair value loss transition adjustment^(c)
Derivative liabilities, current				1				1
Derivative liabilities, long-term				2				3

Total derivatives not designated as hedging instruments		7		545		15		513

Total derivatives	$	7	$	632	$	19	$	552

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

^(b)	As discussed in Note 10, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000.

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

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

Derivatives Designated as Hedging Instruments


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

Total	$	(69	)	$	(30	)	$	(2	)	$	(1	)	$	(1	)	$	—

^(a)	Effective portion.

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

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2011			2010
Commodity derivatives	$	(91	)	$	(114	)	$	(157	)	$	(181	)

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

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


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

Total	$	(62	)	$	1

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

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

Derivatives Designated as Hedging Instruments


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

Total	$	(83	)	$	(80	)	$	(5	)	$	(4	)	$	(3	)	$	—

^(a)	Effective portion.

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

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2011			2010
Commodity derivatives	$	(219	)	$	(264	)	$	(201	)	$	(417	)

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

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


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

Total	$	(57	)	$	1

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

PEC

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


Instrument / Balance sheet location	September 30, 2011				December 31, 2010
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Other assets and deferred debits	$	—			$	3
Derivative liabilities, current			$	35			$	7
Other liabilities and deferred credits				8				4

Total derivatives designated as hedging instruments		—		43		3		11


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets		—				1
Other assets and deferred debits		—				1
Derivative liabilities, current				57				45
Other liabilities and deferred credits				77				78

Fair value of derivatives not designated as hedging instruments		—		134		2		123
Fair value loss transition adjustment^(b)
Derivative liabilities, current				1				1
Other liabilities and deferred credits				2				3

Total derivatives not designated as hedging instruments		—		137		2		127

Total derivatives	$	—	$	180	$	5	$	138

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

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

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

Derivatives Designated as Hedging Instruments


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

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2011			2010
Commodity derivatives	$	(20	)	$	(17	)	$	(42	)	$	(38	)

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

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


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

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

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

Derivatives Designated as Hedging Instruments


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

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2011			2010
Commodity derivatives	$	(42	)	$	(36	)	$	(55	)	$	(82	)

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

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


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

Total	$	2	$	1

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

PEF

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


Instrument / Balance sheet location	September 30, 2011				December 31, 2010
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	1			$	—
Interest rate derivatives
Derivative liabilities, current				—				7
Derivative liabilities, long-term				8				—

Total derivatives designated as hedging instruments				9				7


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	6			$	10
Other assets and deferred debits		1				3
Derivative liabilities, current				174				181
Derivative liabilities, long-term				160				190

Total derivatives not designated as hedging instruments		7		334		13		371

Total derivatives	$	7	$	343	$	13	$	378

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

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

Derivatives Designated as Hedging Instruments


Instrument (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)	2011			2010			2011		2010		2011		2010
Commodity cash flow derivatives^(d)	$	(1	)	$	—		$	—	$	—	$	—	$	—
Interest rate derivatives^{(c) (e)}		(16	)		(6	)		—		—		—		—

Total	$	(17	)	$	(6	)	$	—	$	—	$	—	$	—

^(a)	Effective portion.

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

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2011			2010
Commodity derivatives	$	(71	)	$	(97	)	$	(115	)	$	(143	)

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

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

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

Derivatives Designated as Hedging Instruments


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

Total	$	(22	)	$	(16	)	$	—	$	—	$	—	$	—

^(a)	Effective portion.

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

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2011			2010			2011			2010
Commodity derivatives	$	(177	)	$	(228	)	$	(146	)	$	(335	)

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

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

13.

FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and PESC and other miscellaneous nonregulated businesses that do not separately meet the quantitative thresholds for disclosure as separate reportable business segments.

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


(in millions)	PEC		PEF		Corporate and Other			Eliminations			Totals
At and for the three months ended September 30, 2011
Revenues
Unaffiliated	$	1,332	$	1,413	$	2		$	—		$	2,747
Intersegment		—		1		69			(70	)		—

Total revenues		1,332		1,414		71			(70	)		2,747
Ongoing Earnings		202		202		(60	)		—			344
Total Assets		15,543		14,014		20,954			(16,834	)		33,677

For the three months ended September 30, 2010
Revenues
Unaffiliated	$	1,414	$	1,543	$	5		$	—		$	2,962
Intersegment		—		—		66			(66	)		—

Total revenues		1,414		1,543		71			(66	)		2,962
Ongoing Earnings		233		177		(49	)		—			361

For the nine months ended September 30, 2011
Revenues
Unaffiliated	$	3,525	$	3,637	$	8		$	—		$	7,170
Intersegment		—		2		203			(205	)		—

Total revenues		3,525		3,639		211			(205	)		7,170
Ongoing Earnings		453		454		(150	)		—			757

For the nine months ended September 30, 2010
Revenues
Unaffiliated	$	3,794	$	4,064	$	11		$	—		$	7,869
Intersegment		—		1		179			(180	)		—


Total revenues	3,794	4,065	190		(180	)	7,869
Ongoing Earnings	493	409	(146	)	—		756

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

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

		00000			00000
	For the three months ended September 30
(in millions)	2011			2010
Ongoing Earnings	$	344		$	361
Tax levelization		8			4
CVO mark-to-market, net of tax benefit of $13 (Note 10)		(50	)		—
Impairment, net of tax benefit of $1		—			(2	)
Merger and integration costs, net of tax benefit of $7 (Note 2)		(15	)		—
CR3 indemnification adjustment, net of tax expense of $2 (Note 15B)		4			—
Continuing income attributable to noncontrolling interests, net of tax		2			2

Income from continuing operations before cumulative effect of change in accounting principle		293			365
Discontinued operations, net of tax		—			(2	)
Cumulative effect of change in accounting principle, net of tax		—			2
Net income attributable to noncontrolling interests, net of tax		(2	)		(4	)

Net income attributable to controlling interests	$	291		$	361

		00000			00000
	For the nine months ended September 30
(in millions)	2011			2010
Ongoing Earnings	$	757		$	756
Tax levelization		2			3
CVO mark-to-market, net of tax benefit of $13 (Note 10)		(46	)		—
Impairment, net of tax benefit of $3		—			(5	)
Plant retirement adjustment, net of tax expense of $1		—			1
Change in tax treatment of the Medicare Part D subsidy (Note 11)		—			(22	)
Merger and integration costs, net of tax benefit of $11 (Note 2)		(36	)		—
CR3 indemnification charge, net of tax benefit of $16 (Note 15B)		(22	)		—
Continuing income attributable to noncontrolling interests, net of tax		5			4

Income from continuing operations		660			737

		00000			00000
Discontinued operations, net of tax		(4	)		(2	)
Net income attributable to noncontrolling interests, net of tax		(5	)		(4	)

Net income attributable to controlling interests	$	651		$	731

14.

ENVIRONMENTAL MATTERS

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

A.	HAZARDOUS AND SOLID WASTE

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

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

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

made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PROGRESS ENERGY


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2010	$	20		$	15		$	35
Amount accrued for environmental loss contingencies^(a)		1			6			7
Expenditures for environmental loss contingencies^(b)		(4	)		(13	)		(17	)

Balance, September 30, 2011^(c)	$	17		$	8		$	25


Balance, December 31, 2009	$	22		$	20		$	42
Amount accrued for environmental loss contingencies^(a)		7			11			18
Expenditures for environmental loss contingencies^(b)		(8	)		(14	)		(22	)

Balance, September 30, 2010^(c)	$	21		$	17		$	38

^(a)	Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, our accruals for environmental loss contingencies were not material.

^(b)

Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011, our expenditures for environmental loss contingencies were not material. For the three months ended September 30, 2010, our expenditures were not material for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.

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

PEC


(in millions)	MGP and Other Sites
Balance, December 31, 2010	$	12
Amount accrued for environmental loss contingencies^(a)		—
Expenditures for environmental loss contingencies^(b)		(1	)

Balance, September 30, 2011^(c)	$	11


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

Balance, September 30, 2010^(c)	$	12

^(a)	Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEC’s accruals for the remediation of MGP and other sites were not material.

^(b)	Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEC’s expenditures for the remediation of MGP and other sites were not material.

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

PEF


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2010	$	8		$	15		$	23
Amount accrued for environmental loss contingencies^(a)		1			6			7
Expenditures for environmental loss contingencies^(b)		(3	)		(13	)		(16	)

Balance, September 30, 2011^(c)	$	6		$	8		$	14


Balance, December 31, 2009	$	9		$	20		$	29
Amount accrued for environmental loss contingencies^(a)		4			11			15
Expenditures for environmental loss contingencies^(b)		(4	)		(14	)		(18	)

Balance, September 30, 2010^(c)	$	9		$	17		$	26

^(a)	Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEF’s accruals for environmental loss contingencies were not material.

^(b)

Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011, PEF’s expenditures were not material for the remediation of MGP and other sites and were $4 million for the remediation of distribution and substation transformers. For the three months ended September 30, 2010, PEF’s expenditures were not material for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.

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

PROGRESS ENERGY

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

PEC

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

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site in Raleigh, N.C. (Ward). The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At September 30, 2011 and December 31, 2010, PEC’s recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. In June 2010, the court entered a case management order and discovery is proceeding. The court also set a trial date for May 7, 2012. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation

and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. On September 29, 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. It is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.

PEF

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

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

B.	AIR AND WATER QUALITY

We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations include the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the CAIR.

In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court’s prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for NOx and sulfur dioxide (SO₂) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO₂ Group 1 trading program and the SO₂ Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO₂ annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO₂ emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO₂ emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals’ decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO₂for BART-affected units under the CAVR. Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of NOx and SO₂ emissions in addition to particulate matter emissions for PEF’s BART-eligible units, because Florida will no longer be subject to the annual emissions provisions. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. We are currently evaluating the impacts of the CSAPR.

In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it would develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On October 21, 2011, the EPA requested the U.S. District Court for the District of Columbia to extend the deadline for the final rule to December 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following the conclusion of the 90-day public comment period, the EPA has requested to issue a final rule in December 2011. In addition, North Carolina adopted a state-specific mercury requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of the EPA’s proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted.

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

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

15.

COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2010 Form 10-K are described below.

A.	PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2010 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities’

future needs. At September 30, 2011, our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2010 Form 10-K other than as follows:

PEC

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

PEF

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

B.	GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At September 30, 2011, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Balance Sheets.

At September 30, 2011, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At September 30, 2011, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $351 million, including $75 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. As part of settlement agreements entered into in 2002, PEF is responsible for providing the joint owners of CR3 a specified amount of generating capacity through the expiration of the indemnification provisions of the joint owner agreement in 2013. Due to the CR3 outage (See Note 4B), PEF has been unable to meet the required generating capacity and has provided replacement power from other generation sources or purchased power. During the nine months ended September 30, 2011, we and PEF recorded indemnification charges totaling $56 million for estimated joint owner replacement power costs for 2011 and future years, and provided replacement power totaling $17 million. At September 30, 2011 and December 31, 2010, we had recorded liabilities related to guarantees and indemnifications to third parties of $77 million and $31 million, respectively. These amounts included $50 million and $6 million for PEF at September 30, 2011 and December 31, 2010, respectively. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

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

C.	OTHER COMMITMENTS AND CONTINGENCIES

MERGER

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

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

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

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

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

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

On July 11, 2011, solely to avoid the costs, risks and uncertainties inherent in litigation and to allow its shareholders to vote on the proposals required in connection with the Merger at its special meeting of its shareholders, Progress Energy entered into a memorandum of understanding with plaintiffs in the consolidated state court actions and other named defendants to settle the consolidated action and all related claims that were or could have been asserted in

other actions, subject to court approval. If the court approves the settlement contemplated in the memorandum of understanding, the claims will be released and the consolidated amended complaint will be dismissed with prejudice. Pursuant to the terms of the memorandum of understanding, Progress Energy agreed to make available additional information to its shareholders in advance of the special meeting of shareholders of Progress Energy held on August 23, 2011, in Raleigh, N.C. to vote upon the proposal to approve the plan of merger contained in the Merger Agreement. The additional information was contained in a Current Report on Form 8-K dated July 11, 2011 and filed by Progress Energy with the SEC on July 15, 2011. In addition, Progress Energy has agreed to pay the legal fees and expenses of plaintiffs’ counsel not to exceed $550,000 and ultimately determined by the court. At a hearing on July 29, 2011, the court indicated that it would provide preliminary approval of the settlement so that the special meeting of the shareholders to vote on the merger could proceed as scheduled on August 23, 2011.

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

We cannot predict the outcome of these matters.

ENVIRONMENTAL

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

Hurricane Katrina

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

Water Discharge Permit

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

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities on or before January 31, 1998. The Utilities have asserted over $90 million in damages incurred between January 31, 1998, and December 31, 2005, the time period set by the court for damages in this case. The Utilities may file subsequent damage claims as they incur additional costs.

In 2008, the Utilities received a ruling from the United States Court of Federal Claims awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. A request for reconsideration filed by the DOJ resulted in an immaterial reduction of the award. Substantially all of the award relates to costs incurred by PEC. On August 15, 2008, the DOJ appealed the U.S. Court of Federal Claims ruling to the D.C. Court of Appeals. On July 21, 2009, the D.C. Court of Appeals vacated and remanded the calculation of damages back to the Trial Court but affirmed the portion of damages awarded that were directed to overhead costs and other indirect expenses. The DOJ requested a rehearing en banc but the D.C. Court of Appeals denied the motion on November 3, 2009. The U.S. Court of Federal Claims held the remand hearing on the calculation of damages on February 16, 2011. On June 14, 2011, the judge issued a ruling to award the Utilities substantially all their asserted damages. In September 2011, after the government dismissed its notice of appeal, the judgment became final. As a result, during the three months ended September 30, 2011, PEC recorded the $92 million award as an offset for past spent fuel storage costs incurred, of which $27 million was O&M expense.

SYNTHETIC FUELS MATTERS

On October 21, 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000 (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco; certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the expiration of the Internal Revenue Code Section 29 tax credit program on December 31, 2007, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

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

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

On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates’ declaratory judgment action. On August 7, 2003, the Wake County Superior Court denied Global’s motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court’s order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

FLORIDA NUCLEAR COST RECOVERY

On February 8, 2010, a lawsuit was filed against PEF in state circuit court in Sumter County, Fla., alleging that the Florida nuclear cost-recovery statute (Section 366.93, Florida Statutes) violates the Florida Constitution, and seeking a refund of all monies with interest collected by PEF pursuant to that statute. The complaint also requests that the court grant class action status to the plaintiffs. On April 6, 2010, PEF filed a motion to dismiss the complaint. The trial judge issued an order on May 3, 2010, dismissing the complaint. The plaintiffs filed an amended complaint on June 1, 2010. PEF believes the lawsuit is without merit and filed a motion to dismiss the amended complaint on July 12, 2010. On October 1, 2010, the plaintiffs filed an appeal of the trial court’s order dismissing the complaint. The court issued a per curiam affirmed opinion on May 17, 2011, which affirmed the trial court’s dismissal of the lawsuit. The appellants filed a motion for written opinion on May 20, 2011, which was denied by the appellate court on June 20, 2011. With this final ruling from the appellate court, the plaintiffs have no further appellate rights; therefore this ruling ends this class action litigation against PEF.

CLAIM OF HOLDER OF CONTINGENT VALUE OBLIGATIONS

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

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

OTHER LITIGATION MATTERS

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

16.

CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2010 Form 10-K, we have guaranteed certain payments of two 100 percent owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances, and as disclosed in Note 11B in the 2010 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a VIE of which we are not the primary beneficiary. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.

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

Condensed Consolidating Statement of Income

Three months ended September 30, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	1,415		$	1,332		$	—		$	2,747
Affiliate revenues		—			—			69			(69	)		—

Total operating revenues		—			1,415			1,401			(69	)		2,747

Operating expenses
Fuel used in electric generation		—			456			388			—			844
Purchased power		—			232			117			—			349
Operation and maintenance		2			221			332			(68	)		487
Depreciation, amortization and accretion		—			39			136			—			175
Taxes other than on income		—			106			58			(1	)		163
Other		—			1			38			—			39

Total operating expenses		2			1,055			1,069			(69	)		2,057

Operating (loss) income		(2	)		360			332			—			690

Other income (expense)
Interest income		—			—			1			—			1
Allowance for equity funds used during construction		—			7			15			—			22
Other, net		(63	)		(1	)		(5	)		(1	)		(70	)

Total other (expense) income, net		(63	)		6			11			(1	)		(47	)

Interest charges
Interest charges		80			56			45			(1	)		180
Allowance for borrowed funds used during construction		—			(4	)		(4	)		—			(8	)

Total interest charges, net		80			52			41			(1	)		172

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(145	)		314			302			—			471
Income tax (benefit) expense		(45	)		116			103			4			178
Equity in earnings of consolidated subsidiaries		391			—			—			(391	)		—

Income from continuing operations		291			198			199			(395	)		293
Discontinued operations, net of tax		—			1			(1	)		—			—

Net income		291			199			198			(395	)		293
Net income attributable to noncontrolling interests, net of tax		—			(1	)		—			(1	)		(2	)

Net income attributable to controlling interests	$	291		$	198		$	198		$	(396	)	$	291

Condensed Consolidating Statement of Income

Three months ended September 30, 2010


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	1,548		$	1,414		$	—		$	2,962
Affiliate revenues		—			—			66			(66	)		—

Total operating revenues		—			1,548			1,480			(66	)		2,962

Operating expenses
Fuel used in electric generation		—			471			464			—			935
Purchased power		—			309			109			—			418
Operation and maintenance		2			234			301			(63	)		474
Depreciation, amortization and accretion		—			77			124			—			201
Taxes other than on income		—			102			60			(1	)		161
Other		—			10			10			—			20

Total operating expenses		2			1,203			1,068			(64	)		2,209

Operating (loss) income		(2	)		345			412			(2	)		753

Other income (expense)
Interest income		2			1			2			(2	)		3
Allowance for equity funds used during construction		—			5			17			—			22
Other, net		—			(3	)		(3	)		1			(5	)

Total other income, net		2			3			16			(1	)		20

Interest charges
Interest charges		71			74			53			(1	)		197
Allowance for borrowed funds used during construction		—			(3	)		(5	)		—			(8	)

Total interest charges, net		71			71			48			(1	)		189

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(71	)		277			380			(2	)		584
Income tax (benefit) expense		(25	)		99			147			(2	)		219
Equity in earnings of consolidated subsidiaries		406			—			—			(406	)		—

Income from continuing operations before cumulative effect of change in accounting principle		360			178			233			(406	)		365
Discontinued operations, net of tax		1			(1	)		(2	)		—			(2	)
Cumulative effect of change in accounting principle, net of tax		—			—			2			—			2

Net income		361			177			233			(406	)		365
Net income attributable to noncontrolling interests, net of tax		—			(1	)		(2	)		(1	)		(4	)

Net income attributable to controlling interests	$	361		$	176		$	231		$	(407	)	$	361

Condensed Consolidating Statement of Income

Nine months ended September 30, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	3,645		$	3,525		$	—		$	7,170
Affiliate revenues		—			—			204			(204	)		—

Total operating revenues		—			3,645			3,729			(204	)		7,170

Operating expenses
Fuel used in electric generation		—			1,159			1,077			—			2,236
Purchased power		—			641			257			—			898
Operation and maintenance		6			655			1,026			(196	)		1,491
Depreciation, amortization and accretion		—			112			396			—			508
Taxes other than on income		—			274			168			(5	)		437
Other		—			(7	)		38			—			31

Total operating expenses		6			2,834			2,962			(201	)		5,601

Operating (loss) income		(6	)		811			767			(3	)		1,569

Other income (expense)
Interest income		—			1			1			—			2
Allowance for equity funds used during construction		—			24			53			—			77
Other, net		(59	)		5			(7	)		1			(60	)

Total other (expense) income, net		(59	)		30			47			1			19

Interest charges
Interest charges		216			204			149			(1	)		568
Allowance for borrowed funds used during construction		—			(11	)		(15	)		—			(26	)

Total interest charges, net		216			193			134			(1	)		542

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(281	)		648			680			(1	)		1,046
Income tax (benefit) expense		(100	)		240			243			3			386
Equity in earnings of consolidated subsidiaries		832			—			—			(832	)		—

Income from continuing operations		651			408			437			(836	)		660
Discontinued operations, net of tax		—			(2	)		(2	)		—			(4	)

Net income		651			406			435			(836	)		656
Net income attributable to noncontrolling interests, net of tax		—			(3	)		—			(2	)		(5	)

Net income attributable to controlling interests	$	651		$	403		$	435		$	(838	)	$	651

Condensed Consolidating Statement of Income

Nine months ended September 30, 2010


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	4,075		$	3,794		$	—		$	7,869
Affiliate revenues		—			—			179			(179	)		—

Total operating revenues		—			4,075			3,973			(179	)		7,869

Operating expenses
Fuel used in electric generation		—			1,252			1,322			—			2,574
Purchased power		—			761			235			—			996
Operation and maintenance		5			647			977			(170	)		1,459
Depreciation, amortization and accretion		—			311			369			—			680
Taxes other than on income		—			278			175			(5	)		448
Other		—			15			10			—			25

Total operating expenses		5			3,264			3,088			(175	)		6,182

Operating (loss) income		(5	)		811			885			(4	)		1,687

Other income (expense)
Interest income		6			1			5			(6	)		6
Allowance for equity funds used during construction		—			23			45			—			68
Other, net		(1	)		—			(7	)		3			(5	)

Total other income, net		5			24			43			(3	)		69

Interest charges
Interest charges		214			219			159			(5	)		587
Allowance for borrowed funds used during construction		—			(10	)		(14	)		—			(24	)

Total interest charges, net		214			209			145			(5	)		563

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(214	)		626			783			(2	)		1,193
Income tax (benefit) expense		(83	)		235			301			3			456
Equity in earnings of consolidated subsidiaries		861			—			—			(861	)		—

Income from continuing operations		730			391			482			(866	)		737
Discontinued operations, net of tax		1			—			(3	)		—			(2	)

Net income		731			391			479			(866	)		735
Net (income) loss attributable to noncontrolling interests, net of tax		—			(3	)		1			(2	)		(4	)

Net income attributable to controlling interests	$	731		$	388		$	480		$	(868	)	$	731

Condensed Consolidating Balance Sheet

September 30, 2011


(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	10,351	$	11,578	$	86		$	22,015

Current assets
Cash and cash equivalents		—		34		69		—			103
Receivables, net		—		630		577		—			1,207
Notes receivable from affiliated companies		97		27		138		(262	)		—
Regulatory assets		—		128		52		—			180
Derivative collateral posted		—		98		14		—			112
Prepayments and other current assets		131		816		1,062		(186	)		1,823

Total current assets		228		1,733		1,912		(448	)		3,425

Deferred debits and other assets
Investment in consolidated subsidiaries		14,196		—		—		(14,196	)		—
Regulatory assets		—		1,305		1,029		(1	)		2,333
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		520		992		—			1,512
Other assets and deferred debits		94		215		907		(479	)		737

Total deferred debits and other assets		14,290		2,040		2,928		(11,021	)		8,237

Total assets	$	14,518	$	14,124	$	16,418	$	(11,383	)	$	33,677

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,112	$	4,874	$	5,650	$	(10,524	)	$	10,112
Noncontrolling interests		—		3		—		—			3

Total equity		10,112		4,877		5,650		(10,524	)		10,115

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		—		(36	)		273
Long-term debt, net		3,542		4,482		3,693		—			11,717

Total capitalization		13,654		9,702		9,402		(10,560	)		22,198

Current liabilities
Current portion of long-term debt		450		—		500		—			950
Short-term debt		45		—		—		—			45
Notes payable to affiliated companies		—		259		3		(262	)		—
Derivative liabilities		35		175		93		—			303
Other current liabilities		318		1,015		1,104		(187	)		2,250

Total current liabilities		848		1,449		1,700		(449	)		3,548

Deferred credits and other liabilities
Noncurrent income tax liabilities		—		863		1,902		(455	)		2,310
Regulatory liabilities		—		796		1,443		87			2,326
Other liabilities and deferred credits		16		1,314		1,971		(6	)		3,295

Total deferred credits and other liabilities		16		2,973		5,316		(374	)		7,931

Total capitalization and liabilities	$	14,518	$	14,124	$	16,418	$	(11,383	)	$	33,677

Condensed Consolidating Balance Sheet

December 31, 2010


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

Current assets
Cash and cash equivalents		110		270		231		—			611
Receivables, net		—		497		536		—			1,033
Notes receivable from affiliated companies		14		48		115		(177	)		—
Regulatory assets		—		105		71		—			176
Derivative collateral posted		—		140		24		—			164
Prepayments and other current assets		30		751		984		(273	)		1,492

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

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

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

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

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

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

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

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

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

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

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

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

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

Condensed Consolidating Statement of Cash Flows

Nine months ended September 30, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	659		$	664		$	909		$	(928	)	$	1,304

Investing activities
Gross property additions		—			(624	)		(911	)		—			(1,535	)
Nuclear fuel additions		—			(13	)		(121	)		—			(134	)
Purchases of available-for-sale securities and other investments		—			(4,099	)		(437	)		—			(4,536	)
Proceeds from available-for-sale securities and other investments		—			4,101			408			—			4,509
Changes in advances to affiliated companies		(83	)		22			(23	)		84			—
Contributions to consolidated subsidiaries		(11	)		—			—			11			—
Other investing activities		(6	)		113			14			—			121

Net cash used by investing activities		(100	)		(500	)		(1,070	)		95			(1,575	)

Financing activities
Issuance of common stock, net		42			—			—			—			42
Dividends paid on common stock		(550	)		—			—			—			(550	)
Dividends paid to parent		—			(478	)		(450	)		928			—
Net increase in short-term debt		45			—			—			—			45
Proceeds from issuance of long-term debt, net		494			296			496			—			1,286
Retirement of long-term debt		(700	)		(300	)		—			—			(1,000	)
Changes in advances from affiliated companies		—			84			—			(84	)		—
Contributions from parent		—			10			1			(11	)		—
Other financing activities		—			(12	)		(48	)		—			(60	)

Net cash used by financing activities		(669	)		(400	)		(1	)		833			(237	)

Net decrease in cash and cash equivalents		(110	)		(236	)		(162	)		—			(508	)
Cash and cash equivalents at beginning of period		110			270			231			—			611

Cash and cash equivalents at end of period	$	—		$	34		$	69		$	—		$	103

Condensed Consolidating Statement of Cash Flows

Nine months ended September 30, 2010


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	23		$	872		$	1,205		$	(196	)	$	1,904

Investing activities
Gross property additions		—			(775	)		(893	)		25			(1,643	)
Nuclear fuel additions		—			(32	)		(132	)		—			(164	)
Purchases of available-for-sale securities and other investments		—			(5,461	)		(466	)		—			(5,927	)
Proceeds from available-for-sale securities and other investments		—			5,464			451			—			5,915
Changes in advances to affiliated companies		(24	)		(13	)		242			(205	)		—
Return of investment in consolidated subsidiaries		54			—			—			(54	)		—
Contributions to consolidated subsidiaries		(56	)		—			—			56			—
Other investing activities		—			16			—			(1	)		15

Net cash used by investing activities		(26	)		(801	)		(798	)		(179	)		(1,804	)

Financing activities
Issuance of common stock, net		419			—			—			—			419
Dividends paid on common stock		(535	)		—			—			—			(535	)
Dividends paid to parent		—			(102	)		(75	)		177			—
Dividends paid to parent in excess of retained earnings		—			—			(54	)		54			—
Net decrease in short-term debt		(140	)		—			—			—			(140	)
Proceeds from issuance of long-term debt, net		—			591			—			—			591
Retirement of long-term debt		(100	)		(300	)		—			—			(400	)
Changes in advances from affiliated companies		—			(205	)		—			205			—
Contributions from parent		—			33			37			(70	)		—
Other financing activities		—			(9	)		(69	)		9			(69	)

Net cash (used) provided by financing activities		(356	)		8			(161	)		375			(134	)

Net (decrease) increase in cash and cash equivalents		(359	)		79			246			—			(34	)
Cash and cash equivalents at beginning of period		606			72			47			—			725

Cash and cash equivalents at end of period	$	247		$	151		$	293		$	—		$	691

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