UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 
 FORM 10-Q
 
 xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the quarterly period ended June 30, 2009
 
 OR
 
 oTRANSITION REPORT PURSUANT TO SECTION 13 OR
 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the transition period from                      to                    .
 
 
 Commission File Number
Exact name of registrants as specified in their charters, states of incorporation, addresses of principal executive offices,
and telephone numbers
I.R.S. Employer Identification Numberpgn logo1-15929
Progress Energy, Inc.
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone:   (919) 546-6111
State of Incorporation: North Carolina
56-21554811-3382
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
410 South Wilmington Street
Raleigh, North Carolina  27601-1748
Telephone:   (919) 546-6111
State of Incorporation: North Carolina
56-01654651-3274
Florida Power Corporation
d/b/a Progress Energy Florida, Inc.
299 First Avenue North
St. Petersburg, Florida  33701
Telephone:   (727) 820-5151
State of Incorporation: Florida
59-0247770
 
 NONE
 (Former name, former address and former fiscal year, if changed since last report)
 
 Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.
 
 Progress Energy, Inc. (Progress Energy)
Yes
x
No
oCarolina Power & Light Company (PEC)
Yes
x
No
oFlorida Power Corporation (PEF)
Yes
o
No
x
 
 
 
 Indicate by check mark whether each registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post
such files).
 
 Progress Energy
Yes
o
No
oPEC
Yes
o
No
oPEF
Yes
o
No
o
 
 Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:
 
 Progress Energy
Large accelerated filer
x
Accelerated filer
oNon-accelerated filer
o
Smaller reporting company
oPEC
Large accelerated filer
o
Accelerated filer
oNon-accelerated filer
x
Smaller reporting company
oPEF
Large accelerated filer
o
Accelerated filer
oNon-accelerated filer
x
Smaller reporting company
o
 
 Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
 Progress Energy
Yes
o
No
xPEC
Yes
o
No
xPEF
Yes
o
No
x
 
 At August 3, 2009, each registrant had the following shares of common stock outstanding:
 
 Registrant
Description
SharesProgress Energy
Common Stock (Without Par Value)
279,297,789PEC
Common Stock (Without Par Value)
159,608,055 (all of which were held directly by Progress Energy, Inc.)PEF
Common Stock (Without Par Value)
100 (all of which were held indirectly by Progress Energy, Inc.)
 
 This combined Form 10-Q is filed separately by three registrants: Progress Energy, PEC and PEF (collectively, the Progress Registrants). Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating
exclusively to the other registrants.
 
 PEF meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.
  2
  
 TABLE OF CONTENTSGLOSSARY OF TERMSSAFE HARBOR FOR FORWARD-LOOKING STATEMENTSPART I.  FINANCIAL INFORMATIONITEM 1.
FINANCIAL STATEMENTSUnaudited Condensed Interim Financial Statements:Progress Energy, Inc. (Progress Energy)Unaudited CondensedConsolidated Statements of IncomeUnauditedCondensedConsolidated Balance SheetsUnauditedCondensedConsolidated Statements of Cash FlowsCarolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)UnauditedCondensedConsolidated Statements of IncomeUnauditedCondensedConsolidated Balance SheetsUnauditedCondensedConsolidated Statements of Cash FlowsFlorida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)UnauditedCondensedStatements of IncomeUnauditedCondensedBalance SheetsUnaudited Condensed Statements of Cash FlowsCombined Notes to Unaudited Condensed Interim Financial Statements for Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a Progress Energy Florida, Inc.ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKITEM 4.
CONTROLS AND PROCEDURESITEM 4T.
CONTROLS AND PROCEDURESPART II.  OTHER INFORMATIONITEM 1.
LEGAL PROCEEDINGSITEM 1A.
RISK FACTORSITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDSITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSITEM 5.
OTHER INFORMATIONITEM 6.
EXHIBITSSIGNATURES
 
  3
  
 GLOSSARY OF TERMS
 
 We use the words “Progress Energy,” “we,” “us” or “our” with respect to certain information to indicate that such information relates to Progress Energy, Inc. and its subsidiaries on a consolidated basis. When appropriate, the parent holding company or the subsidiaries of Progress Energy are
specifically identified on an unconsolidated basis as we discuss their various business activities.
  The following abbreviations or acronyms are used by the Progress Registrants:
  TERM
DEFINITION2008 Form 10-K
Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2008401(k)
Progress Energy 401(k) Savings & Stock Ownership PlanAFUDC
Allowance for funds used during constructionARO
Asset retirement obligationASLB
Atomic Safety and Licensing BoardAsset Purchase Agreement
Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000Audit Committee
Audit and Corporate Performance Committee of Progress Energy’s board of directorsBART
Best Available Retrofit TechnologyBroad River
Broad River LLC’s Broad River FacilityBrunswick
PEC’s Brunswick Nuclear PlantBtu
British thermal unitCAIR
Clean Air Interstate RuleCAMR
Clean Air Mercury RuleCAVR
Clean Air Visibility RuleCCO
Competitive Commercial OperationsCERCLA or Superfund
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amendedCeredo
Ceredo Synfuel LLCClean Smokestacks Act
North Carolina Clean Smokestacks Act, enacted in June 2002Coal Mining
Two Progress Fuels subsidiaries engaged in the coal mining business, which were sold on March 7, 2008the Code
Internal Revenue CodeCO2
Carbon dioxideCOL
Combined licenseColona
Colona Synfuel Limited Partnership, LLLPCorporate and Other
Corporate and Other segment primarily includes the Parent, Progress Energy Service Company and miscellaneous other nonregulated businessesCR1 and CR2
PEF’s Crystal River Units No. 1 and 2 coal-fired steam turbinesCR3
PEF’s Crystal River Unit No. 3 Nuclear PlantCR4 and CR5
PEF’s Crystal River Units No. 4 and 5 coal-fired steam turbinesCVO
Contingent value obligationD.C. Court of Appeals
U.S. Court of Appeals for the District of Columbia CircuitDeSoto
DeSoto County Generating Co., LLCDixie Fuels
Dixie Fuels LimitedDOE
United States Department of EnergyDSM
Demand-side managementEarthco
Four coal-based solid synthetic fuels limited liability companies of which three were wholly ownedECCR
Energy Conservation Cost Recovery ClauseECRC
Environmental Cost Recovery ClauseEIP
Equity Incentive PlanEPACT
Energy Policy Act of 2005EPC
Engineering, procurement and constructionERO
Electric reliability organization  4
  ESOP
Employee Stock Ownership PlanFASB
Financial Accounting Standards BoardFDEP
Florida Department of Environmental ProtectionFERC
Federal Energy Regulatory CommissionFGT
Florida Gas Transmission Company, LLCthe Florida Global Case
U.S. Global, LLC v. Progress Energy, Inc. et alFlorida Progress
Florida Progress CorporationFlorida RPS
Florida renewable portfolio standardFPSC
Florida Public Service CommissionFRCC
Florida Reliability Coordinating CouncilFunding Corp.
Florida Progress Funding Corporation, a wholly owned subsidiary of Florida ProgressGAAP
Accounting principles generally accepted in the United States of AmericaGas
Natural gas drilling and production businessthe Georgia Contracts
Full-requirements contracts with 16 Georgia electric membership cooperatives formerly serviced by CCOGeorgia Operations
Former reporting unit consisting of the Effingham, Monroe, Walton and Washington nonregulated generation plants in service and the Georgia ContractsGHG
Greenhouse gasGlobal
U.S. Global, LLCGridSouth
GridSouth Transco, LLCHarris
PEC’s Shearon Harris Nuclear PlantkV
KilovoltkVA
Kilovolt-amperekWh
Kilowatt-hoursLevy
Proposed nuclear plant in Levy County, FloridaLIBOR
London Inter Bank Offering RateMACT
Maximum achievable control technologyMD&A
Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in Part I, Item 2 of this Form 10-QMedicare Act
Medicare Prescription Drug, Improvement and Modernization Act of 2003MGP
Manufactured gas plantMW
MegawattsMWh
Megawatt-hoursMoody’s
Moody’s Investors Service, Inc.NAAQS
National Ambient Air Quality StandardsNC REPS
North Carolina Renewable Energy and Energy Efficiency Portfolio StandardNCUC
North Carolina Utilities CommissionNDT
Nuclear decommissioning trustNEIL
Nuclear Electric Insurance LimitedNERC
North American Electric Reliability CorporationNorth Carolina Global Case
Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLCthe Notes Guarantee
Florida Progress’ full and unconditional guarantee of the Subordinated NotesNOx
Nitrogen OxidesNOx SIP Call
EPA NOx State Implementation Plan Call rule which requires 22 states including North Carolina, South Carolina and Georgia (but excluding Florida) to further reduce emissions of nitrogen oxidesNSR
New Source Review requirements by the EPANRC
United States Nuclear Regulatory CommissionO&M
Operation and maintenance expenseOATT
Open Access Transmission TariffOCI
Other comprehensive incomeOPC
Florida’s Office of Public CounselOPEB
Postretirement benefits other than pensionsORS
South Carolina’s Office of Regulatory Staffthe Parent
Progress Energy, Inc. holding company on an unconsolidated basis  5
  PEC
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.PEF
Florida Power Corporation d/b/a Progress Energy Florida, Inc.PESC
Progress Energy Service Company, LLCPower Agency
North Carolina Eastern Municipal Power AgencyPreferred Securities
7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the TrustPreferred Securities Guarantee
Florida Progress’ guarantee of all distributions related to the Preferred SecuritiesProgress Affiliates
Five affiliated coal-based solid synthetic fuels facilitiesProgress Energy
Progress Energy, Inc. and subsidiaries on a consolidated basisProgress Registrants
The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEFProgress Fuels
Progress Fuels Corporation, formerly Electric Fuels CorporationPRP
Potentially responsible party, as defined in CERCLAPSSP
Performance Share Sub-PlanPUHCA 1935
Public Utility Holding Company Act of 1935, as amendedPUHCA 2005
Public Utility Holding Company Act of 2005PVI
Progress Energy Ventures, Inc., formerly referred to as Progress Ventures, Inc.QF
Qualifying facilityRCA
Revolving credit agreementReagents
Commodities such as ammonia and limestone used in emissions control technologiesREC
Renewable energy certificatesREPS
Renewable energy portfolio standardRockport
Indiana Michigan Power Company’s Rockport Unit No. 2Robinson
PEC’s Robinson Nuclear PlantRSU
Restricted stock unitRTO
Regional transmission organizationSCPSC
Public Service Commission of South CarolinaSection 29
Section 29 of the CodeSection 29/45K
General business tax credits earned after December 31, 2005 for synthetic fuels production in accordance with Section 29Section 316(b)
Section 316(b) of the Clean Water Act(See Note/s “#”)
For all sections, this is a cross-reference to the Combined Notes to the Unaudited Condensed Interim Financial Statements contained in PART I, Item 1 of this Form 10-QSERC
SERC Reliability CorporationS&P
Standard & Poor’s Rating ServicesSNG
Southern Natural Gas CompanySO2
Sulfur dioxideSubordinated Notes
7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.Tax Agreement
Intercompany Income Tax Allocation AgreementTerminals
Coal terminals and docks in West Virginia and Kentucky, which were sold on March 7, 2008the Trust
FPC Capital Ithe Utilities
Collectively, PEC and PEFVIE
Variable interest entityWard
Ward Transformer site located in Raleigh, N.C.Ward OU1
Operable unit for stream segments downstream from the Ward siteWard OU2
Operable unit for further investigation at the Ward facility and certain adjacent areas
 6
 
 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
  In this combined report, each of the Progress Registrants makes forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-Q that are not historical facts are forward looking and, accordingly, involve estimates,
projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such
statement is made.
  In addition, examples of forward-looking statements discussed in this Form 10-Q include, but are not limited to, statements made in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the sub-heading “Results of Operations”
about trends and uncertainties; “Liquidity and Capital Resources” about operating cash flows, future liquidity requirements and estimated capital expenditures and “Other Matters” about goodwill, our synthetic fuels tax credits, the effects of new environmental regulations, meeting anticipated demand in our regulated service territories, potential nuclear construction and changes in the regulatory environment.
  Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and the Energy Policy Act of 2005 (EPACT); the ability to meet the
anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; the financial resources and capital needed to comply with environmental laws and renewable energy portfolio standards and our ability to recover related eligible costs under cost-recovery clauses or base rates; our ability to meet current and future renewable energy requirements; the inherent risks associated with the operation
and potential construction of nuclear facilities, including environmental, health, regulatory and financial risks; the impact on our facilities and businesses from a terrorist attack; weather and drought conditions that directly influence the production, delivery and demand for electricity; recurring seasonal fluctuations in demand for electricity; the ability to recover in a timely manner, if at all, costs associated with future significant weather events through the regulatory process; economic fluctuations
and the corresponding impact on our customers, including downturns in the housing and consumer credit markets; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; the Progress Registrants’ ability to control costs, including operations and maintenance expense (O&M) and large construction projects; the ability of our subsidiaries to pay upstream dividends or distributions to Progress Energy, Inc. holding company (the
Parent); the duration and severity of the recession and current financial market conditions; the ability to successfully access capital markets on favorable terms; the stability of commercial credit markets and our access to short- and long-term credit; the impact that increases in leverage may have on each of the Progress Registrants; the Progress Registrants’ ability to maintain their current credit ratings and the impact on the Progress Registrants’ financial condition and ability to meet their
cash and other financial obligations in the event their credit ratings are downgraded; our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); the investment performance of our nuclear decommissioning trust (NDT) funds; the investment performance of the assets of our pension and benefit plans and resulting impact on future funding requirements; the impact of potential goodwill impairments;
the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact our nonreporting subsidiaries.
  These and other risk factors are detailed from time to time in the Progress Registrants’ filings with the SEC. Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors section in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2008 (2008
Form 10-K), which was filed with the SEC on March 2, 2009, and are updated for material changes, if any, in this Form 10-Q and in our other SEC filings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on the Progress Registrants.
  7
  PART I.  FINANCIAL INFORMATION
 
 ITEM 1.                 FINANCIAL STATEMENTS
  PROGRESS ENERGY, INC.
 UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
 June 30, 2009
 
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOMEThree months ended June 30,


Six months ended June 30,(in millions except per share data)

2009


2008


2009


2008Operating revenues

$
2,312


$
2,244


$
4,754


$
4,310Operating expensesFuel used in electric generation


826



696



1,780



1,393Purchased power


257



330



474



562Operation and maintenance


484



488



937



931Depreciation, amortization and accretion


226



208



506



414Taxes other than on income


130



125



273



246Other


10



(9
)


12



(7
)Total operating expenses


1,933



1,838



3,982



3,539Operating income


379



406



772



771Other income (expense)Interest income


2



5



6



12Allowance for equity funds used during construction


36



27



75



50Other, net


13



3



12



(2
)Total other income, net


51



35



93



60Interest chargesInterest charges


181



154



360



315Allowance for borrowed funds used during construction


(12
)


(8
)


(24
)


(16
)Total interest charges, net


169



146



336



299Income from continuing operations before income tax


261



295



529



532Income tax expense


86



95



171



179Income from continuing operations


175



200



358



353Discontinued operations, net of tax


(1
)


5



(1
)


66Net income


174



205



357



419Net income attributable to noncontrolling interests, net of tax


–



–



(1
)


(5
)Net income attributable to controlling interests

$
174


$
205


$
356


$
414Average common shares outstanding – basic


280



261



278



261Basic and diluted earnings per common shareIncome from continuing operations attributable to controlling interests, net of tax

$
0.62


$
0.76


$
1.28


$
1.34Discontinued operations attributable to controlling interests, net of tax


–



0.02



–



0.25Net income attributable to controlling interests

$
0.62


$
0.78


$
1.28


$
1.59Dividends declared per common share

$
0.620


$
0.615


$
1.240


$
1.230Amounts attributable to controlling interestsIncome from continuing operations attributable to controlling interests, net of tax

$
175


$
200


$
357


$
349Discontinued operations attributable to controlling interests, net of tax


(1
)


5



(1
)


65Net income attributable to controlling interests

$
174


$
205


$
356


$
414See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
  8
  PROGRESS ENERGY, INC.UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS(in millions)

June 30, 2009


December 31, 2008ASSETSUtility plantUtility plant in service

$
27,822


$
26,326Accumulated depreciation


(11,396
)


(11,298
)Utility plant in service, net


16,426



15,028Held for future use


38



38Construction work in progress


2,024



2,745Nuclear fuel, net of amortization


486



482Total utility plant, net


18,974



18,293Current assetsCash and cash equivalents


452



180Receivables, net


882



867Inventory


1,353



1,239Regulatory assets


426



533Derivative collateral posted


302



353Income taxes receivable


72



194Prepayments and other current assets


218



154Total current assets


3,705



3,520Deferred debits and other assetsRegulatory assets


2,623



2,567Nuclear decommissioning trust funds


1,160



1,089Miscellaneous other property and investments


450



446Goodwill


3,655



3,655Other assets and deferred debits


307



303Total deferred debits and other assets


8,195



8,060Total assets

$
30,874


$
29,873CAPITALIZATION AND LIABILITIESCommon stock equityCommon stock without par value, 500 million shares authorized, 279 million and 264 million shares issued and outstanding, respectively

$
6,776


$
6,206Unearned ESOP shares (1 million shares)


(12
)


(25
)Accumulated other comprehensive loss


(96
)


(116
)Retained earnings


2,621



2,622Total common stock equity


9,289



8,687Noncontrolling interests


6



6Total equity


9,295



8,693Preferred stock of subsidiaries


93



93Long-term debt, affiliate


272



272Long-term debt, net


10,834



10,387Total capitalization


20,494



19,445Current liabilitiesCurrent portion of long-term debt


400



–Short-term debt


500



1,050Accounts payable


853



912Interest accrued


181



167Dividends declared


174



164Customer deposits


290



282Derivative liabilities


409



493Other current liabilities


411



418Total current liabilities


3,218



3,486Deferred credits and other liabilitiesNoncurrent income tax liabilities


941



818Accumulated deferred investment tax credits


122



127Regulatory liabilities


2,276



2,181Asset retirement obligations


1,518



1,471Accrued pension and other benefits


1,602



1,594Capital lease obligations


227



231Derivative liabilities


244



269Other liabilities and deferred credits


232



251Total deferred credits and other liabilities


7,162



6,942Commitments and contingencies (Notes 14 and 15)Total capitalization and liabilities

$
30,874


$
29,873See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
  9
  PROGRESS ENERGY, INC.UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS(in millions)Six months ended June 30

2009


2008Operating activitiesNet income

$
357


$
419Adjustments to reconcile net income to net cash provided by operating activitiesDepreciation, amortization and accretion


576



467Deferred income taxes and investment tax credits, net


13



98Deferred fuel cost (credit)


129



(166
)Allowance for equity funds used during construction


(75
)


(50
)Gain on sale of assets


–



(71
)Other adjustments to net income


118



57Cash (used) provided by changes in operating assets and liabilitiesReceivables


(36
)


224Inventory


(118
)


(116
)Prepayments and other current assets


48



(28
)Income taxes, net


110



(60
)Accounts payable


(30
)


293Derivative collateral held


–



312Other current liabilities


13



10Other assets and deferred debits


40



(33
)Other liabilities and deferred credits


(50
)


1Net cash provided by operating activities


1,095



1,357Investing activitiesGross property additions


(1,172
)


(1,260
)Nuclear fuel additions


(60
)


(43
)Proceeds from sales of discontinued operations and other assets, net of cash divested


–



64Purchases of available-for-sale securities and other investments


(982
)


(836
)Proceeds from available-for-sale securities and other investments


960



816Other investing activities


(3
)


(15
)Net cash used by investing activities


(1,257
)


(1,274
)Financing activitiesIssuance of common stock


545



42Dividends paid on common stock


(347
)


(320
)Payments of short-term debt with original maturities greater than 90 days


(29
)


(176
)Net (decrease) increase in short-term debt


(621
)


318Proceeds from issuance of long-term debt, net


1,337



1,798Retirement of long-term debt


(400
)


(427
)Cash distributions to noncontrolling interests


(4
)


(85
)Other financing activities


(47
)


(65
)Net cash provided by financing activities


434



1,085Net increase in cash and cash equivalents


272



1,168Cash and cash equivalents at beginning of period


180



255Cash and cash equivalents at end of period

$
452


$
1,423Supplemental disclosuresSignificant noncash transactionsAccrued property additions

$
301


$
263See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
  10
  CAROLINA POWER & LIGHT COMPANY
 d/b/a PROGRESS ENERGY CAROLINAS, INC.
 UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
 June 30, 2009
 
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOMEThree months ended June 30,


Six months ended June 30,(in millions)

2009


2008


2009


2008Operating revenues

$
1,076


$
1,048


$
2,254


$
2,116Operating expensesFuel used in electric generation


383



323



825



679Purchased power


57



72



114



121Operation and maintenance


283



275



542



523Depreciation, amortization and accretion


118



129



235



255Taxes other than on income


51



49



105



99Other


2



(5
)


2



(6
)Total operating expenses


894



843



1,823



1,671Operating income


182



205



431



445Other income (expense)Interest income


1



2



3



7Allowance for equity funds used during construction


7



5



16



10Other, net


4



6



(3
)


5Total other income, net


12



13



16



22Interest chargesInterest charges


52



52



109



110Allowance for borrowed funds used during construction


(3
)


(2
)


(6
)


(4
)Total interest charges, net


49



50



103



106Income before income tax


145



168



344



361Income tax expense


51



64



122



134Net income


94



104



222



227Net loss attributable to noncontrolling interests, net of tax


1



–



1



–Net income attributable to controlling interests


95



104



223



227Preferred stock dividend requirement


–



–



1



1Net income available to common stockholders

$
95


$
104


$
222


$
226See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
 11
 CAROLINA POWER & LIGHT COMPANYd/b/a PROGRESS ENERGY CAROLINAS, INC.UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS(in millions)

June 30, 2009


December 31, 2008ASSETSUtility plantUtility plant in service

$
16,237


$
15,698Accumulated depreciation


(7,471
)


(7,352
)Utility plant in service, net


8,766



8,346Held for future use


3



3Construction work in progress


450



660Nuclear fuel, net of amortization


351



376Total utility plant, net


9,570



9,385Current assetsCash and cash equivalents


18



18Receivables, net


453



502Receivables from affiliated companies


16



29Notes receivable from affiliated companies


130



55Inventory


691



633Deferred fuel cost


148



207Income taxes receivable


32



98Prepayments and other current assets


45



28Total current assets


1,533



1,570Deferred debits and other assetsRegulatory assets


1,247



1,243Nuclear decommissioning trust funds


725



672Miscellaneous other property and investments


203



197Other assets and deferred debits


98



98Total deferred debits and other assets


2,273



2,210Total assets

$
13,376


$
13,165CAPITALIZATION AND LIABILITIESCommon stock equityCommon stock without par value, 200 million shares authorized, 160 million shares issued and outstanding

$
2,099


$
2,083Unearned ESOP common stock


(12
)


(25
)Accumulated other comprehensive loss


(31
)


(35
)Retained earnings


2,298



2,278Total common stock equity


4,354



4,301Noncontrolling interests


3



4Total equity


4,357



4,305Preferred stock


59



59Long-term debt, net


3,709



3,509Total capitalization


8,125



7,873Current liabilitiesShort-term debt


–



110Accounts payable


296



377Payables to affiliated companies


58



82Interest accrued


66



59Customer deposits


90



82Derivative liabilities


48



82Other current liabilities


178



173Total current liabilities


736



965Deferred credits and other liabilitiesNoncurrent income tax liabilities


1,162



1,111Accumulated deferred investment tax credits


113



115Regulatory liabilities


1,082



987Asset retirement obligations


1,158



1,122Accrued pension and other benefits


863



856Other liabilities and deferred credits


137



136Total deferred credits and other liabilities


4,515



4,327Commitments and contingencies (Notes 14 and 15)Total capitalization and liabilities

$
13,376


$
13,165See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
  12
  CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS(in millions)Six months ended June 30

2009


2008Operating activitiesNet income

$
222


$
227Adjustments to reconcile net income to net cash provided by operating activitiesDepreciation, amortization and accretion


286



304Deferred income taxes and investment tax credits, net


10



15Deferred fuel cost


92



30Allowance for equity funds used during construction


(16
)


(10
)Other adjustments to net income


52



19Cash provided (used) by changes in operating assets and liabilitiesReceivables


42



(27
)Receivables from affiliated companies


13



30Inventory


(60
)


(36
)Prepayments and other current assets


7



20Income taxes, net


63



(78
)Accounts payable


(43
)


74Payables to affiliated companies


(24
)


16Other current liabilities


(6
)


26Other assets and deferred debits


25



(21
)Other liabilities and deferred credits


(17
)


(26
)Net cash provided by operating activities


646



563Investing activitiesGross property additions


(402
)


(331
)Nuclear fuel additions


(42
)


(42
)Purchases of available-for-sale securities and other investments


(517
)


(337
)Proceeds from available-for-sale securities and other investments


492



321Changes in advances to affiliated companies


(75
)


(39
)Other investing activities


–



(6
)Net cash used by investing activities


(544
)


(434
)Financing activitiesDividends paid on preferred stock


(1
)


(1
)Dividends paid to parent


(200
)


–Net decrease in short-term debt


(110
)


–Proceeds from issuance of long-term debt, net


595



322Retirement of long-term debt


(400
)


(300
)Changes in advances from affiliated companies


–



(154
)Other financing activities


14



(3
)Net cash used by financing activities


(102
)


(136
)Net decrease in cash and cash equivalents


–



(7
)Cash and cash equivalents at beginning of period


18



25Cash and cash equivalents at end of period

$
18


$
18Supplemental disclosuresSignificant noncash transactionsAccrued property additions

$
128


$
80See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
  13
  FLORIDA POWER CORPORATION
 d/b/a PROGRESS ENERGY FLORIDA, INC.
 UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
 June 30, 2009
 
 UNAUDITED CONDENSED STATEMENTS of INCOMEThree months ended June 30,


Six months ended June 30,(in millions)

2009


2008


2009


2008Operating revenues

$
1,234


$
1,194


$
2,496


$
2,190Operating expensesFuel used in electric generation


443



373



955



714Purchased power


200



258



360



441Operation and maintenance


204



217



406



420Depreciation, amortization and accretion


105



76



265



152Taxes other than on income


80



76



168



147Other


7



(4
)


7



(4
)Total operating expenses


1,039



996



2,161



1,870Operating income


195



198



335



320Other income (expense)Interest income


–



1



1



2Allowance for equity funds used during construction


29



22



59



40Other, net


7



–



7



(1
)Total other income, net


36



23



67



41Interest chargesInterest charges


64



45



131



95Allowance for borrowed funds used during construction


(9
)


(6
)


(18
)


(12
)Total interest charges, net


55



39



113



83Income before income tax


176



182



289



278Income tax expense


57



57



81



86Net income


119



125



208



192Preferred stock dividend requirement


–



–



1



1Net income available to common stockholders

$
119


$
125


$
207


$
191See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.
  14
  FLORIDA POWER CORPORATIONd/b/a PROGRESS ENERGY FLORIDA, INC.UNAUDITED CONDENSED BALANCE SHEETS(in millions)

June 30, 2009


December 31, 2008ASSETSUtility plantUtility plant in service

$
11,401


$
10,449Accumulated depreciation


(3,859
)


(3,885
)Utility plant in service, net


7,542



6,564Held for future use


35



35Construction work in progress


1,574



2,085Nuclear fuel, net of amortization


135



106Total utility plant, net


9,286



8,790Current assetsCash and cash equivalents


19



19Receivables, net


426



362Receivables from affiliated companies


7



15Inventory


663



606Regulatory assets


278



326Derivative collateral posted


294



335Prepayments and other current assets


155



139Total current assets


1,842



1,802Deferred debits and other assetsRegulatory assets


1,376



1,324Nuclear decommissioning trust funds


435



417Miscellaneous other property and investments


41



37Other assets and deferred debits


94



101Total deferred debits and other assets


1,946



1,879Total assets

$
13,074


$
12,471CAPITALIZATION AND LIABILITIESCommon stock equityCommon stock without par value, 60 million shares authorized, 100 shares issued and outstanding

$
1,430


$
1,116Accumulated other comprehensive income (loss)


2



(1
)Retained earnings


2,491



2,284Total common stock equity


3,923



3,399Preferred stock


34



34Long-term debt, net


3,882



4,182Total capitalization


7,839



7,615Current liabilitiesCurrent portion of long-term debt


300



–Short-term debt


–



371Notes payable to affiliated companies


478



72Accounts payable


540



514Payables to affiliated companies


48



55Interest accrued


46



51Customer deposits


200



200Derivative liabilities


361



380Other current liabilities


172



128Total current liabilities


2,145



1,771Deferred credits and other liabilitiesNoncurrent income tax liabilities


667



634Accumulated deferred investment tax credits


9



12Regulatory liabilities


1,077



1,076Asset retirement obligations


360



349Accrued pension and other benefits


495



494Capital lease obligations


213



216Derivative liabilities


184



209Other liabilities and deferred credits


85



95Total deferred credits and other liabilities


3,090



3,085Commitments and contingencies (Notes 14 and 15)Total capitalization and liabilities

$
13,074


$
12,471See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.
  15
  FLORIDA POWER CORPORATIONd/b/a PROGRESS ENERGY FLORIDA, INC.UNAUDITED CONDENSED STATEMENTS of CASH FLOWS(in millions)Six months ended June 30

2009


2008Operating activitiesNet income

$
208


$
192Adjustments to reconcile net income to net cash provided by operating activitiesDepreciation, amortization and accretion


280



153Deferred income taxes and investment tax credits, net


(41
)


48Deferred fuel cost (credit)


37



(196
)Allowance for equity funds used during construction


(59
)


(40
)Other adjustments to net income


47



4Cash (used) provided by changes in operating assets and liabilitiesReceivables


(76
)


(65
)Receivables from affiliated companies


8



–Inventory


(58
)


(85
)Prepayments and other current assets


45



(49
)Income taxes, net


16



34Accounts payable


16



237Payables to affiliated companies


(7
)


(45
)Derivative collateral held


–



409Other current liabilities


37



27Other assets and deferred debits


15



(10
)Other liabilities and deferred credits


(23
)


40Net cash provided by operating activities


445



654Investing activitiesGross property additions


(770
)


(921
)Nuclear fuel additions


(18
)


(1
)Purchases of available-for-sale securities and other investments


(415
)


(418
)Proceeds from available-for-sale securities and other investments


420



418Changes in advances to affiliated companies


–



149Proceeds from sales of assets to affiliated companies


–



10Other investing activities


(4
)


(2
)Net cash used by investing activities


(787
)


(765
)Financing activitiesDividends paid on preferred stock


(1
)


(1
)Net decrease in short-term debt


(371
)


–Proceeds from issuance of long-term debt, net


–



1,476Retirement of long-term debt


–



(82
)Changes in advances from affiliated companies


406



43Contributions from parent


310



–Other financing activities


(2
)


–Net cash provided by financing activities


342



1,436Net increase in cash and cash equivalents


–



1,325Cash and cash equivalents at beginning of period


19



23Cash and cash equivalents at end of period

$
19


$
1,348Supplemental disclosuresSignificant noncash transactionsAccrued property additions

$
172


$
180See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.
  16
  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 NotesPEC
1, 2, 4, 6, 8 through 11, and 13 through 15PEF
1, 2, 4, 6, 8 through 11, and 13 through 15
  17
  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 INTERIM FINANCIAL STATEMENTS
  
 1.
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
  A.      ORGANIZATION
  In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily
includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to the Combined Notes. However, neither of the Utilities makes any representation
as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.
  PROGRESS ENERGY
 
 The Parent is a holding company headquartered in Raleigh, N.C. As such, we are subject to regulation by the Federal Energy Regulatory Commission (FERC) under the regulatory provisions of the Public Utility Holding Company Act of 2005 (PUHCA 2005).
  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 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 provisions of the North Carolina Utilities Commission
(NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.
 
 PEF
 
 PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory provisions 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, 2008 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, 2008 (2008 Form 10-K). We have evaluated subsequent events through August 7, 2009, which is the date we issued our financial statements.
  18
  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 electric operating revenues and taxes other than on income in the statements of income were as follows:
 Three Months Ended June 30,


Six Months Ended June 30,(in millions)

2009


2008


2009


2008Progress Energy

$
77


$
72


$
156


$
136PEC


26



25



52



49PEF


51



47



104



87
 
 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 2008 have been reclassified to conform to the 2009 presentation.
  C.      CONSOLIDATION OF VARIABLE INTEREST ENTITIES
  We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. In general, we determine whether we are the primary beneficiary of a VIE through a qualitative analysis of risk that identifies which variable interest holder absorbs
the majority of the financial risk and variability of the VIE. In performing this 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. If the qualitative analysis is inconclusive, a specific quantitative
analysis is performed. For purposes of the following disclosures, the maximum loss amounts represent the maximum exposure that would be absorbed by the Progress Registrants in the event that all of the assets of the VIE are deemed worthless, including any additional costs that the Progress Registrants would incur.
  PROGRESS ENERGY
  In addition to the following variable interests listed for PEC and PEF, Progress Energy, through its subsidiary Progress Fuels Corporation (Progress Fuels), is the primary beneficiary of, and consolidates, Ceredo Synfuel, LLC (Ceredo), a coal-based solid synthetic fuels production facility that qualified for federal tax credits under Section
45K of the Internal Revenue Code (the Code). See Note 1C in the 2008 Form 10-K for discussion of our variable interest in Ceredo and our disposal of Ceredo in 2007. There were no changes to our assessment of the primary beneficiary during 2008 or for the period ended June 30, 2009. No financial or other support has been provided to Ceredo during the periods presented. At June 30, 2009, we had no assets and $20 million of liabilities related to the legal and tax indemnifications provided to the buyer included
in other liabilities and deferred credits on the Consolidated Balance Sheets. The ultimate resolution of the indemnifications could result in adjustments to the gain on disposal in future periods. The creditors of Ceredo do not have recourse to the general credit of Progress Energy. See Note 3D for additional information on the disposal of Ceredo and Note 15B for a general discussion of guarantees.
  19
  PEC
  VARIABLE INTEREST ENTITIES FOR WHICH PEC IS THE PRIMARY BENEFICIARY
  PEC is the primary beneficiary of, and consolidates, two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Code. PEC’s variable interests are debt and equity investments in the two VIEs. PEC performed quantitative analyses to determine the primary beneficiaries of the
two VIEs. The primary factors in the analyses were the estimated economic lives of the partnerships and their net cash flow projections, estimates of available tax credits, and the likelihood of default on debt and other commitments. There were no changes to PEC’s assessment of the primary beneficiary during 2008 or for the period ended June 30, 2009. No financial or other support has been provided to the VIEs during the periods presented. At June 30, 2009, PEC had assets of $39 million, substantially all
of which were reflected in miscellaneous other property and investments, $15 million in long-term debt, $3 million in other liabilities and deferred credits and $5 million in accounts payable on the Consolidated Balance Sheets related to the two VIEs. The assets of the two VIEs are collateral for, and can only be used to settle, their obligations. The creditors of these VIEs do not have recourse to the general credit of PEC and there are no other arrangements that could expose PEC to losses.
  OTHER VARIABLE INTERESTS
  PEC has an equity investment in, and consolidates, one limited partnership investment fund that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. The investment fund accounts for the 17 partnerships on the equity method of accounting. PEC also has an interest in one power plant resulting from
long-term power purchase contracts. PEC’s only significant exposure to variability from the power purchase contracts results from fluctuations in the market price of fuel used by the entity’s plants to produce the power purchased by PEC. We are able to recover these fuel costs under PEC’s fuel clause. The generation capacity of the entity’s power plant is approximately 847 megawatts (MW). PEC has requested the necessary information to determine if the investment fund’s 17 partnerships
and the power plant owner are VIEs or to identify the primary beneficiaries; all entities from which the necessary financial information was requested declined to provide the information to PEC, and, accordingly, PEC has applied the information scope exception provided by GAAP to the 17 partnerships and the power plant. PEC believes that if it is determined to be the primary beneficiary of these entities, the effect of consolidating the power plant and the investment fund consolidating the 17 partnerships would
result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings or cash flows. However, because PEC has not received any financial information from the counterparties, the impact cannot be determined at this time.
  PEF
  The following information is provided for PEF’s significant variable interests in VIEs for which PEF is not the primary beneficiary:
  PEF has a prepayment clause in a building capital lease with a special purpose entity that is a VIE. In accordance with the lease agreement, PEF is not required to make any lease payments over the last 20 years of the lease, during which period $51 million of rental expense will be recorded in the PEF Statements of Income. The prepayment
clause is PEF’s only variable interest in the VIE and, therefore, PEF’s exposure to loss primarily relates to the recovery of the prepayments through future use of the rental property. PEF performed qualitative and quantitative analyses and concluded that it is not the primary beneficiary of the VIE. The primary factors in the analyses were the lease term, the fact that the lease payments are not variable interests, the likelihood of construction and casualty risks to the building and the existence
of insurance to offset those risks, and the estimated fair value of the building at the end of the lease term. There were no changes to PEF’s assessment of the primary beneficiary during 2008 or for the period ended June 30, 2009. No financial or other support has been provided to the VIE during the periods presented. At June 30, 2009, PEF had a $5 million prepayment included in other assets and deferred debits on the Balance Sheets. No liabilities associated with the prepayment clause were recorded. The
aggregate maximum exposure to loss at June 30, 2009, is $51 million, which represents the loss if the maximum prepayment of rent at the end of year 20 was not recovered through future use of the rental property or from third-party insurers at that time.
  PEF has a residual value guarantee in an operating railcar lease agreement with a special purpose entity that is a VIE. The lease agreement has an early termination clause that permits PEF to terminate the lease in certain circumstances. If PEF terminates the lease in accordance with the agreement, it must sell the railcars and remit the
 
 20
 
 proceeds to the lessor plus any amount for which the residual value guarantee exceeds the realized value of the equipment. The residual value guarantee is PEF’s primary variable interest in the VIE and, therefore, PEF’s exposure to loss is from the potential decrease in the fair value of the railcars. PEF performed qualitative
and quantitative analyses and concluded that it is not the primary beneficiary of the VIE. The primary factors in the analyses were the terms of the lease, the probability of exercising the early termination clause, and the estimated fair value of the railcars. There were no changes to PEF’s assessment of the primary beneficiary during 2008 or for the period ended June 30, 2009. No financial or other support has been provided to the VIE during the periods presented. No liabilities associated with the residual
value guarantee were recorded at June 30, 2009, because the early termination clause was not exercised. The aggregate maximum exposure to loss at June 30, 2009, is $18 million, which represents the maximum loss if the early termination clause were exercised in 2009 and the related railcars were deemed worthless.
  
 2.
NEW ACCOUNTING STANDARDS
  FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
  In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP FAS 157-2), which for us and the Utilities delayed the effective date of SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), for all nonfinancial assets
and nonfinancial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. The adoption of SFAS No. 157, including FSP FAS 157-2, did not have a material impact on our or the Utilities' financial position or results of operations. See Note 9B for information regarding fair value measurements under SFAS No. 157 and FSP FAS 157-2.
  SFAS No. 141R, “Business Combinations”
  In December 2007, the FASB issued SFAS Statement No. 141R, “Business Combinations” (SFAS No. 141R), which introduces significant changes in the accounting for business acquisitions. SFAS No. 141R considerably broadens the definition of a “business” and a “business combination,” which should result in
an increased number of transactions or other events that will qualify as business combinations. Other significant changes include the expensing of all acquisition-related transaction costs and most acquisition-related restructuring costs, the fair value remeasurement of certain earn-out arrangements and the discontinuance of the expense at acquisition of acquired-in-process research and development. SFAS No. 141R was effective for us for business combinations for which the acquisition date is on or after January
1, 2009. The adoption of SFAS No. 141R did not have any impact on our or the Utilities' financial position or results of operations.
  SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”
  In conjunction with the issuance of SFAS No. 141R, in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160), which introduces significant changes in the accounting for noncontrolling interests in a partially owned consolidated subsidiary.
SFAS No. 160 was adopted concurrently with the effective date of SFAS No. 141R, which for us was January 1, 2009. See Note 6B for information regarding our first quarter 2009 implementation of SFAS No. 160. The adoption of SFAS No. 160 resulted in a change in presentation of the financial statements and additional disclosures but did not have a material impact on our or the Utilities' financial position or results of operations.
  SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”
  On January 1, 2009, we implemented SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (SFAS No. 161), which requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments
and related hedged items are accounted for under Statement 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. See Note 11 for information regarding our first quarter 2009 implementation of SFAS No. 161. The adoption of SFAS No. 161 did not have a material impact on our or the Utilities' financial position or results of operations.
  21
  FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”
 
 On January 1, 2009, we implemented FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1), which requires that certain unvested share-based payment awards (e.g. restricted stock) that contain nonforfeitable rights to dividends or dividend
equivalents be included in the computation of earnings per share using the two-class method. FSP EITF 03-6-1 required a retrospective adjustment for all prior-period earnings per share data. The adoption of FSP EITF 03-6-1 did not have a material impact on our or the Utilities' financial position, results of operations or earnings per share amounts.
  New FSPs for Fair Value Measurement and Disclosures and Other-Than-Temporary Impairments
 
 In April 2009, the FASB issued three FSPs for guidance on accounting for fair value measurement and other-than-temporary impairments.
 
 FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That are Not Orderly,” provides guidance on determining fair value when market activity has decreased for an asset or liability. FSP FAS 107-1 and APB 28-1, “Interim
Disclosures About Fair Value of Financial Instruments,” increases the frequency of fair value disclosures required by SFAS No. 107, “Disclosures of Fair Value of Financial Instruments,” from annually to quarterly.
  FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2), revises the recognition and reporting requirements for other-than-temporary impairments of debt securities and increases the frequency of disclosures for debt and equity securities. Under FSP FAS 115-2, if an entity
intends to sell an impaired debt security or more likely than not will be required to sell the security before recovery of its amortized cost basis less any current-period credit loss, an other-than-temporary impairment must be recognized currently in earnings equal to the difference between the investment’s amortized cost and its fair value at the balance sheet date.
  The three FSPs were effective for us during the three months ended June 30, 2009. The adoption of the three FSPs resulted in additional disclosures but did not have a material impact on our or the Utilities' financial position or results of operations. See Note 9 for the disclosures resulting from our second quarter 2009 implementation
of the three FSPs.
  SFAS No. 165, “Subsequent Events”
  In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (SFAS No. 165), which is applicable to the accounting for and disclosure of subsequent events not otherwise addressed in GAAP. SFAS No. 165 defines subsequent events as “events or transactions that occur after the balance sheet date but before financial statements
are issued or are available to be issued.” For public entities, financial statements are considered “issued” when they are widely distributed to shareholders and other financial users for general use and reliance in a form and format that complies with GAAP. SFAS No. 165 is effective for us on June 30, 2009. The adoption of SFAS No. 165 requires the disclosure of the date through which subsequent events have been evaluated, as well as whether the date is the date the financial statements were
issued or the date the financial statements were available to be issued. See Note 1 for the information regarding our implementation of SFAS No. 165.
  FSP FAS 132R-1, “Employers’ Disclosures about Post Retirement Benefit Plan Assets”
  In December 2008, the FASB issued FSP FAS 132R-1, “Employers’ Disclosures about Post Retirement Benefit Plan Assets” (FSP FAS 132R-1), which requires additional disclosures on the investment allocation decision making process, the fair value of each major category of plan assets and the inputs and valuation techniques
used to remeasure the fair value of plan assets. FSP FAS 132R-1 is effective for us on December 31, 2009. The adoption of FSP FAS 132R-1 will change certain disclosures in the notes to the financial statements but we do not expect the adoption of FSP FAS 132R-1 to have a material impact on our or the Utilities’ financial position or results of operations.
  22
  SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”
  In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140” (SFAS No. 166), which is a revision to SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”. SFAS No. 166 eliminates the
concept of a “qualifying special purpose entity”, changes the requirements for derecognizing financial assets and requires additional disclosures. SFAS No. 166 is effective for us January 1, 2010. Earlier application is prohibited. We do not expect the adoption of SFAS No. 166 to have a material impact on our or the Utilities’ financial position or results of operations.
  SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”
  In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” (SFAS No. 167), which makes significant changes to the model for determining who should consolidate a variable interest entity and addresses how often this assessment should be performed.
SFAS No. 167 requires all existing arrangements to be evaluated, and must be adopted through a cumulative-effect adjustment. SFAS No. 167 is effective for us on January 1, 2010. We are currently evaluating the impact adoption may have on our or the Utilities’ financial position, results of operations and cash flows.
  
 3.
DIVESTITURES
  A.
TERMINALS OPERATIONS AND SYNTHETIC FUELS BUSINESSES
  On March 7, 2008, we sold coal terminals and docks in West Virginia and Kentucky (Terminals) for $71 million in gross cash proceeds. The terminals had a total annual capacity in excess of 40 million tons for transloading, blending and storing coal and other commodities. Proceeds from the sale were used for general corporate purposes. During
the six months ended June 30, 2008, we recorded an after-tax gain of $41 million on the sale of these assets. The accompanying consolidated financial statements reflect the operations of Terminals as discontinued operations.
  Prior to 2008, we had substantial operations associated with the production of coal-based solid synthetic fuels (Synthetic Fuels) as defined under Section 29 (Section 29) of the Code and as redesignated effective 2006 as Section 45K of the Code (Section 45K and collectively, Section 29/45K). The production and sale of these products qualified
for federal income tax credits so long as certain requirements were satisfied. As a result of the expiration of the tax credit program, all of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007. The accompanying consolidated statements of income reflect the abandoned operations of our synthetic fuels businesses as discontinued operations.
  Results of discontinued operations for the three and six months ended June 30 for Terminals and Synthetic Fuels were as follows:
 (in millions)

Three Months Ended
June 30, 2008


Six Months Ended
June 30, 2008Revenues

$
–


$
17Earnings before income taxes and noncontrolling interest


1



11Income tax benefit, including tax credits and tax levelization


8



12Earnings attributable to noncontrolling interests of Synthetic Fuels


–



(1
)Net earnings from discontinued operations attributable to controlling interests


9



22(Loss) gain on disposal of discontinued operations, including income tax expense of $– and $7


(4
)


41Earnings from discontinued operations attributable to controlling interests

$
5


$
63
 23
 B.
COAL MINING BUSINESSES
  On March 7, 2008, we sold the remaining operations of Progress Fuels subsidiaries engaged in the coal mining business (Coal Mining) for gross cash proceeds of $23 million. Proceeds from the sale were used for general corporate purposes. These assets included Powell Mountain Coal Co. and Dulcimer Land Co., which consisted of about 30,000
acres in Lee County, Va. and Harlan County, Ky. As a result of the sale, during the six months ended June 30, 2008, we recorded an after-tax gain of $7 million on the sale of these assets.
  The accompanying consolidated financial statements reflect Coal Mining as discontinued operations. Results of Coal Mining discontinued operations for the three and six months ended June 30 were as follows:
  (in millions)

Three Months Ended
June 30, 2008


Six Months Ended
June 30, 2008Revenues

$
–


$
2Gain (loss) before income taxes


1



(6
)Income tax benefit


1



2Net gain (loss) from discontinued operations


2



(4
)Gain on disposal of discontinued operations, including income tax expense of $2


–



7Earnings from discontinued operations

$
2


$
3
 
 C.
OTHER DIVERSIFIED BUSINESSES
  Also included in discontinued operations are amounts related to adjustments of our prior sales of other diversified businesses, primarily the Competitive Commercial Operations (CCO) in Georgia and Progress Rail Services Corporation. These adjustments are mainly due to the finalization of working capital and in connection with guarantees
and indemnifications provided by Progress Fuels and Progress Energy for certain legal, tax and environmental matters (See Note 15B). The ultimate resolution of these matters could result in additional adjustments in future periods. For each of the three and six months ended June 30, 2009, we recorded additional losses of $1 million, net of tax. For the three and six months ended June 30, 2008, we recorded additional losses of $2 million and $1 million, respectively, net of tax.
  D.
CEREDO SYNTHETIC FUELS INTERESTS
  On March 30, 2007, our Progress Fuels subsidiary disposed of its 100 percent ownership interest in Ceredo, a subsidiary that produced and sold qualifying coal-based solid synthetic fuels, to a third-party buyer. In addition, we entered into an agreement to operate the Ceredo facility on behalf of the buyer. At closing, we received cash
proceeds of $10 million and a non-recourse note receivable of $54 million. Payments on the note were due as we produced and sold qualifying synthetic fuels on behalf of the buyer. In accordance with the terms of the agreement, we received payments on the note related to 2007 production of $49 million during the year ended December 31, 2007, and $5 million during the six months ended June 30, 2008. The note had an interest rate equal to the three-month London Inter Bank Offering Rate (LIBOR) rate plus 1%. The
estimated fair value of the note at the inception of the transaction was $48 million. Under the terms of the agreement, the purchase price was reduced by $7 million during the six months ended June 30, 2008, based on the final value of the 2007 Section 29/45K tax credits.
  During the six months ended June 30, 2008, we recognized previously deferred gains on disposal of $5 million based on the final value of the 2007 Section 29/45K tax credits. The operations of Ceredo ceased as of December 31, 2007, and are recorded as discontinued operations for all periods presented. See discussion of the abandonment of
our synthetic fuels operations at Note 3A. In connection with the disposal, Progress Fuels and Progress Energy provided guarantees and indemnifications for certain legal and tax matters to the buyer. The ultimate resolution of these matters could result in adjustments to the loss on disposal in future periods. See general discussion of guarantees at Note 15B.
 24
 4.
REGULATORY MATTERS
  A.
PEC RETAIL RATE MATTERS
  FUEL COST RECOVERY
  On May 7, 2009, PEC filed with the SCPSC for a decrease in the fuel rate charged to its South Carolina ratepayers. On May 28, 2009, PEC jointly filed a settlement agreement with the South Carolina Office of Regulatory Staff (ORS) and Nucor Steel. Under the terms of the settlement agreement, the parties agreed to PEC’s proposed rate
reduction of approximately $13 million. A hearing on the matter was held by the SCPSC on June 11, 2009, and on June 19, 2009, the SCPSC approved the settlement agreement. The decrease is effective July 1, 2009, and decreases residential electric bills by $2.08 per 1,000 kilowatt-hours (kWh), or 2.0 percent, for fuel cost recovery.
  On June 4, 2009, PEC filed with the NCUC for a decrease in the fuel rate charged to its North Carolina ratepayers. PEC is asking the NCUC to approve a $5 million decrease in the fuel rates driven by declining fuel prices. If approved, the decrease would take effect December 1, 2009, and would decrease residential electric bills by $0.17
per 1,000 kWh, or 0.2 percent, for fuel cost recovery. A hearing on the matter has been scheduled by the NCUC for September 15, 2009. We cannot predict the outcome of this matter.
  DEMAND-SIDE MANAGEMENT AND ENERGY-EFFICIENCY COST RECOVERY
  See Note 7B in the 2008 Form 10-K for discussion of North Carolina’s comprehensive energy legislation, which became law on August 20, 2007. As a result of the legislation, PEC has implemented a series of demand-side management (DSM) and energy-efficiency programs and will continue to pursue additional programs. These programs must
be approved by the NCUC and we cannot predict the outcome of the DSM and energy-efficiency filings currently pending approval by the NCUC or whether the implemented programs will produce the expected operational and economic results.
  On June 6, 2008, and as subsequently amended, PEC filed an application with the NCUC for approval of a DSM and energy-efficiency rider to recover all program costs, including the recovery of appropriate incentives for investing in such programs. On November 14, 2008, the NCUC issued an order allowing PEC to implement the rates requested
in PEC’s November 14, 2008 revision to its initial application. The new rates, subject to true-up to the final order, were implemented on December 1, 2008, increasing residential electrical bills by $0.74 per 1,000 kWh, or 0.8 percent. On December 9, 2008, the North Carolina Public Staff filed an Agreement and Stipulation of Partial Settlement with PEC and some of the other parties to the proceedings. The NCUC held a hearing on the matter on January 7, 2009. On June 15, 2009, the NCUC issued an order approving
the Agreement and Stipulation of Partial Settlement, subject to certain modifications. PEC estimates the year-to-date impact of these modifications to be immaterial. On July 13, 2009, PEC filed a motion asking the NCUC to reconsider certain provisions of the June 15, 2009 order and stay the requirements for PEC to revise its cost-recovery filings in accordance with the decisions approved in the order. On July 20, 2009, the NCUC issued an order requesting comments on the motion and allowed the motion for
stay, pending a ruling on the motion for reconsideration, on a portion of PEC’s request. Reply comments are due August 7, 2009. We cannot predict the outcome of this matter.
  On June 4, 2009, PEC filed with the NCUC for a decrease in the DSM and energy-efficiency rate charged to its North Carolina ratepayers. PEC is asking the NCUC to approve a $3 million decrease in the DSM and energy-efficiency rates. If approved, the decrease would take effect December 1, 2009, and would decrease residential electric bills
by $0.19 per 1,000 kWh, or 0.2 percent, for DSM and energy-efficiency cost recovery. A hearing on the matter has been scheduled by the NCUC for September 16, 2009. We cannot predict the outcome of this matter.
  PEC filed a petition on November 30, 2007, with the SCPSC seeking authorization to create a deferred account for DSM and energy-efficiency expenses. On December 21, 2007, the SCPSC issued an order granting PEC’s petition. On June 27, 2008, PEC filed an application with the SCPSC to establish procedures that encourage investment in
cost-effective energy-efficient technologies and energy conservation programs and approve the establishment of an annual rider to allow recovery for all costs associated with such programs, as well as the recovery of appropriate incentives for investing in such programs. On January 23, 2009, PEC filed a Stipulation Agreement between PEC and some of the other parties to the proceeding. On May 6, 2009, the SCPSC approved the Stipulation Agreement and issued a directive requiring PEC to file for approval of all
proposed DSM and energy-efficiency programs. On May 11, 2009, in accordance with the SCPSC directive, PEC filed its programs for approval and an application for a
 
 25
 
 cost-recovery rider for PEC’s DSM and energy-efficiency programs. On June 10, 2009, SCPSC approved the proposed DSM and energy-efficiency programs and the cost-recovery rider application, on a provisional basis pending a review of the cost-recovery rider by the ORS. The rate increase was effective July 1, 2009, and increased residential
electric bills by $0.79 per 1,000 kWh or 0.8 percent, for DSM and energy-efficiency cost recovery. We cannot predict the outcome of this matter.
  RENEWABLE ENERGY AND ENERGY EFFICIENCY PORTFOLIO STANDARD COST RECOVERY
  On June 4, 2009, PEC filed with the NCUC for an increase in the Renewable Energy and Energy Efficiency Portfolio standard (NC REPS) rate charged to its North Carolina ratepayers. PEC is asking the NCUC to approve a $6 million increase in the NC REPS rates. If approved, the increase would take effect December 1, 2009, and would increase
residential electric bills by $0.26 per month, or 0.2 percent, for REPS cost recovery. A hearing on the matter has been scheduled by the NCUC for September 16, 2009. We cannot predict the outcome of this matter.
  B.
PEF RETAIL RATE MATTERS
  BASE RATE FILING
  As a result of a base rate proceeding in 2005, PEF is party to a base rate settlement agreement that was effective with the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009.
  On March 20, 2009, in anticipation of the expiration of its current base rate settlement agreement, PEF filed with the FPSC a proposal for an increase in base rates effective January 1, 2010. In its filing, PEF requested the FPSC to approve calendar year 2010 as the projected test period for setting new base rates and approve annual rate
relief for PEF of $499 million, which includes PEF’s petition for a combined $76 million of new base rates in 2009 as discussed below. The request for increased base rates is based, in part, on investments PEF is making in its generating fleet and in its transmission and distribution systems.
  Included within the base rate proposal is a request for an interim base rate increase of $13 million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a limited proceeding to include in base rates revenue requirements of $63 million for the repowered Bartow power plant, which began commercial operations in June 2009. On May
19, 2009, the FPSC approved both the annualized interim base rate increase and the cost recovery for the repowered Bartow power plant subject to refund with interest effective July 1, 2009. These increases are expected to result in additional revenues of approximately $70 million in 2009. The changes increased residential bills by approximately $4.52 per 1,000 kWh, or 3.7 percent. On July 2, 2009, Florida’s Office of Public Counsel (OPC), the Florida Industrial Power Users Group, the Attorney
General, the Florida Retail Federation and PCS Phosphate filed a petition protesting portions of the FPSC approval. A hearing on the matter will not be held until after the annual rate relief hearings are concluded. We cannot predict the outcome of this matter.
  If PEF’s remaining rate request is approved by the FPSC as filed by PEF, the new base rates would increase residential bills by approximately $9.66 per 1,000 kWh, or 7.6 percent, effective January 1, 2010. The FPSC has scheduled hearings on the remaining annual rate relief filing beginning September 21, 2009. A ruling by the FPSC
is expected in November 2009. We cannot predict the outcome of this matter.
  FUEL COST RECOVERY
  On March 17, 2009, PEF received approval from the FPSC to reduce its 2009 fuel cost-recovery factors by an amount sufficient to achieve a $206 million reduction in fuel charges to retail customers as a result of effective fuel purchasing strategies and lower fuel prices. The approval reduces residential customers’ fuel charges by
$6.90 per 1,000 kWh, or 5.0 percent, starting with the first billing cycle of April 2009. Commercial and industrial customers will see similar reductions.
  In 2006, OPC filed a petition with the FPSC asking that the FPSC require PEF to refund to ratepayers $135 million, plus interest, of alleged excessive past fuel recovery charges and sulfur dioxide (SO2) allowance costs during the period 1996 to 2005. The OPC claimed
that although Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5) were designed to burn a blend of coals, PEF failed to act to lower ratepayers’ costs by purchasing the most economical blends of coal. During the period specified in the petition, PEF’s costs recovered through fuel recovery clauses were annually reviewed for prudence and approval by the FPSC. On October 10, 2007, the FPSC issued its order rejecting most of the OPC’s contentions. However, the FPSC found that PEF had not
been prudent in
 
 26
 
 purchasing a portion of its coal requirements during the period from 2003 to 2005. Accordingly, the FPSC ordered PEF to refund its ratepayers $14 million, inclusive of interest, over a 12-month period beginning January 1, 2008. The refund was returned to ratepayers through a reduction of prior year under-recovered fuel costs. The FPSC also
ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On October 4, 2007, PEF filed a motion to establish a separate docket on the prudence of its coal purchases for CR4 and CR5 for the years 2006 and 2007. On October 17, 2007, the FPSC granted that motion. On February 2, 2009, the OPC filed direct testimony in this hearing alleging that during 2006 and 2007, PEF collected excessive fuel costs and SO2 allowance
costs of $61 million before interest. The OPC claimed that these excessive costs were attributed to PEF’s ongoing practice of not blending the most economical sources of coal at its CR4 and CR5 plants. A hearing on PEF’s 2006 and 2007 coal purchases was held April 13-15, 2009. During the hearing, the OPC reduced the alleged excessive fuel costs to $33 million before interest. On June 30, 2009, the FPSC approved a refund of $8 million to PEF’s ratepayers to be paid over a 12-month period beginning
January 1, 2010, and ordered PEF to file a report by September 2009 regarding the prospective application of PEF’s coal procurement plan and the prudence of PEF’s coal procurement actions. For the three months ended June 30, 2009, PEF recorded a pre-tax other operating expense of $8 million plus an immaterial amount of interest and an associated regulatory liability for the disallowed fuel costs and interest. PEF is evaluating its options, including a request for reconsideration and an appeal of the
FPSC’s order to the Florida Supreme Court. We cannot predict the outcome of this matter.
  NUCLEAR COST RECOVERY
  On March 17, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear pre-construction costs for PEF’s proposed nuclear plant in Levy County, Florida (Levy), which the FPSC had authorized to be collected in 2009. The approval reduced residential customers’ nuclear cost-recovery charge
by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first billing cycle of April 2009. Commercial and industrial customers experienced similar reductions.
  On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million, which consists of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and Crystal River Unit 3 (CR3) uprate projects. In an effort to help
mitigate the initial price impact on its customers, as part of its filing, PEF has proposed collecting certain costs over a five-year period, with associated carrying costs. The deferral would result in a nuclear cost-recovery charge of $6.69 per 1,000 kWh for residential customers, which is approximately half of the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery rule. If approved, the charges would begin with the first billing cycle of January 2010. The FPSC has scheduled hearings
in this matter beginning September 8, 2009, with a decision expected in October 2009. We cannot predict the outcome of this matter.
  OTHER MATTERS
  On March 20, 2009, PEF filed a petition with the FPSC for expedited approval of the deferral of $53 million in 2009 pension expense and the authorization to charge $33 million in estimated 2009 storm hardening expenses to its storm damage reserve. PEF requested that the deferral of pension expense continue until the recovery of these costs
is provided for in FPSC-approved base rates. On June 16, 2009, the FPSC denied PEF’s request related to the storm hardening expenses, but approved the deferral of the retail portion of actual 2009 pension expense. As a result of the order, during the three months ended June 30, 2009, PEF deferred $16 million of pension expense that had been recognized year to date and established a deferred pension regulatory asset. PEF will not earn a carrying charge on the deferred pension regulatory asset. The retail
portion of subsequent pension expense will be deferred as incurred during the remainder of 2009. The deferral of pension expense will not result in a change in PEF’s 2009 retail rates or prices. In accordance with the order, subsequent to 2009 PEF will amortize the deferred pension regulatory asset to the extent that annual pension expense is less than the allowance provided for in the base rates established in the 2010 base rate proceeding. In the event such amortization is insufficient to fully amortize
the regulatory asset, PEF can seek recovery of the remaining unamortized amount in a base rate proceeding no earlier than 2015.
  C.
OTHER RATE MATTERS
  On May 15, 2009 and May 29, 2009, PEC and PEF filed updates to their Open Access Transmission Tariffs (OATT) with the FERC. For PEC, the updates increased the transmission rate charged to wholesale customers by 18 percent effective June 1, 2009, and by an additional 1 percent effective August 1, 2009. The impact to PEC’s 2009 revenue
is expected to be an increase of $4 million. For PEF, the updates increased the transmission rate charged to
 
 27
 
 wholesale customers by 11 percent, effective June 1. The impact to PEF’s 2009 revenue is expected to be an increase of $2 million. The rates are subject to wholesale customers filing a formal challenge with the FERC. Any challenge could result in a refund or adjustment. We cannot predict the outcome of this matter.
  
 5.
GOODWILL
  Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility segments and our goodwill impairment tests are performed at the utility segment level. The carrying amounts of goodwill at June 30, 2009 and December 31, 2008, for reportable
segments PEC and PEF, were $1.922 billion and $1.733 billion, respectively. The amounts assigned to PEC and PEF are recorded in our Corporate and Other business segment. We perform our annual impairment tests as of April 1 each year. During the second quarter of 2009, we completed the 2009 annual tests, which indicated the goodwill was not impaired.
  
 6.
EQUITY AND COMPREHENSIVE INCOME
  A.
EARNINGS PER COMMON SHARE
  A reconciliation of our weighted-average number of common shares outstanding for basic and dilutive earnings per share purposes follows:
 Three Months Ended June 30,


Six Months Ended June 30,(in millions)

2009


2008


2009


2008Weighted-average common shares – basic


280



261



278



261Net effect of dilutive stock-based compensation plans


–



–



–



–Weighted-average shares – fully dilutive


280



261



278



261
 
 B.  RECONCILIATION OF TOTAL EQUITY
  PROGRESS ENERGY
  The consolidated financial statements include the accounts of Progress Energy and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of our subsidiary, Progress Telecom Holdings LLC and several variable interest entities (see Note 1C).
  28
  The following table presents changes in total equity for the year to date:
  ( (in millions)

Total
Common
Stock Equity


Noncontrolling
Interests


Total
EquityBalance, December 31, 2008

$
8,687


$
6


$
8,693Net income (loss)(a)


356



(1
)


355Other comprehensive income


20



–



20Comprehensive income










375Issuance of shares through offerings and stock-based compensation plans (See Note 6D)


582



–



582Dividends paid and declared


(356
)


–



(356
)Distributions to noncontrolling interest


–



(1
)


(1
)Other transactions


–



2



2Balance, June 30, 2009

$
9,289


$
6


$
9,295
 
 (a)
  (in millions)

Total
Common
Stock Equity


Noncontrolling
Interests


Total
EquityBalance, December 31, 2007

$
8,395


$
84


$
8,479Net income


414



5



419Other comprehensive income


6



–



6Comprehensive income










425Issuance of shares through offerings and stock-based compensation plans (See Note 6D)


85



–



85Dividends paid and declared


(321
)


–



(321
)Contributions from noncontrolling interest


–



2



2Distributions to noncontrolling interest


–



(85
)


(85
)Balance, June 30, 2008

$
8,579


$
6


$
8,585
 29
 
 PEC
 
 The consolidated financial statements include the accounts of PEC and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of several variable interest entities (see Note 1C).
 
 The following table presents changes in total equity for the year to date:
 
 (in millions)

Total
Common
Stock Equity


Noncontrolling
Interests


Total
EquityBalance, December 31, 2008

$
4,301


$
4


$
4,305Net income (loss)


223



(1
)


222Other comprehensive income


4



–



4Comprehensive income










226Issuance of shares through stock-based compensation plans


29



–



29Dividends paid to parent


(200
)


–



(200
)Preferred stock dividends at stated rate


(1
)


–



(1
)Tax benefit dividend


(2
)


–



(2
)Balance, June 30, 2009

$
4,354


$
3


$
4,357
 
 ( (in millions)

Total
Common
Stock Equity


Noncontrolling
Interests


Total
EquityBalance, December 31, 2007

$
3,752


$
4


$
3,756Net income


227



–



227Other comprehensive loss


(5
)


–



(5
)Comprehensive income










222Issuance of shares through stock-based compensation plans


35



–



35Preferred stock dividends at stated rate


(1
)


–



(1
)Tax benefit dividend


(1
)


–



(1
)Balance, June 30, 2008

$
4,007


$
4


$
4,011
 
 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.
 
 30
  C.  COMPREHENSIVE INCOME
  Progress EnergyThree Months Ended June 30,(in millions)

2009


2008Net income

$
174


$
205Other comprehensive incomeReclassification adjustments included in net incomeChange in cash flow hedges (net of tax expense of $1)


2



–Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $1 and $-, respectively)


1



1Net unrealized gains on cash flow hedges (net of tax expense of $5 and $8, respectively)


8



13Other comprehensive income


11



14Comprehensive income


185



219Comprehensive income attributable to controlling interests

$
185


$
219
 
 Six Months Ended June 30,(in millions)

2009


2008Net income

$
357


$
419Other comprehensive incomeReclassification adjustments included in net incomeChange in cash flow hedges (net of tax expense of $2 and $1, respectively)


3



1Change in unrecognized items for pension and other postretirement benefits (net of tax expense of $1 and $-, respectively)


2



1Net unrealized gains on cash flow hedges (net of tax expense of $9 and $2, respectively)


14



4Other (net of tax expense of $-)


1



–Other comprehensive income


20



6Comprehensive income


377



425Comprehensive income attributable to noncontrolling interests, net of tax


(1
)


(5
)Comprehensive income attributable to controlling interests

$
376


$
420
 31
  PECThree Months Ended June 30,(in millions)

2009


2008Net income

$
94


$
104Other comprehensive incomeReclassification adjustments included in net incomeChange in cash flow hedges (net of tax expense of $1)


2



–Net unrealized gains on cash flow hedges (net of tax expense of $2)


2



–Other comprehensive income


4



–Comprehensive income


98



104C Comprehensive loss attributable to noncontrolling interests, net of tax


1



–Comprehensive income attributable to controlling interests

$
99


$
104
 
 Six Months Ended June 30,(in millions)

2009


2008Net income

$
222


$
227Other comprehensive income (loss)Reclassification adjustments included in net incomeChange in cash flow hedges (net of tax expense of $1)


2



–Net unrealized gains (losses) on cash flow hedges (net of tax (expense) benefit of $(2) and $3, respectively)


2



(5
)Other comprehensive income (loss)


4



(5
)Comprehensive income


226



222Comprehensive loss attributable to noncontrolling interests, net of tax


1



–Comprehensive income attributable to controlling interests

$
227


$
222
 
 
 PEFThree Months Ended June 30,(in millions)

2009


2008Net income

$
119


$
125Other comprehensive incomeNet unrealized gains on cash flow hedges (net of tax expense of $2 and $8, respectively)


3



12Other comprehensive income


3



12Comprehensive income

$
122


$
137
 
 Six Months Ended June 30,(in millions)

2009


2008Net income

$
208


$
192Other comprehensive incomeNet unrealized gains on cash flow hedges (net of tax expense of $2 and $5, respectively)


3



8Other comprehensive income


3



8Comprehensive income

$
211


$
200
 32
  D.  COMMON STOCK
  At December 31, 2008, we had 500 million shares of common stock authorized under our charter, of which approximately 264 million were outstanding. For the three months ended June 30, 2009, we issued an immaterial number of shares of common stock. For the six months ended June 30, 2009, we issued approximately 15.5 million shares of common
stock resulting in approximately $545 million in net proceeds. Included in these amounts were approximately 0.6 million shares for net proceeds of approximately $22 million to meet the requirements of the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan. For the three and six months ended June 30, 2008, respectively, we issued approximately 0.5 million shares and 1.5 million shares of common stock resulting in approximately $22 million and $42 million
in proceeds. Included in these amounts were approximately 0.5 million shares and 0.9 million shares for proceeds of approximately $22 million and $41 million, respectively, to meet the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan.
  The 15.5 million shares issued during the six months ended June 30, 2009, also included the Parent’s issuance of 14.4 million shares of common stock at a public offering price of $37.50 per share on January 12, 2009. Net proceeds from this offering were approximately $523 million. We used $100 million of the proceeds to reduce the
Parent’s revolving credit agreement (RCA) borrowings and the remainder was used for general corporate purposes.
  
 7.
PREFERRED STOCK OF SUBSIDIARIES
  As discussed in Note 10 in the 2008 Form 10-K, 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 of a default by PEC or PEF equivalent to the payment of four quarterly dividends on
the preferred stock, the holders of the preferred stock are entitled to elect a majority of PEC or PEF’s respective Board of Directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities’ respective Board of Directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share
plus any accumulated unpaid dividends except for PEF’s 4.75%, $100 par value class, which does not have a liquidation preference. Each holder of PEC’s preferred stock is entitled to one vote. Each holder of PEF’s preferred stock has no right to vote except for certain circumstances regarding dividends payable on preferred stock in default or potential changes to the preferred stock’s rights and preferences.
  
 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, 2008, are as follows.
  On January 15, 2009, PEC issued $600 million of First Mortgage Bonds, 5.30% Series due 2019. A portion of the proceeds was used to repay the maturity of PEC’s $400 million 5.95% Senior Notes, due March 1, 2009. The remaining proceeds were used to repay PEC’s outstanding short-term debt and for general corporate purposes.
  On February 3, 2009, the Parent repaid $100 million of the $600 million outstanding balance at December 31, 2008, borrowed under its RCA with proceeds from its 14.4 million share common stock issuance discussed in Note 6D. Subsequent to June 30, 2009, the Parent repaid an additional $200 million of the outstanding balance with cash on hand.
At August 7, 2009, the outstanding balance of the RCA loan was $300 million. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity.
  On March 19, 2009, the Parent issued an aggregate $750 million of Senior Notes consisting of $300 million of 6.05% Senior Notes due 2014 and $450 million of 7.05% Senior Notes due 2019. A portion of the proceeds was used to fund PEF’s capital expenditures through an equity contribution with the remaining proceeds used for general
corporate purposes.
  On June 18, 2009, PEC entered into a Seventy-seventh Supplemental Indenture to its Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, in connection with certain amendments to the mortgage. The amendments are
 
 33
 
 set forth in the Seventy-seventh Supplemental Indenture and include an amendment to extend the maturity date of the mortgage by 100 years. The maturity date of the mortgage is now May 1, 2140.
  
 9.
FAIR VALUE DISCLOSURES
  A.
DEBT AND INVESTMENTS
  PROGRESS ENERGY
  DEBT
  The carrying amount of our long-term debt, including current maturities, was $11.506 billion and $10.659 billion at June 30, 2009 and December 31, 2008, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $12.3 billion and $11.3 billion at June 30, 2009 and December
31, 2008, respectively.
  INVESTMENTS
  Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning
the Utilities’ nuclear plants as discussed in Note 4D of the 2008 Form 10-K. Nuclear decommissioning trust (NDT) funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, we hold other debt and equity investments classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.
  The following table summarizes our available-for-sale securities at June 30, 2009 and December 31, 2008.
  June 30, 2009
(in millions)

Unrealized
Losses


Unrealized
Gains


Fair
ValueEquity securities

$
(47
)

$
175


$
678Debt securities


(9
)


13



422Cash equivalents


–



–



104Total

$
(56
)

$
188


$
1,204December 31, 2008
(in millions)

Unrealized
Losses


Unrealized
Gains


Fair
ValueEquity securities

$
(93
)

$
134


$
559Debt securities


(27
)


15



466Cash equivalents


–



–



114Total

$
(120
)

$
149


$
1,139
 
 The NDT funds and other available-for-sale debt and equity investments held in certain benefit trusts are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated
entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments; $55 million of the unrealized losses and $187 million of the unrealized gains at June 30, 2009, and $118 million of the unrealized losses and $148 million of the unrealized gains at December 31, 2008, relate to the NDT funds. There were no material unrealized losses for the other
available-for-sale debt and equity securities held in benefit trusts as of June 30, 2009 and December 31, 2008.
  The aggregate fair value of investments with unrealized losses at June 30, 2009 and December 31, 2008 was $266 million and $374 million, respectively.
  34
  At June 30, 2009, the fair value of available-for-sale debt securities by contractual maturity was:
  (in millions)Due in one year or less

$
29Due after one through five years


191Due after five through 10 years


118Due after 10 years


84Total

$
422
 
  The following table presents selected information about our sales of available-for-sale securities during the three and six months ended June 30, 2009. Proceeds were primarily related to the NDT funds. Realized gains and losses were determined on a specific identification basis.
  (in millions)

Three Months Ended June 30, 2009


Six Months Ended June 30, 2009Proceeds

$
216


$
871Realized gains


3



15Realized losses


(22
)


(74
)
 
  PEC
  DEBT
  The carrying amount of PEC’s long-term debt, including current maturities, was $3.709 billion and $3.509 billion at June 30, 2009 and December 31, 2008, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3.9 billion and $3.7 billion at June 30, 2009 and December
31, 2008, respectively.
  INVESTMENTS
  Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning
PEC’s nuclear plants as discussed in Note 4D of the 2008 Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, PEC holds other debt and equity investments classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value.
  The following table summarizes PEC’s available-for-sale securities at June 30, 2009 and December 31, 2008.
  June 30, 2009
(in millions)

Unrealized
Losses


Unrealized
Gains


Fair
ValueEquity securities

$
(35
)

$
105


$
441Debt securities


(3
)


10



277Cash equivalents


–



–



14Total

$
(38
)

$
115


$
732December 31, 2008
(in millions)

Unrealized
Losses


Unrealized
Gains


Fair
ValueEquity securities

$
(55
)

$
75


$
334Debt securities


(10
)


11



250Cash equivalents


–



–



105Total

$
(65
)

$
86


$
689
  35
  The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment.
Therefore, the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments; all of the unrealized losses and gains at June 30, 2009 and December 31, 2008, relate to the NDT funds.
  The aggregate fair value of investments with unrealized losses at June 30, 2009 and December 31, 2008, was $174 million and $191 million, respectively.
  At June 30, 2009, the fair value of available-for-sale debt securities by contractual maturity was:
  (in millions)Due in one year or less

$
4Due after one through five years


155Due after five through 10 years


79Due after 10 years


39Total

$
277
 
  The following table presents selected information about PEC’s sales of available-for-sale securities during the three and six months ended June 30, 2009. Proceeds were primarily related to the NDT funds. Realized gains and losses were determined on a specific identification basis.
  (in millions)

Three Months Ended June 30, 2009


Six Months Ended June 30, 2009Proceeds

$
78


$
466Realized gains


1



5Realized losses


(9
)


(30
)
 
  PEF
  DEBT
  The carrying amount of PEF’s long-term debt, including current maturities, was $4.182 billion at June 30, 2009 and December 31, 2008. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.4 billion and $4.5 billion at June 30, 2009 and December 31, 2008, respectively.
  INVESTMENTS
  Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF’s available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs
of decommissioning PEF’s nuclear plant as discussed in Note 4D of the 2008 Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.
  36
  The following table summarizes PEF’s available-for-sale securities at June 30, 2009 and December 31, 2008.
  June 30, 2009
(in millions)

Unrealized
Losses


Unrealized
Gains


Fair
ValueEquity securities

$
(12
)

$
70


$
237Debt securities


(5
)


2



106Cash equivalents


–



–



89Total

$
(17
)

$
72


$
432December 31, 2008
(in millions)

Unrealized
Losses


Unrealized
Gains


Fair
ValueEquity securities

$
(38
)

$
59


$
225Debt securities


(15
)


3



177Cash equivalents


–



–



9Total

$
(53
)

$
62


$
411
 
 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 that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore,
the preceding tables include the unrealized gains and losses for the NDT funds based on the original cost of the trust investments; all of the unrealized losses and gains at June 30, 2009 and December 31, 2008, relate to the NDT funds.
  The aggregate fair value of investments with unrealized losses at June 30, 2009 and December 31, 2008 was $78 million and $165 million, respectively.
  At June 30, 2009, the fair value of available-for-sale debt securities by contractual maturity was:
  (in millions)Due in one year or less

$
24Due after one through five years


33Due after five through 10 years


29Due after 10 years


20Total

$
106
 
  The following table presents selected information about PEF’s sales of available-for-sale securities during the three and six months ended June 30, 2009. Proceeds from the sale of securities primarily related to the NDT funds. Realized gains and losses were determined on a specific identification basis.
  (in millions)

Three Months Ended June 30, 2009


Six Months Ended June 30, 2009Proceeds

$
119


$
365Realized gains


2



9Realized losses


(13
)


(44
)
 
  B.
FAIR VALUE MEASUREMENTS
  Fair value is defined 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). A mid-market pricing convention (the mid-point price between bid and ask prices) is permitted for use as a practical expedient and
requires 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
 
 37
 
 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 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 has been established. 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 those 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 that are 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 where quoted
prices or other observable inputs are not available.
  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 at June 30, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is 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


TotalAssets:Nuclear decommissioning trust fundsEquity

$
678


$
–


$
–


$
678Corporate debt


–



61



–



61U.S. state and municipal debt


–



137



–



137U.S. Treasury and other US government agency debt


68



196



–



264Money market funds and other


1



19



–



20Total nuclear decommissioning trust funds


747



413



–



1,160Commodity and interest rate derivatives


–



26



3



29Other marketable securities


24



39



–



63Total assets

$
771


$
478


$
3


$
1,252Liabilities:Commodity and interest rate derivatives

$
–


$
(613
)

$
(34
)

$
(647
)CVO derivatives


–



(26
)


–



(26
)Total liabilities

$
–


$
(639
)

$
(34
)

$
(673
)
  38
  PEC(in millions)

Level 1


Level 2


Level 3


TotalAssets:Nuclear decommissioning trust fundsEquity

$
441


$
–


$
–


$
441Corporate debt


–



59



–



59U.S. state and municipal debt


–



34



–



34U.S. Treasury and other US government agency debt


68



107



–



175Money market funds and other


1



15



–



16Total nuclear decommissioning trust funds


510



215



–



725Commodity and interest rate derivatives


–



5



1



6Other marketable securities


5



–



–



5Total assets

$
515


$
220


$
1


$
736Liabilities:Commodity and interest rate derivatives

$
–


$
(82
)

$
(20
)

$
(102
)
 
 PEF(in millions)

Level 1


Level 2


Level 3


TotalAssets:Nuclear decommissioning trust fundsEquity

$
237


$
–


$
–


$
237Corporate debt


–



3



–



3U.S. state and municipal debt


–



103



–



103U.S. Treasury and other US government agency debt


–



89



–



89Money market funds and other


–



3



–



3Total nuclear decommissioning trust funds


237



198



–



435Commodity and interest rate derivatives


–



17



2



19Other marketable securities


2



–



–



2Total assets

$
239


$
215


$
2


$
456Liabilities:Commodity and interest rate derivatives

$
–


$
(531
)

$
(14
)

$
(545
)
 
 The determination of the fair values above 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 and interest rate derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity and interest rate derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable
for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 11 for discussion of risk management activities and derivative transactions.
  NDT funds reflect the assets of the Utilities’ nuclear decommissioning trusts, as discussed in Note 13 of the 2008 Form 10-K. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments,
and are classified within Level 2.
  Other marketable securities represent available-for-sale debt and equity securities used to fund certain employee benefit costs.
  39
  We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the 2008 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less than active market and are classified as Level 2.
  The following tables set forth a reconciliation of changes in the fair value of our and the Utilities’ commodity derivatives classified as Level 3 in the fair value hierarchy for the three and six months ended June 30.
  Progress EnergyThree Months Ended
June 30,


Six Months Ended
June 30,(in millions)

2009


2008


2009


2008Derivatives, net at beginning of period

$
(43
)

$
55


$
(41
)

$
26Total gains (losses), realized and unrealized:Included in earnings


–



–



–



–Included in other comprehensive income


–



–



–



–Deferred as regulatory assets and liabilities, net


12



108



10



137Purchases, issuances and settlements, net


–



–



–



–Transfers in (out) of Level 3, net


–



–



–



–Derivatives, net at end of period

$
(31
)

$
163


$
(31
)

$
163
 
 PECThree Months Ended
June 30,


Six Months Ended
June 30,(in millions)

2009


2008


2009


2008Derivatives, net at beginning of period

$
(23
)

$
12


$
(22
)

$
6Total gains (losses), realized and unrealized:Included in earnings


–



–



–



–Included in other comprehensive income


–



–



–



–Deferred as regulatory assets and liabilities, net


4



24



3



30Purchases, issuances and settlements, net


–



–



–



–Transfers in (out) of Level 3, net


–



–



–



–Derivatives, net at end of period

$
(19
)

$
36


$
(19
)

$
36
 
 PEFThree Months Ended
June 30,


Six Months Ended
June 30,(in millions)

2009


2008


2009


2008Derivatives, net at beginning of period

$
(20
)

$
43


$
(19
)

$
20Total gains (losses), realized and unrealized:Included in earnings


–



–



–



–Included in other comprehensive income


–



–



–



–Deferred as regulatory assets and liabilities, net


8



84



7



107Purchases, issuances and settlements, net


–



–



–



–Transfers in (out) of Level 3, net


–



–



–



–Derivatives, net at end of period

$
(12
)

$
127


$
(12
)

$
127
 
 Substantially all unrealized gains and losses on commodity derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment.
  Transfers in (out) of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were
no transfers into or out of Level 3 during the periods ended June 30, 2009 and 2008.
  40
  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 and six months ended June 30 were:
  Progress EnergyPension Benefits


Other PostretirementBenefitsThree months ended June 30,(in millions)

2009


2008


2009


2008Service cost

$
10


$
12


$
2


$
2Interest cost


34



31



9



8Expected return on plan assets


(35
)


(41
)


(1
)


(2
)Amortization of actuarial loss (a)


12



3



1



1Other amortization, net (a)


2



–



1



1Net periodic cost

$
23


$
5


$
12


$
10
 
 Pension Benefits


Other PostretirementBenefitsSix months ended June 30,(in millions)

2009


2008


2009


2008Service cost

$
21


$
24


$
4


$
4Interest cost


68



62



18



16Expected return on plan assets


(69
)


(82
)


(3
)


(3
)Amortization of actuarial loss (a)


24



5



2



1Other amortization, net (a)


3



1



3



2Net periodic cost

$
47


$
10


$
24


$
20
 
 (a)
  41
  PECPension Benefits


Other PostretirementBenefitsThree months ended June 30(in millions)

2009


2008


2009


2008Service cost

$
4


$
6


$
1


$
1Interest cost


16



14



5



4Expected return on plan assets


(17
)


(16
)


(1
)


(1
)Amortization of actuarial loss


2



2



1



–Other amortization, net


1



–



–



–Net periodic cost

$
6


$
6


$
6


$
4
 
 Pension Benefits


Other Postretirement BenefitsSix months ended June 30(in millions)

2009


2008


2009


2008Service cost

$
8


$
12


$
3


$
2Interest cost


31



28



9



8Expected return on plan assets


(34
)


(32
)


(2
)


(2
)Amortization of actuarial loss


4



4



1



–Other amortization, net


3



1



1



1Net periodic cost

$
12


$
13


$
12


$
9
 
 PEFPension Benefits


Other Postretirement BenefitsThree months ended June 30(in millions)

2009


2008


2009


2008Service cost

$
5


$
4


$
1


$
1Interest cost


14



13



3



3Expected return on plan assets


(15
)


(21
)


–



–Amortization of actuarial loss


9



–



–



–Other amortization, net


–



–



1



1Net periodic cost (benefit)

$
13


$
(4
)

$
5


$
5
 
 Pension Benefits


Other Postretirement BenefitsSix months ended June 30(in millions)

2009


2008


2009


2008Service cost

$
9


$
9


$
1


$
1Interest cost


28



26



7



7Expected return on plan assets


(29
)


(44
)


(1
)


(1
)Amortization of actuarial loss


18



–



1



1Other amortization, net


–



–



2



2Net periodic cost (benefit)

$
26


$
(9
)

$
10


$
10
 
 On June 16, 2009, PEF received permission from the FPSC to defer the retail portion of pension expense incurred in 2009. The FPSC order does not change the total net periodic pension cost presented above, but defers a portion of those costs to be recovered in future periods. For the three and six months ended June 30, 2009, PEF deferred
$16 million of net periodic pension cost as a regulatory asset (See Note 4B).
  42
  In 2009, contributions directly to pension plan assets are expected to approximate $220 million for us, $170 million for PEC and $50 million for PEF. An immaterial amount was contributed during the three and six months ended June 30, 2009.
  
 11.
RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
  We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk
policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect
on our financial position or results of operations.
  A.      COMMODITY DERIVATIVES
  GENERAL
  Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value.
  ECONOMIC DERIVATIVES
  Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with
trading positions.
  The Utilities have derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. 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. PEC had a cash collateral asset included in prepayments and other current assets of $8 million and $18 million on the PEC Consolidated Balance Sheet at June 30, 2009 and December 31, 2008, respectively. At June 30, 2009, PEC had 57.1 million MMBtu
notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases. Due to changes in natural gas prices and settlements of financial hedge agreements since December 31, 2008, PEF’s cash collateral asset included in derivative collateral posted on the PEF Balance Sheet was $294 million at June 30, 2009, compared to $335 million at December 31, 2008. At June 30, 2009, PEF had 227.0 million MMBtu notional of natural gas and 2.4 million
barrels notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted oil and natural gas purchases.
  CASH FLOW HEDGES
  The Utilities designate a portion of commodity derivative instruments as cash flow hedges. From time to time we hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. We also hedge exposure to market risk associated with
fluctuations in the price of fuel for fleet vehicles. At June 30, 2009, we had 0.6 million gallons notional of gasoline
 
 43
 
 and 0.6 million gallons notional of heating oil related to outstanding commodity derivative swaps at each of PEC and PEF that were entered into to hedge forecasted gasoline and diesel purchases. Realized gains and losses are recorded net as part of fleet vehicle fuel costs. At June 30, 2009 and December 31, 2008, neither we nor the Utilities
had material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for the three and six months ended June 30, 2009 and 2008.
  At June 30, 2009 and December 31, 2008, the amount recorded in our or the Utilities’ accumulated other comprehensive income related to commodity cash flow hedges was not material.
  B.      INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES
  We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss.
In the event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates.
  CASH FLOW HEDGES
  At June 30, 2009, all open interest rate hedges will reach their mandatory termination dates within approximately three years. It is expected that in the next twelve months $3 million and $4 million, net of tax, related to terminated hedges, will be reclassified to interest expense at the Parent and PEC, respectively. The actual amounts
that will be reclassified to earnings may vary from the expected amounts as a result of the timing of debt issuances at the Parent and the Utilities and changes in the market value of currently open interest rate hedges.
 
 At December 31, 2008, the Parent had $200 million notional of interest rate cash flow hedges. All of these forward starting swaps were terminated on March 16, 2009, in conjunction with the Parent’s issuance of $450 million of 7.05% Senior Notes due 2019. In January and June 2009, the Parent entered into forward starting swaps to mitigate
exposure to interest rate risk in anticipation of future debt issuances. At June 30, 2009, the Parent had $100 million notional of interest rate cash flow hedges. In July 2009, the Parent entered into an additional $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances.
  At December 31, 2008, PEC had $250 million notional of interest rate cash flow hedges. All of these forward starting swaps were terminated on January 8, 2009, in conjunction with PEC’s issuance of $600 million First Mortgage Bonds 5.30% Series due 2019. In January and June 2009, PEC entered into forward starting swaps to mitigate
exposure to interest rate risk in anticipation of future debt issuances. At June 30, 2009, PEC had $100 million notional of interest rate cash flow hedges.
  At December 31, 2008, PEF had no outstanding interest rate cash flow hedges. In January and June 2009, PEF entered into forward starting swaps to mitigate exposure to interest rate risk in anticipation of future debt issuances. At June 30, 2009, PEF had $75 million notional of interest rate cash flow hedges.
  FAIR VALUE HEDGES
  For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At June 30, 2009, and December 31, 2008, neither we nor the Utilities had any outstanding positions in such contracts.
  C.      CONTINGENT FEATURES
  Certain of our derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate
payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.
  The aggregate fair value of all derivative instruments at PEC with credit risk-related contingent features that are in a liability position at June 30, 2009 is $102 million, for which PEC has posted collateral of $8 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were
triggered at June 30, 2009, PEC would have been required to post an additional $94 million of collateral with its counterparties.
  44
  The aggregate fair value of all derivative instruments at PEF with credit risk-related contingent features that are in a liability position at June 30, 2009, is $545 million, for which PEF has posted collateral of $294 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were
triggered on June 30, 2009, PEF would have been required to post an additional $237 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, 2009 and December 31, 2008:
  (in millions)

June 30, 2009


December 31, 2008Instrument / Balance sheet location

Asset


Liability


Asset


LiabilityDerivatives designated as hedging instrumentsCommodity cash flow derivativesDerivative liabilities, current




$
–





$
(2
)Interest rate derivativesPrepayments and other current assets

$
4






$
–Other assets and deferred debits


9







–Derivative liabilities, current






–







(65
)Total derivatives designated as hedging instruments


13



–



–



(67
)Derivatives not designated as hedging instrumentsCommodity derivatives(a)Prepayments and other current assets


6







9Other assets and deferred debits


10







1Derivative liabilities, current






(407
)






(425
)Derivative liabilities, long-term






(240
)






(263
)CVOs(b)Other liabilities and deferred credits






(26
)






(34
)Fair value of derivatives not designated as hedging instruments


16



(673
)


10



(722
)Fair value loss transition adjustment(c)Derivative liabilities, current






(2
)






(1
)Derivative liabilities, long-term






(4
)






(6
)Total derivatives not designated as hedging instruments


16



(679
)


10



(729
)Total derivatives

$
29


$
(679
)

$
10


$
(796
)
  (a)
 (b)
 (c)
 45
 
 The following tables present the effect of derivative instruments on other comprehensive income (OCI) (See Note 6C) and the Consolidated Statements of Income for the three months ended June 30, 2009 and 2008:
  Derivatives Designated as Hedging InstrumentsInstrument

Amount of Gainor (Loss)Recognized
inOCI, Net of TaxonDerivatives(a)

Location of
Gain or (Loss) Reclassified
from
Accumulated
OCI into
Income(a)

Amount of Gainor (Loss), Net ofTaxReclassified
fromAccumulatedOCI intoIncome(a)

Location of
Gain or (Loss) Recognized in
Income on
Derivatives(b)

Amount of Pre-tax Gain or(Loss)Recognized
inIncome onDerivatives(b)(in millions)

2009


2008



2009


2008



2009


2008Interest rate derivatives(c)

$
8


$
13

Interest charges

$
(2
)

$
–

Interest charges


–


$
1  (a)
 (b)
 (c)
 
 Derivatives Not Designated as Hedging InstrumentsInstrument

Realized Gain or (Loss)(a)


Unrealized Gain or (Loss)(b)(in millions)

2009


2008


2009


2008Commodity derivatives

$
(185
)

$
109


$
78


$
824
  (a)
 (b)
 
 Instrument
Location of Gain or(Loss)Recognized
inIncome onDerivatives

Amount of Gain or(Loss)Recognized
inIncome onDerivatives(in millions)


2009


2008Commodity derivatives
Other, net

$
1


$
4Fair value loss transition adjustment
Other, net


1



–CVOs
Other, net


1



(2
)Total


$
3


$
2
 46
  The following tables present the effect of derivative instruments on OCI (see Note 6C) and the Consolidated Statements of Income for the six months ended June 30, 2009 and 2008:
  Derivatives Designated as Hedging InstrumentsInstrument

Amount of Gainor (Loss)Recognized
inOCI, Net of TaxonDerivatives(a)

Location of
Gain or (Loss) Reclassified
from
Accumulated
OCI into
Income(a)

Amount of Gainor (Loss), Net ofTax Reclassified
fromAccumulatedOCI intoIncome(a)

Location of
Gain or (Loss) Recognized in
Income on
Derivatives(b)

Amount of Pre-tax Gain or(Loss)Recognized
inIncome onDerivatives(b)(in millions)

2009


2008



2009


2008



2009


2008Commodity cash flow derivatives

$
1


$
(1
)


$
–


$
–



$
–


$
–Interest rate derivatives(c)


13



5

Interest charges


(3
)


(1
)
Interest charges


(3
)


1Total

$
14


$
4



$
(3
)

$
(1
)


$
(3
)

$
1  (a)
 (b)
 (c)
 Derivatives Not Designated as Hedging InstrumentsInstrument

Realized Gain or (Loss)(a)


Unrealized Gain or (Loss)(b)(in millions)

2009


2008


2009


2008Commodity derivatives

$
(312
)

$
125


$
(265
)

$
1,105
  (a)
 (b)
 
 Instrument
Location of Gain or(Loss)Recognized
inIncome onDerivatives

Amount of Gain or(Loss)Recognized
inIncome onDerivatives(in millions)


2009


2008Commodity derivatives
Other, net

$
–


$
4Fair value loss transition adjustment
Other, net


1



1CVOs
Other, net


8



(2
)Total


$
9


$
3
 47
  PEC
  The following table presents the fair value of derivative instruments at June 30, 2009 and December 31, 2008:
  (in millions)

June 30, 2009


December 31, 2008Instrument / Balance sheet location

Asset


Liability


Asset


LiabilityDerivatives designated as hedging instrumentsCommodity cash flow derivativesDerivative liabilities, current




$
–





$
(1
)Interest rate derivativesOther assets and deferred debits

$
5






$
–Derivative liabilities, current






–







(35
)Total derivatives designated as hedging instruments


5



–



–



(36
)Derivatives not designated as hedging instrumentsCommodity derivatives(a)Other assets and deferred debits


1







–Derivative liabilities, current






(46
)






(45
)Other liabilities and deferred credits






(56
)






(54
)Fair value of derivatives not designated as hedging instruments


1



(102
)


–



(99
)Fair value loss transition adjustment(b)Derivative liabilities, current






(2
)






(1
)Other liabilities and deferred credits






(4
)






(6
)Total derivatives not designated as hedging instruments


1



(108
)


–



(106
)Total derivatives

$
6


$
(108
)

$
–


$
(142
)
  (a)
 (b)
  48
 
 The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Consolidated Statements of Income for the three months ended June 30, 2009 and 2008:
  Derivatives Designated as Hedging InstrumentsInstrument

Amount ofGain or(Loss)Recognized
in OCI, Netof Tax onDerivatives(a)

Location of Gain
or (Loss)
Reclassified from Accumulated OCI
into Income(a)

Amount of Gainor (Loss), Netof TaxReclassified
fromAccumulatedOCI intoIncome(a)

Location of
Gain or (Loss) Recognized in
Income on
Derivatives(b)

Amount of Pre-tax Gain or(Loss)Recognized
inIncomeonDerivatives(b)(in millions)

2009


2008



2009


2008



2009


2008Interest rate derivatives(c)

$
2


$
–

Interest charges

$
(2
)

$
–

Interest charges

$
–


$
–
  (a)
 (b)
 (c)
 Derivatives Not Designated as Hedging InstrumentsInstrument

Realized Gain or (Loss)(a)


Unrealized Gain or (Loss)(b)(in millions)

2009


2008


2009


2008Commodity derivatives

$
(21
)

$
6


$
6


$
110
  (a)
 (b)
 Instrument
Location of Gain or(Loss)Recognized
inIncomeonDerivatives

Amount of Gain or(Loss)Recognized
inIncomeonDerivatives(in millions)


2009


2008Commodity derivatives
Other, net

$
1


$
4Fair value loss transition adjustment
Other, net


1



–Total


$
2


$
4
  49
  The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Consolidated Statements of Income for the six months ended June 30, 2009 and 2008:
  Derivatives Designated as Hedging InstrumentsInstrument

Amount ofGain or(Loss)Recognized
in OCI, Netof Tax onDerivatives(a)

Location of Gain
or (Loss)
Reclassified from Accumulated OCI
into Income(a)

Amount of Gainor (Loss), Netof TaxReclassified
fromAccumulatedOCI intoIncome(a)

Location of
Gain or (Loss) Recognized in Income on Derivatives(b)

Amount of Pre-tax Gain or(Loss)Recognized
inIncome onDerivatives(b)(in millions)

2009


2008



2009


2008



2009


2008Commodity cash flow derivatives

$
–


$
(2
)


$
–


$
–



$
–


$
–Interest rate derivatives(c)


2



(3
)
Interest charges


(2
)


–

Interest charges


(2
)


–Total

$
2


$
(5
)


$
(2
)

$
–



$
(2
)

$
–
  (a)
 (b)
 (c)
 Derivatives Not Designated as Hedging InstrumentsInstrument

Realized Gain or (Loss)(a)


Unrealized Gain or (Loss)(b)(in millions)

2009


2008


2009


2008Commodity derivatives

$
(39
)

$
6


$
(41
)

$
141
  (a)
 (b)
 Instrument
Location of Gain or(Loss)Recognized
inIncomeonDerivatives

Amount of Gain or(Loss)Recognized
inIncome onDerivatives(in millions)


2009


2008Commodity derivatives
Other, net

$
–


$
4Fair value loss transition adjustment
Other, net


1



1Total


$
1


$
5
  50
  PEF
  The following table presents the fair value of derivative instruments at June 30, 2009 and December 31, 2008:
  (in millions)

June 30, 2009


December 31, 2008Instrument / Balance sheet location

Asset


Liability


Asset


LiabilityDerivatives designated as hedging instrumentsInterest rate derivativesPrepayments and other current assets

$
4





$
–Total derivatives designated as hedging instruments


4






–Derivatives not designated as hedging instrumentsCommodity derivatives(a)Prepayments and other current assets


6






9Other assets and deferred debits


9






1Derivative liabilities, current





$
(361
)





$
(380
)Derivative liabilities, long-term






(184
)






(209
)Total derivatives not designated as hedging instruments


15



(545
)


10



(589
)Total derivatives

$
19


$
(545
)

$
10


$
(589
)
 
 (a) Substantially all of these contracts receive regulatory treatment.
 
 The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Statements of Income for the three months ended June 30, 2009 and 2008:
  Derivatives Designated as Hedging InstrumentsInstrument

Amount ofGain or(Loss)Recognized
in OCI, Netof Tax onDerivatives(a)

Location of Gain
or (Loss)
Reclassified from Accumulated OCI
into Income(a)

Amount of Gainor (Loss), Netof TaxReclassified
fromAccumulatedOCI intoIncome(a)

Location of
Gain or (Loss) Recognized in
Income on
Derivatives(b)

Amount of Pre-tax Gain or(Loss)Recognized
inIncome onDerivatives(b)(in millions)

2009


2008



2009


2008



2009


2008Interest rate derivatives(c)

$
3


$
12

Interest charges

$
–


$
–

Interest charges

$
–


$
1  (a)
 (b)
 (c)
 51
  Derivatives Not Designated as Hedging InstrumentsInstrument

Realized Gain or (Loss)(a)


Unrealized Gain or (Loss)(b)(in millions)

2009


2008


2009


2008Commodity derivatives

$
(164
)

$
103


$
72


$
714
  (a)
 (b)
 The following tables present the effect of derivative instruments on OCI (See Note 6C) and the Statements of Income for the six months ended June 30, 2009 and 2008:
  Derivatives Designated as Hedging InstrumentsInstrument

Amount ofGain or(Loss)Recognized
inOCI, Netof Tax onDerivatives(a)

Location of Gain
or (Loss)
Reclassified from Accumulated OCI
into Income(a)

Amount of Gainor (Loss), Netof TaxReclassified
fromAccumulatedOCI intoIncome(a)

Location of
Gain or (Loss) Recognized in
Income on
Derivatives(b)

Amount of Pre-tax Gain or(Loss)Recognized
inIncome onDerivatives(b)(in millions)

2009


2008



2009


2008



2009


2008Interest rate derivatives(c)

$
3


$
8

Interest charges

$
–


$
–

Interest charges

$
–


$
1  (a)
 (b)
 (c)
 
 Derivatives Not Designated as Hedging InstrumentsInstrument

Realized Gain or (Loss)(a)


Unrealized Gain or (Loss)(b)(in millions)

2009


2008


2009


2008Commodity derivatives

$
(273
)

$
119


$
(224
)

$
964
  (a)
 (b)
 52
 12.
FINANCIAL INFORMATION BY BUSINESS SEGMENT
  Our reportable PEC and PEF business segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. 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. The profit or loss of our reportable segments plus
the profit or loss of Corporate and Other represents our total income from continuing operations.
  Income of discontinued operations is not included in the table presented below. The following information is for the three and six months ended June 30:
 Income (Loss)Revenues


From Continuing(in millions)

Unaffiliated


Intersegment


Total


Operations


AssetsThree Months Ended June 30, 2009PEC

$
1,076


$
–


$
1,076


$
95


$
13,376PEF


1,234



–



1,234



119



13,074Corporate and Other


2



55



57



(39
)


19,227Eliminations


–



(55
)


(55
)


–



(14,803
)Totals

$
2,312


$
–


$
2,312


$
175


$
30,874Three Months Ended June 30, 2008PEC

$
1,048


$
–


$
1,048


$
104PEF


1,194



–



1,194



125Corporate and Other


2



94



96



(29
)Eliminations


–



(94
)


(94
)


–Totals

$
2,244


$
–


$
2,244


$
200
 
  Income (Loss)Revenues


From Continuing(in millions)

Unaffiliated


Intersegment


Total


Operations


AssetsSix Months Ended June 30, 2009PEC

$
2,254


$
–


$
2,254


$
222


$
13,376PEF


2,496



–



2,496



207



13,074Corporate and Other


4



120



124



(71
)


19,227Eliminations


–



(120
)


(120
)


–



(14,803
)Totals

$
4,754


$
–


$
4,754


$
358


$
30,874Six Months Ended June 30, 2008PEC

$
2,116


$
–


$
2,116


$
226PEF


2,190



–



2,190



191Corporate and Other


4



176



180



(64
)Eliminations


–



(176
)


(176
)


–Totals

$
4,310


$
–


$
4,310


$
353
  53
 
 13.
OTHER INCOME AND OTHER EXPENSE
  Other income and expense includes interest income and other income and expense items as discussed below. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities.
The components of other, net as shown on the accompanying Statements of Income were as follows:
  Progress EnergyThree Months Ended
June 30,


Six Months Ended
June 30,(in millions)

2009


2008


2009


2008Other incomeNonregulated energy and delivery services income

$
14


$
15


$
19


$
22Fair value loss transition adjustment amortization (see Note 11)


1



–



1



1Investment gains, net


4



–



4



–Gains from equity investments, net


1



–



–



–CVOs unrealized gain, net


1



–



8



–Derivative mark-to-market gain, net


1



4



–



4Other, net


2



–



–



–Total other income


24



19



32



27Other expenseNonregulated energy and delivery services expenses


6



5



10



9Donations


2



7



5



11Investment losses, net


–



1



–



3Loss from equity investments, net


–



1



2



3CVOs unrealized loss, net


–



2



–



2Impairment loss


3



–



3



–Other, net


–



–



–



1Total other expense


11



16



20



29Other, net – Progress Energy

$
13


$
3


$
12


$
(2
)
 
 PECThree Months Ended
June 30,


Six Months Ended
June 30,(in millions)

2009


2008


2009


2008Other incomeNonregulated energy and delivery services income

$
9


$
9


$
9


$
12Fair value loss transition adjustment amortization (see Note 11)


1



–



1



1Derivative mark-to-market gain, net


1



4



–



4Other, net


1



2



–



1Total other income


12



15



10



18Other expenseNonregulated energy and delivery services expenses


3



2



5



3Donations


2



4



3



6Investment losses, net


3



3



2



2Loss from equity investments, net


–



–



2



2Other, net


–



–



1



–Total other expense


8



9



13



13Other, net – PEC

$
4


$
6


$
(3
)

$
5
  54
  PEFThree Months Ended
June 30,


Six Months Ended
June 30,(in millions)

2009


2008


2009


2008Other incomeNonregulated energy and delivery services income

$
5


$
6


$
10


$
10Investment gains, net


5



1



4



–Other, net


–



–



–



2Total other income


10



7



14



12Other expenseNonregulated energy and delivery services expenses


2



3



4



6Donations


1



3



3



5Investment losses, net


–



–



–



1Loss from equity investments, net


–



1



–



1Total other expense


3



7



7



13Other, net – PEF

$
7


$
–


$
7


$
(1
)
 
  
 14.
ENVIRONMENTAL MATTERS
  We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and
operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.
  A.
HAZARDOUS AND SOLID WASTE
  The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of
statutes. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups as described below in greater detail. Various organic materials associated with the production of
manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate.
The outcome of potential and pending claims cannot be predicted. A discussion of sites by legal entity follows.
  We record accruals for probable and estimable costs related to environmental sites on an undiscounted basis. We measure our liability for these 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 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.
  55
  The following table contains 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:
  (in millions)

June 30, 2009


December 31, 2008PECMGP and other sites(a)

$
16


$
16PEFRemediation of distribution and substation transformers


17



22MGP and other sites


13



15Total PEF environmental remediation accruals(b)


30



37Total Progress Energy environmental remediation accruals

$
46


$
53
 
 (a)
Expected to be paid out over one to five years.
 (b)       Expected to be paid out over one to 15 years.
 
 PROGRESS ENERGY
  In addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 15B).
  PEC
  The NCUC and the SCPSC have authorized PEC to defer and amortize certain environmental remediation expenses. Remediation expenses not authorized to be deferred are included in operation and maintenance (O&M) expense.
  Including the Ward Transformer site located in Raleigh, N.C. (Ward), and MGP sites discussed below, for the three months ended June 30, 2009, PEC accrued approximately $1 million and spent approximately $2 million. For the six months ended June 30, 2009, PEC accrued approximately $4 million and spent approximately $4 million. For the three
months ended June 30, 2008, PEC accrued approximately $5 million and spent approximately $2 million. For the six months ended June 30, 2008, PEC accrued approximately $6 million and spent approximately $4 million. These amounts primarily relate to the Ward site.
  PEC has recorded a minimum estimated total remediation cost for all of its remaining MGP sites based upon its historical experience with remediation of several of its MGP sites. The maximum amount of the range for all the sites cannot be determined at this time as one of the remaining sites is significantly larger than the sites for which
we have historical experience. 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 site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA’s past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs
signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At June 30, 2009 and December 31, 2008, PEC’s recorded liability for the site was approximately $7 million. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. On September 12, 2008, PEC filed an initial civil action against a number of 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. On March 13, 2009, a subsequent action was filed against additional PRPs, and on April 30, 2009, suit was filed against the remaining approximately 160 PRPs. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. With respect to the defendants that do not settle, the federal district court in which this matter is pending requires that alternative dispute resolution be
pursued early in civil litigation. The outcome of these matters cannot be predicted.
  On September 30, 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).
 
 56
 
 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 January 19, 2009, PEC and several of the other participating PRPs at the Ward site submitted a letter containing a good faith response to the EPA’s special notice letter. Another group of PRPs separately submitted a good faith response, which the EPA advised would be used to negotiate implementation of the required actions. The other PRPs’ good faith response was subsequently withdrawn. Discussions among representatives of
certain PRPs, including PEC, and the EPA are ongoing. Although a loss is considered probable, an agreement among the PRPs for these matters has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation, if any, for Ward OU1 and Ward OU2.
  PEF
  PEF has received approval from the FPSC for recovery through the environmental cost recovery clause (ECRC) of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed all distribution transformer sites
and all substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should further distribution transformer sites be identified outside of this population, the distribution O&M costs will not be recoverable through the ECRC. For the three and six months ended June 30, 2009, PEF accrued approximately $2 million and spent approximately $4 million and $7 million, respectively, related to the remediation of transformers. For the three and six months ended June 30, 2008, PEF accrued approximately
$10 million and $12 million, respectively, due to the identification of additional transformer sites and an increase in estimated remediation costs, and spent approximately $8 million and $14 million, respectively, related to the remediation of transformers. At June 30, 2009, PEF had recorded a regulatory asset for the probable recovery of these costs through the ECRC.
  The accruals for MGP and other sites, in the previous table, relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. For the three and six months ended June 30, 2009, PEF made no material accruals and spent approximately $2 million, which primarily
related to its MGP sites. For the three and six months ended June 30, 2008, PEF made no material accruals or expenditures.
  B.
AIR AND WATER QUALITY
  At June 30, 2009 and December 31, 2008, we were subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expenses. These compliance laws and regulations included the Clean Air Interstate Rule (CAIR), the Clean
Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury regulation. PEC’s and PEF’s environmental compliance capital expenditures related to these regulations began in 2002 and 2005, respectively. At June 30, 2009, cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $2.027 billion, including $1.042 billion at PEC and $985 million at PEF. At December 31, 2008,
cumulative environmental compliance capital expenditures to date with regard to these environmental laws and regulations were $1.859 billion, including $1.012 billion at PEC, which primarily relates to Clean Smokestacks Act projects, and $847 million at PEF.
  PEF participated in a coalition of Florida utilities that filed a challenge to the CAIR as it applied to Florida. PEF withdrew from the coalition during the fourth quarter of 2008. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) issued its decision on multiple challenges to the CAIR, including
the Florida challenge, which vacated the CAIR in its entirety. On September 24, 2008, petitions for rehearing were filed by a number of parties. On December 23, 2008, the D.C. Court of Appeals remanded the CAIR without vacating the rule for the EPA to conduct further proceedings consistent with the D.C. Court of Appeals’ prior opinion. The outcome of the EPA’s further proceedings cannot be predicted. Because the D.C. Court of Appeals’ December 23, 2008 decision remanded the CAIR, the current
implementation of the CAIR continues to fulfill best available retrofit technology (BART) for SO2 and nitrogen oxides (NOx) for BART-affected units under the CAVR. Should this determination change as the CAIR is revised, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition to particulate matter emissions for BART-eligible units.
  57
  On February 8, 2008, the D.C. Court of Appeals vacated the delisting determination and the Clean Air Mercury Rule (CAMR). The three states in which the Utilities operate adopted mercury regulations implementing CAMR and submitted their state implementation rules to the EPA. It is uncertain how the decision that vacated the federal CAMR
will affect the state rules; however, state-specific provisions are likely to remain in effect. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of these decisions. The outcome of these matters cannot be predicted.
  PEF is continuing construction of its in-process emission control projects. On December 18, 2008, PEF and the FDEP announced an agreement under which PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and complete construction of its emission control projects at CR4 and CR5. CR1 and CR2 will be retired
after the second proposed nuclear unit at Levy completes its first fuel cycle, which was anticipated to be around 2020. On May, 1, 2009, PEF announced that it expects the construction schedule to shift later than the originally estimated 2016 to 2018 timeframe by a minimum of 20 months for the commercial operation dates of Levy. We are currently evaluating the impacts of the schedule shift. We cannot predict the outcome of this matter.
  We account for emission allowances as inventory using the average cost method. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. The EPA is continuing to record allowance allocations under the CAIR NOx trading program, in some cases for years beyond the estimated two-year period for promulgation
of a replacement rule. The EPA’s continued recording of CAIR NOx allowance allocations does not guarantee that allowances will continue to be usable for compliance after a replacement rule is finalized or that they will continue to have value in the future. SO2 emission allowances will be utilized to comply with existing Clean Air Act requirements. PEF’s CAIR expenses, including NOx allowance inventory expense, are recoverable
through the ECRC. At June 30, 2009 and December 31, 2008, PEC had approximately $17 million and $22 million, respectively, in SO2 emission allowances and an immaterial amount of NOx emission allowances. At June 30, 2009 and December 31, 2008, PEF had approximately $9 million and $11 million, respectively, in SO2 emission allowances and approximately $54 million and
$65 million, respectively, in NOx emission allowances.
  In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. Two of PEC’s largest coal-fired generating
units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. Pursuant to joint ownership agreements, the joint owners are required to pay a portion of the costs of owning and operating these plants. PEC has determined that the most cost-effective Clean Smokestacks Act compliance strategy is to maximize the SO2 removal from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to avoid
the installation of expensive emission controls on its smaller coal-fired units. In order to address the joint owner's concerns that such a compliance strategy would result in a disproportionate share of the cost of compliance for the jointly owned units, in 2005 PEC entered into an agreement with the joint owner to limit its aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act to approximately $38 million. PEC recorded a related liability for the joint owner's share of
estimated costs in excess of the contract amount. The terms of the agreement place no limit on PEC’s maximum remaining liability; however PEC estimates its remaining exposure to be $7 million as of June 30, 2009. At June 30, 2009 and December 31, 2008, the amount of the liability was $7 million and $10 million, respectively, based upon the respective estimates for the remaining Clean Smokestacks Act compliance costs. During the three and six months ended June 30, 2009, PEC accrued approximately $2 million
and spent approximately $1 million and $5 million, respectively, that exceeded the joint owner limit (See Note 15B). Because PEC has taken a system-wide compliance approach, its North Carolina retail ratepayers have significantly benefited from the strategy of focusing emission reduction efforts on the jointly owned units, and, therefore, PEC believes that any costs in excess of the joint owner’s share should be recovered from North Carolina retail ratepayers, consistent with other capital expenditures
associated with PEC’s compliance with the Clean Smokestacks Act. On September 5, 2008, the NCUC ordered that PEC shall be allowed to include in rate base all reasonable and prudently incurred environmental compliance costs in excess of $584 million, including eligible compliance costs in excess of the joint owner’s share, as the projects are closed to plant in service.
 58
 15.
COMMITMENTS AND CONTINGENCIES
  Contingencies and significant changes to the commitments discussed in Note 22 in the 2008 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 2008 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.
  PEF
 
 On May 1, 2009, PEF announced that it expects the construction schedule for Levy to shift. Although the overall schedule impact is not certain at this time, PEF expects the schedule for the commercial operation of Levy to shift later than the 2016 to 2018 timeframe by a minimum of 20 months. We anticipate amending the Levy Engineering,
Procurement, and Construction agreement due to the schedule shift but cannot predict the impact, if any, such amendment might have on the project’s total cost. However, consistent with nuclear cost-recovery filings with the FPSC (See Note 4B), PEF anticipates that approximately $1 billion of the construction obligations disclosed in Note 22A in the 2008 Form 10-K for the three-year period following December 31, 2008, could be deferred to later periods as a result of the schedule shift.
  During the second quarter of 2009, PEF entered into conditional agreements for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with these agreements is estimated to be approximately $281 million. These agreements are subject
to several conditions precedent, including various federal regulatory approvals, the completion and commencement of operation of necessary related interstate natural pipeline system expansions, and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEF’s fuel and purchased power commitments.
 
 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, 2009, 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, 2009, 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. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of
legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications have no limitations as to time or maximum potential future payments. In 2005, PEC entered into an agreement with the joint owner of certain facilities at the Mayo and Roxboro plants to limit their aggregate costs associated
with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability related to this indemnification (See Note 14B). The terms of the agreement place no limit on PEC’s maximum remaining liability; however PEC estimates its remaining exposure to be $7 million as of June 30, 2009. Pursuant to a September 2008 NCUC order, PEC is including the indemnification costs as allowable costs to be included in rate base for ratemaking purposes (See Note 14B). At June 30, 2009, our estimated
maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $458 million, including $32 million at PEF. At June 30, 2009 and December 31, 2008, we have recorded liabilities related to guarantees and indemnifications to third parties of approximately $58 million and $61 million, respectively. These amounts include $7 million and $10 million, respectively, for PEC and $8 million for PEF at
 
 59
 
 June 30, 2009, and December 31, 2008. During the three and six months ended June 30, 2009, PEC accrued approximately $2 million and spent approximately $1 million and $5 million, respectively, that exceeded the joint owner limit. As current estimates change, it is possible that additional losses related to guarantees and indemnifications
to third parties, which could be material, may be recorded in the future.
  In addition, the Parent and a subsidiary have issued $300 million of guarantees for certain payments of two wholly owned indirect subsidiaries. See Note 16 for additional information.
  C.
OTHER COMMITMENTS AND CONTINGENCIES
  SPENT NUCLEAR FUEL MATTERS
  Pursuant to the Nuclear Waste Policy Act of 1982, the Utilities entered into contracts with the United States Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.
  The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from our various facilities
on or before January 31, 1998. Approximately 60 cases involving the government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. The Utilities have asserted nearly $91 million in damages incurred between January 31, 1998 and December 31, 2005; the time period set by the court for damages in this case. The Utilities will be free to file subsequent damage claims as they incur additional costs.
  A trial was held in November 2007 in the United States Court of Federal Claims, and closing arguments were presented on April 4, 2008. On May 19, 2008, the Utilities received a ruling from the Trial Court awarding $83 million in the claim against the DOE for failure to abide by a contract for federal disposition of spent nuclear fuel. The
United States Department of Justice requested that the Trial Court reconsider its ruling. The Trial Court did reconsider its ruling and reduced the damage award by an immaterial amount. On August 15, 2008, the Department of Justice appealed the Trial Court’s ruling to the D.C. Court of Appeals. Oral arguments were held on May 4, 2009. On July 21, 2009, the D.C. Court of Appeals vacated and remanded the calculation of damages back to the Trial Court but affirmed the portion of damages awarded that were directed
to overhead costs and other indirect expenses. The Trial Court has not yet scheduled further proceedings. In the event that the Utilities recover damages in this matter, such recovery is not expected to have a material impact on the Utilities’ results of operations given the anticipated regulatory and accounting treatment. However, the Utilities cannot predict the outcome of this matter.
  SYNTHETIC FUELS MATTERS
  A number of our subsidiaries and affiliates are parties to two lawsuits arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000, (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco; certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by
Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates). Global has asserted (1) that pursuant to the Asset Purchase Agreement, it is 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, (2) that it is entitled to damages
because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities and (3) a number of tort claims are related to the contracts.
  The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al. (the Florida Global Case), asserts the above claims in a case filed in the Circuit Court for Broward County, Fla., in March 2003, and requests an unspecified amount of compensatory damages, as well as declaratory relief.
The Progress Affiliates have answered the Complaint by generally denying all of Global’s substantive allegations and asserting numerous substantial affirmative defenses.
  The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), was filed by the Progress Affiliates in the Superior Court for Wake County, N.C., seeking declaratory relief consistent with our interpretation of the Asset Purchase Agreement.
Global was served with the North Carolina Global Case on April 17, 2003.
  60
  On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates’ declaratory judgment action. On August 7, 2003, the Wake County Superior Court denied Global’s
motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court’s order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates’ appeal. Since that time, the parties have been engaged in discovery in the Florida Global Case.
  In December 2006, we reached agreement with Global to settle an additional claim in the suit related to amounts due to Global that were placed in escrow pursuant to a defined tax event. Upon the successful resolution of the IRS audit of the Earthco synthetic fuels facilities in 2006, and pursuant to a settlement agreement, the escrow totaling
$42 million at December 31, 2006, was paid to Global in January 2007.
  In January 2008, Global agreed to simplify the Florida action by dismissing the tort claims. The Florida Global Case continues now under contract theories alone. The case is scheduled to go to trial in September 2009. We cannot predict the outcome of this matter.
  OTHER LITIGATION MATTERS
  We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, we have made accruals and disclosures to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse
effect on our consolidated results of operations or financial position.
  
 16.
CONDENSED CONSOLIDATING STATEMENTS
  As discussed in Note 23 in the 2008 Form 10-K, we have guaranteed certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.) since September 2005. Our guarantees are joint and several, full and unconditional and are in addition to the joint and several,
full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 11B in the 2008 Form 10-K, there were no restrictions on PEC’s or PEF’s retained earnings.
  The Trust is a variable-interest entity for which we are not the primary beneficiary. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.
  Presented below are the condensed consolidating Statements of Income, Balance Sheets and Statements of Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed consolidating statements, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the consolidated
financial results of Florida Progress only, which is primarily comprised of its wholly owned subsidiary PEF. The Non-Guarantor Subsidiary column includes the consolidated financial results of our wholly owned subsidiary PEC. The Other column includes the consolidated financial results of all other non-guarantor subsidiaries and elimination entries for all intercompany transactions. 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.
  61
  
 Condensed Consolidating Statement of Income
Three Months Ended June 30, 2009(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.Operating revenues

$
–


$
1,236


$
1,076


$
–


$
2,312Operating expensesFuel used in electric generation


–



443



383



–



826Purchased power


–



200



57



–



257Operation and maintenance


2



204



283



(5
)


484Depreciation, amortization and accretion


–



105



118



3



226Taxes other than on income


–



80



51



(1
)


130Other


–



8



2



–



10Total operating expenses


2



1,040



894



(3
)


1,933Operating (loss) income


(2
)


196



182



3



379Other income (expense)Interest income


3



1



1



(3
)


2Allowance for equity funds used during construction


–



29



7



–



36Other, net


1



6



4



2



13Total other income (expense), net


4



36



12



(1
)


51Interest chargesInterest charges


58



71



52



–



181Allowance for borrowed funds used during construction


–



(9
)


(3
)


–



(12
)Total interest charges, net


58



62



49



–



169(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries


(56
)


170



145



2



261Income tax (benefit) expense


(26
)


55



51



6



86Equity in earnings of consolidated subsidiaries


204



–



–



(204
)


–Income (loss) from continuing operations


174



115



94



(208
)


175Discontinued operations, net of tax


–



–



–



(1
)


(1
)Net income (loss)


174



115



94



(209
)


174Net loss (income) attributable to noncontrolling interests, net of tax


–



–



1



(1
)


–Net income (loss) attributable to controlling interests

$
174


$
115


$
95


$
(210
)

$
174
 
  62
  
 Condensed Consolidating Statement of Income
Three Months Ended June 30, 2008(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.Operating revenues

$
–


$
1,196


$
1,048


$
–


$
2,244Operating expensesFuel used in electric generation


–



373



323



–



696Purchased power


–



258



72



–



330Operation and maintenance


2



217



275



(6
)


488Depreciation, amortization and accretion


–



76



129



3



208Taxes other than on income


–



76



49



–



125Other


–



(4
)


(5
)


–



(9
)Total operating expenses


2



996



843



(3
)


1,838Operating (loss) income


(2
)


200



205



3



406Other income (expense)Interest income


2



2



2



(1
)


5Allowance for equity funds used during construction


–



22



5



–



27Other, net


(2
)


–



6



(1
)


3Total other income (expense), net


–



24



13



(2
)


35Interest chargesInterest charges


50



52



52



–



154Allowance for borrowed funds used during construction


–



(6
)


(2
)


–



(8
)Total interest charges, net


50



46



50



–



146(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries


(52
)


178



168



1



295Income tax (benefit) expense


(22
)


53



64



–



95Equity in earnings of consolidated subsidiaries


235



–



–



(235
)


–Income (loss) from continuing operations


205



125



104



(234
)


200Discontinued operations, net of tax


–



7



–



(2
)


5Net income (loss)


205



132



104



(236
)


205Net income (loss) attributable to controlling interests

$
205


$
132


$
104


$
(236
)

$
205
  63
  
 Condensed Consolidating Statement of Income
Six Months Ended June 30, 2009(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.Operating revenues

$
–


$
2,500


$
2,254


$
–


$
4,754Operating expensesFuel used in electric generation


–



955



825



–



1,780Purchased power


–



360



114



–



474Operation and maintenance


3



406



542



(14
)


937Depreciation, amortization and accretion


–



265



235



6



506Taxes other than on income


–



168



105



–



273Other


–



10



2



–



12Total operating expenses


3



2,164



1,823



(8
)


3,982Operating (loss) income


(3
)


336



431



8



772Other income (expense)Interest income


6



2



3



(5
)


6Allowance for equity funds used during construction


–



59



16



–



75Other, net


8



6



(3
)


1



12Total other income (expense), net


14



67



16



(4
)


93Interest chargesInterest charges


110



143



109



(2
)


360Allowance for borrowed funds used during construction


–



(18
)


(6
)


–



(24
)Total interest charges, net


110



125



103



(2
)


336(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries


(99
)


278



344



6



529Income tax (benefit) expense


(39
)


76



122



12



171Equity in earnings of consolidated subsidiaries


415



–



–



(415
)


–Income (loss) from continuing operations


355



202



222



(421
)


358Discontinued operations, net of tax


1



(1
)


–



(1
)


(1
)Net income (loss)


356



201



222



(422
)


357Net (income) loss attributable to noncontrolling interests, net of tax


–



(1
)


1



(1
)


(1
)Net income (loss) attributable to controlling interests

$
356


$
200


$
223


$
(423
)

$
356
  64
  
 Condensed Consolidating Statement of Income
Six Months Ended June 30, 2008(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.Operating revenues

$
–


$
2,194


$
2,116


$
–


$
4,310Operating expensesFuel used in electric generation


–



714



679



–



1,393Purchased power


–



441



121



–



562Operation and maintenance


2



420



523



(14
)


931Depreciation, amortization and accretion


–



152



255



7



414Taxes other than on income


–



147



99



–



246Other


–



(2
)


(6
)


1



(7
)Total operating expenses


2



1,872



1,671



(6
)


3,539Operating (loss) income


(2
)


322



445



6



771Other income (expense)Interest income


6



2



7



(3
)


12Allowance for equity funds used during construction


–



40



10



–



50Other, net


(2
)


(3
)


5



(2
)


(2
)Total other income (expense), net


4



39



22



(5
)


60Interest chargesInterest charges


98



109



110



(2
)


315Allowance for borrowed funds used during construction


–



(12
)


(4
)


–



(16
)Total interest charges, net


98



97



106



(2
)


299(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries


(96
)


264



361



3



532Income tax (benefit) expense


(40
)


80



134



5



179Equity in earnings of consolidated subsidiaries


470



–



–



(470
)


–Income (loss) from continuing operations


414



184



227



(472
)


353Discontinued operations, net of tax


–



64



–



2



66Net income (loss)


414



248



227



(470
)


419Net income attributable to noncontrolling interests, net of tax


–



(5
)


–



–



(5
)Net income (loss) attributable to controlling interests

$
414


$
243


$
227


$
(470
)

$
414
  65
 
 Condensed Consolidating Balance Sheet
June 30, 2009(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.ASSETSUtility plant, net

$
–


$
9,286


$
9,570


$
118


$
18,974Current assetsCash and cash equivalents


365



68



18



1



452Notes receivable from affiliated companies


363



100



130



(593
)


–Regulatory assets


–



278



148



–



426Derivative collateral posted


–



294



8



–



302Income taxes receivable


1



35



32



4



72Prepayments and other current assets


4



1,235



1,197



17



2,453Total current assets


733



2,010



1,533



(571
)


3,705Deferred debits and other assetsInvestment in consolidated subsidiaries


12,519



–



–



(12,519
)


–Regulatory assets


–



1,376



1,247



–



2,623Goodwill


–



–



–



3,655



3,655Other assets and deferred debits


165



629



1,026



97



1,917Total deferred debits and other assets


12,684



2,005



2,273



(8,767
)


8,195Total assets

$
13,417


$
13,301


$
13,376


$
(9,220
)

$
30,874CAPITALIZATION AND LIABILITIESEquityCommon stock equity

$
9,289


$
4,067


$
4,354


$
(8,421
)

$
9,289Noncontrolling interests


–



3



3



–



6Total equity


9,289



4,070



4,357



(8,421
)


9,295Preferred stock of subsidiaries


–



34



59



–



93Long-term debt, affiliate


–



309



–



(37
)


272Long-term debt, net


3,243



3,882



3,709



–



10,834Total capitalization


12,532



8,295



8,125



(8,458
)


20,494Current liabilitiesCurrent portion of long-term debt


100



300



–



–



400Short-term debt


500



–



–



–



500Notes payable to affiliated companies


–



623



–



(623
)


–Other current liabilities


250



1,382



736



(50
)


2,318Total current liabilities


850



2,305



736



(673
)


3,218Deferred credits and other liabilitiesNoncurrent income tax liabilities


–



174



1,162



(395
)


941Regulatory liabilities


–



1,077



1,082



117



2,276Other liabilities and deferred credits


35



1,450



2,271



189



3,945Total deferred credits and other liabilities


35



2,701



4,515



(89
)


7,162Total capitalization and liabilities

$
13,417


$
13,301


$
13,376


$
(9,220
)

$
30,874
 
  66
   Condensed Consolidating Balance Sheet
December 31, 2008(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.ASSETSUtility plant, net

$
–


$
8,790


$
9,385


$
118


$
18,293Current assetsCash and cash equivalents


88



73



18



1



180Notes receivable from affiliated companies


34



44



55



(133
)


–Regulatory assets


–



326



207



–



533Derivative collateral posted


–



335



18



–



353Income taxes receivable


34



56



98



6



194Prepayments and other current assets


14



1,082



1,174



(10
)


2,260Total current assets


170



1,916



1,570



(136
)


3,520Deferred debits and other assetsInvestment in consolidated subsidiaries


11,924



–



–



(11,924
)


–Regulatory assets


–



1,324



1,243



–



2,567Goodwill


–



–



–



3,655



3,655Other assets and deferred debits


155



613



967



103



1,838Total deferred debits and other assets


12,079



1,937



2,210



(8,166
)


8,060Total assets

$
12,249


$
12,643


$
13,165


$
(8,184
)

$
29,873CAPITALIZATION AND LIABILITIESEquityCommon stock equity

$
8,687


$
3,519


$
4,301


$
(7,820
)

$
8,687Noncontrolling interests


–



3



4



(1
)


6Total equity


8,687



3,522



4,305



(7,821
)


8,693Preferred stock of subsidiaries


–



34



59



–



93Long-term debt, affiliate


–



309



–



(37
)


272Long-term debt, net


2,696



4,182



3,509



–



10,387Total capitalization


11,383



8,047



7,873



(7,858
)


19,445Current liabilitiesShort-term debt


569



371



110



–



1,050Notes payable to affiliated companies


–



206



–



(206
)


–Other current liabilities


251



1,344



855



(14
)


2,436Total current liabilities


820



1,921



965



(220
)


3,486Deferred credits and other liabilitiesNoncurrent income tax liabilities


1



118



1,111



(412
)


818Regulatory liabilities


–



1,076



987



118



2,181Other liabilities and deferred credits


45



1,481



2,229



188



3,943Total deferred credits and other liabilities


46



2,675



4,327



(106
)


6,942Total capitalization and liabilities

$
12,249


$
12,643


$
13,165


$
(8,184
)

$
29,873
  67
 
 Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2009(in millions)

Parent


Subsidiary
Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.Net cash provided (used) by operating activities

$
169


$
454


$
646


$
(174
)

$
1,095Investing activitiesGross property additions


–



(770
)


(402
)


–



(1,172
)Nuclear fuel additions


–



(18
)


(42
)


–



(60
)Purchases of available-for-sale securities and other investments


–



(420
)


(517
)


(45
)


(982
)Proceeds from available-for-sale securities and other investments


–



423



492



45



960Changes in advances to affiliated companies


(329
)


(56
)


(75
)


460



–Contributions to consolidated subsidiaries


(347
)


–



–



347



–Return of investment in consolidated subsidiaries


12



–



–



(12
)


–Other investing activities


–



(1
)


–



(2
)


(3
)Net cash (used) provided by investing activities


(664
)


(842
)


(544
)


793



(1,257
)Financing activitiesIssuance of common stock


545



–



–



–



545Dividends paid on common stock


(347
)


–



–



–



(347
)Dividends paid to parent


–



(1
)


(200
)


201



–Payments of short-term debt with original maturities greater than 90 days


(29
)


–



–



–



(29
)Net decrease in short-term debt


(140
)


(371
)


(110
)


–



(621
)Proceeds from issuance of long-term debt, net


742



–



595



–



1,337Retirement of long-term debt


–



–



(400
)


–



(400
)Cash distributions to noncontrolling interests


–



(3
)


–



(1
)


(4
)Changes in advances from affiliated companies


–



417



–



(417
)


–Contributions from parent


–



343



15



(358
)


–Other financing activities


1



(2
)


(2
)


(44
)


(47
)Net cash provided (used) by financing activities


772



383



(102
)


(619
)


434Net increase (decrease) in cash and cash equivalents


277



(5
)


–



–



272Cash and cash equivalents at beginning of period


88



73



18



1



180Cash and cash equivalents at end of period

$
365


$
68


$
18


$
1


$
452
 
  68
  
 Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2008(in millions)

Parent


Subsidiary Guarantor


Non-
Guarantor
Subsidiary


Other


Progress
Energy,
Inc.Net cash (used) provided by operating activities

$
(53
)

$
856


$
563


$
(9
)

$
1,357Investing activitiesGross property additions


–



(921
)


(331
)


(8
)


(1,260
)Nuclear fuel additions


–



(1
)


(42
)


–



(43
)Proceeds from sales of discontinued operations and other assets, net of cash divested


–



61



4



(1
)


64Proceeds from sales of assets to affiliated companies


–



10



–



(10
)


–Purchases of available-for-sale securities and other investments


–



(418
)


(337
)


(81
)


(836
)Proceeds from available-for-sale securities and other investments


–



418



321



77



816Changes in advances to affiliated companies


129



31



(39
)


(121
)


–Contributions to consolidated subsidiaries


(98
)


–



–



98



–Return of investment in consolidated subsidiaries


–



10



–



(10
)


–Other investing activities


(7
)


3



(10
)


(1
)


(15
)Net cash provided (used) by investing activities


24



(807
)


(434
)


(57
)


(1,274
)Financing activitiesIssuance of common stock


42



–



–



–



42Dividends paid on common stock


(320
)


–



–



–



(320
)Dividends paid to parent


–



(3
)


–



3



–Payments of short-term debt with original maturities greater than 90 days


(176
)


–



–



–



(176
)Net increase in short-term debt


318



–



–



–



318Proceeds from issuance of long-term debt, net


–



1,476



322



–



1,798Retirement of long-term debt


–



(127
)


(300
)


–



(427
)Cash distributions to noncontrolling interests


–



(85
)


–



–



(85
)Changes in advances from affiliated companies


–



(56
)


(154
)


210



–Contributions from parent


–



85



14



(99
)


–Other financing activities


–



1



(18
)


(48
)


(65
)Net cash (used) provided by financing activities


(136
)


1,291



(136
)


66



1,085Net (decrease) increase in cash and cash equivalents


(165
)


1,340



(7
)


–



1,168Cash and cash equivalents at beginning of period


185



43



25



2



255Cash and cash equivalents at end of period

$
20


$
1,383


$
18


$
2


$
1,423
 
  69
  ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSISOF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
  
 
 The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is separately filed by Progress Energy, Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF).
As used in this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy,
PEC and PEF. Information contained herein relating to PEC and PEF individually is filed by such company on its own behalf. Neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.
  The following MD&A contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “Safe Harbor for Forward-Looking Statements”
and Item 1A, “Risk Factors” found within Part II of this Form 10-Q and Item 1A, “Risk Factors” to the Progress Registrant’s annual report on Form 10-K for the fiscal year ended December 31, 2008 (2008 Form 10-K) for a discussion of the factors that may impact any such forward-looking statements made herein.
  Amounts reported in the interim statements of income are not necessarily indicative of amounts expected for the respective annual or future periods due to the effects of weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, among other factors.
  This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2008 Form 10-K.
  PROGRESS ENERGY
  RESULTS OF OPERATIONS
  In this section, earnings and the factors affecting earnings for the three and six months ended June 30, 2009, are compared to the same period in 2008. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.
  Our reportable operating business segments are PEC and PEF, which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina, and Florida, respectively.
  Our “Corporate and Other” segment primarily includes the operations of the Parent, Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a reportable business segment.
  OVERVIEW
  For the three months ended June 30, 2009, our net income attributable to controlling interests was $174 million, or $0.62 per share, compared to net income attributable to controlling interests of $205 million, or $0.78 per share, for the same period in 2008. For the three months ended June 30, 2009, our income from continuing operations
was $175 million compared to $200 million for the same period in 2008. The decrease in income from continuing operations as compared to prior year was primarily due to:
  ·
unfavorable net retail customer growth and usage at the Utilities;
 ·
higher interest expense at PEF; and
 ·
lower wholesale revenues at the Utilities.
 70
  Offsetting these items was:
  ·
lower depreciation expense associated with PEC’s accelerated cost-recovery program for nuclear generating assets recognized during 2008.
 
 For the six months ended June 30, 2009, our net income attributable to controlling interests was $356 million, or $1.28 per share, compared to net income attributable to controlling interests of $414 million, or $1.59 per share, for the same period in 2008. For the six months ended June 30, 2009, our income from continuing operations was
$358 million compared to $353 million for the same period in 2008. The increase in income from continuing operations as compared to prior year was primarily due to:
  ·
favorable allowance for funds used during construction (AFUDC) equity at the Utilities;
 ·
favorable weather at the Utilities; and
 ·
lower depreciation and amortization expense at PEC related to North Carolina Clean Smokestacks Act (Clean Smokestacks Act) amortization expense and depreciation expense associated with the accelerated cost-recovery program for nuclear generating assets recognized during 2008.
 
 Offsetting these items were:
  ·
unfavorable net retail customer growth and usage at the Utilities; and
 ·
higher interest expense at PEF.
 
 Our segments contributed the following profits or losses for the three and six months ended June 30, 2009 and 2008:
  Three Months Ended June 30,


Six Months Ended June 30,(in millions)

2009


2008


2009


2008Business SegmentPEC

$
95


$
104


$
222


$
226PEF


119



125



207



191Total segment profit


214



229



429



417Corporate and Other


(39
)


(29
)


(71
)


(64
)Income from continuing operations


175



200



358



353Discontinued operations, net of tax


(1
)


5



(1
)


66Net income attributable to noncontrolling interests, net of tax


–



–



(1
)


(5
)Net income attributable to controlling interests

$
174


$
205


$
356


$
414
 
 PROGRESS ENERGY CAROLINAS
  PEC contributed segment profits of $95 million and $104 million for the three months ended June 30, 2009 and 2008, respectively. The decrease in profits for the three months ended June 30, 2009, compared to the same period in 2008, was primarily due to lower wholesale revenues and unfavorable net retail customer growth and usage, primarily
in the industrial customer class, partially offset by the impact of lower depreciation expense.
  PEC contributed segment profits of $222 million and $226 million for the six months ended June 30, 2009 and 2008, respectively. The decrease in profits for the six months ended June 30, 2009, compared to the same period in 2008, was primarily due to higher operation and maintenance expenses (O&M), unfavorable net retail customer growth
and usage, primarily in the industrial customer class, and lower wholesale revenues, partially offset by lower depreciation and amortization expense and the favorable impact of weather.
  The revenue tables that follow present the total amount and percentage change of revenues excluding fuel and other pass-through revenues. Revenues excluding fuel and other pass-through revenues is defined as total electric revenues less fuel and other pass-through revenues. We and PEC consider revenues excluding fuel and other pass-through
revenues a useful measure to evaluate PEC’s electric operations because fuel and other pass-through revenues primarily represent the recovery of fuel and a portion of purchased power expenses and other pass-through expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. Pass-through
  71
 
 revenues do not include the revenues associated with the return on asset component of demand-side management (DSM), energy-efficiency and renewable energy clause revenues as these revenues will have an impact on reported earnings. We and PEC have included the analysis below as a complement to the financial information we provide in accordance
with accounting principles generally accepted in the United States of America (GAAP). However, revenues excluding fuel and other pass-through revenues is not defined under GAAP, and the presentation may not be comparable to other companies’ presentation or more useful than the GAAP information provided elsewhere in this report.
  Three Months Ended June 30, 2009, Compared to Three Months Ended June 30, 2008
  REVENUES
  PEC’s electric revenues for the three months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions)

Three Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential

$
367


$
33



9.9


$
334Commercial


288



19



7.1



269Industrial


172



(15
)


(8.0
)


187Governmental


26



3



13.0



23Unbilled


31



7



–



24Total retail revenues


884



47



5.6



837Wholesale


165



(24
)


(12.7
)


189Miscellaneous


27



5



22.7



22Total electric revenues


1,076



28



2.7



1,048Less: Fuel and other pass-through revenues


(430
)


(45
)


–



(385
)Revenues excluding fuel and other pass-through revenues

$
646


$
(17
)


(2.6
)

$
663
 
 PEC’s revenues, excluding fuel and other pass-through revenues of $430 million and $385 million for the three months ended June 30, 2009 and 2008, respectively, decreased $17 million. The decrease in revenues, excluding fuel and other pass-through revenues, was primarily due to $16 million lower wholesale revenues, and $14 million
unfavorable impact of net retail customer growth and usage, primarily in the industrial customer class, partially offset by $9 million favorable impact of weather. Lower wholesale revenues, excluding fuel and other pass-through revenues, were primarily due to lower energy rates with a major customer. The unfavorable impact of net retail customer growth and usage was driven by a decrease in the average usage per retail customer, partially offset by a net 15,000 increase in the average number of customers for the
three months ended June 30, 2009, compared to the same period in 2008. However, PEC’s rate of residential growth has declined as PEC’s average number of customers for the three months ended June 30, 2008, compared to the same period in 2007, increased a net 25,000 customers. The favorable impact of weather was driven by 13 percent higher cooling degree days than 2008. Cooling degree days were higher than normal in both 2009 and 2008.
  72
  PEC’s electric energy sales for the three months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions of kWh)

Three Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential


3,591



5



0.1



3,586Commercial


3,290



(94
)


(2.8
)


3,384Industrial


2,562



(560
)


(17.9
)


3,122Governmental


357



22



6.6



335Unbilled


634



389



–



245Total retail kWh sales


10,434



(238
)


(2.2
)


10,672Wholesale


3,259



(182
)


(5.3
)


3,441Total kWh sales


13,693



(420
)


(3.0
)


14,113
 
 Many of the manufacturers in PEC’s service territory have been adversely impacted by the recession, and we expect continued industrial sales weakness until the broader economy recovers.  PEC’s industrial kilowatt-hours (kWh) sales have decreased 17.9 percent from 2008, primarily due to reductions in textile manufacturing
in the Carolinas as a result of global competition and domestic consolidation as well as a downturn in the lumber and building materials segment as a result of declines in construction activities. However, sales to the chemical segment, now our largest industrial segment, have slightly increased. While industrial kWh sales have decreased 17.9 percent from 2008, industrial revenues have only decreased 8.0 percent due in part to increased fuel revenues and the demand charges component of industrial revenues.
  Retail revenues increased for the three months ended June 30, 2009, despite a decrease in retail kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates.
  Wholesale kWh sales decreased for the three months ended June 30, 2009, primarily due to decreased excess generation sales resulting from unfavorable market dynamics. In June 2009, PEC executed a contract extension with its largest municipal wholesale customer, Public Works Commission of the City of Fayetteville, N.C. The 20-year agreement
extends the current contract, representing more than 500 megawatts (MW) of electricity load, through 2032.
  PEC has experienced a decline in the rate of residential sales growth and in its commercial and industrial kWh sales due to the current recession in the United States. We cannot predict how long the recession may last or the extent to which it may impact revenues. In the future, PEC’s customer usage could be impacted by customer response
to energy-efficiency programs and to increased rates.
  EXPENSES
  Fuel and Purchased Power
  Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and a portion of purchased power expenses are recovered primarily through cost-recovery clauses, and as such, changes in these expenses do not have a material
impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection from or refund to customers.
  Fuel and purchased power expenses were $440 million for the three months ended June 30, 2009, which represents a $45 million increase compared to the same period in 2008. Fuel used in electric generation increased $60 million to $383 million primarily due to $40 million higher deferred fuel expense and the $20 million net impact of higher
fuel costs. The increase in deferred fuel expense was primarily due to the implementation of new fuel rates in North Carolina. The higher fuel costs are primarily due to higher coal prices and a change in generation mix, partially offset by lower system requirements. Purchased power expense decreased $15 million to $57 million compared to the same period in 2008 primarily due to lower purchases resulting from higher relative fuel pricing.
  73
  Operation and Maintenance
  O&M expense was $283 million for the three months ended June 30, 2009, which represents an $8 million increase compared to the same period in 2008. This increase is primarily due to higher net nuclear plant outage and maintenance costs.
  Depreciation, Amortization and Accretion
  Depreciation, amortization and accretion expense was $118 million for the three months ended June 30, 2009, which represents an $11 million decrease compared to the same period in 2008. Depreciation, amortization and accretion expense decreased primarily due to the $15 million depreciation associated with the accelerated cost-recovery program
for nuclear generating assets recognized during 2008, partially offset by the $4 million impact of depreciable asset base increases. The North Carolina jurisdictional aggregate minimum amount of accelerated cost recovery has been met and the South Carolina jurisdictional obligation was terminated by the Public Service Commission of South Carolina (SCPSC). PEC does not anticipate recording additional accelerated depreciation in the North Carolina jurisdiction, but will record depreciation over the remaining useful
life of the assets.
  Other
  Other operating expenses consisted of losses of $2 million and gains of $5 million for the three months ended June 30, 2009 and 2008, respectively, primarily due to land sales in 2008.
  Income Tax Expense
  Income tax expense decreased $13 million for the three months ended June 30, 2009, as compared to the same period in 2008, primarily due to the $9 million impact of lower pre-tax income and the $3 million impact of tax levelization. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with
the estimated annual effective tax rate. PEC’s income tax expense was decreased by $1 million for the three months ended June 30, 2009, compared to an increase of $2 million for the three months ended June 30, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will
vary each quarter, but will have no effect on net income for the year.
  Six Months Ended June 30, 2009, Compared to Six Months Ended June 30, 2008
  REVENUES
  PEC’s electric revenues for the six months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions)

Six Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential

$
879


$
119



15.7


$
760Commercial


578



47



8.9



531Industrial


336



(19
)


(5.4
)


355Governmental


52



6



13.0



46Unbilled


(7
)


(14
)


–



7Total retail revenues


1,838



139



8.2



1,699Wholesale


358



(12
)


(3.2
)


370Miscellaneous


58



12



26.1



46Total electric revenues


2,254



139



6.6



2,115Less: Fuel and other pass-through revenues


(909
)


(137
)


–



(772
)Revenues excluding fuel and other pass-through revenues

$
1,345


$
2



0.1


$
1,343
 
 PEC’s revenues, excluding fuel and other pass-through revenues of $909 million and $772 million for the six months ended June 30, 2009 and 2008, respectively, increased $2 million. The increase in revenues, excluding fuel
 
 74
 
 and other pass-through revenues, was primarily due to the $22 million favorable impact of weather and $12 million higher miscellaneous revenues, partially offset by $19 million unfavorable impact of net retail customer growth and usage, primarily in the industrial customer class, and $12 million lower wholesale revenues. The favorable impact
of weather was driven by higher cooling and heating degree days than 2008. Cooling degree days were 22 percent higher than normal in 2009 compared to 5 percent higher than normal in 2008. Higher miscellaneous revenues were primarily due to higher transmission revenues resulting from the Open Access Transmission Tariff rates that went into effect on July 1, 2008. The unfavorable impact of net retail customer growth and usage was driven by a decrease in the average usage per retail customer, partially offset by
a net 16,000 increase in the average number of customers for the six months ended June 30, 2009, compared to the same period in 2008. Lower wholesale revenues, excluding fuel and other pass-through revenues, were primarily due to lower energy rates with a major customer and lower excess generation sales due to unfavorable market dynamics and higher relative fuel costs.
  PEC’s electric energy sales for the six months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions of kWh)

Six Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential


8,729



465



5.6



8,264Commercial


6,605



(57
)


(0.9
)


6,662Industrial


4,982



(912
)


(15.5
)


5,894Governmental


700



32



4.8



668Unbilled


170



166



–



4Total retail kWh sales


21,186



(306
)


(1.4
)


21,492Wholesale


6,935



(278
)


(3.9
)


7,213Total kWh sales


28,121



(584
)


(2.0
)


28,705
 
 Retail revenues increased for the six months ended June 30, 2009, despite a decrease in retail kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates. PEC’s industrial kWh sales have decreased 15.5 percent from 2008, primarily due to reductions in textile manufacturing
in the Carolinas as a result of global competition and domestic consolidation as well as a downturn in the lumber and building materials segment as a result of declines in construction. However, sales to the chemical segment, now our largest industrial segment, have slightly increased. Many of the manufacturers in PEC’s service territory have been adversely impacted by the recession, and we expect continued industrial sales weakness until the broader economy recovers. While industrial kWh sales have decreased
15.5 percent from 2008, industrial revenues have only decreased 5.4 percent due in part to increased fuel revenues and the demand charges component of industrial revenues.
  Wholesale kWh sales decreased for the six months ended June 30, 2009, primarily due to decreased excess generation sales resulting from unfavorable market dynamics. As previously discussed, PEC executed a contract extension with its largest municipal wholesale customer through 2032.
  As previously discussed, PEC has been, and may continue to be, impacted by the current recession in the United States.
  EXPENSES
  Fuel and Purchased Power
  Fuel and purchased power expenses were $939 million for the six months ended June 30, 2009, which represents a $139 million increase compared to the same period in 2008. Fuel used in electric generation increased $146 million to $825 million primarily due to the $90 million net impact of higher fuel costs and $56 million higher deferred
fuel expense. The higher fuel costs are primarily due to higher coal prices and an unfavorable change in generation mix, partially offset by lower system requirements. The increase in deferred fuel expense was primarily due to the implementation of new fuel rates in North Carolina. Purchased power expense decreased $7 million to $114 million compared to the same period in 2008 primarily due to lower co-generation of $18 million, partially offset by an increase in interchange purchases of $5 million and purchases
from renewable energy sources of $7 million. The
 
 75
  lower co-generation purchases were primarily due to higher relative fuel pricing. The increase in interchange purchases was primarily due to plant outages in 2009.
  Operation and Maintenance
  O&M expense was $542 million for the six months ended June 30, 2009, which represents a $19 million increase compared to the same period in 2008. This increase is primarily due to $22 million higher net nuclear plant outage and maintenance costs, as a result of two nuclear refueling and maintenance outages in the current year compared
to one in the prior year.
 
 Depreciation, Amortization and Accretion
  Depreciation, amortization and accretion expense was $235 million for the six months ended June 30, 2009, which represents a $20 million decrease compared to the same period in 2008. Depreciation, amortization and accretion expense decreased primarily due to the $15 million of Clean Smokestacks Act amortization and the $15 million of depreciation
associated with the accelerated cost-recovery program for nuclear generating assets recognized during 2008, partially offset by the $8 million impact of depreciable asset base increases. In accordance with a regulatory order, PEC ceased to amortize Clean Smokestack Act compliance costs, but will record depreciation over the useful life of the assets. As previously discussed, PEC does not anticipate recording additional accelerated depreciation.
  Taxes Other Than on Income
  Taxes other than on income was $105 million for the six months ended June 30, 2009, which represents a $6 million increase compared to the same period in 2008. This increase is primarily due to an increase in gross receipts taxes due to higher retail revenues. Gross receipts taxes are collected from customers and recorded as revenues and
then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.
 
 Other
  Other operating expenses consisted of losses of $2 million and gains of $6 million for the six months ended June 30, 2009 and 2008, respectively, primarily due to land sales in 2008.
 
 Total Other Income, Net
  Total other income, net was $16 million for the six months ended June 30, 2009, which represents a $6 million decrease compared to the same period in 2008. This decrease is primarily due to losses on a balanced billing program of $6 million and lower interest income of $4 million, partially offset by favorable AFUDC equity of $6 million.
 
 Income Tax Expense
  Income tax expense decreased $12 million for the six months ended June 30, 2009, as compared to the same period in 2008, primarily due to the $7 million impact of lower pre-tax income and $5 million of favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from nonqualified nuclear decommissioning
trust (NDT) funds to qualified NDT funds.
  76
  PROGRESS ENERGY FLORIDA
  PEF contributed segment profits of $119 million and $125 million for the three months ended June 30, 2009 and 2008, respectively. The decrease in profits for the three months ended June 30, 2009, compared to the same period in 2008, was primarily due to higher interest expense, the unfavorable impact of net retail customer growth and usage
and the regulatory disallowance of fuel costs, partially offset by favorable AFUDC equity, favorable returns on nuclear and environmental cost recovery clause (ECRC) assets, higher other income and the favorable impact of interim and limited rate relief (See Note 4B).
  PEF contributed segment profits of $207 million and $191 million for the six months ended June 30, 2009 and 2008, respectively. The increase in profits for the six months ended June 30, 2009, compared to the same period in 2008, was primarily due to favorable AFUDC equity, the favorable impact of weather, lower income tax expense resulting from
the deduction related to NDT funds and higher wholesale revenues, partially offset by higher interest expense and the unfavorable impact of net retail customer growth and usage.
  The revenue tables that follow present the total amount and percentage change of revenues excluding fuel and other pass-through revenues. Revenues excluding fuel and other pass-through revenues is defined as total electric revenues less fuel and other pass-through revenues. We and PEF consider revenues excluding fuel and other pass-through
revenues a useful measure to evaluate PEF’s electric operations because fuel and other pass-through revenues primarily represent the recovery of fuel, purchased power and other pass-through expenses through cost-recovery clauses and, therefore, do not have a material impact on earnings. Pass-through revenues do not include the revenues associated with the return on asset component of nuclear and ECRC revenues as these revenues will have an impact on reported earnings. We and PEF have included the analysis
below as a complement to the financial information we provide in accordance with GAAP. However, revenues excluding fuel and other pass-through revenues is not defined under GAAP, and the presentation may not be comparable to other companies’ presentation or more useful than the GAAP information provided elsewhere in this report.
  Three Months Ended June 30, 2009, Compared to Three Months Ended June 30, 2008
  REVENUES
  PEF’s electric revenues for the three months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions)

Three Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential

$
592


$
39



7.1


$
553Commercial


315



34



12.1



281Industrial


79



(1
)


(1.3
)


80Governmental


83



13



18.6



70Unbilled


31



8



–



23Total retail revenues


1,100



93



9.2



1,007Wholesale


89



(56
)


(38.6
)


145Miscellaneous


45



3



7.1



42Total electric revenues


1,234



40



3.4



1,194Less: Fuel and other pass-through revenues


(768
)


(39
)


–



(729
)Revenues excluding fuel and other pass-through revenues

$
466


$
1



0.2


$
465
 
 PEF’s revenues, excluding fuel and other pass-through revenues of $768 million and $729 million for the three months ended June 30, 2009 and 2008, respectively, increased $1 million. The increase in revenues, excluding fuel and other pass-through revenues, was primarily due to the $7 million favorable impact of interim and limited
rate relief (See Note 4B), and $6 million increased revenues related to returns on nuclear and ECRC assets, offset by the $15 million unfavorable impact of retail customer growth and usage. In addition to lower average usage per customer, PEF's average number of customers for the three months ended June 30, 2009, compared to the same period in 2008, decreased a net 8,000 customers. In comparison, PEF's average number of customers for the three years ended June 30, 2008, compared to the same period in
2007, increased a net 2,000 customers.
  77
  PEF’s electric energy sales for the three months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions of kWh)

Three Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential


4,508



(247
)


(5.2
)


4,755Commercial


2,948



(121
)


(3.9
)


3,069Industrial


832



(177
)


(17.5
)


1,009Governmental


805



5



0.6



800Unbilled


703



76



–



627Total retail kWh sales


9,796



(464
)


(4.5
)


10,260Wholesale


960



(1,058
)


(52.4
)


2,018Total kWh sales


10,756



(1,522
)


(12.4
)


12,278
 
 The current recession and general housing downturn in the United States has continued to contribute to a slowdown in customer growth and usage in PEF’s service territory resulting in a 4.5 percent decrease in retail kWh sales for the three months ended June 30, 2009, compared to the same period in 2008.  The impact of the general
housing downturn was especially severe in several states, including Florida.  Consequently, PEF's residential kWh sales decreased 5.2 percent compared to the same period in 2008.  We cannot predict how long the recession and housing downturn may last or the extent to which revenues may be impacted.  In the future, PEF's customer usage could be impacted by customer response to energy-efficiency programs and to increased rates. Retail revenues increased for the three months ended June 30, 2009, despite a decrease in kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates and the recovery of nuclear costs in accordance with a regulatory order issued in late 2008.
  Wholesale revenues decreased for the three months ended June 30, 2009, primarily due to decreased fuel revenues. Wholesale kWh sales decreased for the three months ended June 30, 2009, primarily due to market conditions in which wholesale customers fulfilled a portion of their system requirements from other sources.
 
 EXPENSES
  Fuel and Purchased Power
  Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost-recovery clauses and, as such, changes in these expenses do not have a material impact on earnings.
The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection from or refund to customers.
  Fuel and purchased power expenses were $643 million for the three months ended June 30, 2009, which represents a $12 million increase compared to the same period in 2008. Fuel used in electric generation increased $70 million to $443 million compared to the same period in 2008. This increase was primarily due to higher deferred fuel expense
of $167 million driven by the implementation of new fuel rates, partially offset by decreased current year fuel costs of $98 million. The decrease in current year fuel costs was primarily due to lower system requirements. Purchased power expense decreased $58 million to $200 million compared to the same period in 2008. This decrease was primarily due to a decrease in interchange purchases of $36 million resulting from lower system requirements and a decrease in the recovery of deferred capacity costs of $17 million.
  78
  Operation and Maintenance
  O&M expense was $204 million for the three months ended June 30, 2009, which represents a $13 million decrease when compared to the same period in 2008. O&M expense decreased $30 million due to the storm damage reserve replenishment surcharge that ended in July 2008, partially offset by $18 million higher ECRC costs due to increased
rates resulting primarily from the recovery of emission allowances. The replenishment of storm damage reserves and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. In aggregate, O&M expenses recoverable through base rates decreased $3 million compared to the same period in 2008.
  Depreciation, Amortization and Accretion
  Depreciation, amortization and accretion expense was $105 million for the three months ended June 30, 2009, which represents a $29 million increase compared to the same period in 2008. Depreciation, amortization and accretion expense increased primarily due to $23 million higher nuclear cost-recovery amortization which began in January
2009 in accordance with a 2008 regulatory order. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and, therefore, has no material impact on earnings. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates increased $4 million compared to the same period in 2008.
  Taxes Other Than on Income
  Taxes other than on income was $80 million for the three months ended June 30, 2009, which represents a $4 million increase compared to the same period in 2008. This increase is primarily due to an unfavorable increase in gross receipts and franchise taxes due to higher retail revenues. Gross receipts and franchise taxes are collected from
customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.
  Other
  Other operating expenses of $7 million for the three months ended June 30, 2009, compared to other operating income of $4 million for the same period in 2008, represents an $11 million change, primarily due to the $8 million regulatory disallowance of fuel costs (See Note 4B) and the $4 million prior year gain on land sales.
  Total Other Income, Net
  Total other income, net was $36 million for the three months ended June 30, 2009, which represents a $13 million increase compared to the same period in 2008. This increase was primarily due to $7 million of favorable AFUDC equity related to eligible construction project costs and $4 million investment gains on certain employee benefit
trusts resulting from improved financial market conditions.
  Total Interest Charges, net
  Total interest charges, net was $55 million for the three months ended June 30, 2009, which represents a $16 million increase compared to the same period in 2008. This increase was primarily due to $13 million higher interest as a result of higher average debt outstanding and the prior year interest benefit of $7 million resulting from
the resolution of tax matters, partially offset by $3 million favorable AFUDC debt related to eligible construction projects.
  79
  Six Months Ended June 30, 2009, Compared to Six Months Ended June 30, 2008
  REVENUES
  PEF’s electric revenues for the six months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions)

Six Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential

$
1,217


$
201



19.8


$
1,016Commercial


619



95



18.1



524Industrial


163



15



10.1



148Governmental


166



29



21.2



137Unbilled


30



4



–



26Total retail revenues


2,195



344



18.6



1,851Wholesale


212



(40
)


(15.9
)


252Miscellaneous


89



2



2.3



87Total electric revenues


2,496



306



14.0



2,190Less: Fuel and other pass-through revenues


(1,609
)


(275
)


–



(1,334
)Revenues excluding fuel and other pass-through revenues

$
887


$
31



3.6


$
856
 
 PEF’s revenues, excluding fuel and other pass-through revenues of $1.609 billion and $1.334 billion for the six months ended June 30, 2009 and 2008, respectively, increased $31 million. The increase in revenues, excluding fuel and other pass-through revenues, was primarily due to the $19 million favorable impact of weather, $15 million
higher wholesale revenues, $15 million increased revenues related to returns on nuclear and ECRC assets, and the $7 million favorable impact of interim and limited rate relief (See Note 4B), partially offset by the $26 million unfavorable impact of retail customer growth and usage. The favorable impact of weather was primarily driven by 37 percent higher heating degree days than 2008. Heating degree days were 2 percent higher
than normal in 2009 and 26 percent lower than normal in 2008. Wholesale revenues, excluding fuel and other pass-through revenues, increased primarily due to increased capacity charges from new and amended contracts.
  As discussed previously, PEF has experienced a slowdown in customer growth and usage in its service territory. In addition to lower average usage per customer, PEF’s average number of customer for the six months ended June 30, 2009, compared to the same period in 2008, decreased a net 8,000 customers. In comparison, PEF’s average
number of customers for the six months ended June 30, 2008, compared to the same period in 2007, increased a net 4,000 customers.
  PEF’s electric energy sales for the six months ended June 30, 2009 and 2008, and the amount and percentage change by customer class were as follows:
  (in millions of kWh)

Six Months Ended June 30,Customer Class

2009


Change


% Change


2008Residential


8,795



35



0.4



8,760Commercial


5,502



(227
)


(4.0
)


5,729Industrial


1,623



(251
)


(13.4
)


1,874Governmental


1,537



(30
)


(1.9
)


1,567Unbilled


688



(8
)


–



696Total retail kWh sales


18,145



(481
)


(2.6
)


18,626Wholesale


2,012



(1,547
)


(43.5
)


3,559Total kWh sales


20,157



(2,028
)


(9.1
)


22,185
 
 Retail revenues increased for the six months ended June 30, 2009, despite a decrease in kWh sales for the same period primarily due to the impact of increased fuel revenues as a result of higher fuel rates and the recovery of nuclear costs in accordance with a regulatory order issued in late 2008.
  80
  Wholesale revenues decreased for the six months ended June 30, 2009, primarily due to decreased fuel revenues. Wholesale kWh sales decreased for the six months ended June 30, 2009, primarily due to market conditions in which wholesale customers fulfilled a portion of their system requirements from other sources.
 
 EXPENSES
  Fuel and Purchased Power
  Fuel and purchased power expenses were $1.315 billion for the six months ended June 30, 2009, which represents a $160 million increase compared to the same period in 2008. Fuel used in electric generation increased $241 million to $955 million compared to the same period in 2008. This increase was primarily due to higher deferred fuel expense
of $260 million driven by the implementation of new fuel rates. Purchased power expense decreased $81 million to $360 million compared to the same period in 2008. This decrease was primarily due to a decrease in interchange purchases of $56 million resulting from lower system requirements and a decrease in the recovery of deferred capacity costs of $25 million.
  Operation and Maintenance
  O&M expense was $406 million for the six months ended June 30, 2009, which represents a $14 million decrease when compared to the same period in 2008. O&M expense decreased $55 million due to the storm damage reserve replenishment surcharge that ended in July 2008, partially offset by $33 million higher ECRC costs due to increased
rates resulting primarily from the recovery of emission allowances and higher pension costs of $11 million. The replenishment of storm damage reserves and ECRC expenses are recovered through cost-recovery clauses and, therefore, have no material impact on earnings. Pension costs are higher due to a $9 million pension credit in the prior year. Substantially all of 2009’s pension expense has been deferred as approved by the Florida Public Service Commission (FPSC) (See Note 4B). In aggregate, O&M expenses
recoverable through base rates increased $3 million compared to the same period in 2008.
  Depreciation, Amortization and Accretion
  Depreciation, amortization and accretion expense was $265 million for the six months ended June 30, 2009, which represents a $113 million increase compared to the same period in 2008. Depreciation, amortization and accretion expense increased primarily due to $104 million higher nuclear cost-recovery amortization which began in January
2009 in accordance with a 2008 regulatory order. The nuclear cost-recovery amortization is recovered through a cost-recovery clause and, therefore, has no material impact on earnings. In aggregate, depreciation, amortization and accretion expenses recoverable through base rates increased $6 million compared to the same period in 2008.
  Taxes Other Than on Income
  Taxes other than on income was $168 million for the six months ended June 30, 2009, which represents a $21 million increase compared to the same period in 2008. This increase is primarily due to a $17 million increase in gross receipts and franchise taxes due to higher retail revenues. Gross receipts and franchise taxes are collected from
customers and recorded as revenues and then remitted to the applicable taxing authority. Therefore, these taxes have no material impact on earnings.
  Other
  Other operating expenses of $7 million for the six months ended June 30, 2009, compared to other operating income of $4 million for the same period in 2008, represents an $11 million change, primarily due to the $8 million regulatory disallowance of fuel costs (See Note 4B) and the $4 million prior year gain on land sales.
  Total Other Income, Net
  Total other income, net was $67 million for the six months ended June 30, 2009, which represents a $26 million increase compared to the same period in 2008. This increase was primarily due to $19 million favorable AFUDC equity related to eligible construction project costs and $6 million investment gains on certain employee benefit trusts
resulting from improved financial market conditions.
  81
  Total Interest Charges, net
  Total interest charges, net was $113 million for the six months ended June 30, 2009, which represents a $30 million increase compared to the same period in 2008. This increase was primarily due to $28 million higher interest as a result of higher average debt outstanding.
  Income Tax Expense
  Income tax expense decreased $5 million for the six months ended June 30, 2009, compared to the same period in 2008, primarily due to the $11 million impact of the favorable tax benefit related to a deduction triggered by the transfer of previously funded amounts from the nonqualified NDT fund to the qualified NDT fund and the $8 million
impact of the increase in AFUDC equity discussed above, partially offset by the $8 million impact of tax levelization and the $4 million impact of higher pre-tax income. AFUDC equity is excluded from the calculation of income tax expense. GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was increased by $5 million for the six months ended June 30, 2009 compared to a decrease of $3
million for the six months ended June 30, 2008, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.
  CORPORATE AND OTHER
  The Corporate and Other segment primarily includes the operations of the Parent, PESC and other miscellaneous nonregulated businesses that do not separately meet the quantitative disclosure requirements as a reportable business segment. Corporate and Other expense is summarized below:
  Three Months Ended June 30,


Six Months Ended June 30,(in millions)

2009


2008


2009


2008Other interest expense

$
(64
)

$
(57
)

$
(119
)

$
(111
)Contingent value obligations


1



(2
)


8



(2
)Tax levelization


(5
)


1



(6
)


–Other income tax benefit


28



24



38



41Continuing income attributable to noncontrolling interests, net of tax


2



–



3



4Other


(1
)


5



5



4Corporate and Other after-tax expense

$
(39
)

$
(29
)

$
(71
)

$
(64
)
 
 Other interest expense increased $7 million for the three months ended June 30, 2009, and increased $8 million for the six months ended June 30, 2009, compared to the same periods in 2008. The increase for the three and six months ended June 30, 2009, was primarily due to higher average debt outstanding at the Parent.
  At June 30, 2009 and 2008, the contingent value obligations (CVOs) had fair values of approximately $26 million and $36 million, respectively, and average unit prices of $0.27 and $0.37 at June 30, 2009 and 2008, respectively. We recorded an unrealized gain of $1 million for the three months ended June 30, 2009, and an unrealized loss of
$2 million for the three months ended June 30, 2008, to record the changes in fair value of the CVOs. We recorded an unrealized gain of $8 million for the six months ended June 30, 2009, and an unrealized loss of $2 million for the six months ended June 30, 2008, to record the changes in fair value of the CVOs. See Note 15 in the 2008 Form 10-K for further information.
  GAAP requires companies to apply a levelized effective income tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was increased by $5 million and decreased by $1 million for the three months ended June 30, 2009 and 2008, respectively, and increased by $6 million for the six months
ended June 30, 2009, in order to maintain an effective rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent items of income or deduction can cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.
  82
  Other income tax benefit decreased $3 million for the six months ended June 30, 2009, compared to the same period in 2008, primarily due to the unfavorable impact at the Corporate level resulting from the deductions taken by the Utilities related to NDT funds (See “Income Tax Expense” under “Six Months Ended June 30, 2009,
Compared to Six Months Ended June 30, 2008” in “Progress Energy Carolinas” and “Progress Energy Florida”.)
  Other decreased $6 million for the three months ended June 30, 2009, compared to the same period in 2008, primarily due to a $3 million impairment of investments in limited partnerships that qualify for federal affordable housing credits.
  DISCONTINUED OPERATIONS
  In 2008, we completed our business strategy of divesting of nonregulated businesses to reduce our business risk and focus on the core operations of the Utilities. During the six months ended June 30, 2008, we recognized $66 million of income from discontinued operations, net of tax, which was comprised primarily of $48 million after-tax
of gains on sales of our coal terminals and docks in West Virginia and Kentucky (Terminals) and our remaining coal mining businesses (See Note 3).
   LIQUIDITY AND CAPITAL RESOURCES
  OVERVIEW
  Our significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations, including expenditures for environmental compliance. We rely upon our operating cash flow, substantially all of which is generated by the Utilities, commercial paper and bank facilities, and our ability to access the long-term
debt and equity capital markets for sources of liquidity. As discussed in “Future Liquidity and Capital Resources” below, synthetic fuels tax credits provide an additional source of liquidity as those credits are realized.
  The majority of our operating costs are related to the Utilities. Most of these costs are recovered from ratepayers in accordance with various rate plans. We are allowed to recover certain fuel, purchased power and other costs incurred by PEC and PEF through their respective recovery clauses. The types of costs recovered through clauses
vary by jurisdiction. Fuel price volatility can lead to over- or under-recovery of fuel costs, as changes in fuel prices are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility can be both a source of and a use of liquidity resources, depending on what phase of the cycle of price volatility we are experiencing. Changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows, but not materially affect
net income.
  As a registered holding company, we are subject to regulation by the Federal Energy Regulatory Commission (FERC) for, among other things, the establishment of intercompany extensions of credit. Our subsidiaries participate in internal money pools, administered by PESC, to more effectively utilize cash resources and reduce outside short-term
borrowings. The utility money pool allows the Utilities to lend to and borrow from each other. The non-utility money pool allows our nonregulated subsidiaries to lend to and borrow from each other. The Parent can lend money to the utility and non-utility money pools, but cannot borrow funds.
  The Parent is a holding company and, as such, has no revenue-generating operations of its own. The primary cash needs at the Parent level are our common stock dividend, interest and principal payments on the Parent’s $3.35 billion of senior unsecured debt and potentially funding the Utilities’ capital expenditures through equity
contributions. The Parent’s ability to meet these needs is typically funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; repayment of funds due to the Parent by its subsidiaries; the Parent’s bank facility; and/or the Parent’s ability to access the short- and long-term debt and equity capital markets. In recent years, rather than paying dividends to the Parent, the Utilities, to a large extent, have
retained their free cash flow to fund their capital expenditures. The Utilities did not pay dividends to the Parent in 2008. During the six months ended June 30, 2009, PEC paid dividends of $200 million to the Parent. During the six months ended June 30, 2009, PEF received equity contributions of $310 million from the Parent. There are a number of factors that impact the Utilities’ decision or ability to pay dividends to the Parent or to seek equity contributions from the Parent, including capital expenditure
decisions and the timing of recovery of fuel and other pass-through costs. Therefore, we cannot predict the level of dividends or equity contributions between the Utilities and the Parent from year-to-year.
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  Cash from operations, commercial paper issuance, borrowings under our credit facilities, long-term debt financings, equity offerings, and limited ongoing sales of common stock from our Investor Plus Stock Purchase Plan, employee benefit and stock option plans are expected to fund capital expenditures, long-term debt maturities and common
stock dividends for 2009. During the six months ended June 30, 2009, net proceeds from our long-term debt issuances were $1.337 billion. For the fiscal year 2009, we expect to realize approximately $575 million in the aggregate from the sale of stock through marketed and ongoing equity sales of which $545 million was realized through June 30, 2009. These long-term debt and equity issuances helped provide additional liquidity support during the first half of 2009. (See discussion that follows under “Financing
Activities”.)
  We have 16 financial institutions that support our combined $2.030 billion revolving credit facilities for the Parent, PEC and PEF, thereby limiting our dependence on any one institution. The credit facilities serve as back-ups to our commercial paper programs. To the extent amounts are reserved for commercial paper or letters of credit
outstanding, they are not available for additional borrowings. Due to conditions in the financial markets in 2008, the short-term credit markets tightened, resulting in volatility in commercial paper durations and interest rates. In November 2008, the Parent borrowed $600 million under its RCA to reduce rollover risk in the commercial paper markets. We subsequently repaid $100 million of the borrowings, and at June 30, 2009, the Parent had $500 million of outstanding borrowings under its credit facility. In addition,
at June 30, 2009, the Parent had issued $37 million of letters of credit, which were supported by the revolving credit agreement (RCA). Based on these amounts outstanding at June 30, 2009, $1.493 billion was available for additional borrowings under our combined revolving credit facilities. Subsequent to June 30, 2009, the Parent repaid an additional $200 million of the outstanding balance under its revolving credit facility with
cash on hand. At August 7, 2009, the outstanding balance was $300 million.
  Borrowings under our RCA during 2008, coupled with long-term debt and equity issuances in 2009, provided liquidity during a period of uncertain financial market conditions. We will continue to monitor the credit markets to maintain an appropriate level of liquidity.
  At June 30, 2009, PEC and PEF had limited counterparty mark-to-market exposure for financial commodity hedges (primarily gas and oil hedges) due to spreading our concentration risk over a number of counterparties. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current
market rates. At June 30, 2009, the majority of the Utilities’ open financial commodity hedges were in net mark-to-market liability positions. See Note 11A for additional information with regard to our commodity derivatives.
 
 At June 30, 2009, we had limited mark-to-market exposure to certain financial institutions under pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions for each of the Parent, PEC and PEF. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the
agreements at current market rates. At June 30, 2009, all of the Parent’s, PEC’s and PEF’s open pay-fixed forward starting swaps were in a net mark-to-market asset position. See Note 11B for additional information with regard to our interest rate derivatives.
  Our pension trust funds and NDT funds are managed by a number of financial institutions, and the assets being managed are diversified in order to limit concentration risk in any one institution or business sector.
  We believe our internal and external liquidity resources will be sufficient to fund our current business plans. Risk factors associated with credit facilities and credit ratings are discussed below and in Item 1A, “Risk Factors” in the 2008 Form 10-K.
  The following discussion of our liquidity and capital resources is on a consolidated basis.
  HISTORICAL FOR 2009 AS COMPARED TO 2008
  CASH FLOWS FROM OPERATIONS
  Net cash provided by operating activities decreased $262 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to a $323 million decrease from accounts payable, largely driven by changes in fuel purchase costs and the timing of purchases and payments to
vendors at the Utilities; a $312 million impact from derivative collateral held in 2008; a $260 million decrease from receivables; and $55 million in storm recovery surcharge collections at PEF during 2008. The storm surcharge
 
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 expired in the third quarter of 2008. In 2008, $420 million of cash collateral was posted by counterparties on derivative contracts at the Utilities, which was partially offset by a $108 million decrease in collateral held associated with derivative contracts at our former synthetic fuels businesses. The change in receivables was primarily
driven by the 2008 settlement of $247 million of derivative receivables largely related to derivative contracts for our former synthetic fuels businesses. These impacts were partially offset by a $295 million increase in the recovery of deferred fuel costs due to higher fuel rates, primarily at PEF; a $170 million increase from income taxes, net, that was largely driven by lower net federal income tax payments; a $104 million increase in the recovery of nuclear construction costs under Florida’s nuclear
cost-recovery rule; an $84 million increase due to derivative collateral included in prepayments and other current assets; and a $66 million decrease in emission allowance purchases.
  INVESTING ACTIVITIES
  Net cash used by investing activities decreased by $17 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. This decrease was primarily due to a $151 million decrease in gross property additions at PEF, partially offset by a $71 million increase in gross property additions at PEC.
The net decrease in gross property additions was partially offset by $64 million in proceeds received in 2008 from sales of discontinued operations and other assets, net of cash divested, which primarily included proceeds from the sale of Terminals and Coal Mining (See Notes 3A and 3B).
  FINANCING ACTIVITIES
  Net cash provided by financing activities decreased by $651 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to a $939 million decrease in short-term indebtedness, primarily driven by commercial paper repayments and the Parent’s repayment of
borrowings outstanding under its RCA, a $461 million decrease in proceeds from long-term debt issuances, net, due to PEC’s $600 million issuance and the Parent’s $750 million issuance in 2009 compared to PEC’s $325 million issuance and PEF’s $1.500 billion issuance in 2008. These impacts were partially offset by a $503 million increase from the issuance of common stock, primarily related to the Parent’s January 2009 common stock offering; and a $147 million decrease in payments of
short-term debt with original maturities greater than 90 days compared to 2008. A discussion of our 2009 financing activities follows.
  On January 12, 2009, the Parent issued 14.4 million shares of common stock at a public offering price of $37.50 per share. Net proceeds from this offering were approximately $523 million. On February 3, 2009, we used $100 million of the proceeds to reduce the Parent’s $600 million RCA balance outstanding at December 31, 2008, and
the remainder was used for general corporate purposes. Subsequent to June 30, 2009, the Parent repaid an additional $200 million of the outstanding balance with cash on hand. At August 7, 2009, the outstanding balance of the RCA loan was $300 million. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining outstanding balance of the RCA loan, while maintaining an appropriate level of liquidity.
  On January 15, 2009, PEC issued $600 million of First Mortgage Bonds, 5.30% Series due 2019. A portion of the proceeds was used to repay the maturity of PEC’s $400 million 5.95% Senior Notes, due March 1, 2009. The remaining proceeds were used to repay PEC’s outstanding short-term debt and for general corporate purposes.
  On March 19, 2009, the Parent issued an aggregate $750 million of Senior Notes consisting of $300 million of 6.05% Senior Notes due 2014 and $450 million of 7.05% Senior Notes due 2019. A portion of the proceeds was used to fund PEF’s capital expenditures through an equity contribution with the remaining proceeds used for general
corporate purposes.
  On June 18, 2009, PEC entered into a Seventy-seventh Supplemental Indenture to its Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, in connection with certain amendments to the mortgage. The amendments are set forth in the Seventy-seventh Supplemental Indenture and include an amendment to extend the maturity date of the mortgage
by 100 years. The maturity date of the mortgage is now May 1, 2140.
  At December 31, 2008, we had 500 million shares of common stock authorized under our charter, of which approximately 264 million were outstanding. For the three months ended June 30, 2009, we issued an immaterial number of shares of common stock. For the six months ended June 30, 2009, we issued approximately 15.5 million
 
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 shares of common stock resulting in approximately $545 million in net proceeds. Included in these amounts were the previously discussed 14.4 million shares issued in a public offering for net proceeds of approximately $523 million and approximately 0.6 million shares for net proceeds of approximately $22 million to meet the requirements
of the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)) and the Investor Plus Stock Purchase Plan. For the three and six months ended June 30, 2008, respectively, we issued approximately 0.5 million shares and 1.5 million shares of common stock resulting in approximately $22 million and $42 million in proceeds. Included in these amounts were approximately 0.5 million shares and 0.9 million shares for proceeds of approximately $22 million and $41 million, respectively, to meet the requirements
of the 401(k) Plan and the Investor Plus Stock Purchase Plan.
  FUTURE LIQUIDITY AND CAPITAL RESOURCES
  At June 30, 2009, there were no material changes in our “Capital Expenditures,” “Other Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 to the 2008 Form 10-K, other than as described below and under
“Regulatory Matters and Recovery of Costs” and “Financing Activities.”
  The Utilities produce substantially all of our consolidated cash from operations. We anticipate that the Utilities will continue to produce substantially all of the consolidated cash flows from operations over the next several years. Our discontinued synthetic fuels operations historically produced significant net earnings from the generation
of tax credits (See “Other Matters – Synthetic Fuels Tax Credits”). A portion of these tax credits has yet to be realized in cash due to the difference in timing of when tax credits are recognized for financial reporting purposes and realized for tax purposes. At June 30, 2009, we have carried forward $761 million of deferred tax credits. Realization of these tax credits is dependent upon our future taxable income,
which is expected to be generated primarily by the Utilities.
  We expect to be able to meet our future liquidity needs through cash from operations, commercial paper issuance, availability under our credit facilities, long-term debt financings and equity offerings. We may also use periodic ongoing sales of common stock from our Investor Plus Stock Purchase Plan and employee benefit and stock option
plans to meet our liquidity requirements.
  We issue commercial paper to meet short-term liquidity needs. As discussed above under “Overview,” the Parent borrowed $600 million under its RCA and repaid $100 million of the outstanding balance with proceeds from the January 2009 equity issuance. Subsequent to June 30, 2009, the Parent repaid an additional $200 million of
the outstanding balance with cash on hand. We will continue to monitor the commercial paper and short-term credit markets to determine when to repay the remaining $300 million balance of the RCA loan, while maintaining an appropriate level of liquidity. If liquidity conditions deteriorate further and negatively impact the commercial paper market, we will need to evaluate other, potentially more expensive, options for meeting our short-term liquidity needs, which may include extending the term and amount of our
borrowings under the Parent’s RCA, issuing short-term notes, and/or issuing long-term debt.
  Progress Energy and its subsidiaries have approximately $11.506 billion in outstanding long-term debt. Currently, approximately $860 million of the Utilities’ debt obligations, consisting of approximately $620 million at PEC and approximately $240 million at PEF, are tax-exempt auction rate securities insured by bond insurance. Bond
insurance generally allows companies to issue tax-exempt bonds with the insurance company’s higher credit rating. Ambac Assurance Corporation insures PEC’s bonds and Syncora Guarantee Inc., formerly XL Capital Assurance, Inc., insures PEF’s bonds.
  The tax-exempt bonds continue to experience failed auctions. In the event of a failed auction, the bond holders cannot sell their bonds and the interest rate is calculated based on a multiple of a market index such as the Securities Industry and Financial Markets Association’s Municipal Swap Index or the London Interbank Offered Rate
(LIBOR). The interest rates for most of PEC’s portfolio of tax-exempt securities reset based on the Securities Industry and Financial Markets Association’s Municipal Swap Index. The interest rates for PEF’s portfolio of tax-exempt securities reset based on one-month LIBOR. The multiple on our auction rate bonds is stable as long as the bonds are rated A3 or higher by Moody’s Investors Service, Inc. (Moody’s) or A- or higher by Standard & Poor’s Rating Services (S&P).
If the insurance companies’ ratings fall below the Utilities’ ratings, then the bonds will be rated at the Utilities’ senior secured debt ratings, which are currently A2 by Moody’s and A- by S&P for both
 
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 Utilities. We do not expect any future rating actions on Syncora Guarantee Inc. and Ambac Assurance Corporation to materially impact the reset rates of the tax-exempt securities.
  Assuming the failed auctions persist, future interest rate resets on our tax-exempt auction rate bond portfolio will be dependent on the volatility experienced in the indices that dictate our interest rate resets and/or rating agency actions that may move our tax-exempt bonds below A3/A-. We will continue to monitor this market and evaluate
options to mitigate our exposure to future volatility.
  The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations under our defined benefit pension plans. Although a number of factors impact our pension funding requirements, a decline in the market value of these assets may significantly increase the future funding requirements of the
obligations under our defined benefit pension plans. In 2009, contributions directly to pension plan assets are expected to approximate $220 million for us, $170 million for PEC and $50 million for PEF. An immaterial amount was contributed during the three and six months ended June 30, 2009 (See Note 10).
  As discussed in “Other Matters – Environmental Matters,” over the long term, compliance with environmental regulations and meeting the anticipated load growth at the Utilities as described under “Other Matters – Increasing Energy Demand” will require the Utilities to make significant capital investments.
These anticipated capital investments are expected to be funded through a combination of cash from operations and issuance of long-term debt, preferred stock and/or common equity, which are dependent on our ability to successfully access capital markets. We may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks associated with new baseload generation.
As discussed under “Other Matters – Nuclear,” PEF expects the schedule for the commercial operation of its proposed nuclear plant in Levy County, Florida (Levy) to shift later than the 2016 to 2018 timeframe by a minimum of 20 months, which will reduce the near-term capital expenditures for the project.
  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. Substantially
all derivative commodity instrument positions are subject to retail regulatory treatment. After settlement of the derivatives and consumption of the fuel, any realized gains or losses are passed through the fuel cost-recovery clause. Due to changes in natural gas prices and settlements of financial hedge agreements since December 31, 2008, the amount of collateral posted with counterparties has changed. At June 30, 2009, we had posted approximately $290 million of cash collateral compared to $340 million of cash
collateral posted at December 31, 2008. The majority of our financial hedge agreements will settle in 2009 and 2010. Additional commodity market price decreases could result in significant increases in the derivative collateral that we are required to post with counterparties. We continually monitor our derivative positions in relation to market price activity.
  The amount and timing of future sales of securities will depend on market conditions, operating cash flow and our specific needs. We may from time to time sell securities beyond the amount immediately needed to meet capital requirements in order to allow for the early redemption of long-term debt, the redemption of preferred stock, the
reduction of short-term debt or for other corporate purposes.
    REGULATORY MATTERS AND RECOVERY OF COSTS
  Regulatory matters, including nuclear cost recovery, as discussed in Note 4 and “Other Matters – Regulatory Environment,” and filings for recovery of environmental costs, as discussed in Note 14 and in “Other Matters – Environmental Matters,” may impact our future liquidity and financing activities. The
impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Regulatory developments expected to have a material impact on our liquidity are discussed below.
  As discussed further in Note 4 and in “Other Matters – Regulatory Environment,” the North Carolina, South Carolina and Florida legislatures passed energy legislation that became law in recent years. These laws may impact
 
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 our liquidity over the long term, including among others, provisions regarding cost recovery, mandated renewable portfolio standards, DSM and energy efficiency.
  PEC Cost-Recovery Clause
  On May 7, 2009, PEC filed with the SCPSC for a decrease in the fuel rate charged to its South Carolina ratepayers. On June 19, 2009, the SCPSC approved a settlement agreement filed jointly by PEC and the South Carolina Office of Regulatory Staff (ORS) and Nucor Steel. Under the terms of the settlement agreement, the parties agreed to PEC’s
proposed rate reduction of approximately $13 million. The decrease is effective July 1, 2009, and decreases residential electric bills by $2.08 per 1,000 kWh, or 2.0 percent, for fuel cost recovery.
  On June 4, 2009, PEC filed with the North Carolina Utilities Commission (NCUC) for a decrease in the fuel rate charged to its North Carolina ratepayers. PEC is asking the NCUC to approve a $5 million decrease in the fuel rates driven by declining fuel prices. If approved, the decrease would take effect December 1, 2009, and would decrease
residential electric bills by $0.17 per 1,000 kWh, or 0.2 percent, for fuel cost recovery. A hearing on the matter has been scheduled by the NCUC for September 15, 2009. We cannot predict the outcome of this matter.
  PEF Base Rates
  As a result of a base rate proceeding in 2005, PEF is party to a base rate settlement agreement that was effective with the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009.
  On March 20, 2009, in anticipation of the expiration of its current base rate settlement agreement, PEF filed with the FPSC a proposal for an increase in base rates effective January 1, 2010. In its filing, PEF requested the FPSC to approve calendar year 2010 as the projected test period for setting new base rates and approve annual rate
relief for PEF of $499 million, which includes PEF’s petition for a combined $76 million of new base rates in 2009 as discussed below. The request for increased base rates is based, in part, on investments PEF is making in its generating fleet and in its transmission and distribution systems.
  Included within the base rate proposal is a request for an interim base rate increase of $13 million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a limited proceeding to include in base rates revenue requirements of $63 million for the repowered Bartow power plant, which began commercial operations in June 2009. On May
19, 2009, the FPSC approved both the annualized interim base rate and the cost recovery for the repowered Bartow power plant subject to refund with interest effective July 1, 2009. These increases are expected to result in additional revenues of approximately $70 million in 2009. The changes increased residential bills by approximately $4.52 per 1,000 kWh, or 3.7 percent. On July 2, 2009, Florida’s Office of Public Counsel (OPC), the Florida Industrial Power Users Group, the Attorney General, the Florida
Retail Federation and PCS Phosphate filed a petition protesting portions of the FPSC approval. A hearing on the matter will not be held until after the annual rate relief hearings are concluded. We cannot predict the outcome of this matter.
  If PEF’s remaining rate request is approved by the FPSC as filed by PEF, the new base rates would increase residential bills by approximately $9.66 per 1,000 kWh, or 7.6 percent, effective January 1, 2010. The FPSC has scheduled hearings on the remaining annual rate relief filing beginning September 21, 2009. A ruling by the FPSC
is expected in November 2009. We cannot predict the outcome of this matter.
  PEF Cost-Recovery Clause
  On March 17, 2009, PEF received approval from the FPSC to reduce its 2009 fuel cost-recovery factors by an amount sufficient to achieve a $206 million reduction in fuel charges to retail customers as a result of effective fuel purchasing strategies and lower fuel prices. The approval reduces residential customers’ fuel charges by
$6.90 per 1,000 kWh, or 5.0 percent, starting with the first billing cycle of April 2009. Commercial and industrial customers will see similar reductions.
  In 2007, the FPSC ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for Crystal River Units No. 4 and 5 (CR4 and CR5). On February 2, 2009, Florida’s Office of Public Counsel (OPC) filed direct testimony alleging that during 2006 and 2007, PEF collected excessive fuel costs and sulfur dioxide (SO2)
allowance costs of $61 million before interest. The OPC claimed that these excessive costs were attributed to PEF’s ongoing practice of not blending the most economical sources of coal at its CR4 and CR5 plants. A hearing on PEF’s 2006 and 2007 coal purchases was held April 13-15, 2009. During the hearing, the OPC reduced the alleged excessive
 
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 fuel costs to $33 million before interest. On June 30, 2009, the FPSC approved a refund of $8 million to PEF’s ratepayers to be paid over a 12-month period beginning January 1, 2010, and ordered PEF to file a report by September 2009 regarding the prospective application of PEF’s coal procurement plan and the prudence of PEF’s
coal procurement actions. For the three months ended June 30, 2009, PEF recorded a pre-tax other operating expense of $8 million plus an immaterial amount of interest and an associated regulatory liability for the disallowed fuel costs and interest. PEF is evaluating its options, including a request for reconsideration and an appeal of the FPSC’s order to the Florida Supreme Court. 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, which were estimated to be $17 million at June 30, 2009. The FPSC has approved cost recovery of PEF’s prudently incurred costs necessary to achieve its integrated
strategy to address compliance with the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule (CAMR) and the Clean Air Visibility Rule (CAVR) through the ECRC (See “Other Matters – Environmental Matters” for discussion regarding the CAIR, CAMR and CAVR).
  Nuclear Cost Recovery
  PEF is allowed to recover prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balances on an annual basis through the capacity cost-recovery clause. Such amounts will not be included in PEF’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery
rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except
upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility. On March 17, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear preconstruction costs for PEF’s proposed nuclear plant in Levy, which the FPSC had authorized to be collected in 2009. The approval reduced residential customers’ nuclear cost-recovery
charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first billing cycle of April 2009. Commercial and industrial customers experienced similar reductions.
  On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million, which consists of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and Crystal River Unit No. 3 (CR3) uprate projects. In an effort to
help mitigate the initial price impact on its customers, as part of its filing, PEF has proposed collecting certain costs over a five-year period, with associated carrying costs. The deferral would result in a nuclear cost-recovery charge of $6.69 per 1,000 kWh for residential customers, which is approximately half of the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery rule. If approved, the charges would begin with the first billing cycle of January 2010. The FPSC has scheduled hearings
in this matter beginning September 8, 2009, with a decision expected in October 2009. We cannot predict the outcome of this matter.
  OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
  Our off-balance sheet arrangements and contractual obligations are described below.
  GUARANTEES
  At June 30, 2009, our guarantees have not changed materially from what was reported in the 2008 Form 10-K.
  MARKET RISK AND DERIVATIVES
  Under our risk management policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” for a discussion of market risk and derivatives.
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  CONTRACTUAL 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 2008 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. Contingencies and significant changes, if any, to our and the Utilities contractual cash obligations and other commercial commitments from what was reported
in Note 22 in the 2008 Form 10-K are described below.
  PEF
 
 On May 1, 2009, PEF announced that it expects the construction schedule for Levy to shift. Although the overall schedule impact is not certain at this time, PEF expects the schedule for the commercial operation of Levy to shift later than the 2016 to 2018 timeframe by a minimum of 20 months. We anticipate amending the Levy Engineering,
Procurement, and Construction (EPC) agreement due to the schedule shift but cannot predict the impact, if any, such amendment might have on the project’s total cost. However, consistent with nuclear cost-recovery filings with the FPSC (See Note 4B), PEF anticipates that approximately $1 billion of the contractual cash obligations for the three-year period following December 31, 2008, disclosed in the 2008 Form 10-K could be deferred to later periods as a result of the schedule shift. Refer to “Other
Matters - Nuclear” below for further discussion of the Levy nuclear project.
  During the second quarter of 2009, PEF entered into conditional agreements for firm pipeline transportation capacity to support PEF’s gas supply needs for the period from April 2011 through March 2036. The total cost to PEF associated with these agreements is estimated to be approximately $281 million. These agreements are subject
to several conditions precedent, including various federal regulatory approvals, the completion and commencement of operation of necessary related interstate natural pipeline system expansions, and other contractual provisions. Due to the conditions of these agreements, the estimated costs associated with these agreements are not currently included in PEF’s fuel and purchased power commitments.
   OTHER MATTERS
  GOODWILL
  Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility segments and our goodwill impairment tests are performed at the utility segment level. The carrying amounts of goodwill at June 30, 2009 and December 31, 2008, for reportable
segments PEC and PEF, were $1.922 billion and $1.733 billion, respectively. We perform our annual impairment tests as of April 1 each year. During the second quarter of 2009, we completed the 2009 annual tests, which indicated the goodwill was not impaired. If the fair value of PEC had been lower by 10 percent and the fair value of PEF had been lower by 7.5 percent, there still would be no impact on the reported value of their goodwill.
 
 We calculate the fair value of our utility segments by considering various factors, including valuation studies based primarily on income and market approaches. More emphasis is applied to the income approach as substantially all of the utility segments’ cash flows are from rate-regulated operations. In such environments, revenue
requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, the utility segments operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions.
 
 The income approach uses discounted cash flow analyses to determine the fair value of the utility segments. The estimated future cash flows from operations are based on the utility segments’ business plans, which reflect management’s assumptions related to customer usage based on internal data and economic data obtained from
third party sources. The business plans assume the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, the timing of anticipated significant future capital investments, the anticipated earnings and returns related to such capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also determines the appropriate discount rate for the utility
 
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 segments based on the weighted average cost of capital for each utility, which takes into account both the cost of equity and pre-tax cost of debt. As each utility segment has a different risk profile based on the nature of its operations, the discount rate for each reporting unit may differ.
 
 The market approach uses implied market multiples derived from comparable peer utilities and market transactions to estimate the fair value of the utility segments. Peer utilities are evaluated based on percentage of revenues generated by regulated utility operations, percentage of revenues generated by electric operations, generation mix,
including coal, gas, nuclear and other resources, market capitalization as of the valuation date, and geographic location. Comparable market transactions are evaluated based on the availability of financial transaction data and the nature and geographic location of the businesses or assets acquired, including whether the target company had a significant electric component. The selection of comparable peer utilities and market transactions, as well as the appropriate multiples from within a reasonable range, is
a matter of professional judgment.
 
 The calculations in both the income and market approaches are highly dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates from a marketplace participant’s perspective, and the selection of peer utilities and marketplace transactions for comparative
valuation purposes. These underlying assumptions and estimates are made as of a point in time. If these assumptions change or should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, the fair value of the utility segments could be significantly different in future periods, which could result in a future impairment charge to goodwill.
 
 As an overall test of the reasonableness of the estimated fair values of the utility segments, we compared their combined fair value estimate to Progress Energy’s market capitalization as of April 1, 2009. The analysis confirmed that the fair values were reasonably representative of market views when applying a reasonable control
premium to the market capitalization.
 
 We monitor for events or circumstances, including financial market conditions and economic factors, that may indicate an interim goodwill impairment test is necessary. We would perform an interim impairment test should any events occur or circumstances change
that would more likely than not reduce the fair value of a utility segment below its carrying value.
 
 SYNTHETIC FUELS TAX CREDITS
  Historically, we had substantial operations associated with the production of coal-based solid synthetic fuels as defined under Section 29 of the Internal Revenue Code (the Code) (Section 29) and as redesignated effective 2006 as Section 45K of the Code as discussed below. The production and sale of these products qualified for federal
income tax credits so long as certain requirements were satisfied. Qualifying synthetic fuels facilities entitled their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuels produced and sold by these plants. The synthetic fuels tax credit program expired at the end of 2007 and the synthetic fuels businesses were abandoned and reclassified to discontinued operations.
  Legislation enacted in 2005 redesignated the Section 29 tax credit as a general business credit under Section 45K of the Code effective January 1, 2006. The previous amount of Section 29 tax credits that we were allowed to claim in any calendar year through December 31, 2005, was limited by the amount of our regular federal income tax liability.
Section 29 tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. The redesignation of Section 29 tax credits as a Section 45K general business credit removed the regular federal income tax liability limit on synthetic fuels production and subjects the credits to a one-year carry back period and a 20-year carry forward period.
  Total Section 29/45K credits generated under the synthetic fuels tax credit program (including those generated by Florida Progress Corporation (Florida Progress) prior to our acquisition), were $1.891 billion, of which $1.130 billion has been used through June 30, 2009, to offset regular federal income tax liability and $761 million is
being carried forward as deferred tax credits.
  See Note 15C for additional discussion related to our previous synthetic fuels operations.
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  REGULATORY ENVIRONMENT
  The Utilities’ operations in North Carolina, South Carolina and Florida are regulated by the NCUC, the SCPSC and the FPSC, respectively. The Utilities are also subject to regulation by the FERC, the Nuclear Regulatory Commission (NRC) and other federal and state agencies common to the utility business. As a result of regulation, many
of the fundamental business decisions, as well as the rate of return the Utilities are permitted to earn, are subject to the approval of one or more of these governmental agencies.
  To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give retail ratepayers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. We cannot anticipate when, or if, any of these states will move to increase retail
competition in the electric industry.
  The American Recovery and Reinvestment Act signed into law in February 2009 contains provisions promoting energy efficiency and renewable energy, including $11 billion for Smart Grid-related technologies, $6.3 billion for energy-efficiency and conservation grants and $2 billion in tax credits for the purchase of plug-in electric vehicles.
We are currently evaluating the provisions of the law and assessing the conditions imposed by participation in the incentive programs. Also, the Obama administration has announced a goal of encouraging investment in transmission and promoting renewable resources while also pricing greenhouse gas (GHG) emissions and setting a federal requirement for renewable energy.
  On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009. This bill would establish a national cap-and-trade program to reduce GHG emissions as well as a national renewable energy portfolio standard (REPS). The bill also calls for investment in the electric grid, more production
and utilization of electric vehicles and improvements in energy efficiency in buildings and appliances. The full impact of the legislation if enacted into law cannot be determined at this time and will depend upon changes made to its provisions during the legislative process and the manner in which key provisions are implemented, including the regulation of carbon. We are currently assessing the impact of the current provisions of the legislation on our customer rates and, while we have not completed our assessment,
we anticipate that it could result in significant rate increases over time. The U.S. Senate is considering similar proposals. The full impact of final legislation, if enacted, and additional regulation resulting from other federal GHG initiatives cannot be determined at this time.
  Current retail rate matters affected by state regulatory authorities are discussed in Notes 4A and 4B. This discussion identifies specific retail rate matters, the status of the issues and the associated effects on our consolidated financial statements.
  On July 31, 2009, the governor of North Carolina signed into law a bill that includes three key provisions that may impact PEC. First, the legislation abbreviates the certification process for PEC to construct a new natural gas plant as long as PEC permanently retires the existing coal unit at that specific site (see further discussion
in “Other Matters – Environmental Matters.”) Second, a recovery mechanism is provided for utilities if they invest in zero emissions renewable energy facilities within the next five years. Finally, the legislation changes the state’s Dam Safety Act such that dams at utility coal-fired power plants, including dams on ash ponds, will now be subject to the Act’s applicable provisions, including state inspection.
  Florida energy law enacted in 2008 includes provisions that would, among other things, (1) help enhance the ability to cost-effectively site transmission lines; (2) require the FPSC to develop a renewable portfolio standard that the FPSC would present to the legislature for ratification in 2009; (3) direct the Florida Department of Environmental
Protection (FDEP) to develop rules establishing a cap-and-trade program to regulate GHG emissions that the FDEP would present to the legislature no earlier than January 2010 for ratification by the legislature; and (4) establish a new Florida Energy and Climate Commission as the principal governmental body to develop energy and climate policy for the state and to make recommendations to the governor and legislature on energy and climate issues. In complying with the provisions of the law, PEF would be able to
recover its reasonable prudent compliance costs. However, until these agency actions are finalized, we cannot predict the costs of complying with the law.
  On July 13, 2007, the governor of Florida issued executive orders to address reduction of GHG emissions. The executive orders call for the first southeastern state cap-and-trade program and include adoption of a maximum allowable emissions level of GHGs for Florida utilities. The standard will require, at a minimum, the following three
reduction milestones: by 2017, emissions not greater than Year 2000 utility sector emissions; by 2025, emissions not
 
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 greater than Year 1990 utility sector emissions; and by 2050, emissions not greater than 20 percent of Year 1990 utility sector emissions. To date, the FDEP has held three rulemaking workshops on the GHG cap-and-trade rulemaking. The rulemaking is expected
to continue through 2009, and the rule requires legislative ratification before implementation.
  The executive orders also requested that the FPSC initiate a rulemaking by September 1, 2007, that would (1) require Florida utilities to produce at least 20 percent of their electricity from renewable sources; (2) reduce the cost of connecting solar and other renewable energy technologies to Florida’s power grid by adopting uniform
statewide interconnection standards for all utilities; and (3) authorize a uniform, statewide method to enable residential and commercial customers, who generate electricity from on-site renewable technologies of up to 1 MW in capacity, to offset their consumption over a billing period by allowing their electric meters to turn backward when they generate electricity (net metering). On January 12, 2009, the FPSC approved a draft Florida renewable portfolio standard (Florida RPS) rule with a goal of 20 percent
renewable energy production by 2020. The FPSC provided the draft Florida RPS rule to the Florida legislature in February 2009, but the legislature did not take action in the 2009 session. We cannot predict the outcome of this matter.
  We cannot predict the costs of complying with the laws and regulations that may ultimately result from these executive orders. Our balanced solution, as described in “Increasing Energy Demand,” includes greater investment in energy efficiency, renewable energy and state-of-the-art generation and demonstrates our commitment to
environmental responsibility.
  North Carolina energy law enacted in 2007 includes provisions for a North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), expansion of the definition of the traditional fuel clause and recovery of the costs of new DSM and energy-efficiency programs through an annual DSM clause. On February 29, 2008, the NCUC
issued an order adopting final rules for implementing North Carolina’s 2007 energy law. The rules include filing requirements regarding NC REPS compliance and inclusion in the Utility’s integrated resource plan. The order also establishes a schedule and filing requirements for DSM and energy-efficiency cost recovery and financial incentives. Rates for the DSM and energy-efficiency clause and the NC REPS clause will be set based on projected costs with true-up provisions. PEC has implemented a series
of DSM and energy-efficiency programs and will continue to pursue additional programs. These programs must be approved by the NCUC and we cannot predict the outcome of filings currently pending approval by the NCUC or whether the implemented programs will produce the expected operational and economic results.
  LEGAL
  We are subject to federal, state and local legislation and court orders. The specific issues, the status of the issues, accruals associated with issue resolutions and our associated exposures are discussed in detail in Note 15C.
  INCREASING ENERGY DEMAND
  Meeting the anticipated long-term growth within the Utilities’ service territories will require a balanced approach. The three main elements of this balanced solution are: (1) expanding our energy-efficiency programs; (2) investing in the development of alternative energy resources for the future; and (3) operating state-of-the-art
plants that produce energy cleanly and efficiently by modernizing existing plants and pursuing options for building new plants and associated transmission facilities.
  We are actively pursuing expansion of our DSM, energy-efficiency and conservation programs as energy efficiency is one of the most effective ways to reduce energy costs, offset the need for new power plants and protect the environment. DSM programs include programs and initiatives that shift the timing of electricity use from peak to nonpeak
periods, such as load management, electricity system and operating controls, direct load control, interruptible load, and electric system equipment and operating controls. We provide our residential customers with home energy audits and offer energy-efficiency programs that provide incentives for customers to implement measures that reduce energy use. For business customers, we also provide energy audits and other tools, including an interactive Internet Web site with online calculators, programs and efficiency
tips, to help them reduce their energy use.
  We are actively engaged in a variety of alternative energy projects to pursue the generation of electricity from swine waste and other plant or animal sources, biomass, solar, hydrogen and landfill-gas technologies. Among our
 
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 projects, we have executed contracts to purchase approximately 300 MW of electricity generated from biomass and 60 MW of electricity generated from municipal solid waste sources. The majority of these projects should be online within the next five years. In addition, we have executed purchased power agreements for 5 MW of electricity generated
from solar photovoltaic generation. The majority of these projects are online and the remainder should be online by early 2010. We will continue to pursue solar projects and expect to add additional projects before year end. Additionally, in June 2009, we expanded our solar energy strategy to include a range of new residential and commercial solar incentives and programs, which are expected to increase our use of solar energy by more than 100 MW over the next decade.
  In the coming years, we will continue to invest in existing plants and consider plans for building new generating plants. Due to the anticipated long-term growth in our service territories, we estimate that we will require new generation facilities in both Florida and the Carolinas toward the end of the next decade, and we are evaluating
the best available options for this generation, including advanced design nuclear and gas technologies. At this time, no definitive decisions have been made to construct new nuclear plants. In 2007, PEC announced a two-year moratorium on constructing new coal-fired plants while pursuing expansion of energy-efficiency and conservation programs. If PEC proceeds with construction of a new nuclear plant, the new plant would not be online until at least 2019 (See “Nuclear” below).
  As authorized under the Energy Policy Act of 2005 (EPACT), on October 4, 2007, the United States Department of Energy (DOE) published final regulations for the disbursement of up to $13 billion in loan guarantees for clean-energy projects using innovative technologies. The guarantees, which will cover up to 100 percent of the amount of
any loan for no more than 80 percent of the project cost, are expected to spur development of nuclear, clean-coal and ethanol projects.
  In 2008, Congress authorized $38.5 billion in loan guarantee authority for innovative energy projects. Of the total provided, $18.5 billion is set aside for nuclear power facilities, $2 billion for advanced nuclear facilities for the "front-end" of the nuclear fuel cycle, $10 billion for renewable and/or energy-efficient systems and manufacturing and
distributed energy generation/transmission and distribution, $6 billion for coal-based power generation and industrial gasification at retrofitted and new facilities that incorporate carbon capture and sequestration or other beneficial uses of carbon, and $2 billion for advanced coal gasification. In June 2008, the DOE announced solicitations for a total of up to $30.5 billion of the amount authorized by Congress in federal loan guarantees for projects that employ advanced energy technologies that avoid, reduce
or sequester air pollutants or GHG emissions and advanced nuclear facilities for the “front-end” of the nuclear fuel cycle.
  PEF submitted Part I of the Application for Federal Loan Guarantees for Nuclear Power Facilities on September 29, 2008, for Levy. PEF was one of 19 applicants that submitted Part I of the application. The program requires that the guarantee be in a first lien position on all assets of the project, which conflicts with PEF’s current
mortgage. Obtaining the required approval to amend the current mortgage from 100 percent of PEF’s current bondholders would be unlikely, and current secured debt of $4.0 billion would need to be refinanced with unsecured debt to meet the requirements of the guarantee. In addition, the costs associated with obtaining the loan guarantee are unclear. PEF decided not to pursue the loan guarantee program and did not submit Part II of the application, which was due on December 19, 2008. However, this decision
does not preclude PEF from revisiting the program at a later date if there are changes to the program. We cannot predict if PEF will pursue this program further.
  A new nuclear plant may be eligible for the federal production tax credits and risk insurance provided by EPACT. EPACT provides an annual tax credit of 1.8 cents per kWh for nuclear facilities for the first eight years of operation. The credit is limited to the first 6,000 MW of new nuclear generation in the United States and has an annual
cap of $125 million per 1,000 MW of national MW capacity limitation allocated to the unit. In April 2006, the IRS provided interim guidance that the 6,000 MW of production tax credits generally will be allocated to new nuclear facilities that filed license applications with the NRC by December 31, 2008, had poured safety-related concrete prior to January 1, 2014, and were placed in service before January 1, 2021. There is no guarantee that the interim guidance will be incorporated into the final regulations governing
the allocation of production tax credits. Multiple utilities have announced plans to pursue new nuclear plants. There is no guarantee that any nuclear plant we construct would qualify for these or other incentives. We cannot predict the outcome of this matter.
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  NUCLEAR
  Nuclear generating units are regulated by the NRC. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. Our nuclear units are periodically
removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.
  The NRC operating licenses for PEC’s nuclear units expire between 2030 and 2046. The NRC operating license held by PEF for CR3 currently expires in December 2016. On March 9, 2009, the NRC docketed, or accepted for review, PEF’s application for a 20-year extension on the operating license for CR3, which would extend the operating
license through 2036, if approved. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will renew the license. The license renewal application for CR3 is currently under review by the NRC with a decision expected in 2010 or 2011.
  POTENTIAL NEW CONSTRUCTION
  While we have not made a final determination on nuclear construction, we have taken steps to keep open the option of building a plant or plants. During 2008, PEC and PEF filed combined license (COL) applications to potentially construct new nuclear plants in North Carolina and Florida. The NRC estimates that it will take approximately three
to four years to review and process the COL applications.
  On January 23, 2006, we announced that PEC selected a site at the Shearon Harris Nuclear Plant (Harris) to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. On February 19, 2008, PEC filed its COL application
with the NRC for two additional reactors at Harris. On April 17, 2008, the NRC docketed, or accepted for review, the Harris application. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will issue the license. One petition to intervene in the licensing proceeding, which included 11 contentions, was filed with the NRC within the 60-day notice period by the North Carolina Waste Awareness and Reduction Network. The Atomic
Safety and Licensing Board (ASLB) admitted one of the contentions and PEC appealed. Upon review by the NRC, the contention was remanded to the ASLB for reconsideration of admissibility on May 18, 2009. On remand, the ASLB ruled on June 30, 2009 that the contention was not admissible and denied the petition to intervene. On July 22, 2009, the petitioner requested that the NRC reconsider the ASLB’s decision on all 11 contentions.
PEC filed its brief in response on August 3, 2009. We cannot predict the outcome of this matter. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, a new plant would not be online until at least 2019 (See “Increasing Energy Demand” above).
  On December 12, 2006, we announced that PEF selected a greenfield site at Levy to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application submission. In 2007, PEF completed the purchase of approximately 5,000 acres for Levy and
associated transmission needs. In 2007, both the Levy County Planning Commission and the Board of Commissioners voted unanimously in favor of PEF’s requests to change the comprehensive land use plan. On May 29, 2008, the Florida Department of Community Affairs issued its final determination that the amendments to the Levy County Comprehensive Plan are in compliance with land use regulations.
  In 2008, PEF submitted filings for two key state approvals. First, on March 11, 2008, PEF filed a Petition for a Determination of Need for Levy with the FPSC. The FPSC issued a final order granting PEF’s petition for Levy on August 12, 2008. Second, on June 2, 2008, PEF filed its application for site certification with the FDEP. Certification
addresses permitting, land use and zoning, and property interests and replaces state and local permits. Certification grants approval for the location of the power plant and its associated facilities such as roadways and electrical transmission lines carrying power to the electrical grid, among others. Certification does not include licenses required by the federal government. On January 12, 2009, the FDEP filed a favorable staff analysis report in advance of certification hearings. The technical proceedings
concluded on March 12, 2009, and the administrative law judge issued a recommended order on certification on May 15, 2009. The Power Plant Siting Board, comprised of the governor and the cabinet, issues certifications and is scheduled to review the Levy certification on August 11, 2009.
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  On July 30, 2008, PEF filed its COL application with the NRC for two reactors. PEF also completed and submitted a Limited Work Authorization request for Levy concurrent with the COL application. On October 6, 2008, the NRC docketed, or accepted for review, the Levy application. Docketing the application does not preclude additional requests
for information as the review proceeds; nor does it indicate whether the NRC will issue the license. On February 24, 2009, PEF received the NRC’s schedule for review and approval of the COL. One joint petition to intervene in the licensing proceeding was filed with the NRC within the 60-day notice period by the Green Party of Florida, the Nuclear Information and Resource Service and the Ecology Party of Florida. On April 20-21, 2009, the ASLB heard oral arguments on whether any of the joint interveners’
proposed contentions will be admitted in the Levy COL proceeding. On July 8, 2009, the ASLB issued a decision accepting three of the 12 contentions submitted. The admitted contentions involved questions about the storage of low-level radioactive waste, how construction would affect the aquifer in the area and Levy’s use and disposal of salt water. PEF filed an appeal of the ASLB’s decision on July 20, 2009. A hearing on the contentions will be conducted in the future. Other COL applicants have received
similar petitions raising similar potential contentions. We cannot predict the outcome of this matter.
  Based on the NRC’s treatment of certain work prior to the issuance of the Levy COL, PEF now expects a schedule shift for the commercial operation dates of the Levy nuclear units. Specifically, PEF’s initial schedule anticipated the ability to perform certain site work pursuant to a Limited Work Authorization from the NRC prior
to COL receipt. However, earlier in 2009, the NRC Staff has determined that certain schedule-critical work that PEF had proposed to perform within the Limited Work Authorization scope will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work will be shifted until after COL issuance. Although the overall schedule impact is not certain at this time, PEF expects the schedule for the commercial operation of Levy to shift later than the 2016 to 2018 timeframe
by a minimum of 20 months.
  As discussed below, the schedule shift will reduce the near-term capital expenditures for the project and also reduce the near-term impact on customer rates. The schedule shift will also allow more time for certainty around federal climate change policy, which is currently being debated, and could result in more favorable financing than
currently available. We believe that continuing, although at a slower pace than initially anticipated, is a reasonable and prudent course at this early stage of the project. We still consider Levy as PEF’s preferred baseload generation option, taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification. Along with the FPSC’s annual prudence reviews, we
will continue to evaluate the project on an ongoing basis based on certain criteria, including public, regulatory and political support; adequate financial cost-recovery mechanisms; and availability and terms of capital financing.
  PEF signed the EPC agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two Westinghouse AP1000 nuclear units to be constructed at Levy. More than half of the approximate $7.650 billion contract price is fixed or firm with agreed upon escalation factors. The total cost for the two generating
units is estimated to be approximately $14 billion. This total cost estimate includes land, plant components, financing costs, construction, labor, regulatory fees and the initial core for the two units. An additional $3 billion is estimated for the necessary transmission equipment and approximately 200 miles of transmission lines associated with the project. As noted above, the final cost of the project will depend on the completion dates, which will be determined in large part by the NRC review schedule. The
EPC agreement includes various incentives, warranties, performance guarantees, liquidated damage provisions and parent guarantees designed to incent the contractor to perform efficiently. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. We anticipate amending the EPC agreement due to the schedule shift previously discussed but cannot predict the impact such amendment might have on the project’s
cost, if any.
  Florida regulations allow investor-owned utilities such as PEF to recover prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balance of a nuclear power plant prior to commercial operation. The costs are recovered on an annual basis through the capacity cost-recovery clause. Such amounts
will not be included in a utility’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness
and prudence of all such costs, including construction
 
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  costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility.
  In 2008, PEF sought and received approval from the FPSC to recover Levy pre-construction and carrying charges of $357 million as well as site selection costs of $38 million through the 2009 capacity cost-recovery clause. In 2009, PEF received approval to defer until 2010 the recovery of $198 million of these costs (See Note 4B). PEF will
be a participant in the annual nuclear cost-recovery proceeding, which was opened by the FPSC on January 5, 2009. The proceeding will occur throughout the year with an order expected by the end of 2009. On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million, which consists of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to
help mitigate the initial price impact on its customers, as part of its filing, PEF has proposed collecting certain costs over a five-year period, with associated carrying costs. The deferral would result in a nuclear cost-recovery charge of $6.69 per 1,000 kWh for residential customers, which is approximately half of the amount PEF is eligible to recover in 2010 under the nuclear cost-recovery rule. If approved, the charges would begin with the first billing cycle of January 2010. The FPSC has scheduled hearings
in this matter for September 8-11, 2009, with a decision expected in October 2009. We cannot predict the outcome of this matter.
  PEC’s jurisdictions also have laws encouraging nuclear baseload generation. South Carolina law includes provisions for cost-recovery mechanisms associated with nuclear baseload generation. North Carolina law authorizes the NCUC to allow annual prudence reviews of baseload generating plant construction costs and removes the requirement
that a public utility prove financial distress before it may include construction work in progress in rate base and adjust rates, accordingly, in a general rate case while a baseload generating plant is under construction (See “Other Matters – Regulatory Environment”).
  SPENT NUCLEAR FUEL MATTERS
  Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. We have a contract with the DOE for the future storage and disposal of our spent nuclear fuel. Delays have occurred in the DOE’s proposed permanent repository
to be located at Yucca Mountain, Nev. The DOE has stated that the earliest date the repository may be able to start accepting spent nuclear fuel is 2020. However, the 2010 federal budget proposed by the Obama administration largely eliminates funding for the Yucca Mountain facility while the administration devises a new strategy toward nuclear waste disposal. Debate surrounding any new strategy likely will address centralized
interim storage, permanent storage at multiple sites and/or spent nuclear fuel reprocessing. We cannot predict the outcome of this matter.
  On October 9, 2008, the NRC proposed revisions to its waste confidence findings that would remove the provisions stating that the NRC’s confidence in waste management, underlying the licensing of reactors, is based in part on a repository being in operation by 2025. Instead, the NRC states that repository capacity will be available
within 50 to 60 years beyond the licensed operation of all reactors, and that used fuel generated in any reactor can be safely stored on site without significant environmental impact for at least 60 years beyond the licensed operation of the reactor.
  With certain modifications and additional approvals by the NRC, including the installation of on-site dry cask storage facilities at PEC’s Robinson Nuclear Plant (Robinson), Brunswick Nuclear Plant (Brunswick) and CR3, the Utilities’ spent nuclear fuel storage facilities will be sufficient to provide storage space for spent
fuel generated by their respective systems through the expiration of the operating licenses, including any license extensions, for their nuclear generating units. Harris has sufficient storage capacity in its spent fuel pools through the expiration of its extended operating license.
  See Note 15C for information about the complaint filed by the Utilities in the United States Court of Federal Claims against the DOE for its failure to fulfill its contractual obligation to receive spent fuel from nuclear plants. Failure to open the Yucca Mountain or other facility would leave the DOE open to further claims by utilities.
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  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.
  HAZARDOUS AND SOLID WASTE MANAGEMENT
  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 parties (PRP) groups. Various organic materials associated with the production of manufactured gas, generally referred
to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 4 and 14). 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. Hazardous and solid waste management matters are discussed in detail in Note 14A.
  As discussed in “Other Matters – Regulatory Environment” on July 31, 2009, the governor of North Carolina signed into law a bill that changed the state’s Dam Safety Act such that dams at utility coal-fired power plants, including dams on ash ponds, will now be subject to the Act’s applicable provisions, including
state inspection.
  The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion products, 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. We are evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures. These issues are also under evaluation by state agencies. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when those new regulations are finalized.
  We accrue costs to the extent our liability is probable and the costs can be reasonably estimated in accordance with GAAP. 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 could change and additional losses, which could be material, may be incurred in the future.
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  AIR QUALITY AND WATER QUALITY
  We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations, which likely would result in increased capital expenditures and O&M expenses. Additionally, Congress is considering legislation that would require reductions in air emissions of nitrogen oxides
(NOx), SO2, carbon dioxide (CO2)and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multipollutant approach to air pollution control could involve significant capital costs that could be material to our financial position or results of operations. Control
equipment installed pursuant to the provisions of CAIR, CAVR and mercury regulations, which are discussed below, may address some of the issues outlined above. PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, CAVR and mercury regulation (see discussion of the court decisions that impacted the CAIR, the delisting determination and the CAMR below). The CAVR requires the installation of best available retrofit technology (BART) on certain units. However, the
outcome of these matters cannot be predicted.
  Clean Smokestacks Act
  In June 2002, the Clean Smokestacks Act was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from their North Carolina coal-fired power plants in phases by 2013. PEC currently has approximately 5,000 MW of coal-fired
generation capacity in North Carolina that is affected by the Clean Smokestacks Act. On March 31, 2009, PEC filed its annual estimate with the NCUC of the total capital expenditures to meet emission targets under the Clean Smokestacks Act by the end of 2013, which were approximately $1.4 billion at the time of the filing.
  We are continuing to evaluate various design, technology and new generation options that could change expenditures required by the Clean Smokestacks Act. In the short-term, with many unknowns about the future of emission regulations, it may be cost-prohibitive to retrofit older, smaller coal-fired units with emission-reduction technology.
We are evaluating many different options, including the possibility of retiring some coal-fired generation plants and replacing them with combined cycle turbines that burn natural gas. Changes in projected fuel sources may require us to incur costs, which are not currently estimable, to install additional controls subsequent to 2013 in order to remain compliant with the requirements of the Clean Smokestacks Act. As discussed in “Other Matters – Regulatory Environment”, on July 31, 2009, the
governor of North Carolina signed into law a bill that may impact PEC’s Clean Smokestacks Act compliance plans. The legislation abbreviates the certification process for PEC to construct a new natural gas plant as long as PEC permanently retires the existing coal unit at that specific site. The abbreviated certification process gives PEC the option to seek certification and construct a new natural gas plant, with resulting reduced emissions, in time to comply with the Clean Smokestacks Act’s 2013
emission targets.
  O&M expenses increase with the operation of pollution control equipment due to the cost of commodities such as ammonia and limestone used in emissions control technologies (reagents), additional personnel and general maintenance associated with the pollution control equipment. Legislation in North Carolina and South Carolina expanded
the traditional fuel clause to include the annual recovery of reagents and certain other costs; all other O&M expenses are currently recoverable through base rates.
  Two of PEC’s largest coal-fired generating units (the Roxboro No. 4 and Mayo Units) impacted by the Clean Smokestacks Act are jointly owned. In 2005, PEC entered into an agreement with the joint owner to limit their aggregate costs associated with capital expenditures to comply with the Clean Smokestacks Act and recognized a liability
related to this indemnification (See Note 14B).
  Clean Air Interstate Rule
  The CAIR issued by the EPA on March 10, 2005, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively,
for NOx and beginning in 2010 and 2015, respectively, for SO2. States were required to adopt rules implementing the CAIR and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR in 2007.
  PEF participated in a coalition of Florida utilities that filed a challenge to the CAIR as it applied to Florida (PEF withdrew from the coalition during the fourth quarter of 2008). On July 11, 2008, the D.C. Court of Appeals issued its decision on multiple challenges to the CAIR, including the Florida challenge, which vacated the CAIR
in its
 
 99
 
 entirety. On December 23, 2008, the D.C. Court of Appeals remanded the CAIR, without vacating the rule, for the EPA to conduct further proceedings consistent with the D.C. Court of Appeals’ prior opinion. This decision leaves the CAIR in effect until such time that it is revised or replaced. The EPA informed the D.C. Court of Appeals
that development and finalization of a replacement rule could take approximately two years. The outcome of this matter cannot be predicted.
  PEF is continuing construction of its in-process emission control projects. On December 18, 2008, PEF and the FDEP announced an agreement under which PEF will retire CR1 and CR2 as coal-fired units and complete construction of its emission control projects at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit
at Levy completes its first fuel cycle, which was anticipated to be around 2020. As discussed under “Other Matters – Nuclear,” PEF expects the schedule for the commercial operation of Levy to shift  later than the 2016 to 2018 timeframe by a minimum of 20 months. PEF is required to advise the FDEP of any developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated completion date of the first fuel cycle for Levy Unit 2. Accordingly, PEF has advised the FDEP
of the Levy schedule shift. We are currently evaluating the impacts of the Levy schedule shift. We cannot predict the outcome of this matter.
  Clean Air Mercury Rule
  On March 15, 2005, the EPA finalized two separate but related rules: the CAMR that set mercury emissions limits to be met in two phases beginning in 2010 and 2018, respectively, and encouraged a cap-and-trade approach to achieving those caps, and a delisting rule that eliminated any requirement to pursue a maximum achievable control technology
(MACT) approach for limiting mercury emissions from coal-fired power plants. On February 8, 2008, the D.C. Court of Appeals vacated the delisting determination and the CAMR. The U.S. Supreme Court declined to hear an appeal of the D.C. Court of Appeals decision in January 2009. As a result, the EPA subsequently announced that it will develop a MACT standard consistent with the agency’s original listing determination. The three states in which the Utilities operate adopted mercury regulations implementing
the CAMR and submitted their state implementation rules to the EPA. 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. The outcome of this matter cannot be predicted.
  Clean Air Visibility Rule
  On June 15, 2005, the EPA issued the final CAVR. The EPA’s rule requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in 156 specially protected areas, including national parks and wilderness areas, designated as Class
I areas. To help restore visibility in those areas, states must require the identified facilities to install BART to control their emissions. PEC’s BART-eligible units are Asheville Units No. 1 and No. 2, Roxboro Units No. 1, No. 2 and No. 3, and Sutton Unit No. 3. PEF’s BART-eligible units are Anclote Units No. 1 and No. 2, CR1 and CR2. The reductions associated with BART begin in 2013. As discussed above, on December 18, 2008, PEF and the FDEP announced an agreement under which PEF will retire CR1
and CR2 as coal-fired units.
  The CAVR included the EPA’s determination that compliance with the NOx and SO2 requirements of the CAIR could be used by states as a BART substitute to fulfill BART obligations, but the states could require the installation of additional air quality controls
if they did not achieve reasonable progress in improving visibility. The D.C. Court of Appeals’ December 23, 2008 decision remanding the CAIR maintained its implementation such that CAIR satisfies BART for SO2 and NOx. Should this determination change as the CAIR is revised, CAVR compliance eventually may require consideration of NOx and SO2 emissions in addition
to particulate matter emissions for BART-eligible units. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. On December 4, 2007, the FDEP finalized a Regional Haze implementation rule that goes beyond BART by requiring sources significantly impacting visibility in Class I areas to install additional controls by
December 31, 2017. However, the FDEP has not determined the level of additional controls PEF may have to implement. The outcome of these matters cannot be predicted.
  100
  Compliance Strategy
  Both PEC and PEF have been developing an integrated compliance strategy to meet the requirements of the CAIR, the CAVR, mercury regulation and related air quality regulations. The air quality controls installed to comply with the requirements of the NOx State Implementation Plan Call Rule under Section 110 of the Clean Air Act (NOx SIP
Call) and Clean Smokestacks Act resulted in a reduction of the costs to meet the CAIR requirements for our North Carolina units at PEC.
  PEC has completed installation of controls to meet the NOx SIP Call requirements. The NOx SIP Call is not applicable to sources in Florida. Expenditures for the NOx SIP Call included the cost to install NOx controls under programs by North Carolina and South Carolina to comply with the federal eight-hour ozone standard.
  The FPSC approved PEF’s petition to develop and implement an Integrated Clean Air Compliance Plan to comply with the CAIR, CAMR and CAVR and for recovery of prudently incurred costs necessary to achieve this strategy through the ECRC (see discussion above regarding the vacating of the CAMR and remanding of the CAIR). PEF’s most
recent filing with the FPSC, filed on April 1, 2009, seeks approval for true-up of final 2008 environmental costs and included a review of the Integrated Clean Air Compliance Plan, which reconfirmed the efficacy of the recommended plan and included an estimated total project cost of approximately $1.2 billion to be spent through 2016, to plan, design, build and install pollution control equipment at the Anclote and Crystal River plants. Additional costs may be incurred if pollution controls are required in order
to comply with the requirements of the CAVR, as discussed above, or to meet revised compliance requirements of a revised or new implementing rule for the CAIR. Subsequent rule interpretations, increases in the underlying material, labor and equipment costs, equipment availability, or the unexpected acceleration of compliance dates, among other things, could result in significant increases in our estimated costs to comply and acceleration of some projects. The outcome of this matter cannot be predicted.
  Environmental Compliance Cost Estimates
  Environmental compliance cost estimates are dependent upon a variety of factors and, as such, are highly uncertain and subject to change. Factors impacting our environmental compliance cost estimates include new and frequently changing laws and regulations; the impact of legal decisions on environmental laws and regulations; changes in
the demand for, supply of and costs of labor and materials; changes in the scope and timing of projects; various design, technology and new generation options; and projections of fuel sources, prices, availability and security. Costs to comply with environmental laws and regulations are eligible for regulatory recovery through either base rates or cost-recovery clauses. The outcome of future petitions for recovery cannot be predicted. Our estimates of capital expenditures to comply with environmental laws and
regulations are subject to periodic review and revision and may vary significantly. We cannot predict the impact that the EPA’s further CAIR proceedings will have on our compliance with the CAVR requirements and will continue to reassess our plans and estimated costs to comply with the CAVR. The timing and extent of the costs for future projects will depend upon final compliance strategies.
 
 101
 
 The following tables contain information about our current estimates of capital expenditures to comply with environmental laws and regulations described above. Amounts presented in the tables exclude AFUDC.
  Progress EnergyAir and Water Quality Estimated Required Environmental Expenditures (in millions)

Estimated
Timetable


Total Estimated Expenditures


Cumulative Spent throughJune 30, 2009Clean Smokestacks Act(a)


2002 – 2013


$
1,400


$
1,037In-process CAIR projects(b)


2005 – 2010



1,200



985CAVR(c)


– 2017



–



–Mercury regulation(d)


2006 – 2017



–



5Total air quality






2,600



2,027Clean Water Act Section 316(b)(e)






–



–Total air and water quality





$
2,600


$
2,027
 
 PECAir and Water Quality Estimated Required Environmental Expenditures (in millions)

Estimated
Timetable


Total Estimated Expenditures


Cumulative Spent through June 30, 2009Clean Smokestacks Act(a)


2002 – 2013


$
1,400


$
1,037In-process CAIR projects(b)


2005 – 2008



–



–CAVR(c)


– 2017



–



–Mercury regulation(d)


2006 – 2017



–



5Total air quality






1,400



1,042Clean Water Act Section 316(b)(e)






–



–Total air and water quality





$
1,400


$
1,042
 
 PEFAir and Water Quality Estimated Required Environmental Expenditures (in millions)

Estimated
Timetable


Total Estimated Expenditures


Cumulative Spent through June 30, 2009In-process CAIR projects(b)


2005 – 2010


$
1,200


$
985CAVR(c)


– 2017



–



–Mercury regulation(d)






–



–Total air quality






1,200



985Clean Water Act Section 316(b)(e)






–



–Total air and water quality





$
1,200


$
985
 
 (a)
PEC is continuing to evaluate various design, technology and new generation options that could change expenditures required by the Clean Smokestacks Act.
 (b)
PEF is continuing construction of its in-process emission control projects. Additional compliance plans for PEC and PEF to meet the requirements of a revised rule will be determined upon finalization of the rule. See discussion under “Clean Air Interstate Rule.”
 (c)
As a result of the decision remanding the CAIR, compliance plans and costs to meet the requirements of the CAVR are being reassessed. See discussion under “Clean Air Visibility Rule.”
 (d)
Compliance plans to meet the requirements of a revised or new implementing rule will be determined upon finalization of the rule. See discussion under “Clean Air Mercury Rule.”
 (e)
Compliance plans to meet the requirements of a revised or new implementing rule under Section 316(b) of the Clean Water Act will be determined upon finalization of the rule. See discussion under “Water Quality.”
 
 All environmental compliance projects under the first phase of Clean Smokestacks Act emission reductions, which included projects at PEC’s Asheville, Lee, Mayo and Roxboro plants, have been placed in service. The remaining projects to comply with the second phase of emission reductions, which are smaller in scope, have not yet begun.
These estimates are conceptual in nature and subject to change. Additional compliance projects requiring material environmental compliance costs may be implemented in the future.
  102
  To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects under construction at CR5 and CR4, which are expected to be placed in service in 2009 and 2010, respectively. As a result of changes in the scope of work related to estimation of costs for compliance with the CAIR and the uncertainty regarding
the EPA’s further CAIR proceedings, the delisting determination and the CAMR discussed above, PEF is currently unable to estimate certain costs of compliance. However, PEF believes that future costs to comply with new or subsequent rule interpretations could be significant. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when those new regulations are finalized.
  North Carolina Attorney General Petition under Section 126 of the Clean Air Act
  In March 2004, the North Carolina attorney general filed a petition with the EPA, under Section 126 of the Clean Air Act, asking the federal government to force fossil fuel-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO2 emissions.
The state of North Carolina contends these out-of-state emissions interfere with North Carolina’s ability to meet National Ambient Air Quality Standards (NAAQS) for ozone and particulate matter. In 2006, the EPA issued a final response denying the petition and the North Carolina attorney general filed a petition in the D.C. Court of Appeals seeking a review of the agency’s denial. The D.C. Court of Appeals has remanded the EPA’s denial to the agency for reconsideration. The outcome of the remand
proceeding cannot be predicted.
  National Ambient Air Quality Standards
  In 2006, the EPA announced changes to the NAAQS for particulate matter. The changes in particulate matter standards did not result in designation of any additional nonattainment areas in PEC’s or PEF’s service territories. Environmental groups and 13 states filed a joint petition with the D.C. Court of Appeals arguing that the
EPA's particulate matter rule does not adequately restrict levels of particulate matter, especially with respect to the annual and secondary standards. On February 24, 2009, the D.C. Court of Appeals remanded the annual and secondary standards to the EPA for further review and consideration. The outcome of this matter cannot be predicted.
  On March 12, 2008, the EPA announced changes to the NAAQS for ground-level ozone. The EPA revised the 8-hour primary and secondary standards from 0.08 parts per million to 0.075 parts per million. Additional nonattainment areas may be designated in PEC’s and PEF’s service territories as a result of these revised standards. The
EPA has indicated that it plans to designate nonattainment areas for these standards by March 2010. Should additional nonattainment areas be designated in our service territories, we may be required to install additional emission controls at some of our facilities. On May 27, 2008, a number of states, environmental groups and industry associations filed petitions against the revised NAAQS in the D.C. Court of Appeals. The EPA has requested the D.C. Court of Appeals to suspend proceedings in the case while the
EPA evaluates whether to maintain, modify or otherwise reconsider the revised NAAQS. The outcome of this matter cannot be predicted.
  On June 29, 2009, the EPA announced a proposed revision to the primary NAAQS for nitrogen dioxide. Since 1971, when the first NAAQS were promulgated, the standard for nitrogen dioxide has been an annual average of 53 parts per billion. The EPA is proposing to retain the annual standard and add a new 1-hour NAAQS of between 80
and 100 parts per billion. In conjunction with proposing changes to the standard, the EPA is also proposing to increase the coverage of the monitoring network, particularly near roadways where the highest concentrations are expected to occur due to traffic emissions. The EPA plans to finalize the standard by January 22, 2010, and to designate nonattainment areas by January 2012. The outcome of this matter cannot be predicted.
  New Source Review
  The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether changes at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. We were asked to provide information to the EPA as part of this initiative
and cooperated in supplying the requested information. The EPA has undertaken civil enforcement actions against unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements requiring expenditures by these unaffiliated utilities, several of which included reported expenditures in excess of $1.0 billion for retrofit of pollution control equipment. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the
unaffiliated utilities may seek recovery of the related costs through rate adjustments or similar mechanisms.
  103
  Water Quality
  1. General
  As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams will be generated at certain affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes is currently ongoing and will result in permitting, construction
and treatment requirements imposed on the Utilities now and into the future. The future costs of these requirements could be material to our or the Utilities’ results of operations or financial position.
  2. Section 316(b) of the Clean Water Act
  Section 316(b) of the Clean Water Act (Section 316(b)) requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. The EPA promulgated a rule implementing Section 316(b) in respect to existing power plants in July 2004.
  A number of states, environmental groups and others sought judicial review of the July 2004 rule. In 2007, the U.S. Court of Appeals for the Second Circuit issued an opinion and order remanding many provisions of the rule to the EPA and the EPA suspended the rule pending further rulemaking, with the exception of the requirement that permitted
facilities must meet any requirements under Section 316(b) as determined by the permitting authorities on a case-by-case, best professional judgment basis. Several parties filed petitions for writ of certiorari to the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court issued its opinion holding that the EPA, in selecting the “best technology” pursuant to Section 316(b), does have the authority to reject technology when its costs are “wholly disproportionate” to the benefits expected.
Also, the U.S. Supreme Court held that EPA’s site-specific variance procedure (contained in the July 2004 rule) was permissible in that the procedure required testing to determine whether costs would be “significantly greater than” the benefits before a variance would be considered. The EPA has announced that it expects to publish proposed rules in December 2009 responding to both the remand by the U.S. Court of Appeals for the Second Circuit and the U.S. Supreme Court’s opinion. As a
result of these developments, our plans and associated estimated costs to comply with Section 316(b) will need to be reassessed and determined in accordance with any revised or new implementing rule once it is established by the EPA. Costs of compliance with a revised or new implementing rule are expected to be higher, and could be significantly higher, than estimated costs under the July 2004 rule. Our most recent cost estimates to comply with the July 2004 rule were $60 million to $90 million, including $5
million to $10 million at PEC and $55 million to $80 million at PEF. The outcome of this matter cannot be predicted.
  OTHER ENVIRONMENTAL MATTERS
  Global Climate Change
  Growing state, federal and international attention to global climate change may result in the regulation of CO2 and other GHGs. As discussed under “Other Matters – Regulatory Environment,” on June 26, 2009 the U.S. House of Representatives passed
the American Clean Energy and Security Act of 2009. This bill would establish a national cap-and-trade program to reduce GHG emissions as well as a national REPS. The full impact of the legislation if enacted into law cannot be determined at this time and will depend upon changes made to its provisions during the legislative process and the manner in which key provisions are implemented, including for the regulation of carbon. We are currently assessing the impact of the current provisions of the legislation
on our customer rates and, while we have not completed our assessment, we anticipate that it could result in significant rate increases over time. The full U.S. Senate may consider climate change legislation after its summer recess. The Obama administration has agreed to review whether or not CO2 emissions from coal-fired power plants should be regulated. We are preparing for a carbon-constrained future and are actively engaged in helping
shape effective policies to address the issue.
  As discussed under “Other Matters – Regulatory Environment,” in 2008 the state of Florida passed comprehensive energy legislation, which includes a directive that the FDEP develop rules to establish a cap-and-trade program to regulate GHG emissions that would be presented to the legislature no earlier than January 2010.
As discussed under “Clean Smokestacks Act,” on July 31, 2009, the governor of North Carolina signed into law a bill that may impact PEC’s Clean Smokestacks Act compliance plans. While state-level study groups have been active in all three of our jurisdictions, we continue to believe that this is an issue that requires a national policy framework – one that provides certainty and consistency. Our balanced solution as discussed in “Other Matters – Increasing
Energy
 
 104
 
 Demand” is a comprehensive plan to meet the anticipated demand in the Utilities’ service territories and provides a solid basis for slowing and reducing CO2 emissions by focusing on energy efficiency, alternative energy and state-of-the-art power generation.
We issued our latest report on global climate change in the second quarter of 2008, which further evaluates and states our position on this dynamic issue.
  There are ongoing efforts to reach a new international climate change treaty to succeed the Kyoto Protocol. The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of CO2 and other GHGs. Although the treaty
went into effect on February 16, 2005, the United States has not adopted it.
  Reductions in CO2 emissions to the levels specified by the Kyoto Protocol, potential new international treaties or federal or state proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation
cannot be recovered from ratepayers. The cost impact of legislation or regulation to address global climate change would depend on the specific legislation or regulation enacted and cannot be determined at this time.
  On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority under the Clean Air Act to regulate CO2 emissions from new automobiles. On April 2, 2008, 18 states and 11 environmental groups filed an action in the D.C. Court of Appeals against the EPA
Administrator seeking an order requiring the EPA to make a determination within 60 days of whether GHG emissions endanger public health and welfare. The D.C. Court of Appeals denied the petition on June 26, 2008. On April 17, 2009, the EPA issued a proposed endangerment finding under the Clean Air Act, which identified six GHGs (CO2, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) that pose a potential
threat to human health and welfare. The EPA is expected to make a final determination later this year. The outcome of this matter cannot be predicted.
  Prior to 2009, the EPA received waiver requests from a number of states to allow those states to set standards for CO2 emissions from new vehicles. The EPA denied those requests. On January 26, 2009, the Obama administration requested the EPA to review those denials
of waiver requests. On June 30, 2009, the EPA granted California’s waiver request, enabling the state to enforce its GHG emissions standards for new motor vehicles, beginning with the current model year. Additional states may set similar standards as a result of the decision. The impact of this development cannot be predicted.
   NEW ACCOUNTING STANDARDS
  See Note 2 for a discussion of the impact of new accounting standards.
 
 105
 
 PEC
  The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review
“Safe Harbor for Forward-Looking Statements” included within this Form 10-Q and Item 1A, “Risk Factors” to the 2008 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.
  RESULTS OF OPERATIONS
  This information is incorporated herein by reference to “Results of Operations” in Progress Energy’s MD&A, insofar as it relates to PEC.
  LIQUIDITY AND CAPITAL RESOURCES
  This information is incorporated herein by reference to “Liquidity and Capital Resources” in Progress Energy’s MD&A, insofar as it relates to PEC.
  Net cash provided by operating activities increased $83 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $141 million increase from income taxes, net, primarily due to lower net federal income tax payments; a $62 million increase in the
recovery of deferred fuel costs due to higher fuel rates in 2009; and a $52 million decrease in accounts receivable and receivables from affiliated companies, largely driven by lower wholesale revenues and the timing of customer billings and receipts. These impacts were partially offset by a $157 million decrease from accounts payable and accounts payable to affiliated companies, primarily driven by the timing of purchases and payments to vendors.
  Net cash used by investing activities increased $110 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due to a $71 million increase in gross property additions and a $36 million increase in advances to affiliated companies.
  Net cash used by financing activities decreased $34 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to the $400 million payment at maturity of PEC’s 5.95% Senior Notes, the $200 million in dividends paid to the Parent and the $110 million net
repayment of commercial paper outstanding in 2009. These impacts were partially offset by a $273 million increase in the proceeds from the issuance of long-term debt in 2009 compared to 2008, as well as the $300 million payment at maturity of long-term debt and $154 million repayment of advances from affiliates in 2008. PEC’s 2009 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources.”
  OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
  PEC’s off-balance sheet arrangements and contractual obligations are described below.
  MARKET RISK AND DERIVATIVES
  Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.
  CONTRACTUAL OBLIGATIONS
  This information is incorporated herein by reference to “Contractual Obligations” in Progress Energy’s MD&A, insofar as it relates to PEC.
  OTHER MATTERS
  This information is incorporated herein by reference to “Other Matters” in Progress Energy’s MD&A, insofar as it relates to PEC.
   106
  PEF
  The following MD&A and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review
“Safe Harbor for Forward-Looking Statements” included within this Form 10-Q and Item 1A, “Risk Factors” to the 2008 Form 10-K for a discussion of the factors that may impact any such forward-looking statements made herein.
  Other than as discussed below, the information called for by Item 2 is omitted pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).
  RESULTS OF OPERATIONS
  This information is incorporated herein by reference to “Results of Operations” in Progress Energy’s MD&A, insofar as it relates to PEF.
  LIQUIDITY AND CAPITAL RESOURCES
  This information is incorporated herein by reference to “Liquidity and Capital Resources” in Progress Energy’s MD&A, insofar as it relates to PEF.
  Net cash provided by operating activities decreased $209 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to $409 million in cash collateral posted by counterparties on derivative contracts in 2008; a $183 million decrease from accounts payable and
payables to affiliated companies, largely driven by changes in fuel purchase costs and the timing of payments to vendors; a $94 million net increase in federal income tax payments; and $55 million in storm recovery surcharge collections during 2008. The storm surcharge expired in the third quarter of 2008. These impacts were partially offset by a $233 million increase in the recovery of deferred fuel costs due to higher fuel rates, a $104 million increase in the recovery of nuclear construction costs under Florida’s
nuclear cost-recovery rule, an $84 million increase due to derivative collateral included in prepayments and other current assets, and a $66 million decrease in emission allowance purchases.
  Net cash used by investing activities increased $22 million for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The increase was primarily due  to a $149 million decrease in settlements of advances to affiliates and a $17 million increase in nuclear fuel additions. These impacts were
partially offset by a $151 million decrease in property additions. The decrease in property additions was driven by decreases in environmental compliance spending and spending for repowering the Bartow plant to more efficient natural gas-burning technology, partially offset by an increase in expenditures for nuclear projects.
  Net cash provided by financing activities decreased $1.094 billion for the six months ended June 30, 2009, when compared to the corresponding period in the prior year. The decrease was primarily due to $1.476 billion in proceeds received from the issuance of long-term debt, net in 2008 and the $371 million net repayment of commercial paper
outstanding in 2009. These impacts were partially offset by a $363 million change in advances from affiliates, $310 million in contributions from the Parent, and the payment at maturity of $80 million of long-term debt in 2008. PEF’s 2009 financing activities are further described under Progress Energy’s MD&A, “Liquidity and Capital Resources.”
  OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
  PEF’s off-balance sheet arrangements and contractual obligations are described below.
  MARKET RISK AND DERIVATIVES
  Under its risk management policy, PEF may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 11 and Item 3, “Quantitative and Qualitative Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.
  107
  CONTRACTUAL OBLIGATIONS
  This information is incorporated herein by reference to “Contractual Obligations” in Progress Energy’s MD&A, insofar as it relates to PEF.
  OTHER MATTERS
  This information is incorporated herein by reference to “Other Matters” in Progress Energy’s MD&A, insofar as it relates to PEF.
   108
  ITEM 3.                 QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK
  We are exposed to various risks related to changes in market conditions. Market risk represents the potential loss arising from adverse changes in market rates and prices. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk
management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk to the extent that 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 (See Note 11). Both PEC and PEF also have limited counterparty exposure from commodity hedges (primarily gas and oil hedges) by spreading concentration risk over a number of counterparties.
  The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review Item 1A, “Risk Factors”
to the 2008 Form 10-K, and Item 1A, “Risk Factors” found within Part II and “Safe Harbor for Forward-Looking Statements” included within this Form 10-Q for a discussion of the factors that may impact any such forward-looking statements made herein.
  Certain market risks are inherent in our financial instruments, which arise from transactions entered into in the normal course of business. Our primary exposures are changes in interest rates with respect to our long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to our NDT funds, changes
in the market value of CVOs, and changes in energy-related commodity prices.
  These financial instruments are held for purposes other than trading. The risks discussed below do not include the price risks associated with nonfinancial instrument transactions and positions associated with our operations, such as purchase and sales commitments and inventory.
  PROGRESS ENERGY
  Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2008.
  INTEREST RATE RISK
  Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at June 30, 2009, has changed from December 31, 2008. The total notional amount of fixed rate long-term debt at June 30, 2009, was $10.295 billion, with an average interest rate of 6.16% and fair market value of $11.0 billion. The total notional amount
of fixed rate long-term debt at December 31, 2008, was $9.346 billion, with an average interest rate of 6.17% and fair market value of $9.9 billion. The total notional amount of variable rate long-term debt at June 30, 2009, was $961 million, with an average interest rate of 0.74% and fair market value of $1.0 billion. The total notional amount of variable rate long-term debt at December 31, 2008, was $1.061 billion, with an average interest rate of 2.27% and fair market value of $1.1 billion. The total notional
amount of debt to affiliated trust at June 30, 2009, and December 31, 2008, was $309 million, with an average interest rate of 7.10%. At June 30, 2009 and December 31, 2008, the fair market value of debt to affiliated trust was $301 million and $290 million, respectively.
  In addition to our variable rate long-term debt, we typically have commercial paper and/or loans outstanding under our RCA facilities, which are also exposed to floating interest rates. At June 30, 2009 and December 31, 2008, approximately 12 percent and 18 percent, respectively, of consolidated debt was in floating rate mode.
  Based on our variable rate long-term debt balances at June 30, 2009, a 100 basis point change in interest rates would result in an annual interest expense change of approximately $10 million. Based on our variable rate short-term debt balances at June 30, 2009, a 100 basis point change in interest rates would result in an annual interest
expense change of approximately $5 million.
  From time to time, we use interest rate derivative instruments to adjust the mix between fixed and floating rate debt in our debt portfolio, to mitigate our exposure to interest rate fluctuations associated with certain debt instruments, and to hedge interest rates with regard to future fixed rate debt issuances.
  109
  The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the exposure in the transaction is the cost of replacing the agreements at current market rates. We only enter into interest rate derivative transactions with banks with credit ratings
of single A or better.
  We use a number of models and methods to determine interest rate risk exposure and fair value of derivative positions. For reporting purposes, fair values and exposures of derivative positions are determined as of the end of the reporting period using the Bloomberg Financial Markets system.
  In accordance with GAAP, interest rate derivatives that qualify as hedges are separated into one of two categories, cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest
rate changes.
  110
  The following table summarizes the terms, fair market values and exposures of our interest rate derivative instruments. All of the positions included in the table consist of forward starting swaps used to mitigate exposure to interest rate risk in anticipation of future debt issuances. Subsequent to June 30, 2009, the Parent entered into
an additional $50 million notional forward starting swap to mitigate exposure to interest rate risk in anticipation of future debt issuances.
  Cash Flow Hedges (dollars in millions)

Notional
Amount


Pay

Receive (a)

Fair Value


Exposure (b)ParentRisk hedged at June 30, 2009Anticipated 10-year debt issue (c)

$
100



3.86
%
3-month LIBOR

$
4


$
(2
)Risk hedged at December 31, 2008Anticipated 10-year debt issue (d)

$
200



4.36
%
3-month LIBOR

$
(30
)

$
(5
)PECRisk hedged at June 30, 2009Anticipated 10-year debt issue (e)

$
100



4.07
%
3-month LIBOR

$
5


$
(2
)Risk hedged at December 31, 2008Anticipated 10-year debt issue (f)

$
250



4.18
%
3-month LIBOR

$
(35
)

$
(6
)PEFRisk hedged at June 30, 2009Anticipated 10-year debt issue (g)

$
75



3.48
%
3-month LIBOR

$
4


$
(1
)Risk hedged at December 31, 2008:

None
 (a)
3-month LIBOR rate was 0.595% at June 30, 2009, and 1.43% at December 31, 2008.
 (b)
Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.
 (c)
Anticipated 10-year debt issue hedges executed January 2009 and June 2009 mature on March 1, 2021, and require mandatory cash settlement on March 1, 2011.
 (d)
Anticipated 10-year debt issue hedges were terminated on March 16, 2009, in conjunction with the Parent’s issuance of $450 million of 7.05% Senior Notes due 2019.
 (e)
Anticipated 10-year debt issue hedges executed January 2009 and June 2009 mature on July 16, 2022, and require mandatory cash settlement on July 16, 2012.
 (f)
Anticipated 10-year debt issue hedges were terminated on January 8, 2009, in conjunction with PEC’s issuance of $600 million 5.30% First Mortgage Bonds due 2019.
 (g)
Anticipated 10-year debt issue hedges executed January 2009 and June 2009 mature on June 1, 2020, and require mandatory cash settlement on June 1, 2010.
 
 MARKETABLE SECURITIES PRICE RISK
  At June 30, 2009 and December 31, 2008, the fair value of our NDT funds was $1.160 billion and $1.089 billion, respectively, including $725 million and $672 million, respectively, for PEC and $435 million and $417 million, respectively, for PEF. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric
rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.
   111
  
 CONTINGENT VALUE OBLIGATIONS MARKET VALUE RISK
  CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At June 30, 2009 and December 31, 2008, the fair value of CVOs was $26 million and $34 million, respectively. We perform sensitivity analyses to estimate our exposure to the market risk of the CVOs. The sensitivity analysis
performed on the CVOs uses quoted prices obtained from brokers or quote services to measure the potential loss in earnings from a hypothetical 10 percent adverse change in market prices over the next 12 months. A hypothetical 10 percent increase in the June 30, 2009 market price would result in a $3 million increase in the fair value of the CVOs and a corresponding increase in the CVO liability.
  COMMODITY PRICE RISK
  We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of our ownership of energy-related assets. Our exposure to these fluctuations is significantly limited by the cost-based regulation of the Utilities. Each state
commission allows electric utilities to recover certain of these costs through various cost-recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, most of our long-term power sales contracts shift substantially all fuel price risk to the purchaser.
  Most of our commodity contracts are not derivatives or qualify as normal purchases or sales and, therefore, are not recorded at fair value. We perform sensitivity analyses to estimate our exposure to the market risk of our derivative commodity instruments that are not eligible for recovery from ratepayers. At June 30, 2009, substantially
all derivative commodity instrument positions were subject to retail regulatory treatment.
  See Note 11 for additional information with regard to our commodity contracts and use of derivative financial instruments.
  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 derivative instruments related to their exposure to price fluctuations on fuel oil and natural gas purchases. 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, realized gains or losses are passed through the fuel cost-recovery clause. During the three and six months ended June 30, 2009, PEC recorded net realized losses of $21 million and $39 million, respectively. PEC’s net realized gain was $6 million during the three and six months ended June 30, 2008. During the three and six months ended June 30, 2009, PEF recorded net realized losses of $164 million and $273 million,
respectively. During the three and six months ended June 30, 2008, PEF recorded net realized gains of $103 million and $119 million, respectively.
  Certain of our 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 counterparty 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.
  At June 30, 2009, the fair value of PEC’s commodity derivative instruments was recorded as a $1 million long-term derivative asset position included in other assets and deferred debits, a $46 million short-term derivative liability position included in derivative liabilities and a $56 million long-term derivative liability position
included in other liabilities and deferred credits on the PEC Consolidated Balance Sheet. At December 31, 2008, the fair value of such instruments was recorded as a $45 million short-term derivative liability position included in derivative liabilities and a $54 million long-term derivative liability position included in other liabilities and deferred credits on the PEC Consolidated Balance Sheet. Certain counterparties have held cash collateral with PEC in support of these
 
 112
  instruments. PEC had a cash collateral asset included in prepayments and other current assets of $8 million and $18 million on the PEC Consolidated Balance Sheet at June 30, 2009 and December 31, 2008, respectively.
  At June 30, 2009, the fair value of PEF’s commodity derivative instruments was recorded as a $6 million short-term derivative asset position included in prepayments and other current assets, a $9 million long-term derivative asset position included in other assets and deferred debits, a $361 million short-term derivative liability
position included in current derivative liabilities, and a $184 million long-term derivative liability position included in derivative liabilities on the PEF Balance Sheet. At December 31, 2008, the fair value of such instruments was recorded as a $9 million short-term derivative asset position included in prepayments and other current assets, a $1 million long-term derivative asset position included in other assets and deferred debits, a $380 million short-term derivative liability position included in current
derivative liabilities, and a $209 million long-term derivative liability position included in derivative liabilities on the PEF Balance Sheet. Certain counterparties have held cash collateral in support of these instruments. Due to the changes in natural gas prices and settlements of financial hedge agreements since December 31, 2008, PEF’s cash collateral asset included in derivative collateral posted on the PEF Balance Sheet was $294 million at June 30, 2009, compared to $335 million at December 31,
2008.
  CASH FLOW HEDGES
  The Utilities designate a portion of commodity derivative instruments as cash flow hedges. From time to time we hedge exposure to market risk associated with fluctuations in the price of power for our forecasted sales. Realized gains and losses are recorded net in operating revenues. We also hedge exposure to market risk associated with
fluctuations in the price of fuel for fleet vehicles. Realized gains and losses are recorded net as part of fleet vehicle costs. At June 30, 2009 and December 31, 2008, neither we nor the Utilities had material outstanding positions in such contracts. The ineffective portion of commodity cash flow hedges was not material to our or the Utilities’ results of operations for the three and six months ended June 30, 2009 and 2008.
  At June 30, 2009 and December 31, 2008, the amount recorded in our or the Utilities accumulated other comprehensive income related to commodity cash flow hedges was not material.
  PEC
  The information required by this item is incorporated herein by reference to the “Quantitative and Qualitative Disclosures about Market Risk” discussed above insofar as it relates to PEC.
  PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC’s primary exposures are changes in interest rates with respect to long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to its NDT funds,
and changes in energy related commodity prices. Other than discussed above, PEC’s exposure to these risks has not materially changed since December 31, 2008.
  PEF
  Other than as discussed above, the information called for by Item 3 is omitted pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).
 113
  ITEM 4.                 CONTROLS AND PROCEDURES
  PROGRESS ENERGY
  Pursuant to the Securities Exchange Act of 1934, we carried out an evaluation, with the participation of management, including our Chairman, President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end
of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
  There has been no change in our internal control over financial reporting during the quarter ended June 30, 2009, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
  ITEM 4T.               CONTROLS AND PROCEDURES
  PEC
  Pursuant to the Securities Exchange Act of 1934, PEC carried out an evaluation, with the participation of its management, including PEC’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of PEC’s disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of
the period covered by this report. Based upon that evaluation, PEC’s Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by PEC in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to PEC’s management,
including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
  
 There has been no change in PEC’s internal control over financial reporting during the quarter ended June 30, 2009, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
  PEF
  Pursuant to the Securities Exchange Act of 1934, PEF carried out an evaluation, with the participation of its management, including PEF’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of PEF’s disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of
the period covered by this report. Based upon that evaluation, PEF’s Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by PEF in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to PEF’s management,
including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
  There has been no change in PEF’s internal control over financial reporting during the quarter ended June 30, 2009, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
   114
  
 PART II.  OTHER INFORMATION
 
 ITEM 1.                   LEGAL PROCEEDINGS
  Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 15C).
  ITEM 1A.                RISK FACTORS
  In addition to the risk factor disclosed below and the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors to the 2008 Form 10-K, which could materially affect our business, financial condition or future results. The risks described herein and in the 2008 Form
10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
  Impairment of goodwill could have a significant negative impact on our financial condition and results of operations.
  Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility segments and goodwill impairment tests are performed at the utility segment level.
 
 We calculate the fair value of our utility segments by considering various factors, including valuation studies based primarily on income and market approaches. These calculations are dependent on subjective factors such as management’s estimate of future cash flows and the selection of appropriate discount and growth rates from a
marketplace participant’s perspective. These underlying assumptions and estimates are made as of a point in time; subsequent changes, particularly changes in management’s estimate of future cash flows and the discount rates, interest rates and growth rates, could result in a future impairment charge to goodwill. Impairment of our recorded goodwill could result in earnings volatility and an increase in our leverage, which could trigger a downgrade of our credit ratings leading to higher borrowing costs
and/or dilution through additional issuances of common stock.
  ITEM 2.                 UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
  RESTRICTED STOCK UNIT AWARD PAYOUTS
  (a)
Securities Delivered. On May 21, 2009, 812 shares of our common stock were delivered to certain former employees pursuant to the terms of the Progress Energy 2002 and 2007 Equity Incentive Plans (individually and collectively, the “EIP,”) which have been approved by Progress Energy’s
shareholders. Additionally, on June 22, 2009, 262 shares of our common stock were delivered to a current employee pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.
  (b)
Underwriters and Other Purchasers. No underwriters were used in connection with the delivery of our common stock described above.
  (c)
Consideration. The restricted stock unit awards were granted to provide an incentive to the former and current employees to exert their utmost efforts on Progress Energy’s behalf and thus enhance our performance while aligning the employees’ interest with those of our shareholders.
  (d)
Exemption from Registration Claimed. The common shares described in this Item were delivered pursuant to a broad-based involuntary, non-contributory employee benefit plan, and thus did not involve an offer to sell or sale of securities within the meaning of Section 2(3) of the Securities
Act of 1933. Receipt of the shares of our common stock required no investment decision on the part of the recipient.
   115
  
 ISSUER PURCHASES OF EQUITY SECURITIES FOR SECOND QUARTER OF 2009
  Period

(a)
Total Number of Shares
(or Units) Purchased
(1)(2)(3)(4)(5)


(b)
Average
Price Paid
Per Share
(or Unit)


(c)
Total Number of Shares (or Units) Purchased as
Part of Publicly Announced Plans or Programs(1)


(d)
Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs(1)April 1 – April 30


225,165


$
35.1661



N/A



N/AMay 1– May 31


444,257



34.6224



N/A



N/AJune 1– June 30


122,240



36.7229



N/A



N/ATotal


791,662


$
35.1014



N/A



N/A
 
 (1)
At June 30, 2009, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.
 (2)
The plan administrator purchased 295,667 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy 401(k) Savings and Stock Ownership Plan.
 (3)
The plan administrator purchased 154,567 shares of our common stock in open-market transactions to meet share delivery obligations under the Savings Plan for Employees of Florida Progress Corporation.
 (4)
The plan administrator purchased 341,042 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy Investor Plus Plan.
 (5)
Progress Energy withheld 386 shares of our common stock during the second quarter of 2009 and 460 shares during the first quarter of 2009 to pay taxes due upon the payout of certain Restricted Stock Unit Awards and Performance Share Sub-Plan Awards pursuant to the terms of the Company’s 2002 and 2007 Equity Incentive Plans.
 
 ITEM 4.                SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
 PROGRESS ENERGY
  (a)
The Annual Meeting of the Shareholders of Progress Energy, Inc. was held on May 13, 2009.
 
 (b)
The meeting involved the election of twelve directors for one-year terms. Proxies for the meeting were solicited pursuant to Regulation 14, there was no solicitation in opposition to management’s nominees as listed below, and all nominees were elected.
 
 (c)
The total votes for the election of directors were as follows:
 Director
Shares Voted For
Shares Voted Against
Shares AbstainingJames E. Bostic, Jr.
216,383,914
2,386,784
1,188,981Harris E. DeLoach, Jr.
213,219,928
5,627,637
1,112,114James B. Hyler, Jr.
216,397,193
2,460,029
1,102,457William D. Johnson
215,418,570
3,354,227
1,186,882Robert W. Jones
163,516,934
54,836,868
1,605,877W. Steven Jones
215,953,142
2,876,964
1,129,573E. Marie McKee
215,961,085
2,835,652
1,162,942John H. Mullin, III
215,812,030
3,014,403
1,133,245Charles W. Pryor, Jr.
216,390,256
2,428,083
1,141,340Carlos A. Saladrigas
215,884,954
2,844,638
1,230,087Theresa M. Stone
216,305,347
2,533,159
1,121,173Alfred C. Tollison, Jr.
216,253,114
2,566,275
1,140,290
 
  116
  The Board of Directors’ proposal to ratify the selection of Deloitte & Touche LLP as Progress Energy’s independent registered public accounting firm was approved by the shareholders.
 
 The number of shares voted for the proposal was 216,875,018
 The number of shares voted against the proposal was 2,048,114
 The number of abstaining votes was 1,036,548
 
 The Board of Directors’ proposal relating to the executive incentive plan was approved by the shareholders.
 
 The number of shares voted for the proposal was 165,252,786
 The number of shares voted against the proposal was 52,296,396
 The number of abstaining votes was 2,408,997
 The number of broker non-votes was 1,500
 
 PEC
  (a)
The Annual Meeting of the Shareholders of Carolina Power & Light Company was held on May 13, 2009.
 
 (b)
The meeting involved the election of two Class II directors (term expiring in 2012). Proxies for the meeting were solicited pursuant to Regulation 14, there was no solicitation in opposition to management’s nominees as listed below, and all nominees were elected.
 
 (c)
The total votes for the election of directors were as follows:
 Director
Votes For
Votes WithheldClass II (Term Expiring in 2012)William D. Johnson
159,933,207
13,560Paula J. Sims
159,931,606
15,161
 
 The Board of Directors’ proposal to ratify the selection of Deloitte & Touche LLP as PEC’s independent registered public accounting firm was approved by the shareholders.
  The number of shares voted for the proposal was 159,933,951
 The number of shares voted against the proposal was 6,431
 The number of abstaining votes was 6,385
  The Board of Directors’ proposal to amend the By-Laws of the Company to reduce the size of the Board of Directors was approved by the shareholders.
  The number of shares voted for the proposal was 159,926,653
 The number of shares voted against the proposal was 11,268
 The number of abstaining votes was 8,846
  The Board of Directors’ proposal to amend the By-Laws of the Company to provide for the annual election of all members of the Board of Directors was approved by the shareholders.
  The number of shares voted for the proposal was 159,928,153
 The number of shares voted against the proposal was 12,322
 The number of abstaining votes was 6,292
 
 ITEM 5.                 OTHER INFORMATION
  As allowed under the SEC’s implementation guidelines contained in the Interactive Data to Improve Financial Reporting Final Rule, we will furnish Exhibit 101 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009 in Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarterly period ended June
30, 2009, within the initial 30-day grace period following our filing date. No other changes or additions to the financial statements or disclosure provided in this Form 10-Q are expected in connection with the Amendment No. 1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009.
  117
  ITEM 6.                 EXHIBITS
  (a)
Exhibits
 
 Exhibit Number
Description
Progress
Energy
PEC
PEF3(b)
By-laws of Carolina Power & Light Company, as amended on May 13, 2009

X31(a)
302 Certifications of Chief Executive Officer
X31(b)
302 Certifications of Chief Financial Officer
X31(c)
302 Certifications of Chief Executive Officer

X31(d)
302 Certifications of Chief Financial Officer

X31(e)
302 Certifications of Chief Executive Officer


X31(f)
302 Certifications of Chief Financial Officer


X32(a)
906 Certifications of Chief Executive Officer
X32(b)
906 Certifications of Chief Financial Officer
X32(c)
906 Certifications of Chief Executive Officer

X32(d)
906 Certifications of Chief Financial Officer

X32(e)
906 Certifications of Chief Executive Officer


X32(f)
906 Certifications of Chief Financial Officer


X
 
  118
  
 SIGNATURES
  Pursuant to requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
  PROGRESS ENERGY, INC.CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.Date: August 7, 2009
(Registrants)By: /s/ Mark F. MulhernMark F. MulhernSenior Vice President and Chief Financial OfficerBy: /s/ Jeffrey M. StoneJeffrey M. StoneChief Accounting Officer and ControllerProgress Energy, Inc.Chief Accounting OfficerCarolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.Florida Power Corporation d/b/a Progress Energy Florida, Inc.
 
  119