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

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8-K - FORM 8-K - Duke Energy CORP	d393334d8k.htm
EX-99.2 - UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION - Duke Energy CORP	d393334dex992.htm

Exhibit 99.1

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

June 30, 2012

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME


	Three months ended June 30						Six months ended June 30
(in millions except per share data)	2012			2011			2012			2011
Operating revenues	$	2,273		$	2,256		$	4,365		$	4,423
Operating expenses
Fuel used in electric generation		736			674			1,421			1,392
Purchased power		257			329			467			549
Operation and maintenance		627			510			1,156			1,004
Depreciation, amortization and accretion		231			179			397			333
Taxes other than on income		142			134			280			274
Other		5			2			5			(8	)

Total operating expenses		1,998			1,828			3,726			3,544

Operating income		275			428			639			879

Other income
Interest income		1			—			2			1
Allowance for equity funds used during construction		25			26			49			55
Other, net		1			7			14			10

Total other income, net		27			33			65			66

Interest charges
Interest charges		203			189			397			388
Allowance for borrowed funds used during construction		(11	)		(9	)		(20	)		(18	)

Total interest charges, net		192			180			377			370

Income from continuing operations before income tax		110			281			327			575
Income tax expense		42			101			118			208

Income from continuing operations		68			180			209			367
Discontinued operations, net of tax		(4	)		(2	)		7			(4	)

Net income		64			178			216			363
Net income attributable to noncontrolling interests, net of tax		(1	)		(2	)		(3	)		(3	)

Net income attributable to controlling interests	$	63		$	176		$	213		$	360

Average common shares outstanding – basic		297			296			297			295

Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$	0.23		$	0.60		$	0.70		$	1.23
Discontinued operations attributable to controlling interests, net of tax		(0.02	)		—			0.02			(0.01	)

Net income attributable to controlling interests	$	0.21		$	0.60		$	0.72		$	1.22

Dividends declared per common share	$	0.620		$	0.620		$	1.240		$	1.240

Net income amounts attributable to controlling interests
Income from continuing operations, net of tax	$	67		$	178		$	206		$	364
Discontinued operations, net of tax		(4	)		(2	)		7			(4	)

Net income attributable to controlling interests	$	63		$	176		$	213		$	360

Comprehensive income
Comprehensive income	$	60		$	157		$	217		$	346
Comprehensive income attributable to noncontrolling interests, net of tax		(1	)		(2	)		(3	)		(3	)

Comprehensive income attributable to controlling interests	$	59		$	155		$	214		$	343

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

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


(in millions)	June 30, 2012			December 31, 2011
ASSETS
Utility plant
Utility plant in service	$	31,601		$	31,065
Accumulated depreciation		(12,151	)		(12,001	)

Utility plant in service, net		19,450			19,064
Other utility plant, net		272			217
Construction work in progress		2,711			2,449
Nuclear fuel, net of amortization		759			767

Total utility plant, net		23,192			22,497

Current assets
Cash and cash equivalents		73			230
Receivables, net		849			889
Inventory, net		1,427			1,438
Regulatory assets		302			275
Derivative collateral posted		124			147
Deferred tax assets		508			371
Prepayments and other current assets		104			133

Total current assets		3,387			3,483

Deferred debits and other assets
Regulatory assets		2,954			3,025
Nuclear decommissioning trust funds		1,757			1,647
Miscellaneous other property and investments		411			407
Goodwill		3,655			3,655
Other assets and deferred debits		368			345

Total deferred debits and other assets		9,145			9,079

Total assets	$	35,724		$	35,059

CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized, 296 million and 295 million shares issued and outstanding, respectively	$	7,465		$	7,434
Accumulated other comprehensive loss		(164	)		(165	)
Retained earnings		2,596			2,752

Total common stock equity		9,897			10,021

Noncontrolling interests		3			4

Total equity		9,900			10,025

Preferred stock of subsidiaries		93			93
Long-term debt, affiliate		273			273
Long-term debt, net		12,739			11,718

Total capitalization		23,005			22,109

Current liabilities
Current portion of long-term debt		925			950
Short-term debt		345			671
Accounts payable		907			909
Interest accrued		197			200
Dividends declared		1			78
Customer deposits		342			340
Derivative liabilities		326			436
Accrued compensation and other benefits		168			195
Other current liabilities		359			306

Total current liabilities		3,570			4,085

Deferred credits and other liabilities
Noncurrent income tax liabilities		2,670			2,355
Accumulated deferred investment tax credits		99			103
Regulatory liabilities		2,612			2,700
Asset retirement obligations		1,299			1,265
Accrued pension and other benefits		1,656			1,625
Capital lease obligations		310			200
Derivative liabilities		300			352
Other liabilities and deferred credits		203			265

Total deferred credits and other liabilities		9,149			8,865

Commitments and contingencies (Notes 13 and 14)

Total capitalization and liabilities	$	35,724		$	35,059

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

PROGRESS ENERGY, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS


(in millions)
Six months ended June 30	2012			2011
Operating activities
Net income	$	216		$	363
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		481			425
Deferred income taxes and investment tax credits, net		169			178
Deferred fuel credit		(79	)		(29	)
Allowance for equity funds used during construction		(49	)		(55	)
Other adjustments to net income		39			167
Cash (used) provided by changes in operating assets and liabilities
Receivables		(9	)		(5	)
Inventory		8			(127	)
Other assets		14			16
Income taxes, net		1			56
Accounts payable		70			1
Accrued pension and other benefits		(74	)		(259	)
Other liabilities		(36	)		49

Net cash provided by operating activities		751			780

Investing activities
Gross property additions		(1,080	)		(1,004	)
Nuclear fuel additions		(65	)		(93	)
Purchases of available-for-sale securities and other investments		(625	)		(3,387	)
Proceeds from available-for-sale securities and other investments		610			3,364
Other investing activities		81			82

Net cash used by investing activities		(1,079	)		(1,038	)

Financing activities
Issuance of common stock, net		6			26
Dividends paid on common stock		(446	)		(366	)
Payments of short-term debt with original maturities greater than 90 days		(65	)		—
Proceeds from issuance of short-term debt with original maturities greater than 90 days		65			—
Net (decrease) increase in short-term debt		(326	)		314
Proceeds from issuance of long-term debt, net		1,432			494
Retirement of long-term debt		(450	)		(700	)
Other financing activities		(45	)		(69	)

Net cash provided (used) by financing activities		171			(301	)

Net decrease in cash and cash equivalents		(157	)		(559	)
Cash and cash equivalents at beginning of period		230			611

Cash and cash equivalents at end of period	$	73		$	52

Supplemental disclosures
Significant noncash transactions
Accrued property additions	$	237		$	256
Capital expenditures financed through capital leases		116			—

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

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

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

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


Registrant		Applicable Notes
PEC		1 through 3, 5 through 11, 13 and 14

PEF		1 through 3, 5 through 11, 13 and 14

PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. ORGANIZATION

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

PROGRESS ENERGY

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

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 12 for further information about our segments.

PEC

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

PEF

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

B. BASIS OF PRESENTATION

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and

Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).

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

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

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

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

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


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

C. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

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

PROGRESS ENERGY

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

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


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

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

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

PEC

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

PEF

PEF has no significant variable interests in VIEs.

2. MERGER WITH DUKE ENERGY

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

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

MERGER-RELATED REGULATORY MATTERS

Federal Energy Regulatory Commission

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

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


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

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

•

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

•

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

North Carolina Utilities Commission and Public Service Commission of South Carolina

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

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

ACCOUNTING CHARGES TO BE RECOGNIZED

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

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

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

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

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

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


(in millions)
Balance, December 31, 2011	$	5
Additional exit cost recognized		3

Balance, March 31, 2012		8
Additional exit cost recognized^(a)		2

Balance, June 30, 2012^(b)	$	10

^(a)	PEC and PEF recognized exit costs of $1 million each for the three months ended June 30, 2012, and $3 million and $2 million, respectively, for the six months ended June 30, 2012.

^(b)	Expense related to the recognition of the cumulative exit cost liability at June 30, 2012, was attributed to PEC and PEF totaling $7 million and $3 million, respectively.

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


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

OTHER MATTERS

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

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

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

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

3. NEW ACCOUNTING STANDARDS

FAIR VALUE MEASUREMENT AND DISCLOSURES

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

GOODWILL IMPAIRMENT TESTING

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

DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES

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

4. DIVESTITURES

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

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

5. REGULATORY MATTERS

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

A. PEC RETAIL RATE MATTERS

COST-RECOVERY FILINGS

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

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

OTHER MATTERS

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

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

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

B. PEF RETAIL RATE MATTERS

CR3 OUTAGE

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

while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur during the repair process.

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

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

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

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power when the unit is out of service as a result of these events. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through June 30, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. PEF also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL has unresolved concerns and has not made any payments on the second delamination and has not provided a written coverage decision for either delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, we have agreed to mediation prior to commencing any formal dispute resolution. We are in the process of providing information as requested by NEIL and currently have scheduled the mediation to commence in fourth quarter of 2012. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, as of June 30, 2012, PEF has not recorded insurance receivables from NEIL related to either the first or second delamination. PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

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


(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	534		$	305
NEIL proceeds received to date		(162	)		(143	)

Balance for recovery^(a)	$	372		$	162

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

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

2012 SETTLEMENT AGREEMENT

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

Levy

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

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

CR3

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

unrelated to the CR3 outage. All prudence issues from the steam generator project inception through the date of settlement approval by the FPSC are resolved.

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

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

Base Rates, Customer Refund and Other Terms

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

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

The cost of pollution control equipment that PEF installed and has in-service at Crystal River Units 4 and 5 (CR4 and CR5) to comply with the Federal Clean Air Interstate Rule (CAIR) is currently recovered under the Environmental Cost Recovery Clause (ECRC). The 2012 settlement agreement provides for PEF to remove those assets from recovery in the ECRC and transfer those assets to base rates effective with the first billing cycle of January 2014. The related base rate increase will be in addition to the $150 million base rate increase effective

January 2013. O&M expense associated with those assets will not be included in the base rates and will continue to be recovered through the ECRC.

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

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

COST OF REMOVAL RESERVE

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

NUCLEAR COST RECOVERY

Levy Nuclear

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

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

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

CR3 Uprate

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

Cost Recovery

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

DEMAND-SIDE MANAGEMENT

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

OTHER MATTERS

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

6. EQUITY

A. EARNINGS PER COMMON SHARE

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

B. RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

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

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


(in millions)	Total Common Stock Equity			Noncontrolling Interests			Total Equity
Balance, December 31, 2011	$	10,021		$	4		$	10,025
Net income^(a)		213			1			214
Other comprehensive income		1			—			1
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)		31			—			31
Dividends declared		(369	)		—			(369	)
Distributions to noncontrolling interests		—			(2	)		(2	)

Balance, June 30, 2012	$	9,897		$	3		$	9,900

Balance, December 31, 2010	$	10,023		$	4		$	10,027
Net income^(a)		360			1			361
Other comprehensive loss		(17	)		—			(17	)
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)		47			—			47
Dividends declared		(367	)		—			(367	)
Distributions to noncontrolling interests		—			(2	)		(2	)

Balance, June 30, 2011	$	10,046		$	3		$	10,049

^(a)

For the six months ended June 30, 2012, consolidated net income of $216 million includes $2 million attributable to preferred shareholders of subsidiaries. For the six months ended June 30, 2011, consolidated net income of $363 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

PEC

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

PEF

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

C. COMMON STOCK

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

The following table presents information for our common stock issuances:


	2012				2011
(in millions)	Shares		Net Proceeds		Shares		Net Proceeds
Three months ended June 30
Total issuances		0.1	$	3		0.4	$	18

Six months ended June 30
Total issuances		0.9	$	6		1.4	$	26
Issuances through IPP		—		—		—		1

7. PREFERRED STOCK OF SUBSIDIARIES

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

8. DEBT AND CREDIT FACILITIES

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

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

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

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

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

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

for each borrower, including PEC and PEF. Indebtedness as defined by the Duke Energy MCF includes certain letters of credit, surety bonds and guarantees not recorded on the Consolidated Balance Sheets. Following the merger, the cash needs of the Parent will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; borrowings under an intercompany note with Duke Energy; and/or equity contributions from Duke Energy.

9. FAIR VALUE DISCLOSURES

A. DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

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

INVESTMENTS

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
June 30, 2012
Common stock equity	$	1,109	$	29	$	462
Preferred stock and other equity		47		—		14
Corporate debt		88		—		7
U.S. state and municipal debt		135		2		9
U.S. and foreign government debt		293		—		17
Money market funds and other		85		—		1

Total	$	1,757	$	31	$	510

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

Total	$	1,630	$	31	$	444

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

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

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


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

Total	$	530

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


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

PEC

DEBT

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

INVESTMENTS

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
June 30, 2012
Common stock equity	$	727	$	19	$	293
Preferred stock and other equity		22		—		9
Corporate debt		73		—		6
U.S. state and municipal debt		62		—		4
U.S. and foreign government debt		229		—		15
Money market funds and other		54		—		1

Total	$	1,167	$	19	$	328

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

Total	$	1,101	$	20	$	287

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

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


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

Total	$	375

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


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

PEF

DEBT

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

INVESTMENTS

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


(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
June 30, 2012
Common stock equity	$	382	$	10	$	169
Preferred stock and other equity		25		—		5
Corporate debt		15		—		1
U.S. state and municipal debt		73		2		5
U.S. and foreign government debt		64		—		2
Money market funds and other		31		—		—

Total	$	590	$	12	$	182

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

Total	$	529	$	11	$	157

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

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

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


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

Total	$	155

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


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

B. FAIR VALUE MEASUREMENTS

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

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

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

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

Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best

estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available.

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

The following tables set forth, by level within the fair value hierarchy, our and the Utilities’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PROGRESS ENERGY


(in millions)	Level 1		Level 2		Level 3		Total
June 30, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	1,109	$	—	$	—	$	1,109
Preferred stock and other equity		36		11		—		47
Corporate debt		—		88		—		88
U.S. state and municipal debt		—		135		—		135
U.S. and foreign government debt		128		165		—		293
Money market funds and other		1		84		—		85

Total nuclear decommissioning trust funds		1,274		483		—		1,757
Derivatives
Commodity forward contracts		—		8		—		8
Other marketable securities
Money market and other		16		—		—		16

Total assets	$	1,290	$	491	$	—	$	1,781

Liabilities
Derivatives
Commodity forward contracts	$	—	$	572	$	30	$	602
Interest rate contracts		—		22		—		22
Contingent value obligations		—		3		—		3

Total liabilities	$	—	$	597	$	30	$	627


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

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

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

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

Total liabilities	$	—	$	775	$	24	$	799


*PEC*

(in millions)	Level 1		Level 2		Level 3		Total
June 30, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	727	$	—	$	—	$	727
Preferred stock and other equity		22		—		—		22
Corporate debt		—		73		—		73
U.S. state and municipal debt		—		62		—		62
U.S. and foreign government debt		105		124		—		229
Money market funds and other		1		50		—		51

Total nuclear decommissioning trust funds		855		309		—		1,164
Derivatives
Commodity forward contracts		—		2		—		2
Other marketable securities		2		—		—		2

Total assets	$	857	$	311	$	—	$	1,168

Liabilities
Derivatives
Commodity forward contracts	$	—	$	158	$	28	$	186
Interest rate contracts		—		11		—		11

Total liabilities	$	—	$	169	$	28	$	197


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

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

Total assets	$	777	$	317	$	—	$	1,094

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

Total liabilities	$	—	$	224	$	24	$	248


*PEF*

(in millions)	Level 1		Level 2		Level 3		Total
June 30, 2012
Assets
Nuclear decommissioning trust funds
Common stock equity	$	382	$	—	$	—	$	382
Preferred stock and other equity		14		11		—		25
Corporate debt		—		15		—		15
U.S. state and municipal debt		—		73		—		73
U.S. and foreign government debt		23		41		—		64
Money market funds and other		—		34		—		34

Total nuclear decommissioning trust funds		419		174		—		593
Derivatives
Commodity forward contracts		—		6		—		6
Other marketable securities		1		—		—		1

Total assets	$	420	$	180	$	—	$	600

Liabilities
Derivatives
Commodity forward contracts	$	—	$	414	$	2	$	416
Interest rate contracts		—		11		—		11

Total liabilities	$	—	$	425	$	2	$	427


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

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

Total assets	$	378	$	187	$	—	$	565

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

Total liabilities	$	—	$	499	$	—	$	499

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

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

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

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

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

QUALITATIVE AND QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENTS

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

PROGRESS ENERGY


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

Derivatives, net at end of period	$	30	$	37	$	30	$	37

PEC


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

Derivatives, net at end of period	$	28	$	37	$	28	$	37

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

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

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

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

PROGRESS ENERGY

(in millions)

Fair
Value

Valuation
Technique

Unobservable
Input

Range (price
per MMBtu)

June 30, 2012

Commodity natural gas hedges

Discounted cash flow

Forward natural gas curves

$3.956 - 4.374

PEC

(in millions)

Fair
Value

Valuation
Technique

Unobservable
Input

Range (price
per MMBtu)

June 30, 2012

Commodity natural gas hedges

Discounted cash flow

Forward natural gas curves

$3.956 - 4.374

10. BENEFIT PLANS

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

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

PROGRESS ENERGY


	Pension Benefits						OPEB
(in millions)	2012			2011			2012		2011
Service cost	$	16		$	14		$	4	$	3
Interest cost		33			35			11		10
Expected return on plan assets		(46	)		(45	)		—		—
Amortization of actuarial loss^(a)		26			18			9		3
Other amortization, net ^(a)		2			1			1		1

Net periodic cost	$	31		$	23		$	25	$	17

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

PEC


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

Net periodic cost	$	10		$	7		$	14	$	8

PEF


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

Net periodic cost	$	14		$	10		$	9	$	8

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

PROGRESS ENERGY


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

Net periodic cost	$	58		$	42		$	44		$	34

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

PEC


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

Net periodic cost	$	19		$	12		$	23	$	15

PEF


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

Net periodic cost	$	26		$	20		$	18		$	16

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

11. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We had a risk management committee that included senior executives from various business groups. The risk management committee was responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Following the consummation of the merger with Duke Energy, the risk management committee was replaced with Duke Energy’s Transaction and Risk Committee, which will be responsible for the oversight of risk at the combined company. The Transaction and Risk Committee will include senior executives from various functional areas. Following the consummation of the merger, PEC and PEF will continue to operate under their existing risk guidelines. Under our risk guidelines, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial

reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations.

A. COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. Effective with the consummation of the merger with Duke Energy on July 2, 2012, Progress Energy entered into certain derivative power sales agreements with three counterparties in conjunction with the Interim FERC Mitigation Plan. See Note 2 for additional information regarding future charges related to the merger, including the Interim FERC Mitigation Plan.

ECONOMIC DERIVATIVES

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

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2012 and 2013. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

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

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted on the Progress Energy Consolidated Balance Sheets of $124 million and $147 million at June 30, 2012 and December 31, 2011, respectively. At June 30, 2012, Progress Energy had 394.6 million MMBtu notional of natural gas and 8.1 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases.

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

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

B. INTEREST RATE DERIVATIVES

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

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

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

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

C. CONTINGENT FEATURES

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

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

The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $371 million at June 30, 2012, for which Progress Energy has posted collateral of $124 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at June 30, 2012, Progress Energy would have been required to post an additional $247 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $122 million at June 30, 2012, for which PEC has posted collateral of $21 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at June 30, 2012, PEC would have been required to post an additional $101 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $249 million at June 30, 2012, for which PEF has posted collateral of $103 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on June 30, 2012, PEF would have been required to post an additional $146 million of collateral with its counterparties.

D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

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


Instrument / Balance sheet location	June 30, 2012				December 31, 2011
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	2			$	2
Derivative liabilities, long-term				1				1
Interest rate derivatives
Derivative liabilities, current				11				76
Derivative liabilities, long-term				11				17

Total derivatives designated as hedging instruments				25				96

Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	3			$	5
Other assets and deferred debits		5				—
Derivative liabilities, current				312				357
Derivative liabilities, long-term				287				332
CVOs^(b)
Other current liabilities				—				14
Other liabilities and deferred credits				3				—

Fair value of derivatives not designated as hedging instruments		8		602		5		703
Fair value loss transition adjustment
Derivative liabilities, current				1				1
Derivative liabilities, long-term				1				2

Total derivatives not designated as hedging instruments		8		604		5		706

Total derivatives	$	8	$	629	$	5	$	802

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

^(b)

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

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

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012			2011			2012			2011			2012		2011
Interest rate derivatives^{(c) (d)}	$	(8	)	$	(16	)	$	(3	)	$	(2	)	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012		2011
Commodity derivatives	$	(155	)	$	(76	)	$	38	$	(68	)

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

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


Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2012		2011
Commodity derivatives^(a)	$	2	$	1
Fair value loss transition adjustment^(a)		1		—
CVOs^(a)		—		4

Total	$	3	$	5

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

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

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012			2011			2012			2011			2012		2011
Interest rate derivatives^{(c) (d)}	$	(6	)	$	(14	)	$	(6	)	$	(3	)	$	—	$	(2	)

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012			2011
Commodity derivatives	$	(260	)	$	(128	)	$	(168	)	$	(44	)

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

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


Instrument	Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)	2012		2011
Commodity derivatives^(a)	$	2	$	1
Fair value loss transition adjustment^(a)		1		—
CVOs^(a)		8		4

Total	$	11	$	5

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

PEC

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


Instrument / Balance sheet location	June 30, 2012				December 31, 2011
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
Derivative liabilities, current			$	—			$	38
Other liabilities and deferred credits				11				9

Total derivatives designated as hedging instruments				11				47

Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	1			$	—
Other assets and deferred debits		1				—
Derivative liabilities, current				88				91
Other liabilities and deferred credits				98				110

Fair value of derivatives not designated as hedging instruments		2		186		—		201
Fair value loss transition adjustment
Derivative liabilities, current				1				1
Other liabilities and deferred credits				1				2

Total derivatives not designated as hedging instruments		2		188		—		204

Total derivatives	$	2	$	199	$	—	$	251

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

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

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012			2011			2012			2011			2012		2011
Interest rate derivatives^{(c) (d)}	$	(7	)	$	(6	)	$	(1	)	$	(1	)	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012		2011
Commodity derivatives	$	(39	)	$	(12	)	$	10	$	(19	)

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

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


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

Total	$	3	$	1

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

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

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)						Amount of Pre- tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012			2011			2012			2011			2012		2011
Interest rate derivatives^{(c) (d)}	$	(4	)	$	(5	)	$	(3	)	$	(2	)	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012			2011
Commodity derivatives	$	(65	)	$	(22	)	$	(49	)	$	(13	)

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

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


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

Total	$	3	$	1

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

PEF

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


Instrument / Balance sheet location	June 30, 2012				December 31, 2011
(in millions)	Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
Derivative liabilities, current			$	2			$	2
Derivative liabilities, long-term				1				1
Interest rate derivatives
Derivative liabilities, current				11				—
Derivative liabilities, long-term				—				8

Total derivatives designated as hedging instruments				14				11

Derivatives not designated as hedging instruments
Commodity derivatives^(a)
Prepayments and other current assets	$	2			$	5
Other assets and deferred debits		4				—
Derivative liabilities, current				224				266
Derivative liabilities, long-term				189				222

Total derivatives not designated as hedging instruments		6		413		5		488

Total derivatives	$	6	$	427	$	5	$	499

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

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

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012		2011		2012		2011		2012		2011
Interest rate derivatives^{(c) (d)}	$	(1)	$	(5)	$	—	$	—	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments


Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012		2011
Commodity derivatives	$	(116	)	$	(64	)	$	28	$	(49	)

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

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

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

Derivatives Designated as Hedging Instruments


Instrument	Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives^(a)						Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income^(a)					Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives^(b)
(in millions)	2012			2011			2012			2011		2012		2011
Interest rate derivatives^{(c) (d)}	$	(1	)	$	(5	)	$	(1	)	$	—	$	—	$	—

^(a)	Effective portion.

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

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

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

Derivatives Not Designated as Hedging Instruments



Instrument	Realized Gain or (Loss)^(a)						Unrealized Gain or (Loss)^(b)
(in millions)	2012			2011			2012			2011
Commodity derivatives	$	(195	)	$	(106	)	$	(119	)	$	(31	)

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

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

12. FINANCIAL INFORMATION BY BUSINESS SEGMENT

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

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

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


(in millions)	PEC		PEF		Corporate and Other			Eliminations			Totals
At and for the three months ended June 30, 2012
Revenues
Unaffiliated	$	1,082	$	1,189	$	2		$	—		$	2,273
Intersegment		—		—		72			(72	)		—

Total revenues		1,082		1,189		74			(72	)		2,273
Ongoing Earnings		42		85		(47	)		—			80
Total Assets		16,957		14,657		20,668			(16,558	)		35,724

For the three months ended June 30, 2011
Revenues
Unaffiliated	$	1,060	$	1,193	$	3		$	—		$	2,256
Intersegment		—		—		60			(60	)		—

Total revenues		1,060		1,193		63			(60	)		2,256
Ongoing Earnings		112		141		(42	)		—			211

For the six months ended June 30, 2012
Revenues
Unaffiliated	$	2,167	$	2,193	$	5		$	—		$	4,365
Intersegment		—		1		130			(131	)		—

Total revenues		2,167		2,194		135			(131	)		4,365
Ongoing Earnings		103		214		(94	)		—			223

For the six months ended June 30, 2011
Revenues
Unaffiliated	$	2,193	$	2,224	$	6		$	—		$	4,423
Intersegment		—		1		134			(135	)		—

Total revenues		2,193		2,225		140			(135	)		4,423
Ongoing Earnings		251		252		(90	)		—			413

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

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


	For the three months ended June 30
(in millions)	2012			2011
Ongoing Earnings	$	80		$	211
Tax levelization		(5	)		(4	)
CVO mark-to-market		—			4
Merger and integration costs, net of tax benefit of $6 and $4 (Note 2)		(13	)		(7	)
CR3 indemnification adjustment (charge), net of tax (expense) benefit of $(3) and $18		5			(26	)
Continuing income attributable to noncontrolling interests, net of tax		1			2

Income from continuing operations		68			180
Discontinued operations, net of tax		(4	)		(2	)
Net income attributable to noncontrolling interests, net of tax		(1	)		(2	)

Net income attributable to controlling interests	$	63		$	176


	For the six months ended June 30
(in millions)	2012			2011
Ongoing Earnings	$	223		$	413
Tax levelization		(12	)		(6	)
CVO mark-to-market		8			4
Merger and integration costs, net of tax benefit of $8 and $4 (Note 2)		(18	)		(21	)
CR3 indemnification adjustment (charge), net of tax (expense) benefit of $(3) and $18		5			(26	)
Continuing income attributable to noncontrolling interests, net of tax		3			3

Income from continuing operations		209			367
Discontinued operations, net of tax		7			(4	)
Net income attributable to noncontrolling interests, net of tax		(3	)		(3	)

Net income attributable to controlling interests	$	213		$	360

13. ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations

frequently change and the ultimate costs of compliance cannot always be precisely estimated. We are evaluating the impacts of environmental regulations, which could include the potential need to retire additional generating facilities earlier than their current estimated useful lives.

A. HAZARDOUS AND SOLID WASTE

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

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

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

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

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

PROGRESS ENERGY


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2011	$	17		$	6		$	23
Amount accrued for environmental loss contingencies^(a)		15			2			17
Expenditures for environmental loss contingencies^(b)		(2	)		(4	)		(6	)

Balance, June 30, 2012^(c)	$	30		$	4		$	34

Balance, December 31, 2010	$	20		$	15		$	35
Amount accrued for environmental loss contingencies^(a)		—			3			3
Expenditures for environmental loss contingencies^(b)		(2	)		(9	)		(11	)

Balance, June 30, 2011^(c)	$	18		$	9		$	27

^(a)

Amounts accrued are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012, our accruals were $12 million for the remediation of MGP and other sites and were not material for the remediation of distribution and substations transformers. For the three months ended June 30, 2011, our accruals for environmental loss contingencies were not material.

^(b)	Expenditures are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, our expenditures for environmental loss contingencies were not material.

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

PEC


(in millions)	MGP and Other Sites
Balance, December 31, 2011	$	11
Amount accrued for environmental loss contingencies^(a)		4
Expenditures for environmental loss contingencies^(b)		(1	)

Balance, June 30, 2012^(c)	$	14

Balance, December 31, 2010	$	12
Amount accrued for environmental loss contingencies^(a)		—
Expenditures for environmental loss contingencies^(b)		—

Balance, June 30, 2011^(c)	$	12

^(a)

Amounts accrued are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012, PEC’s accruals were $5 million for the remediation of MGP and other sites. For the three months ended June 30, 2011, PEC’s accruals for the remediation of MGP and other sites were not material.

^(b)	Expenditures are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, PEC’s expenditures for the remediation of MGP and other sites were not material.

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

PEF


(in millions)	MGP and Other Sites			Remediation of Distribution and Substation Transformers			Total
Balance, December 31, 2011	$	6		$	6		$	12
Amount accrued for environmental loss contingencies^(a)		11			2			13
Expenditures for environmental loss contingencies^(b)		(1	)		(4	)		(5	)

Balance, June 30, 2012^(c)	$	16		$	4		$	20

Balance, December 31, 2010	$	8		$	15		$	23
Amount accrued for environmental loss contingencies^(a)		—			3			3
Expenditures for environmental loss contingencies^(b)		(2	)		(9	)		(11	)

Balance, June 30, 2011^(c)	$	6		$	9		$	15

^(a)

Amounts accrued are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012, PEF’s accruals were $7 million for the remediation of MGP and other sites and were not material for the remediation of distribution and substation transformers. For the three months ended June 30, 2011, PEF’s accruals for environmental loss contingencies were not material.

^(b)	Expenditures are for the six months ended June 30, 2012 and 2011. For the three months ended June 30, 2012 and 2011, PEF’s expenditures for environmental loss contingencies were not material.

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

PROGRESS ENERGY

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

PEC

The accruals for PEC’s MGP and other sites relate to one former MGP site and other sites associated with PEC that have required, or are anticipated to require, investigation and/or remediation. Remediation of PEC’s other MGP sites has been substantially completed. During the three and six months ended June 30, 2012, PEC completed a preliminary remedial action plan for its remaining MGP site, which indicates a range of viable remedial approaches with estimated costs of $2 million to $25 million. PEC believes one approach has more merit than the other approaches and increased its accrual for the site to reflect the approximately $7 million estimated cost for the remedial approach considered to have more merit. The maximum amount of the range for all of PEC’s environmental sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. (Ward). The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At June 30, 2012 and December 31, 2011, PEC’s recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against non-participating PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. The court established a “test case” program providing for a determination of liability on the part of a set of representative defendants. Summary judgment motions and responsive pleadings are being filed by and against these defendants and discovery and briefing were completed during the second quarter of 2012. Meanwhile, proceedings with respect to the other defendants have been stayed. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA’s past expenditures in addressing conditions at the site. On September 29, 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. On July 10, 2012, the EPA issued a Special Notice Letter to PEC and the other participating PRPs providing notification of the opportunity to perform and fund the tasks included in Ward OU2. The recipients have 60 days from receipt of the Special Notice Letter to submit a “good faith” offer to perform the work. It is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.

PEF

The accruals for PEF’s MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. Remediation of one MGP site has been substantially completed. At June 30, 2012, PEF’s accrual primarily relates to an MGP site located in Orlando, Fla. The PRP group for the Orlando MGP site has agreed to an interim allocation for the Orlando MGP site and is conducting a feasibility study for remediation of soil and groundwater down to 50 feet, which has not been completed. The study preliminarily indicates a range of viable remedial approaches. During the three months ended June 30, 2012, the PRPs received refined estimates for the range of viable remedial approaches. Additionally, the PRPs believe one approach has more merit than the other approaches; however, the recommendation has not been submitted to or approved by the EPA at this time. During the six months ended June 30, 2012, one participating PRP ended its participation in the PRP group. The PRP allocations have been adjusted accordingly. The PRPs for the Orlando MGP site intend to seek recovery from the non-participating PRP, but no amount for recovery has been recorded. PEF has accrued its best estimate of its obligation with respect to the Orlando MGP site. Based on current estimates for the remedial approach considered to have more merit and its current allocation share, PEF accrued additional obligations of approximately $6 million and $9 million, respectively, during the three and six months ended June 30, 2012, for remediation of soil and groundwater down to 50 feet. Based on current estimates for the range of viable remedial approaches and its current allocation share, PEF could incur additional obligations of up to approximately $8 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material at least 200 feet below the surface. The layer between approximately 50 feet and 200 feet below the surface, which is clay, is not impacted. The maximum amount of the range for remediation, if any, below 200 feet at the Orlando MGP site and for PEF’s other sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. We cannot predict the outcome of this matter.

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

B. AIR AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations governing air and water quality, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act). The air quality controls installed to comply with nitrogen oxides (NOx) and sulfur dioxide (SO₂)

requirements under certain sections of the Clean Air Act (CAA) and the Clean Smokestacks Act, as well as PEC’s plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx and SO₂ for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

After prior mercury regulation was vacated in federal court, the EPA developed maximum achievable control technology (MACT) standards. The Mercury and Air Toxics Standards (MATS), which are the final MACT standards for coal-fired and oil-fired electric steam generating units, became effective on April 16, 2012. Compliance is due three years after the effective date with provision for a one-year extension granted by state agencies on a case-by-case basis. The MATS contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Several petitions regarding portions of the MATS rule have been filed in the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals), including one by the Utility Air Regulatory Group, of which we are a member. On July 20, 2012, the EPA announced that it will reconsider the new source emissions standards contained in the MATS rule. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. Due to significant investments in NOx and SO2 emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy. We are continuing to evaluate the impacts of the MATS on the Utilities. PEF’s Crystal River Units 1 and 2 (CR1 and CR2) are under evaluation for MATS compliance with the potential to be retired. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

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

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

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at CR4 and CR5, which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire CR1 and CR2 as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 were originally scheduled to be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which

was anticipated to be around 2020. As discussed in Note 5B, major construction activities for Levy are being postponed, and the in-service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of developments that may delay the retirement of CR1 and CR2. We are currently evaluating the impacts of the Levy schedule on PEF’s compliance with environmental regulations. We cannot predict the outcome of this matter.

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

14. COMMITMENTS AND CONTINGENCIES

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

A. PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2011 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities’ future needs. At June 30, 2012, our and the Utilities’ contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 Form 10-K.

B. GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At June 30, 2012, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Balance Sheets.

At June 30, 2012, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At June 30, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $222 million, including $48 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications related to discontinued operations have no limitations as to time or maximum potential future payments. At June 30, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $31 million and $63 million, respectively. These amounts included $23 million and $37 million for PEF at June 30, 2012 and December 31, 2011, respectively. Our liabilities decreased primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 4) and the adjustment to the indemnification for the estimated future years’ joint owner replacement power costs related to CR3 (See Note 12). PEF’s liabilities decreased primarily due to the previously mentioned indemnification adjustment related to CR3. During the three and six months ended June 30, 2012, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current

estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

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

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

C. OTHER COMMITMENTS AND CONTINGENCIES

MERGER

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

ENVIRONMENTAL

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

Water Discharge Permit

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

SPENT NUCLEAR FUEL MATTERS

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

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the standard contract and asserting damages incurred through 2005. In 2011, the judge in the U.S. Court of Federal Claims issued a ruling to award PEC substantially all their asserted damages. As a result, PEC recorded the award as an offset for past spent fuel storage costs incurred.

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

SYNTHETIC FUELS MATTERS

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

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

In a second suit filed in the Superior Court for Wake County, N.C., Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), the Progress Affiliates seek declaratory relief consistent with our interpretation of the Asset Purchase Agreement. Global was served with the North Carolina Global Case on April 17, 2003. In May 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates’ declaratory judgment action. In August 2003, the Wake County Superior Court denied Global’s motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court’s order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

OTHER LITIGATION MATTERS

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

15. CONDENSED CONSOLIDATING STATEMENTS

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

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

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

Condensed Consolidating Statement of Comprehensive Income

Three months ended June 30, 2012


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	1,191		$	1,082		$	—		$	2,273
Affiliate revenues		—			—			72			(72	)		—

Total operating revenues		—			1,191			1,154			(72	)		2,273

Operating expenses
Fuel used in electric generation		—			390			346			—			736
Purchased power		—			177			80			—			257
Operation and maintenance		3			246			448			(70	)		627
Depreciation, amortization and accretion		—			92			139			—			231
Taxes other than on income		—			90			54			(2	)		142
Other		—			4			2			(1	)		5

Total operating expenses		3			999			1,069			(73	)		1,998

Operating (loss) income		(3	)		192			85			1			275

Other income
Interest income		—			1			—			—			1
Allowance for equity funds used during construction		—			8			17			—			25
Other, net		—			1			1			(1	)		1

Total other income, net		—			10			18			(1	)		27

Interest charges
Interest charges		64			79			60			—			203
Allowance for borrowed funds used during construction		—			(5	)		(6	)		—			(11	)

Total interest charges, net		64			74			54			—			192

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(67	)		128			49			—			110
Income tax (benefit) expense		(30	)		49			18			5			42
Equity in earnings of consolidated subsidiaries		100			—			—			(100	)		—

Income from continuing operations		63			79			31			(105	)		68
Discontinued operations, net of tax		—			(3	)		(1	)		—			(4	)

Net income		63			76			30			(105	)		64
Net income attributable to noncontrolling interests, net of tax		—			(1	)		—			—			(1	)

Net income attributable to controlling interests	$	63		$	75		$	30		$	(105	)	$	63

Comprehensive income
Comprehensive income	$	59		$	76		$	25		$	(100	)	$	60
Comprehensive income attributable to noncontrolling interests, net of tax		—			(1	)		—			—			(1	)

Comprehensive income attributable to controlling interests	$	59		$	75		$	25		$	(100	)	$	59

Condensed Consolidating Statement of Comprehensive Income

Three months ended June 30, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	1,196		$	1,060		$	—		$	2,256
Affiliate revenues		—			—			61			(61	)		—

Total operating revenues		—			1,196			1,121			(61	)		2,256

Operating expenses
Fuel used in electric generation		—			348			326			—			674
Purchased power		—			256			73			—			329
Operation and maintenance		1			223			343			(57	)		510
Depreciation, amortization and accretion		—			48			131			—			179
Taxes other than on income		—			83			51			—			134
Other		—			2			—			—			2

Total operating expenses		1			960			924			(57	)		1,828

Operating (loss) income		(1	)		236			197			(4	)		428

Other income
Allowance for equity funds used during construction		—			8			18			—			26
Other, net		4			1			—			2			7

Total other income, net		4			9			18			2			33

Interest charges
Interest charges		63			73			53			—			189
Allowance for borrowed funds used during construction		—			(3	)		(6	)		—			(9	)

Total interest charges, net		63			70			47			—			180

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(60	)		175			168			(2	)		281
Income tax (benefit) expense		(24	)		64			60			1			101
Equity in earnings of consolidated subsidiaries		212			—			—			(212	)		—

Income from continuing operations		176			111			108			(215	)		180
Discontinued operations, net of tax		—			(2	)		—			—			(2	)

Net income		176			109			108			(215	)		178
Net income attributable to noncontrolling interests, net of tax		—			(1	)		—			(1	)		(2	)

Net income attributable to controlling interests	$	176		$	108		$	108		$	(216	)	$	176

Comprehensive income
Comprehensive income	$	155		$	103		$	96		$	(197	)	$	157
Comprehensive income attributable to noncontrolling interests, net of tax		—			(1	)		—			(1	)		(2	)

Comprehensive income attributable to controlling interests	$	155		$	102		$	96		$	(198	)	$	155

Condensed Consolidating Statement of Comprehensive Income

Six months ended June 30, 2012


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	2,198		$	2,167		$	—		$	4,365
Affiliate revenues		—			—			131			(131	)		—

Total operating revenues		—			2,198			2,298			(131	)		4,365

Operating expenses
Fuel used in electric generation		—			726			695			—			1,421
Purchased power		—			322			145			—			467
Operation and maintenance		4			406			870			(124	)		1,156
Depreciation, amortization and accretion		—			119			278			—			397
Taxes other than on income		—			172			112			(4	)		280
Other		—			4			2			(1	)		5

Total operating expenses		4			1,749			2,102			(129	)		3,726

Operating (loss) income		(4	)		449			196			(2	)		639

Other income
Interest income		1			1			—			—			2
Allowance for equity funds used during construction		—			17			32			—			49
Other, net		8			2			3			1			14

Total other income, net		9			20			35			1			65

Interest charges
Interest charges		130			152			115			—			397
Allowance for borrowed funds used during construction		—			(9	)		(11	)		—			(20	)

Total interest charges, net		130			143			104			—			377

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(125	)		326			127			(1	)		327
Income tax (benefit) expense		(52	)		122			45			3			118
Equity in earnings of consolidated subsidiaries		286			—			—			(286	)		—

Income from continuing operations		213			204			82			(290	)		209
Discontinued operations, net of tax		—			8			(1	)		—			7

Net income		213			212			81			(290	)		216
Net income attributable to noncontrolling interests, net of tax		—			(2	)		—			(1	)		(3	)

Net income attributable to controlling interests	$	213		$	210		$	81		$	(291	)	$	213

Comprehensive income
Comprehensive income	$	214		$	213		$	80		$	(290	)	$	217
Comprehensive income attributable to noncontrolling interests, net of tax		—			(2	)		—			(1	)		(3	)

Comprehensive income attributable to controlling interests	$	214		$	211		$	80		$	(291	)	$	214

Condensed Consolidating Statement of Comprehensive Income

Six months ended June 30, 2011


(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Operating revenues	$	—		$	2,230		$	2,193		$	—		$	4,423
Affiliate revenues		—			—			135			(135	)		—

Total operating revenues		—			2,230			2,328			(135	)		4,423

Operating expenses
Fuel used in electric generation		—			703			689			—			1,392
Purchased power		—			409			140			—			549
Operation and maintenance		4			434			694			(128	)		1,004
Depreciation, amortization and accretion		—			73			260			—			333
Taxes other than on income		—			168			110			(4	)		274
Other		—			(8	)		—			—			(8	)

Total operating expenses		4			1,779			1,893			(132	)		3,544

Operating (loss) income		(4	)		451			435			(3	)		879

Other income (expense)
Interest income		—			1			—			—			1
Allowance for equity funds used during construction		—			17			38			—			55
Other, net		4			6			(2	)		2			10

Total other income, net		4			24			36			2			66

Interest charges
Interest charges		136			148			104			—			388
Allowance for borrowed funds used during construction		—			(7	)		(11	)		—			(18	)

Total interest charges, net		136			141			93			—			370

(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries		(136	)		334			378			(1	)		575
Income tax (benefit) expense		(55	)		124			140			(1	)		208
Equity in earnings of consolidated subsidiaries		441			—			—			(441	)		—

Income from continuing operations		360			210			238			(441	)		367
Discontinued operations, net of tax		—			(3	)		(1	)		—			(4	)

Net income		360			207			237			(441	)		363
Net income attributable to noncontrolling interests, net of tax		—			(2	)		—			(1	)		(3	)

Net income attributable to controlling interests	$	360		$	205		$	237		$	(442	)	$	360

Comprehensive income
Comprehensive income	$	343		$	202		$	228		$	(427	)	$	346
Comprehensive income attributable to noncontrolling interests, net of tax		—			(2	)		—			(1	)		(3	)

Comprehensive income attributable to controlling interests	$	343		$	200		$	228		$	(428	)	$	343

Condensed Consolidating Balance Sheet

June 30, 2012


(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Utility plant, net	$	—	$	10,710	$	12,398	$	84		$	23,192

Current assets
Cash and cash equivalents		6		33		34		—			73
Receivables, net		—		375		474		—			849
Notes receivable from affiliated companies		62		—		388		(450	)		—
Regulatory assets		—		266		36		—			302
Derivative collateral posted		—		103		21		—			124
Prepayments and other current assets		137		934		1,099		(131	)		2,039

Total current assets		205		1,711		2,052		(581	)		3,387

Deferred debits and other assets
Investment in consolidated subsidiaries		13,871		—		—		(13,871	)		—
Regulatory assets		—		1,481		1,473		—			2,954
Goodwill		—		—		—		3,655			3,655
Nuclear decommissioning trust funds		—		593		1,164		—			1,757
Other assets and deferred debits		115		235		875		(446	)		779

Total deferred debits and other assets		13,986		2,309		3,512		(10,662	)		9,145

Total assets	$	14,191	$	14,730	$	17,962	$	(11,159	)	$	35,724

CAPITALIZATION AND LIABILITIES
Equity
Common stock equity	$	9,897	$	4,770	$	5,432	$	(10,202	)	$	9,897
Noncontrolling interests		—		3		—		—			3

Total equity		9,897		4,773		5,432		(10,202	)		9,900

Preferred stock of subsidiaries		—		34		59		—			93
Long-term debt, affiliate		—		309		—		(36	)		273
Long-term debt, net		3,992		4,057		4,690		—			12,739

Total capitalization		13,889		9,173		10,181		(10,238	)		23,005

Current liabilities
Current portion of long-term debt		—		425		500		—			925
Short-term debt		201		144		—		—			345
Notes payable to affiliated companies		—		447		3		(450	)		—
Derivative liabilities		—		237		89		—			326
Other current liabilities		78		912		1,117		(133	)		1,974

Total current liabilities		279		2,165		1,709		(583	)		3,570

Deferred credits and other liabilities
Noncurrent income tax liabilities		—		1,006		2,084		(420	)		2,670
Regulatory liabilities		—		905		1,622		85			2,612
Other liabilities and deferred credits		23		1,481		2,366		(3	)		3,867

Total deferred credits and other liabilities		23		3,392		6,072		(338	)		9,149

Total capitalization and liabilities	$	14,191	$	14,730	$	17,962	$	(11,159	)	$	35,724

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

Six months ended June 30, 2012


(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	406		$	368		$	458		$	(481	)	$	751

Investing activities
Gross property additions		—			(380	)		(700	)		—			(1,080	)
Nuclear fuel additions		—			(15	)		(50	)		—			(65	)
Purchases of available-for-sale securities and other investments		—			(354	)		(271	)		—			(625	)
Proceeds from available-for-sale securities and other investments		—			354			256			—			610
Changes in advances to affiliated companies		(9	)		—			(169	)		178			—
Other investing activities		(13	)		25			70			(1	)		81

Net cash used by investing activities		(22	)		(370	)		(864	)		177			(1,079	)

Financing activities
Issuance of common stock, net		6			—			—			—			6
Dividends paid on common stock		(446	)		—			—			—			(446	)
Dividends paid to parent		—			(173	)		(310	)		483			—
Payments of short-term debt with original maturities greater than 90 days		—			(65	)		—			—			(65	)
Proceeds from issuance of short-term debt with original maturities greater than 90 days		—			65			—			—			65
Net decrease in short-term debt		(49	)		(89	)		(188	)		—			(326	)
Proceeds from issuance of long-term debt, net		444			—			988			—			1,432
Retirement of long-term debt		(450	)		—			—			—			(450	)
Changes in advances from affiliated companies		—			209			(31	)		(178	)		—
Other financing activities		—			(4	)		(40	)		(1	)		(45	)

Net cash (used) provided by financing activities		(495	)		(57	)		419			304			171

Net (decrease) increase in cash and cash equivalents		(111	)		(59	)		13			—			(157	)
Cash and cash equivalents at beginning of period		117			92			21			—			230

Cash and cash equivalents at end of period	$	6		$	33		$	34		$	—		$	73

Condensed Consolidating Statement of Cash Flows

Six months ended June 30, 2011


(in millions)	Parent			Subsidiary Guarantor			Non-Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	477		$	413		$	567		$	(677	)	$	780

Investing activities
Gross property additions		—			(419	)		(585	)		—			(1,004	)
Nuclear fuel additions		—			(13	)		(80	)		—			(93	)
Purchases of available-for-sale securities and other investments		—			(3,093	)		(294	)		—			(3,387	)
Proceeds from available-for-sale securities and other investments		—			3,095			269			—			3,364
Changes in advances to affiliated companies		(80	)		22			40			18			—
Contributions to consolidated subsidiaries		(10	)		—			—			10			—
Other investing activities		—			74			8			—			82

Net cash used by investing activities		(90	)		(334	)		(642	)		28			(1,038	)

Financing activities
Issuance of common stock, net		26			—			—			—			26
Dividends paid on common stock		(366	)		—			—			—			(366	)
Dividends paid to parent		—			(403	)		(275	)		678			—
Net increase in short-term debt		49			67			198			—			314
Proceeds from issuance of long-term debt, net		494			—			—			—			494
Retirement of long-term debt		(700	)		—			—			—			(700	)
Changes in advances from affiliated companies		—			16			3			(19	)		—
Contributions from parent		—			10			—			(10	)		—
Other financing activities		—			(6	)		(63	)		—			(69	)

Net cash used by financing activities		(497	)		(316	)		(137	)		649			(301	)

Net decrease in cash and cash equivalents		(110	)		(237	)		(212	)		—			(559	)
Cash and cash equivalents at beginning of period		110			270			231			—			611

Cash and cash equivalents at end of period	$	—		$	33		$	19		$	—		$	52

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