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

Attached files

file	filename
8-K - FORM 8-K - Duke Energy CORP	d350604d8k.htm
EX-99.2 - UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL INFORMATION - Duke Energy CORP	d350604dex992.htm

Exhibit 99.1

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

March 31, 2012

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME


(in millions except per share data) Three months ended March 31	2012			2011
Operating revenues	$	2,092		$	2,167

Operating expenses
Fuel used in electric generation		685			718
Purchased power		210			220
Operation and maintenance		529			494
Depreciation, amortization and accretion		166			154
Taxes other than on income		138			140
Other		—			(10	)

Total operating expenses		1,728			1,716

Operating income		364			451

Other income
Interest income		1			1
Allowance for equity funds used during construction		24			29
Other, net		13			3

Total other income, net		38			33

Interest charges
Interest charges		194			199
Allowance for borrowed funds used during construction		(9	)		(9	)

Total interest charges, net		185			190

Income from continuing operations before income tax		217			294
Income tax expense		76			107

Income from continuing operations		141			187
Discontinued operations, net of tax		11			(2	)

Net income		152			185
Net income attributable to noncontrolling interests, net of tax		(2	)		(1	)

Net income attributable to controlling interests	$	150		$	184

Average common shares outstanding – basic		297			295

Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	0.47		$	0.63
Discontinued operations attributable to controlling interests, net of tax		0.04			(0.01	)

Net income attributable to controlling interests	$	0.51		$	0.62

Dividends declared per common share	$	0.620		$	0.620

Net income amounts attributable to controlling interests
Income from continuing operations, net of tax	$	139		$	186
Discontinued operations, net of tax		11			(2	)

Net income attributable to controlling interests	$	150		$	184

Comprehensive income
Comprehensive income	$	157		$	189
Comprehensive income attributable to noncontrolling interests, net of tax		(2	)		(1	)

Comprehensive income attributable to controlling interests	$	155		$	188

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

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


(in millions)	March 31, 2012			December 31, 2011
ASSETS
Utility plant
Utility plant in service	$	31,284		$	31,065
Accumulated depreciation		(12,141	)		(12,001	)

Utility plant in service, net		19,143			19,064
Other utility plant, net		217			217
Construction work in progress		2,698			2,449
Nuclear fuel, net of amortization		747			767

Total utility plant, net		22,805			22,497

Current assets
Cash and cash equivalents		565			230
Receivables, net		758			889
Inventory, net		1,447			1,438
Regulatory assets		250			275
Derivative collateral posted		166			147
Deferred tax assets		518			371
Prepayments and other current assets		131			133

Total current assets		3,835			3,483

Deferred debits and other assets
Regulatory assets		3,123			3,025
Nuclear decommissioning trust funds		1,762			1,647
Miscellaneous other property and investments		413			407
Goodwill		3,655			3,655
Other assets and deferred debits		382			345

Total deferred debits and other assets		9,335			9,079

Total assets	$	35,975		$	35,059

CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 296 million and 295 million shares issued and outstanding, respectively	$	7,451		$	7,434
Accumulated other comprehensive loss		(160	)		(165	)
Retained earnings		2,718			2,752

Total common stock equity		10,009			10,021

Noncontrolling interests		2			4

Total equity		10,011			10,025

Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		11,742			11,718

Total capitalization		22,119			22,109

Current liabilities
Current portion of long-term debt		1,375			950
Short-term debt		1,056			671
Accounts payable		878			909
Interest accrued		193			200
Dividends declared		2			78
Customer deposits		343			340
Derivative liabilities		484			436
Accrued compensation and other benefits		127			195
Other current liabilities		304			306

Total current liabilities		4,762			4,085

Deferred credits and other liabilities
Noncurrent income tax liabilities		2,637			2,355
Accumulated deferred investment tax credits		101			103
Regulatory liabilities		2,684			2,700
Asset retirement obligations		1,282			1,265
Accrued pension and other benefits		1,611			1,625
Derivative liabilities		364			352
Other liabilities and deferred credits		415			465

Total deferred credits and other liabilities		9,094			8,865

Commitments and contingencies (Notes 13 and 14)

Total capitalization and liabilities	$	35,975		$	35,059

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

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS


(in millions) Three months ended March 31	2012			2011
Operating activities
Net income	$	152		$	185
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		200			199
Deferred income taxes and investment tax credits, net		107			101
Deferred fuel (credit) cost		(6	)		70
Allowance for equity funds used during construction		(24	)		(29	)
Other adjustments to net income		(7	)		56
Cash provided (used) by changes in operating assets and liabilities
Receivables		78			163
Inventory		(10	)		(49	)
Other assets		(48	)		7
Income taxes, net		(7	)		57
Accounts payable		23			(89	)
Accrued pension and other benefits		(33	)		(224	)
Other liabilities		(69	)		(1	)

Net cash provided by operating activities		356			446

Investing activities
Gross property additions		(562	)		(501	)
Nuclear fuel additions		(51	)		(57	)
Purchases of available-for-sale securities and other investments		(363	)		(1,817	)
Proceeds from available-for-sale securities and other investments		359			1,809
Other investing activities		65			46

Net cash used by investing activities		(552	)		(520	)

Financing activities
Issuance of common stock, net		3			8
Dividends paid on common stock		(260	)		(183	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		65			—
Net increase in short-term debt		320			79
Proceeds from issuance of long-term debt, net		444			494
Retirement of long-term debt		—			(700	)
Other financing activities		(41	)		(63	)

Net cash provided (used) by financing activities		531			(365	)

Net increase (decrease) in cash and cash equivalents		335			(439	)
Cash and cash equivalents at beginning of period		230			611

Cash and cash equivalents at end of period	$	565		$	172

Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	225		$	178

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

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 these Combined Notes. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

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 12 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (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, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).

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

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

Certain amounts for 2011 have been reclassified to conform to the 2012 presentation.

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

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


	Three months ended March 31
(in millions)	2012		2011
Progress Energy	$	69	$	73
PEC		26		28
PEF		43		45

C.	CONSOLIDATION OF VARIABLE INTEREST ENTITIES

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

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary for this VIE during 2011 or for the period ended March 31, 2012. 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)	March 31, 2012		December 31, 2011
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		1

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

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million for each of the three months ended March 31, 2012 and 2011. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

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

PEF

PEF has no significant variable interests in VIEs.

2.	MERGER AGREEMENT

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

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

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

Shareholder Approval

•

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

Federal Regulatory Approvals

•

Progress Energy and Duke Energy met their obligations under the Hart-Scott-Rodino Act with their March 28, 2011 filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. Because the merger was not anticipated to close before the April 26, 2012 expiration of the original filing, Progress Energy and Duke Energy filed a new Hart-Scott-Rodino filing on March 22, 2012, in order to be able to close the merger and continue to meet their obligations under the Hart-Scott-Rodino Act. 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 January 5, 2012, the Federal Communications Commission extended its approval of the Assignment of Authorization filings to transfer control of certain licenses. The extended approval expires on July 12, 2012.

•

On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC’s acceptance of market power mitigation measures to address the FERC’s finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina wholesale power markets. Progress Energy and Duke Energy filed a market power mitigation plan with the FERC on October 17, 2011, that proposed a “virtual divestiture” under which power up to a certain amount would have been offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. On December 14, 2011, the FERC affirmed its conditional approval of the merger, but the FERC rejected the proposed market power mitigation plan. On March 26, 2012, Progress Energy and Duke Energy filed a second market power mitigation plan with the FERC. The revised mitigation plan consists of both interim and permanent components. The two- to three-year interim component consists of several power purchase agreements whereby the companies propose to sell capacity and firm energy during the summer (June – August) and winter (December – February) to new market participants. Together, the companies would sell 800 megawatts (MWs) during summer off-peak hours, 475 MWs during summer peak hours, 225 MWs during winter off-peak hours, and 25 MWs during winter peak hours. The agreements have been executed, contingent on the closing of the merger, and will be in effect upon the closing of the merger and remain in effect until the permanent component is operational. The permanent component consists of seven transmission projects to be constructed, estimated to cost approximately $110 million. The transmission projects significantly increase power import capabilities into the PEC and Duke Energy Carolinas service territories and enhance competitive power supply options for the region. Progress Energy and Duke Energy have requested that the FERC issue orders approving the revised mitigation plan within 60 days of the filing date, but no later than June 8, 2012. There is no statutory requirement that the FERC act within a specified timeframe. On April 10, 2012, Progress Energy and Duke Energy received a request from the FERC for additional information on the transmission-related models provided by Progress Energy and Duke Energy in the revised mitigation plan. On April 13, 2012, Progress Energy and Duke Energy responded to the FERC’s request. In the response, the companies reaffirmed their request that the FERC approve the revised mitigation plan within 60 days of the original filing date, but no later than June 8, 2012. Four participants to the proceedings filed comments before the April 25, 2012 filing deadline. On May 1, 2012, the companies filed a response to the comments with the FERC. The companies are working with the North Carolina Public Staff and the South Carolina Office of Regulatory Staff (ORS) on appropriate state ratemaking treatment associated with the measures in the revised market mitigation plan and other merger-related issues. The companies’ decision to close the merger will be subject to the companies obtaining acceptable resolution of various state ratemaking issues.

•

On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a joint dispatch agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the merger. The second filing is a joint open access transmission tariff (OATT) pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate. On December 14, 2011, in conjunction with the aforementioned decision on the proposed market power mitigation plan, the FERC dismissed the applications for approval of the joint dispatch agreement and the joint OATT without prejudice. As allowed under the FERC’s December 14, 2011 order, Progress Energy and Duke Energy refiled the joint dispatch agreement and OATT with the FERC on March 26, 2012.

•

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

State Regulatory Approvals

•

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

•

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

•

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

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

Certain substantial changes in ownership of Progress Energy, including the merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 15 in the 2011 Form 10-K).

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

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 offered a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the merger. Approximately 650 employees requested and were approved for separation under the VSP in 2011. The cost of the VSP is estimated to be between $90 million to $100 million, including $65 million to $70 million for PEC and $25 million to $30 million for PEF. If the employee is not required to work for a significant period after the consummation of the merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the merger. If a significant retention period exists, the costs of benefits equal to what would be paid under our existing severance plan will be measured and recorded upon consummation of the merger. Any additional benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the merger and formulated an exit plan to vacate one of our corporate headquarters buildings. We have begun to gradually vacate the premises and will be fully vacated by January 1, 2013. In December 2011, we executed an agreement with a third party to sublease the building until 2035. The estimated exit cost liability associated with this exit plan is $17 million for us, of which $12 million of expense is attributable to PEC and $5 million to PEF. The exit cost liability will be recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. During the first quarter of 2012, we recorded exit cost liabilities of $3 million for us, of which $2 million of expense is attributable to PEC and $1 million to PEF. At March 31, 2012, the total exit cost liability recorded by us is $8 million, of which $6 million of expense is attributable to PEC and $2 million of expense is attributable to PEF. These costs are included in merger and integration-related costs.

We incurred merger and integration-related costs of $5 million, net of tax, including $3 million, net of tax, and $2 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2012. We incurred merger and integration-related costs of $14 million, net of tax, including $7 million, net of tax, and $7 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2011. These costs are included in operations and maintenance (O&M) expense in our Consolidated Statements of Comprehensive Income.

3.	NEW ACCOUNTING STANDARDS

FAIR VALUE MEASUREMENT AND DISCLOSURES

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends Accounting Standards Codification (ASC) 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 was effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 resulted in additional 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.

GOODWILL IMPAIRMENT TESTING

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

DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES

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

4.	DIVESTITURES

We have completed our business strategy of divesting nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. Included in discontinued operations, net of tax are amounts related to adjustments of our prior sales of diversified businesses. These adjustments are generally due to guarantees and indemnifications provided for certain legal, tax and environmental matters. See Note 14B for further discussion of our guarantees. The ultimate resolution of these matters could result in additional adjustments in future periods.

During the three months ended March 31, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $11 million and $(2) million, respectively. Earnings for the three months ended March 31, 2012, relates primarily to an $18 million pre-tax gain from the reversal of certain environmental indemnification liabilities for which the indemnification period has expired.

5.	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 March 1, 2012, PEC filed with the SCPSC for a $5 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate, driven by the introduction of new, and the expansion of existing, DSM and EE programs. If approved, the increase will be effective July 1, 2012, and will increase residential electric bills by $1.37 per 1,000 kilowatt-hours (kWh). We cannot predict the outcome of this matter.

B.	PEF RETAIL RATE MATTERS

CR3 OUTAGE

In September 2009, Crystal River Nuclear Plant Unit 3 (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators.

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

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

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

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

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accident 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 March 31, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. PEF also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. PEF has not yet received a definitive determination from NEIL about the insurance coverage related to the second delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, PEF has not recorded insurance receivables from NEIL related to the second delamination. Negotiations continue with NEIL regarding coverage associated with the second delamination, and PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

The following table summarizes the CR3 replacement power and repair costs and recovery through March 31, 2012:


(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	506		$	279
NEIL proceeds received to date		(162	)		(143	)
Insurance receivable at March 31, 2012, net		(55	)		—

Balance for recovery^(a)	$	289		$	136

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

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

2012 SETTLEMENT AGREEMENT

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

Levy

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

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

CR3

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

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

PEF also retains sole discretion and flexibility to retire the unit without challenge from the parties to the agreement. If PEF decides to retire CR3, PEF is allowed to recover all remaining CR3 investments and to earn a return on the CR3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity (ROE) set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. Additionally, any NEIL proceeds received after the settlement will be applied first to replacement power costs incurred after December 31, 2012, with the remainder used to write down the remaining CR3 investments.

Base Rates, Customer Refund and Other Terms

Under the terms of the 2012 settlement agreement, PEF will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million annual increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5 percent. PEF suspended depreciation expense and reversed certain regulatory liabilities associated with CR3 effective on the February 22, 2012 implementation date of the agreement, resulting in a $47 million benefit for the quarter ended March 31, 2012, which reduced O&M expense. Additionally, rate base associated with CR3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. PEF will accrue, for future rate-setting purposes, a carrying charge at a rate of 7.4 percent on the CR3 investment until CR3 is returned to service and placed back into retail rate base. Upon return of CR3 to commercial service, PEF will be authorized to increase its base rates for the annual revenue requirements of all CR3 investments. The parties to the agreement reserve the right to participate in any hearings challenging the appropriateness of PEF’s CR3 revenue requirements. In the month following CR3’s return to commercial service, PEF’s ROE range will increase to 9.7 percent to 11.7 percent. If PEF’s retail base rate earnings fall below the ROE range, as reported on a FPSC-adjusted or pro-forma basis on a PEF monthly earnings surveillance report, PEF may petition the FPSC to amend its base rates during the term of the agreement.

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

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

The 2012 settlement agreement provides for PEF to continue to recover carrying costs and other nuclear cost recovery clause-recoverable items related to the CR3 uprate project, but PEF will not seek an in-service recovery

until nine months following CR3’s return to commercial service. Carrying costs will be recovered through the nuclear cost recovery clause until base rates have been increased for these assets.

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

COST OF REMOVAL RESERVE

The 2012 and 2010 settlement agreements provide PEF the discretion to reduce amortization expense (cost of removal component) by up to the balance in the cost of removal reserve until the earlier of (a) PEF’s applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 settlement agreement at the end of 2016. For the three months ended March 31, 2012, PEF recognized a $58 million reduction in amortization expense pursuant to the settlement agreements. PEF had eligible cost of removal reserves of $216 million remaining at March 31, 2012, which is impacted by accruals in accordance with PEF’s latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreements.

NUCLEAR COST RECOVERY

Levy Nuclear

In 2008, the FPSC granted PEF’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule for PEF’s proposed Levy project, together with the associated facilities, including transmission lines and substation facilities.

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

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 and accepted for review by the NRC on November 21, 2011.

Cost Recovery

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

DEMAND-SIDE MANAGEMENT COST RECOVERY

On July 26, 2011, the FPSC voted to set PEF’s DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener filed a protest to the FPSC’s Proposed Agency Action order, asserting legal challenges to the order. The parties made legal arguments to the FPSC and the FPSC issued an order denying the protest on December 22, 2011. The intervener then filed a notice of appeal of this order to the Florida Supreme Court on January 17, 2012. We cannot predict the outcome of this matter.

OTHER MATTERS

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

6.	EQUITY

A.	EARNINGS PER COMMON SHARE

There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three months ended March 31, 2012 and 2011. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial.

B.	RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests 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, 2011	$	10,021		$	4		$	10,025
Net income^(a)		150			—			150
Other comprehensive income		5			—			5
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)		17			—			17
Dividends declared		(184	)		—			(184	)
Distributions to noncontrolling interests		—			(2	)		(2	)

Balance, March 31, 2012	$	10,009		$	2		$	10,011


Balance, December 31, 2010	$	10,023		$	4		$	10,027
Net income^(a)		184			(1	)		183
Other comprehensive income		4			—			4
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)		19			—			19
Dividends declared		(183	)		—			(183	)
Distributions to noncontrolling interests		—			(2	)		(2	)
Other		—			2			2

Balance, March 31, 2011	$	10,047		$	3		$	10,050

^(a)

For the three months ended March 31, 2012, consolidated net income of $152 million includes $2 million attributable to preferred shareholders of subsidiaries. For the three months ended March 31, 2011, consolidated net income of $185 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

PEC

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

PEF

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

C.	COMMON STOCK

At March 31, 2012 and December 31, 2011, we had 500 million shares of common stock authorized under our charter, of which 296 million and 295 million shares were outstanding, respectively. We periodically issue shares of common stock through the Progress Energy Investor Plus Plan (IPP), equity incentive plans and other benefit plans.

The following table presents information for our common stock issuances:


	Three months ended March 31
	2012				2011
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Total issuances		0.8	$	3		1.0	$	8
Issuances through IPP		—		—		—		1

7.	PREFERRED STOCK OF SUBSIDIARIES

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

8.	DEBT AND CREDIT FACILITIES

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

On February 15, 2012, the Parent’s $478 million revolving credit agreement was amended to extend the expiration date from May 3, 2012, to May 3, 2013, with its existing syndication of 14 financial institutions. Our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions.

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

9.	FAIR VALUE DISCLOSURES

A.	DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $13.390 billion and $12.941 billion at March 31, 2012 and December 31, 2011, respectively. The estimated fair value of this debt was $15.4 billion and $15.3 billion at March 31, 2012 and December 31, 2011, respectively, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities’ nuclear plants as discussed in Note 5C in the 2011 Form 10-K. Nuclear decommissioning trust (NDT) funds are presented on the Consolidated Balance Sheets at fair value.

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity	$	1,160	$	16	$	508
Preferred stock and other equity		43		—		14
Corporate debt		90		—		7
U.S. state and municipal debt		124		2		7
U.S. and foreign government debt		293		—		14
Money market funds and other		55		1		1

Total	$	1,765	$	19	$	551


December 31, 2011
Common stock equity	$	1,033	$	29	$	401
Preferred stock and other equity		29		—		11
Corporate debt		86		—		6
U.S. state and municipal debt		128		2		7
U.S. and foreign government debt		284		—		18
Money market funds and other		70		—		1

Total	$	1,630	$	31	$	444

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

The aggregate fair value of investments that related to the 2012 and 2011 unrealized losses was $155 million and $136 million, respectively.

At March 31, 2012, the fair value of our available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	34
Due after one through five years		217
Due after five through 10 years		175
Due after 10 years		94

Total	$	520

The following table presents selected information about our sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.


(in millions)	2012		2011
Proceeds	$	304	$	1,744
Realized gains		7		9
Realized losses		3		4

PEC

DEBT

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

INVESTMENTS

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity	$	755	$	11	$	322
Preferred stock and other equity		20		—		9
Corporate debt		75		—		6
U.S. state and municipal debt		53		—		3
U.S. and foreign government debt		229		—		13
Money market funds and other		34		1		1

Total	$	1,166	$	12	$	354


December 31, 2011
Common stock equity	$	673	$	20	$	255
Preferred stock and other equity		17		—		7
Corporate debt		69		—		5
U.S. state and municipal debt		56		—		3
U.S. and foreign government debt		226		—		16
Money market funds and other		60		—		1

Total	$	1,101	$	20	$	287

The aggregate fair value of investments that related to the March 31, 2012 and December 31, 2011 unrealized losses was $99 million and $98 million, respectively.

At March 31, 2012, the fair value of PEC’s available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	11
Due after one through five years		191
Due after five through 10 years		100
Due after 10 years		65



Total	$	367

The following table presents selected information about PEC’s sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.


(in millions)	2012		2011
Proceeds	$	130	$	131
Realized gains		5		3
Realized losses		2		1

PEF

DEBT

The carrying amount of PEF’s long-term debt, including current maturities, was $4.482 billion at March 31, 2012 and December 31, 2011. The estimated fair value of this debt was $5.3 billion and $5.4 billion at March 31, 2012 and December 31, 2011, respectively, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity	$	405	$	5	$	186
Preferred stock and other equity		23		—		5
Corporate debt		15		—		1
U.S. state and municipal debt		71		2		4
U.S. and foreign government debt		64		—		1
Money market funds and other		21		—		—

Total	$	599	$	7	$	197


December 31, 2011
Common stock equity	$	360	$	9	$	146
Preferred stock and other equity		12		—		4
Corporate debt		17		—		1
U.S. state and municipal debt		72		2		4
U.S. and foreign government debt		58		—		2
Money market funds and other		10		—		—

Total	$	529	$	11	$	157

ratemaking treatment. Therefore, the preceding table includes unrealized gains and losses for the NDT funds based on the original cost of the trust investments.

The aggregate fair value of investments that related to the March 31, 2012 and December 31, 2011 unrealized losses was $56 million and $38 million, respectively.

At March 31, 2012, the fair value of PEF’s available-for-sale debt securities by contractual maturity was:


(in millions)
Due in one year or less	$	23
Due after one through five years		26
Due after five through 10 years		75
Due after 10 years		29

Total	$	153

The following table presents selected information about PEF’s sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.


(in millions)	2012		2011
Proceeds	$	174	$	1,606
Realized gains		2		6
Realized losses		1		3

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.

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

The following tables set forth, by level within the fair value hierarchy, our and the Utilities’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PROGRESS ENERGY


(in millions)	Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,160	$	—	$	—	$	1,160
Preferred stock and other equity		33		10		—		43
Corporate debt		—		90		—		90
U.S. state and municipal debt		—		124		—		124
U.S. and foreign government debt		129		164		—		293
Money market funds and other		1		51		—		52

Total nuclear decommissioning trust funds		1,323		439		—		1,762
Derivatives
Commodity forward contracts		—		8		—		8
Other marketable securities
Money market and other		18		—		—		18

Total assets	$	1,341	$	447	$	—	$	1,788


Liabilities
Derivatives
Commodity forward contracts	$	—	$	769	$	27	$	796
Interest rate contracts		—		49		—		49
Contingent value obligations derivatives		—		3		—		3

Total liabilities	$	—	$	821	$	27	$	848


(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,033	$	—	$	—	$	1,033
Preferred stock and other equity		28		1		—		29
Corporate debt		—		86		—		86
U.S. state and municipal debt		—		128		—		128
U.S. and foreign government debt		87		197		—		284
Money market funds and other		—		87		—		87

Total nuclear decommissioning trust funds		1,148		499		—		1,647
Derivatives
Commodity forward contracts		—		5		—		5
Other marketable securities
Money market and other		20		—		—		20

Total assets	$	1,168	$	504	$	—	$	1,672


Liabilities
Derivatives
Commodity forward contracts	$	—	$	668	$	24	$	692
Interest rate contracts		—		93		—		93
Contingent value obligations derivatives		—		14		—		14

Total liabilities	$	—	$	775	$	24	$	799

PEC


(in millions)	Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	755	$	—	$	—	$	755
Preferred stock and other equity		20		—		—		20
Corporate debt		—		75		—		75
U.S. state and municipal debt		—		53		—		53
U.S. and foreign government debt		105		124		—		229
Money market funds and other		1		30		—		31

Total nuclear decommissioning trust funds		881		282		—		1,163
Derivatives
Commodity forward contracts		—		1		—		1
Other marketable securities		4		—		—		4

Total assets	$	885	$	283	$	—	$	1,168


Liabilities
Derivatives
Commodity forward contracts	$	—	$	208	$	27	$	235
Interest rate contracts		—		41		—		41

Total liabilities	$	—	$	249	$	27	$	276


(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	673	$	—	$	—	$	673
Preferred stock and other equity		17		—		—		17
Corporate debt		—		69		—		69
U.S. state and municipal debt		—		56		—		56
U.S. and foreign government debt		81		145		—		226
Money market funds and other		—		47		—		47

Total nuclear decommissioning trust funds		771		317		—		1,088
Other marketable securities		6		—		—		6

Total assets	$	777	$	317	$	—	$	1,094


Liabilities
Derivatives
Commodity forward contracts	$	—	$	177	$	24	$	201
Interest rate contracts		—		47		—		47

Total liabilities	$	—	$	224	$	24	$	248

PEF


(in millions)	Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	405	$	—	$	—	$	405
Preferred stock and other equity		13		10		—		23
Corporate debt		—		15		—		15
U.S. state and municipal debt		—		71		—		71
U.S. and foreign government debt		24		40		—		64
Money market funds and other		—		21		—		21

Total nuclear decommissioning trust funds		442		157		—		599
Derivatives
Commodity forward contracts		—		7		—		7
Other marketable securities		1		—		—		1

Total assets	$	443	$	164	$	—	$	607


Liabilities
Derivatives
Commodity forward contracts	$	—	$	561	$	—	$	561
Interest rate contracts		—		8		—		8

Total liabilities	$	—	$	569	$	—	$	569


(in millions)	Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
Nuclear decommissioning trust funds
Common stock equity	$	360	$	—	$	—	$	360
Preferred stock and other equity		11		1		—		12
Corporate debt		—		17		—		17
U.S. state and municipal debt		—		72		—		72
U.S. and foreign government debt		6		52		—		58
Money market funds and other		—		40		—		40

Total nuclear decommissioning trust funds		377		182		—		559
Derivatives
Commodity forward contracts		—		5		—		5
Other marketable securities		1		—		—		1

Total assets	$	378	$	187	$	—	$	565


Liabilities
Derivatives
Commodity forward contracts	$	—	$	491	$	—	$	491
Interest rate contracts		—		8		—		8

Total liabilities	$	—	$	499	$	—	$	499

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

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Such models may be internally developed, but are similar to models commonly used across industries to value derivative contracts. To determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors may include forward commodity prices and price curves, volumes and notional amounts, location, interest rates and credit quality of us and our counterparties. Certain commodity derivatives are valued utilizing pricing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 11 for discussion of risk management activities and derivative transactions.

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

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 16 in the 2011 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

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

QUALITATIVE AND QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENTS

A reconciliation of changes in the fair value of our and PEC’s commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31 follows:

PROGRESS ENERGY


(in millions)	2012		2011
Derivatives, net at January 1	$	24	$	36
Total unrealized losses (gains) deferred as regulatory assets and liabilities, net		3		(4	)

Derivatives, net at March 31	$	27	$	32

PEC


(in millions)	2012		2011
Derivatives, net at January 1	$	24	$	36
Total unrealized losses (gains) deferred as regulatory assets and liabilities, net		3		(4	)

Derivatives, net at March 31	$	27	$	32

During the three months ended March 31, 2012 and 2011, PEF did not have any assets or liabilities classified as Level 3.

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

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

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

PROGRESS ENERGY

(in millions)

Fair
Value

Valuation

Technique

Unobservable

Input

Range (price
per MMBtu)

March 31, 2012

Commodity natural gas hedges

Discounted cash flow

Forward natural gas curves

4.111 - 4.528

PEC

(in millions)

Fair
Value

Valuation

Technique

Unobservable

Input

Range (price
per MMBtu)

March 31, 2012

Commodity natural gas hedges

Discounted cash flow

Forward natural gas curves

4.111 - 4.528

10.

BENEFIT PLANS

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

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

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	16		$	13		$	3	$	3
Interest cost		33			35			10		10
Expected return on plan assets		(46	)		(45	)		—		—
Amortization of actuarial loss^(a)		23			14			6		3
Other amortization, net^(a)		2			2			1		1

Net periodic cost	$	28		$	19		$	20	$	17

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

PEC


	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	6		$	5		$	1	$	2
Interest cost		15			16			5		5
Expected return on plan assets		(24	)		(23	)		—		—
Amortization of actuarial loss		9			6			3		1
Other amortization, net		2			1			—		—

Net periodic cost	$	8		$	5		$	9	$	8

PEF


	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	7		$	6		$	1	$	1
Interest cost		14			15			4		4
Expected return on plan assets		(20	)		(20	)		—		—
Amortization of actuarial loss		11			8			3		2
Other amortization, net		—			—			1		1

Net periodic cost	$	12		$	9		$	9	$	8

In 2012, we expect to make contributions directly to pension plan assets of approximately $125 million to $225 million, including $60 million to $110 million for PEC and $65 million to $115 million for PEF. We contributed $18 million during the three months ended March 31, 2012, including $10 million for PEC and $8 million for PEF.

11.

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 2012 and 2013. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

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

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $166 million and $147 million on the Progress Energy Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, Progress Energy had 402.8 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $30 million and $24 million on the PEC Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEC had 123.1 million MMBtu notional of natural gas related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas purchases.

PEF’s cash collateral asset included in derivative collateral posted was $136 million and $123 million on the PEF Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEF had 279.7 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

B.	INTEREST RATE DERIVATIVES

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

At March 31, 2012, all open interest rate hedges will reach their mandatory termination dates within two years. At March 31, 2012, including amounts related to terminated hedges, we had $136 million of after-tax losses, including $66 million and $24 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 $13 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, 2011, including amounts related to terminated hedges, we had $141 million of after-tax losses, including $71 million and $25 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps.

At March 31, 2012, Progress Energy had $300 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF. At December 31, 2011, Progress Energy had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

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 $455 million at March 31, 2012, for which Progress Energy has posted collateral of $166 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, Progress Energy would have been required to post an additional $289 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 $147 million at March 31, 2012, for which PEC has posted collateral of $30 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEC would have been required to post an additional $117 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 $308 million at March 31, 2012, for which PEF has posted collateral of $136 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEF would have been required to post an additional $172 million of collateral with its counterparties.

D.	DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

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


Instrument / Balance sheet location	March 31, 2012				December 31, 2011
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	2			$	2
Derivative liabilities, long-term				1				1
Interest rate derivatives
Derivative liabilities, current				42				76
Derivative liabilities, long-term				7				17

Total derivatives designated as hedging instruments				52				96


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	7			$	5
Other assets and deferred debits		1				—
Derivative liabilities, current				439				357
Derivative liabilities, long-term				354				332
CVOs^(b)
Other current liabilities				—				14
Other liabilities and deferred credits				3				—

Fair value of derivatives not designated as hedging instruments		8		796		5		703
Fair value loss transition adjustment
Derivative liabilities, current				1				1
Derivative liabilities, long-term				2				2

Total derivatives not designated as hedging instruments		8		799		5		706

Total derivatives	$	8	$	851	$	5	$	802

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

^(b)

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

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012		2011		2012			2011			2012		2011
Interest rate derivatives^{(c) (d)}	$	2	$	2	$	(3	)	$	(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 on the Consolidated Statements of Comprehensive Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012			2011
Commodity derivatives	$	(105	)	$	(52	)	$	(206	)	$	23

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

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


Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2012		2011
CVOs^(a)	$	8	$	—

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

PEC

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


Instrument / Balance sheet location	March 31, 2012				December 31, 2011
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Derivative liabilities, current			$	34			$	38
Other liabilities and deferred credits				7				9

Total derivatives designated as hedging instruments				41				47


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Other assets and deferred debits	$	1			$	—
Derivative liabilities, current				114				91
Other liabilities and deferred credits				121				110

Fair value of derivatives not designated as hedging instruments		1		235		—		201
Fair value loss transition adjustment
Derivative liabilities, current				1				1
Other liabilities and deferred credits				2				2

Total derivatives not designated as hedging instruments		1		238		—		204

Total derivatives	$	1	$	279	$	—	$	251

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

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012		2011		2012			2011			2012		2011

Interest rate derivatives^{(c) (d)}	$	3	$	1	$	(2	)	$	(1	)	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012			2011
Commodity derivatives	$	(26	)	$	(11	)	$	(59	)	$	7

^(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.

PEF

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


Instrument / Balance sheet location	March 31, 2012				December 31, 2011
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	2			$	2
Derivative liabilities, long-term				1				1
Interest rate derivatives
Derivative liabilities, current				8				—
Derivative liabilities, long-term				—				8

Total derivatives designated as hedging instruments				11				11


Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	7			$	5
Derivative liabilities, current				325				266
Derivative liabilities, long-term				233				222

Total derivatives not designated as hedging instruments		7		558		5		488

Total derivatives	$	7	$	569	$	5	$	499

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

The following tables present the effect of derivative instruments on the Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)					Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012		2011		2012			2011		2012		2011
Interest rate derivatives^{(c) (d)}	$	—	$	—	$	(1	)	$	—	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012			2011
Commodity derivatives	$	(79	)	$	(41	)	$	(147	)	$	17

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

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

12.

FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

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

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


(in millions)	PEC		PEF		Corporate and Other			Eliminations			Totals
At and for the three months ended March 31, 2012
Revenues
Unaffiliated	$	1,085	$	1,005	$	2		$	—		$	2,092
Intersegment		—		—		59			(59	)		—

Total revenues		1,085		1,005		61			(59	)		2,092
Ongoing Earnings		60		130		(47	)		—			143
Total assets		16,424		14,732		21,248			(16,429	)		35,975

For the three months ended March 31, 2011
Revenues
Unaffiliated	$	1,133	$	1,032	$	2		$	—		$	2,167
Intersegment		—		—		74			(74	)		—

Total revenues		1,133		1,032		76			(74	)		2,167
Ongoing Earnings		139		111		(48	)		—			202

Management uses the non-GAAP financial measure “Ongoing Earnings” as a performance measure to evaluate the results of our segments and operations. Ongoing Earnings as presented here may not be comparable to similarly titled measures used by other companies. Ongoing Earnings is computed as GAAP net income attributable to controlling interests less discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Management has identified the following Ongoing Earnings adjustments: 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; and CVO mark-to-market adjustments because we are unable to predict changes in their fair value. Additionally, management does not consider merger and integration costs, and operating results of discontinued operations to be representative of our ongoing operations and excluded these items in computing Ongoing Earnings.

A reconciliation of consolidated Ongoing Earnings to net income attributable to controlling interests follows:


(in millions)	2012			2011
Ongoing Earnings	$	143		$	202
Tax levelization		(7	)		(2	)
CVO mark-to-market		8			—
Merger and integration costs, net of tax benefit of $2 and $- (Note 2)		(5	)		(14	)
Continuing income attributable to noncontrolling interests, net of tax		2			1

Income from continuing operations		141			187
Discontinued operations, net of tax		11			(2	)
Net income attributable to noncontrolling interests, net of tax		(2	)		(1	)

Net income attributable to controlling interests	$	150		$	184

13.

ENVIRONMENTAL MATTERS

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

A.	HAZARDOUS AND SOLID WASTE

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

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

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

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

PROGRESS ENERGY


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2011	$	17		$	6		$	23
Amount accrued for environmental loss contingencies		3			2			5
Expenditures for environmental loss contingencies		(2	)		(2	)		(4	)

Balance, March 31, 2012^(a)	$	18		$	6		$	24


Balance, December 31, 2010	$	20		$	15		$	35
Amount accrued for environmental loss contingencies		—			—			—
Expenditures for environmental loss contingencies		(1	)		(5	)		(6	)

Balance, March 31, 2011^(a)	$	19		$	10		$	29

^(a)	Expected to be paid out over one to 12 years.

PEC


(in millions)	MGP and Other Sites
Balance, December 31, 2011	$	11
Change in estimate for environmental loss contingencies		(1	)
Expenditures for environmental loss contingencies		(1	)

Balance, March 31, 2012^(a)	$	9


Balance, December 31, 2010	$	12
Amount accrued for environmental loss contingencies		—
Expenditures for environmental loss contingencies		—

Balance, March 31, 2011^(a)	$	12

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

PEF


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2011	$	6		$	6		$	12
Amount accrued for environmental loss contingencies		4			2			6
Expenditures for environmental loss contingencies		(1	)		(2	)		(3	)

Balance, March 31, 2012^(a)	$	9		$	6		$	15


Balance, December 31, 2010	$	8		$	15		$	23
Amount accrued for environmental loss contingencies		—			—			—
Expenditures for environmental loss contingencies		(1	)		(5	)		(6	)

Balance, March 31, 2011^(a)	$	7		$	10		$	17

^(a)	Expected to be paid out over one to 12 years.

PROGRESS ENERGY

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

PEC

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

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

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. In September 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. Remediation of one MGP site has been substantially completed. At March 31, 2012, PEF’s accrual primarily relates to a MGP site located in Orlando, Fla. The PRP group for the Orlando MGP site has agreed to an interim allocation for the Orlando MGP site and is conducting a feasibility study for remediation of soil and groundwater down to 50 feet, which has not been completed. The study preliminarily indicates a range of viable remedial approaches, and agreement has not been reached on the remediation approach. During the quarter ended March 31, 2012, one participating PRP ended its participation in the PRP group. The PRP allocations have been adjusted accordingly. The PRP group for the Orlando MGP site intends to seek recovery from the non-participating PRP, but no amount for recovery has been recorded. PEF has accrued its best estimate of its obligation with respect to the Orlando MGP site. Based on current estimates for the range of viable remedial approaches and its current allocation share, PEF could incur additional obligations

of up to approximately $4 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material below 200 feet from the surface. The layer between approximately 50 feet and 200 feet below the surface, which is clay, is not impacted. The maximum amount of the range for remediation, if any, below 200 feet at the Orlando MGP site and for PEF’s other sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. We cannot predict the outcome of this matter.

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

B.	AIR AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations governing air and water quality, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act). The air quality controls installed to comply with nitrogen oxides (NOx) and sulfur dioxide (SO₂) requirements under certain sections of the Clean Air Act (CAA) and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx and SO₂ for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

After prior mercury regulation was vacated in federal court, the EPA developed maximum achievable control technology (MACT) standards. The Mercury and Air Toxics Standards (MATS), which are the final MACT standards for coal-fired and oil-fired electric steam generating units, became effective on April 16, 2012. Compliance is due in three years with provisions for a one-year extension from state agencies on a case-by-case basis. The MATS contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Several petitions regarding portions of the MATS rule have been filed in the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals), including one by the Utility Air Regulatory Group, of which Progress Energy is a member. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. Due to significant investments in NOx and SO₂ emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy. We are continuing to evaluate the impacts of the MATS on the Utilities. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

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

On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) to replace the CAIR. The CSAPR, which was scheduled to take effect on January 1, 2012, contains new emissions trading programs for NOx and SO₂

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

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at CR4 and CR5, which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units 1 and 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 are scheduled to 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 5B, major construction activities for Levy are being postponed, and the in-service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of 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.

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

14.

COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2011 Form 10-K are described below.

A.	PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2011 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs. At March 31, 2012, our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 Form 10-K.

B.	GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2012,

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

At March 31, 2012, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At March 31, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $234 million, including $59 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications related to discontinued operations have no limitations as to time or maximum potential future payments. At March 31, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $43 million and $63 million, respectively. These amounts included $35 million and $37 million for PEF at March 31, 2012 and December 31, 2011, respectively. Our liabilities decreased primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 4). During the three months ended March 31, 2012, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

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

C.	OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

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

Hurricane Katrina

In May 2011, PEC and PEF were named in a class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claimed that PEC and PEF, along with numerous other utility, oil, coal and chemical companies, were liable for damages relating to losses suffered by victims of Hurricane Katrina as a result of their contributions of greenhouse gas emissions to the frequency and intensity of storms such as Hurricane Katrina. On March 20, 2012, the federal district court dismissed the class action lawsuit. On April 16, 2012, the plaintiffs filed a notice of appeal of this decision with the United States Court of Appeals for the Fifth Circuit. We believe the plaintiff’s claim is without merit; however, we cannot predict the outcome of this matter.

Water Discharge Permit

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

SPENT NUCLEAR FUEL MATTERS

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

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the standard

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

On December 12, 2011, the Utilities filed another complaint in the U.S. Court of Federal Claims against the DOE, claiming damages incurred from January 1, 2006, through December 31, 2010. The damages stem from the same breach of contract asserted in the previous litigation. On March 23, 2012, the Utilities filed their initial disclosure of damages with the U.S. Court of Federal Claims and the DOE. The Utilities may file subsequent damage claims as they incur additional costs. We cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

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

The jury awarded Global $78 million. In November 2009, the court assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. In December 2009, we appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we made a $154 million payment, which 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. In May 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates’ declaratory judgment action. In August 2003, the Wake County Superior Court denied Global’s motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court’s order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

OTHER LITIGATION MATTERS

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

15.

CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2011 Form 10-K, we have guaranteed certain payments of two 100 percent owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 12B in the 2011 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.

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

Presented below are the condensed consolidating Statements of Comprehensive Income, Balance Sheets and 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 Comprehensive Income

Three months ended March 31, 2012


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	1,007		$	1,085		$	—		$	2,092
Affiliate revenues		—			—			59			(59	)		—

Total operating revenues		—			1,007			1,144			(59	)		2,092

Operating expenses
Fuel used in electric generation		—			336			349			—			685
Purchased power		—			145			65			—			210
Operation and maintenance		1			160			422			(54	)		529
Depreciation, amortization and accretion		—			27			139			—			166
Taxes other than on income		—			82			58			(2	)		138

Total operating expenses		1			750			1,033			(56	)		1,728

Operating (loss) income		(1	)		257			111			(3	)		364

Other income (expense)
Interest income		1			—			—			—			1
Allowance for equity funds used during construction		—			9			15			—			24
Other, net		8			1			2			2			13

Total other income, net		9			10			17			2			38

Interest charges
Interest charges		66			73			55			—			194
Allowance for borrowed funds used during construction		—			(4	)		(5	)		—			(9	)

Total interest charges, net		66			69			50			—			185

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(58	)		198			78			(1	)		217
Income tax (benefit) expense		(22	)		73			27			(2	)		76
Equity in earnings of consolidated subsidiaries		186			—			—			(186	)		—

Income from continuing operations		150			125			51			(185	)		141
Discontinued operations, net of tax		—			11			—			—			11

Net income		150			136			51			(185	)		152
Net income attributable to noncontrolling interests, net of tax		—			(1	)		—			(1	)		(2	)

Net income attributable to controlling interests	$	150		$	135		$	51		$	(186	)	$	150

Comprehensive income
Comprehensive income	$	155		$	137		$	55		$	(190	)	$	157
Comprehensive income attributable to noncontrolling interests, net of tax		—			(1	)		—			(1	)		(2	)

Comprehensive income attributable to controlling interests	$	155		$	136		$	55		$	(191	)	$	155

Condensed Consolidating Statement of Comprehensive Income

Three months ended March 31, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	1,034		$	1,133		$	—		$	2,167
Affiliate revenues		—			—			74			(74	)		—

Total operating revenues		—			1,034			1,207			(74	)		2,167

Operating expenses
Fuel used in electric generation		—			355			363			—			718
Purchased power		—			153			67			—			220
Operation and maintenance		3			211			351			(71	)		494
Depreciation, amortization and accretion		—			25			129			—			154
Taxes other than on income		—			85			59			(4	)		140
Other		—			(10	)		—			—			(10	)

Total operating expenses		3			819			969			(75	)		1,716

Operating (loss) income		(3	)		215			238			1			451

Other income (expense)
Interest income		—			1			—			—			1
Allowance for equity funds used during construction		—			9			20			—			29
Other, net		—			5			(2	)		—			3

Total other income, net		—			15			18			—			33

Interest charges
Interest charges		73			75			51			—			199
Allowance for borrowed funds used during construction		—			(4	)		(5	)		—			(9	)

Total interest charges, net		73			71			46			—			190

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(76	)		159			210			1			294
Income tax (benefit) expense		(31	)		60			80			(2	)		107
Equity in earnings of consolidated subsidiaries		229			—			—			(229	)		—

Income from continuing operations before cumulative effect of change in accounting principle		184			99			130			(226	)		187
Discontinued operations, net of tax		—			(1	)		(1	)		—			(2	)

Net income		184			98			129			(226	)		185
Net (income) loss attributable to noncontrolling interests, net of tax		—			(1	)		—			—			(1	)

Net income attributable to controlling interests	$	184		$	97		$	129		$	(226	)	$	184

Comprehensive income
Comprehensive income	$	188		$	99		$	132		$	(230	)	$	189
Comprehensive income attributable to noncontrolling interests		—			(1	)		—			—			(1	)

Comprehensive income attributable to controlling interests	$	188		$	98		$	132		$	(230	)	$	188

Condensed Consolidating Balance Sheet

March 31, 2012


(in millions)	Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	10,596	$	12,124	$	85		$	22,805

Current assets
Cash and cash equivalents		511		33		21		—			565
Receivables, net		—		346		412		—			758
Notes receivable from affiliated companies		63		7		172		(242	)		—
Regulatory assets		—		225		25		—			250
Derivative collateral posted		—		136		30		—			166
Prepayments and other current assets		135		960		1,134		(133	)		2,096

Total current assets		709		1,707		1,794		(375	)		3,835

Deferred debits and other assets
Investment in consolidated subsidiaries		13,968		—		—		(13,968	)		—
Regulatory assets		—		1,659		1,464		—			3,123
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		599		1,163		—			1,762
Other assets and deferred debits		116		255		869		(445	)		795

Total deferred debits and other assets		14,084		2,513		3,496		(10,758	)		9,335

Total assets	$	14,793	$	14,816	$	17,414	$	(11,048	)	$	35,975

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,009	$	4,759	$	5,536	$	(10,295	)	$	10,009
Noncontrolling interests		—		2		—		—			2

Total equity		10,009		4,761		5,536		(10,295	)		10,011

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		—		(36	)		273
Long-term debt, net		3,992		4,057		3,693		—			11,742

Total capitalization		14,001		9,161		9,288		(10,331	)		22,119

Current liabilities
Current portion of long-term debt		450		425		500		—			1,375
Short-term debt		255		360		441		—			1,056
Notes payable to affiliated companies		—		198		44		(242	)		—
Derivative liabilities		—		335		149		—			484
Other current liabilities		65		836		1,084		(138	)		1,847

Total current liabilities		770		2,154		2,218		(380	)		4,762

Deferred credits and other liabilities
Noncurrent income tax liabilities		—		990		2,062		(415	)		2,637
Regulatory liabilities		—		967		1,632		85			2,684
Other liabilities and deferred credits		22		1,544		2,214		(7	)		3,773

Total deferred credits and other liabilities		22		3,501		5,908		(337	)		9,094

Total capitalization and liabilities	$	14,793	$	14,816	$	17,414	$	(11,048	)	$	35,975

Condensed Consolidating Balance Sheet

December 31, 2011


(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	10,523	$	11,887	$	87		$	22,497

Current assets
Cash and cash equivalents		117		92		21		—			230
Receivables, net		—		372		517		—			889
Notes receivable from affiliated companies		53		—		219		(272	)		—
Regulatory assets		—		244		31		—			275
Derivative collateral posted		—		123		24		—			147
Prepayments and other current assets		128		852		1,049		(87	)		1,942

Total current assets		298		1,683		1,861		(359	)		3,483

Deferred debits and other assets
Investment in consolidated subsidiaries		14,043		—		—		(14,043	)		—
Regulatory assets		—		1,602		1,423		—			3,025
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		559		1,088		—			1,647
Other assets and deferred debits		140		242		856		(486	)		752

Total deferred debits and other assets		14,183		2,403		3,367		(10,874	)		9,079

Total assets	$	14,481	$	14,609	$	17,115	$	(11,146	)	$	35,059

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	10,021	$	4,728	$	5,646	$	(10,374	)	$	10,021
Noncontrolling interests		—		4		—		—			4

Total equity		10,021		4,732		5,646		(10,374	)		10,025

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		—		(36	)		273
Long-term debt, net		3,543		4,482		3,693		—			11,718

Total capitalization		13,564		9,557		9,398		(10,410	)		22,109

Current liabilities
Current portion of long-term debt		450		—		500		—			950
Short-term debt		250		233		188		—			671
Notes payable to affiliated companies		—		238		34		(272	)		—
Derivative liabilities		38		268		130		—			436
Other current liabilities		161		839		1,112		(84	)		2,028

Total current liabilities		899		1,578		1,964		(356	)		4,085

Deferred credits and other liabilities
Noncurrent income tax liabilities		—		837		1,976		(458	)		2,355
Regulatory liabilities		—		1,071		1,543		86			2,700
Other liabilities and deferred credits		18		1,566		2,234		(8	)		3,810

Total deferred credits and other liabilities		18		3,474		5,753		(380	)		8,865

Total capitalization and liabilities	$	14,481	$	14,609	$	17,115	$	(11,146	)	$	35,059

Condensed Consolidating Statement of Cash Flows

Three months ended March 31, 2012


(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	227		$	166		$	245		$	(282	)	$	356

Investing activities
Gross property additions		—			(197	)		(365	)		—			(562	)
Nuclear fuel additions		—			(13	)		(38	)		—			(51	)
Purchases of available-for-sale securities and other investments		—			(225	)		(138	)		—			(363	)
Proceeds from available-for-sale securities and other investments		—			226			133			—			359
Changes in advances to affiliated companies		(10	)		(7	)		47			(30	)		—
Other investing activities		(14	)		15			64			—			65

Net cash used by investing activities		(24	)		(201	)		(297	)		(30	)		(552	)

Financing activities
Issuance of common stock, net		3			—			—			—			3
Dividends paid on common stock		(260	)		—			—			—			(260	)
Dividends paid to parent		—			(108	)		(175	)		283			—
Proceeds from the issuance of short-term debt with original maturities greater than 90 days		—			65			—			—			65
Net increase in short-term debt		5			62			253			—			320
Proceeds from issuance of long-term debt, net		444			—			—			—			444
Changes in advances from affiliated companies		—			(40	)		11			29			—
Other financing activities		(1	)		(3	)		(37	)		—			(41	)

Net cash provided (used) by financing activities		191			(24	)		52			312			531

Net increase (decrease) in cash and cash equivalents		394			(59	)		—			—			335
Cash and cash equivalents at beginning of period		117			92			21			—			230

Cash and cash equivalents at end of period	$	511		$	33		$	21		$	—		$	565

Condensed Consolidating Statement of Cash Flows

Three months ended March 31, 2011


(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	280		$	257		$	337		$	(428	)	$	446

Investing activities
Gross property additions		—			(218	)		(283	)		—			(501	)
Nuclear fuel additions		—			(7	)		(50	)		—			(57	)
Purchases of available-for-sale securities and other investments		—			(1,661	)		(156	)		—			(1,817	)
Proceeds from available-for-sale securities and other investments		—			1,661			148			—			1,809
Changes in advances to affiliated companies		(75	)		21			42			12			—
Contributions to consolidated subsidiaries		(10	)		—			—			10			—
Other investing activities		—			43			5			(2	)		46

Net cash used by investing activities		(85	)		(161	)		(294	)		20			(520	)

Financing activities
Issuance of common stock, net		8			—			—			—			8
Dividends paid on common stock		(183	)		—			—			—			(183	)
Dividends paid to parent		—			(328	)		(100	)		428			—
Net increase in short-term debt		79			—			—			—			79
Proceeds from issuance of long-term debt, net		494			—			—			—			494
Retirement of long-term debt		(700	)		—			—			—			(700	)
Changes in advances from affiliated companies		—			11			—			(11	)		—
Contributions from parent		—			10			—			(10	)		—
Other financing activities		—			(4	)		(60	)		1			(63	)

Net cash used by financing activities		(302	)		(311	)		(160	)		408			(365	)

Net decrease in cash and cash equivalents		(107	)		(215	)		(117	)		—			(439	)
Cash and cash equivalents at beginning of period		110			270			231			—			611

Cash and cash equivalents at end of period	$	3		$	55		$	114		$	—		$	172

Attached files

Stock widget

Investing forum

Also read