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, 2008





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 Numberlogo1-15929
            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
            x
            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





As of
August 4, 2008, each registrant had the following shares of common stock
outstanding:





Registrant
            Description
            SharesProgress
      Energy
            Common
      Stock (Without Par Value)
            261,987,408PEC
            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 whichwereheld
      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)Unaudited Condensed Consolidated Statements of
      IncomeUnauditedCondensedConsolidated Balance
      SheetsUnauditedCondensedConsolidated Statements of
      Cash FlowsFlorida Power
      Corporation d/b/a Progress Energy Florida, Inc.
    (PEF)Unaudited Condensed Statements of
      IncomeUnauditedCondensedBalance
      SheetsUnauditedCondensedStatements of Cash
      FlowsCombined Notes to UnauditedCondensedInterim 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
      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
            DEFINITION2007
      Form 10-K
            Progress
      Registrants’ annual report on Form 10-K for the fiscal year ended December
      31, 2007401(k)
            Progress
      Energy 401(k) Savings & Stock Ownership PlanAFUDC
            Allowance
      for funds used during constructionAHI
            Affordable
      housing investmentARO
            Asset
      retirement obligationAnnual
      Average Price
            Average
      wellhead price per barrel for unregulated domestic crude oil for the
      yearAsset
      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 LLCCIGFUR
            Carolina
      Industrial Group for Fair Utility Rates IIClean
      Smokestacks Act
            North
      Carolina Clean Smokestacks Act, enacted in June 2002Coal
      Mining
            The
      remaining operations of Progress Fuels subsidiaries engaged in the coal
      mining businessCoal
      and Synthetic Fuels
            Former
      business segment that had been primarily engaged in the production and
      sales of coal-based solid synthetic fuels, the operation of synthetic
      fuels facilities for third parties and coal terminal
    servicesthe
      Code
            Internal
      Revenue CodeCO2
            Carbon
      dioxideCOL
            Combined
      licenseColona
            Colona
      Synfuel Limited Partnership, LLLPCorporate
      and Other
            Corporate
      and Other segment includes Corporate as well as other nonregulated
      businessesCR3
            PEF’s
      Crystal River Unit No. 3 Nuclear PlantCR4
      and CR5
            PEF’s
      Crystal River Units No. 4 and 5 coal-fired steam
  turbinesCUCA
            Carolina
      Utility Customers AssociationCVO
            Contingent
      value obligationD.C.
      Court of Appeals
            U.S.
      Court of Appeals for the District of Columbia CircuitDeSoto
            DeSoto
      County Generating Co., LLCDIG
      Issue C20
            FASB
      Derivatives Implementation Group Issue C20, “Interpretation of the Meaning
      of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts
      with a Price Adjustment Feature”Dixie
      Fuels
            Dixie
      Fuels LimitedDOE
            United
      States Department of Energy




4


DSM
            Demand-side
      managementEarthco
            Four
      Earthco coal-based solid synthetic fuels facilities purchased by
      subsidiaries of Florida Progress in October 1999ECCR
            Energy
      Conservation Cost Recovery ClauseECRC
            Environmental
      Cost Recovery ClauseEIA
            Energy
      Information AgencyEIP
            Equity
      Incentive PlanEPA
            United
      States Environmental Protection AgencyEPACT
            Energy
      Policy Act of 2005EPC
            Engineering,
      procurement and construction agreementERO
            Electric
      reliability organizationESOP
            Employee
      Stock Ownership PlanFASB
            Financial
      Accounting Standards BoardFDEP
            Florida
      Department of Environmental ProtectionFERC
            Federal
      Energy Regulatory CommissionFDCA
            Florida
      Department of Community AffairsFGT
            Florida
      Gas Transmission Company L.L.C.FIN
      39
            FASB
      Interpretation No. 39, “Offsetting of Amounts Related to Certain
      Contracts”FIN
      45
            FASB
      Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements
      for Guarantees, Including Indirect Guarantees of Indebtedness of
      Others”FIN
      46R
            FASB
      Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
      Interpretation of ARB No. 51”FIN
      47
            FASB
      Interpretation No. 47, “Accounting for Conditional Asset Retirement
      Obligations – an Interpretation of FASB Statement No.
  143”FIN
      48
            FASB
      Interpretation No. 48, “Accounting for Uncertainty in Income
      Taxes”the
      Florida Global Case
            U.S.
      Global, LLC v. Progress Energy, Inc. et alFlorida
      Progress
            Florida
      Progress CorporationFPSC
            Florida
      Public Service CommissionFRCC
            Florida
      Reliability Coordinating CouncilFSP
            FASB
      Staff PositionFSP
      FIN 39-1
            FASB
      Staff Position FIN No. 39-1, “An Amendment of FIN 39, Offsetting of
      Amounts Related to Certain Contracts”Funding
      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
      Power
            Georgia
      Power Company, a subsidiary of Southern CompanyGeorgia
      Operations
            Former
      reporting unit consisting of the Effingham, Monroe, Walton and Washington
      nonregulated generation plants in service and the Georgia
      ContractsGlobal
            U.S.
      Global, LLCGridSouth
            GridSouth
      Transco, LLCGulfstream
            Gulfstream
      Gas System, L.L.C.Harris
            PEC’s
      Shearon Harris Nuclear PlantIBEW
            International
      Brotherhood of Electrical WorkersIRS
            Internal
      Revenue ServicekV
            KilovoltkVA
            Kilovolt-amperekWh
            Kilowatt-hoursLevel
      3 Communications
            Level
      3 Communications, Inc.LIBOR
            London
      Inter Bank Offering RateMD&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
    2003




5




MGP
            Manufactured
      gas plant


MW
            MegawattsMWh
            Megawatt-hoursMoody’s
            Moody’s
      Investors Service, Inc.NAAQS
            National
      Ambient Air Quality StandardsNCDWQ
            North
      Carolina Division of Water QualityNCUC
            North
      Carolina Utilities CommissionNEIL
            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
      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 CommissionNuclear
      Waste Act
            Nuclear
      Waste Policy Act of 1982NYMEX
            New
      York Mercantile ExchangeO&M
            Operation
      and maintenance expenseOATT
            Open
      Access Transmission TariffOCI
            Other
      comprehensive incomeOPC
            Florida’s
      Office of Public CounselOPEB
            Postretirement
      benefits other than pensionsthe
      Parent
            Progress
      Energy, Inc. holding company on an unconsolidated basisPEC
            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, LLCthe
      Phase-out Price
            Price
      per barrel of unregulated domestic crude oil at which the value of Section
      29/45K tax credits are fully eliminatedPM
      2.5
            EPA
      standard for particulate matter less than 2.5 microns in
      diameterPM
      2.5-10
            EPA
      standard for particulate matter between 2.5 and 10 microns in
      diameterPM
      10
            EPA
      standard for particulate matter less than 10 microns in
      diameterPower
      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 CorporationProgress
      Rail
            Progress
      Rail Services CorporationPRP
            Potentially
      responsible party, as defined in CERCLAPSSP
            Performance
      Share Sub-PlanPT
      LLC
            Progress
      Telecom, LLCPUHCA
      1935
            Public
      Utility Holding Company Act of 1935, as amendedPUHCA
      2005
            Public
      Utility Holding Company Act of 2005PURPA
            Public
      Utilities Regulatory Policies Act of 1978PVI
            Progress
      Energy Ventures, Inc., formerly referred to as Progress Ventures,
      Inc.PWC
            Public
      Works Commission of the City of Fayetteville, North
    CarolinaQF
            Qualifying
      facilityRCA
            Revolving
      credit agreement


6





REC
            Renewable
      energy certificatesREPS
            North
      Carolina Renewable Energy and Energy Efficiency Portfolio
      StandardReagents
            Commodities
      such as ammonia and limestone used in emissions control
      technologiesRockport
            Indiana
      Michigan Power Company’s Rockport Unit No. 2Robinson
            PEC’s
      Robinson Nuclear PlantROE
            Return
      on equityRowan
            Rowan
      County Power, LLCRSA
            Restricted
      stock awards programRSU
            Restricted
      stock unitRTO
            Regional
      transmission organizationSCPSC
            Public
      Service Commission of South CarolinaSEC
            United
      States Securities and Exchange CommissionSection
      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 ActSection
      45K
            Section
      45K of the Code(See
      Note/s “#”)
            For
      all sections, this is a cross-reference to the Combined Notes to Unaudited
      Condensed Interim Financial Statements contained in PART I, Item 1 of this
      Form 10-QSERC
            SERC
      Reliability CorporationSESH
            Southeast
      Supply Header, L.L.C.S&P
            Standard
      & Poor’s Rating ServicesSFAS
            Statement
      of Financial Accounting StandardsSFAS
      No. 5
            Statement
      of Financial Accounting Standards No. 5, “Accounting for
      Contingencies”SFAS
      No. 71
            Statement
      of Financial Accounting Standards No. 71, “Accounting for the Effects of
      Certain Types of Regulation”SFAS
      No. 87
            Statement
      of Financial Accounting Standards No. 87, “Employers’ Accounting for
      Pensions”SFAS
      No. 109
            Statement
      of Financial Accounting Standards No. 109, “Accounting for Income
      Taxes”SFAS
      No. 115
            Statement
      of Financial Accounting Standards No. 115, “Accounting for Certain
      Investments in Debt and Equity Securities”SFAS
      No. 123R
            Statement
      of Financial Accounting Standards No. 123R, “Share-Based
      Payment”SFAS
      No. 133
            Statement
      of Financial Accounting Standards No. 133, “Accounting for Derivative
      Instruments and Hedging Activities”SFAS
      No. 141R
            Statement
      of Financial Accounting Standards No. 141R, “Business
      Combinations”SFAS
      No. 142
            Statement
      of Financial Accounting Standards No. 142, “Goodwill and Other Intangible
      Assets”SFAS
      No. 143
            Statement
      of Financial Accounting Standards No. 143, “Accounting for Asset
      Retirement Obligations”SFAS
      No. 144
            Statement
      of Financial Accounting Standards No. 144, “Accounting for the Impairment
      or Disposal of Long-Lived Assets”SFAS
      No. 157
            Statement
      of Financial Accounting Standards No. 157, “Fair Value
      Measurements”SFAS
      No. 158
            Statement
      of Financial Accounting Standards No. 158, “Employers’ Accounting for
      Defined Benefit Pension and Other Postretirement Plans”SFAS
      No. 159
            Statement
      of Financial Accounting Standards No. 159, “The Fair Value Option for
      Financial Assets and Financial Liabilities – Including an amendment of
      FASB Statement No. 115”SFAS
      No. 160
            Statement
      of Financial Accounting Standards No. 160, “Noncontrolling Interests in
      Consolidated Financial Statements, an amendment of ARB No.
    51”SFAS
      No. 161
            Statement
      of Financial Accounting Standards No. 161, “Disclosures About Derivative
      Instruments and Hedging Activities — an amendment of FASB Statement No.
      133”




7




SNG
            Southern
      Natural Gas Company


SO2
            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 Kentuckythe
      Threshold Price
            Price
      per barrel of unregulated domestic crude oil at which the value of Section
      29/45K tax credits begin to be reducedthe
      Trust
            FPC
      Capital Ithe
      Utilities
            Collectively,
      PEC and PEFWinchester
      Production
            Winchester
      Production Company, Ltd.


8


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 our synthetic fuels tax credits, changes
in the regulatory environment, meeting increasing energy demand in our service
territories and the impact of environmental regulations.




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
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 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 operation and maintenance expense (O&M) and large construction
projects; the ability of our subsidiaries to pay upstream dividends or
distributions to the Parent; the ability to successfully access capital markets
on favorable terms; 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 funds and the assets
of our pension and benefit plans; 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 United States Securities and Exchange Commission (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, 2007 (2007 Form 10-K), which was filed with
the SEC on February 28, 2008, and is 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.




9


PART
I.  FINANCIAL INFORMATION


ITEM
1.                      FINANCIAL
STATEMENTS




PROGRESS
ENERGY, INC.


UNAUDITED
CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS


June
30, 2008





UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of
      INCOMEThree
      months ended June 30,
            
            
            Six
      months ended June 30,(in
      millions except per share data)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            
            $
            2,244
            
            
            $
            2,129
            
            
            $
            4,310
            
            
            $
            4,201Operating
      expensesFuel
      used in electric generation
            
            
            696
            
            
            
            716
            
            
            
            1,393
            
            
            
            1,452Purchased
      power
            
            
            330
            
            
            
            283
            
            
            
            562
            
            
            
            504Operation
      and maintenance
            
            
            488
            
            
            
            461
            
            
            
            931
            
            
            
            881Depreciation
      and amortization
            
            
            208
            
            
            
            223
            
            
            
            414
            
            
            
            442Taxes
      other than on income
            
            
            125
            
            
            
            125
            
            
            
            246
            
            
            
            249Other
            
            
            (9
            )
            
            
            20
            
            
            
            (7
            )
            
            
            21Total
      operating expenses
            
            
            1,838
            
            
            
            1,828
            
            
            
            3,539
            
            
            
            3,549Operating
      income
            
            
            406
            
            
            
            301
            
            
            
            771
            
            
            
            652Other
      income (expense)Interest
      income
            
            
            5
            
            
            
            6
            
            
            
            12
            
            
            
            14Allowance
      for equity funds used during construction
            
            
            27
            
            
            
            10
            
            
            
            50
            
            
            
            20Other,
      net
            
            
            3
            
            
            
            (2
            )
            
            
            (2
            )
            
            
            (1
            )Total
      other income, net
            
            
            35
            
            
            
            14
            
            
            
            60
            
            
            
            33Interest
      chargesInterest
      charges
            
            
            154
            
            
            
            139
            
            
            
            315
            
            
            
            284Allowance
      for borrowed funds used during construction
            
            
            (8
            )
            
            
            (4
            )
            
            
            (16
            )
            
            
            (7
            )Total
      interest charges, net
            
            
            146
            
            
            
            135
            
            
            
            299
            
            
            
            277Income
      from continuing operations before income tax and minority
      interest
            
            
            295
            
            
            
            180
            
            
            
            532
            
            
            
            408Income
      tax expense
            
            
            95
            
            
            
            41
            
            
            
            179
            
            
            
            113Income
      from continuing operations before minority interest
            
            
            200
            
            
            
            139
            
            
            
            353
            
            
            
            295Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (1
            )
            
            
            (4
            )
            
            
            (8
            )Income
      from continuing operations
            
            
            200
            
            
            
            138
            
            
            
            349
            
            
            
            287Discontinued
      operations, net of tax
            
            
            5
            
            
            
            (331
            )
            
            
            65
            
            
            
            (205
            )Net
      income (loss)
            
            $
            205
            
            
            $
            (193
            )
            
            $
            414
            
            
            $
            82Average
      common shares outstanding – basic
            
            
            260
            
            
            
            256
            
            
            
            259
            
            
            
            255Basic
      earnings per common shareIncome
      from continuing operations
            
            $
            0.77
            
            
            $
            0.54
            
            
            $
            1.35
            
            
            $
            1.13Discontinued
      operations, net of tax
            
            
            0.02
            
            
            
            (1.29
            )
            
            
            0.25
            
            
            
            (0.81
            )Net
      income (loss)
            
            $
            0.79
            
            
            $
            (0.75
            )
            
            $
            1.60
            
            
            $
            0.32Diluted
      earnings per common shareIncome
      from continuing operations
            
            $
            0.77
            
            
            $
            0.54
            
            
            $
            1.34
            
            
            $
            1.12Discontinued
      operations, net of tax
            
            
            0.02
            
            
            
            (1.29
            )
            
            
            0.25
            
            
            
            (0.80
            )Net
      income (loss)
            
            $
            0.79
            
            
            $
            (0.75
            )
            
            $
            1.59
            
            
            $
            0.32Dividends
      declared per common share
            
            $
            0.615
            
            
            $
            0.610
            
            
            $
            1.230
            
            
            $
            1.220





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


10


PROGRESS
ENERGY, INC.


UNAUDITED CONDENSED CONSOLIDATED BALANCE
      SHEETS(in
      millions)
            
            June
      30, 2008
            
            
            December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
            
            $
            25,880
            
            
            $
            25,327Accumulated
      depreciation
            
            
            (11,102
            )
            
            
            (10,895
            )Utility
      plant in service, net
            
            
            14,778
            
            
            
            14,432Held
      for future use
            
            
            37
            
            
            
            37Construction
      work in progress
            
            
            2,297
            
            
            
            1,765Nuclear
      fuel, net of amortization
            
            
            389
            
            
            
            371Total
      utility plant, net
            
            
            17,501
            
            
            
            16,605Current
      assetsCash
      and cash equivalents
            
            
            1,423
            
            
            
            255Receivables,
      net
            
            
            934
            
            
            
            1,167Inventory
            
            
            1,123
            
            
            
            994Deferred
      fuel cost
            
            
            295
            
            
            
            154Derivative
      assets
            
            
            520
            
            
            
            85Assets
      to be divested
            
            
            –
            
            
            
            52Prepayments
      and other current assets
            
            
            187
            
            
            
            122Total
      current assets
            
            
            4,482
            
            
            
            2,829Deferred
      debits and other assetsRegulatory
      assets
            
            
            854
            
            
            
            946Nuclear
      decommissioning trust funds
            
            
            1,302
            
            
            
            1,384Miscellaneous
      other property and investments
            
            
            464
            
            
            
            448Goodwill
            
            
            3,655
            
            
            
            3,655Derivative
      assets
            
            
            617
            
            
            
            119Other
      assets and deferred debits
            
            
            417
            
            
            
            379Total
      deferred debits and other assets
            
            
            7,309
            
            
            
            6,931Total
      assets
            
            $
            29,292
            
            
            $
            26,365CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 500 million shares authorized, 261 million and
      260 million shares issued and outstanding, respectively
            
            $
            6,102
            
            
            $
            6,028Unearned
      ESOP shares (1 million and 2 million shares, respectively)
            
            
            (25
            )
            
            
            (37
            )Accumulated
      other comprehensive loss
            
            
            (28
            )
            
            
            (34
            )Retained
      earnings
            
            
            2,558
            
            
            
            2,465Total
      common stock equity
            
            
            8,607
            
            
            
            8,422Preferred
      stock of subsidiaries – not subject to mandatory
redemption
            
            
            93
            
            
            
            93Minority
      interest
            
            
            6
            
            
            
            84Long-term
      debt, affiliate
            
            
            271
            
            
            
            271Long-term
      debt, net
            
            
            9,886
            
            
            
            8,466Total
      capitalization
            
            
            18,863
            
            
            
            17,336Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            850
            
            
            
            877Short-term
      debt
            
            
            343
            
            
            
            201Accounts
      payable
            
            
            1,078
            
            
            
            819Interest
      accrued
            
            
            162
            
            
            
            173Dividends
      declared
            
            
            161
            
            
            
            160Customer
      deposits
            
            
            268
            
            
            
            255Regulatory
      liabilities
            
            
            17
            
            
            
            173Derivative
      collateral liabilities
            
            
            420
            
            
            
            108Liabilities
      to be divested
            
            
            –
            
            
            
            8Other
      current liabilities
            
            
            568
            
            
            
            528Total
      current liabilities
            
            
            3,867
            
            
            
            3,302Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            252
            
            
            
            361Accumulated
      deferred investment tax credits
            
            
            133
            
            
            
            139Regulatory
      liabilities
            
            
            3,500
            
            
            
            2,554Asset
      retirement obligations
            
            
            1,417
            
            
            
            1,378Accrued
      pension and other benefits
            
            
            759
            
            
            
            763Capital
      lease obligations
            
            
            236
            
            
            
            239Other
      liabilities and deferred credits
            
            
            265
            
            
            
            293Total
      deferred credits and other liabilities
            
            
            6,562
            
            
            
            5,727Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
            
            $
            29,292
            
            
            $
            26,365





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


11


PROGRESS
ENERGY, INC.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH
      FLOWS(in
      millions)Six
      months ended June 30
            
            2008
            
            
            2007Operating
      activitiesNet
      income
            
            $
            414
            
            
            $
            82Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
            
            
            467
            
            
            
            504Deferred
      income taxes and investment tax credits, net
            
            
            98
            
            
            
            132Deferred
      fuel (credit) cost
            
            
            (166
            )
            
            
            83Deferred
      income
            
            
            –
            
            
            
            (64
            )Allowance
      for equity funds used during construction
            
            
            (50
            )
            
            
            (20
            )Other
      adjustments to net income
            
            
            (9
            )
            
            
            85Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
            
            
            224
            
            
            
            13Inventory
            
            
            (116
            )
            
            
            (56
            )Prepayments
      and other current assets
            
            
            (28
            )
            
            
            (58
            )Income
      taxes, net
            
            
            (60
            )
            
            
            (508
            )Accounts
      payable
            
            
            293
            
            
            
            24Derivative
      collateral liabilities
            
            
            312
            
            
            
            (89
            )Other
      current liabilities
            
            
            10
            
            
            
            202Other
      assets and deferred debits
            
            
            (33
            )
            
            
            (127
            )Other
      liabilities and deferred credits
            
            
            1
            
            
            
            (26
            )Net
      cash provided by operating activities
            
            
            1,357
            
            
            
            177Investing
      activitiesGross
      property additions
            
            
            (1,260
            )
            
            
            (899
            )Nuclear
      fuel additions
            
            
            (43
            )
            
            
            (97
            )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
            
            
            64
            
            
            
            646Purchases
      of available-for-sale securities and other investments
            
            
            (836
            )
            
            
            (382
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            816
            
            
            
            433Other
      investing activities
            
            
            (15
            )
            
            
            (8
            )Net
      cash used by investing activities
            
            
            (1,274
            )
            
            
            (307
            )Financing
      activitiesIssuance
      of common stock
            
            
            42
            
            
            
            122Dividends
      paid on common stock
            
            
            (320
            )
            
            
            (311
            )Payments
      of short-term debt with original maturities greater than 90
      days
            
            
            (176
            )
            
            
            –Net
      increase in short-term debt
            
            
            318
            
            
            
            169Proceeds
      from issuance of long-term debt, net
            
            
            1,798
            
            
            
            –Retirement
      of long-term debt
            
            
            (427
            )
            
            
            (2
            )Cash
      distributions to minority interests of consolidated
      subsidiaries
            
            
            (85
            )
            
            
            (10
            )Other
      financing activities
            
            
            (65
            )
            
            
            (17
            )Net
      cash provided (used) by financing activities
            
            
            1,085
            
            
            
            (49
            )Net increase
      (decrease) in cash and cash equivalents
            
            
            1,168
            
            
            
            (179
            )Cash
      and cash equivalents at beginning of period
            
            
            255
            
            
            
            265Cash
      and cash equivalents at end of period
            
            $
            1,423
            
            
            $
            86Supplemental
      disclosuresSignificant
      noncash transactionsCapital
      lease obligation incurred
            
            $
            –
            
            
            $
            182Note
      receivable for disposal of ownership interest in Ceredo
            
            
            –
            
            
            
            48Nuclear
      decommissioning trust funds unrealized loss (gain)
            
            
            98
            
            
            
            (50
            )Accrued
      property additions
            
            
            263
            
            
            
            192See
      Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim
      Financial Statements.





12


CAROLINA POWER & LIGHT COMPANY


d/b/a
PROGRESS ENERGY CAROLINAS, INC.


UNAUDITED
CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS


June
30, 2008





UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of
      INCOMEThree
      months ended June 30,
            
            
            Six
      months ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            
            $
            1,048
            
            
            $
            996
            
            
            $
            2,116
            
            
            $
            2,054Operating
      expensesFuel
      used in electric generation
            
            
            323
            
            
            
            305
            
            
            
            679
            
            
            
            656Purchased
      power
            
            
            72
            
            
            
            76
            
            
            
            121
            
            
            
            134Operation
      and maintenance
            
            
            275
            
            
            
            268
            
            
            
            523
            
            
            
            516Depreciation
      and amortization
            
            
            129
            
            
            
            118
            
            
            
            255
            
            
            
            235Taxes
      other than on income
            
            
            49
            
            
            
            49
            
            
            
            99
            
            
            
            99Other
            
            
            (5
            )
            
            
            –
            
            
            
            (6
            )
            
            
            (1
            )Total
      operating expenses
            
            
            843
            
            
            
            816
            
            
            
            1,671
            
            
            
            1,639Operating
      income
            
            
            205
            
            
            
            180
            
            
            
            445
            
            
            
            415Other
      incomeInterest
      income
            
            
            2
            
            
            
            5
            
            
            
            7
            
            
            
            11Other,
      net
            
            
            11
            
            
            
            7
            
            
            
            15
            
            
            
            10Total
      other income, net
            
            
            13
            
            
            
            12
            
            
            
            22
            
            
            
            21Interest
      chargesInterest
      charges
            
            
            52
            
            
            
            54
            
            
            
            110
            
            
            
            111Allowance
      for borrowed funds used during construction
            
            
            (2
            )
            
            
            (1
            )
            
            
            (4
            )
            
            
            (2
            )Total
      interest charges, net
            
            
            50
            
            
            
            53
            
            
            
            106
            
            
            
            109Income
      before income tax
            
            
            168
            
            
            
            139
            
            
            
            361
            
            
            
            327Income
      tax expense
            
            
            64
            
            
            
            51
            
            
            
            134
            
            
            
            115Net
      income
            
            
            104
            
            
            
            88
            
            
            
            227
            
            
            
            212Preferred
      stock dividend requirement
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Earnings
      for common stock
            
            $
            104
            
            
            $
            88
            
            
            $
            226
            
            
            $
            211





See
Notes to PEC Unaudited Condensed Consolidated Interim Financial
Statements.


13


CAROLINA
POWER & LIGHT COMPANY


d/b/a
PROGRESS ENERGY CAROLINAS, INC.


UNAUDITED CONDENSED CONSOLIDATED BALANCE
      SHEETS(in
      millions)
            
            June
      30, 2008
            
            
            December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
            
            $
            15,433
            
            
            $
            15,117Accumulated
      depreciation
            
            
            (7,225
            )
            
            
            (7,097
            )Utility
      plant in service, net
            
            
            8,208
            
            
            
            8,020Held
      for future use
            
            
            2
            
            
            
            2Construction
      work in progress
            
            
            521
            
            
            
            566Nuclear
      fuel, net of amortization
            
            
            294
            
            
            
            292Total
      utility plant, net
            
            
            9,025
            
            
            
            8,880Current
      assetsCash
      and cash equivalents
            
            
            18
            
            
            
            25Receivables,
      net
            
            
            513
            
            
            
            491Receivables
      from affiliated companies
            
            
            12
            
            
            
            42Notes
      receivable from affiliated companies
            
            
            39
            
            
            
            –Inventory
            
            
            553
            
            
            
            510Deferred
      fuel cost
            
            
            232
            
            
            
            148Prepayments
      and other current assets
            
            
            118
            
            
            
            50Total
      current assets
            
            
            1,485
            
            
            
            1,266Deferred
      debits and other assetsRegulatory
      assets
            
            
            571
            
            
            
            680Nuclear
      decommissioning trust funds
            
            
            767
            
            
            
            804Miscellaneous
      other property and investments
            
            
            198
            
            
            
            192Derivative
      assets
            
            
            113
            
            
            
            19Other
      assets and deferred debits
            
            
            149
            
            
            
            141Total
      deferred debits and other assets
            
            
            1,798
            
            
            
            1,836Total
      assets
            
            $
            12,308
            
            
            $
            11,982CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 200 million shares authorized, 160 million shares
      issued and outstanding
            
            $
            2,076
            
            
            $
            2,054Unearned
      ESOP common stock
            
            
            (25
            )
            
            
            (37
            )Accumulated
      other comprehensive loss
            
            
            (15
            )
            
            
            (10
            )Retained
      earnings
            
            
            1,998
            
            
            
            1,772Total
      common stock equity
            
            
            4,034
            
            
            
            3,779Preferred
      stock – not subject to mandatory redemption
            
            
            59
            
            
            
            59Long-term
      debt, net
            
            
            3,108
            
            
            
            3,183Total
      capitalization
            
            
            7,201
            
            
            
            7,021Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            400
            
            
            
            300Notes
      payable to affiliated companies
            
            
            –
            
            
            
            154Accounts
      payable
            
            
            386
            
            
            
            308Payables
      to affiliated companies
            
            
            87
            
            
            
            71Interest
      accrued
            
            
            60
            
            
            
            58Customer
      deposits
            
            
            76
            
            
            
            70Income
      taxes accrued
            
            
            –
            
            
            
            27Other
      current liabilities
            
            
            208
            
            
            
            182Total
      current liabilities
            
            
            1,217
            
            
            
            1,170Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            915
            
            
            
            936Accumulated
      deferred investment tax credits
            
            
            119
            
            
            
            122Regulatory
      liabilities
            
            
            1,213
            
            
            
            1,098Asset
      retirement obligations
            
            
            1,094
            
            
            
            1,063Accrued
      pension and other benefits
            
            
            453
            
            
            
            459Other
      liabilities and deferred credits
            
            
            96
            
            
            
            113Total
      deferred credits and other liabilities
            
            
            3,890
            
            
            
            3,791Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
            
            $
            12,308
            
            
            $
            11,982





See
Notes to PEC Unaudited Condensed Consolidated Interim Financial
Statements.


14


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
            
            2008
            
            
            2007Operating
      activitiesNet
      income
            
            $
            227
            
            
            $
            212Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
            
            
            304
            
            
            
            277Deferred
      income taxes and investment tax credits, net
            
            
            15
            
            
            
            27Deferred
      fuel cost
            
            
            30
            
            
            
            33Other
      adjustments to net income
            
            
            9
            
            
            
            (28
            )Cash
      (used) provided by changes in operating assets and
    liabilitiesReceivables
            
            
            (27
            )
            
            
            8Receivables
      from affiliated companies
            
            
            30
            
            
            
            9Inventory
            
            
            (36
            )
            
            
            (20
            )Prepayments
      and other current assets
            
            
            20
            
            
            
            5Income
      taxes, net
            
            
            (78
            )
            
            
            (28
            )Accounts
      payable
            
            
            74
            
            
            
            (1
            )Payables
      to affiliated companies
            
            
            16
            
            
            
            (44
            )Other
      current liabilities
            
            
            26
            
            
            
            6Other
      assets and deferred debits
            
            
            (21
            )
            
            
            (4
            )Other
      liabilities and deferred credits
            
            
            (26
            )
            
            
            2Net
      cash provided by operating activities
            
            
            563
            
            
            
            454Investing
      activitiesGross
      property additions
            
            
            (331
            )
            
            
            (407
            )Nuclear
      fuel additions
            
            
            (42
            )
            
            
            (75
            )Purchases
      of available-for-sale securities and other investments
            
            
            (337
            )
            
            
            (226
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            321
            
            
            
            260Changes
      in advances to affiliated companies
            
            
            (39
            )
            
            
            24Other
      investing activities
            
            
            (6
            )
            
            
            (2
            )Net
      cash used by investing activities
            
            
            (434
            )
            
            
            (426
            )Financing
      activitiesDividends
      paid on preferred stock
            
            
            (1
            )
            
            
            (1
            )Dividends
      paid to parent
            
            
            –
            
            
            
            (72
            )Proceeds
      from issuance of long-term debt, net
            
            
            322
            
            
            
            –Retirement
      of long-term debt
            
            
            (300
            )
            
            
            –Changes
      in advances from affiliated companies
            
            
            (154
            )
            
            
            5Other
      financing activities
            
            
            (3
            )
            
            
            17Net
      cash used by financing activities
            
            
            (136
            )
            
            
            (51
            )Net
      decrease in cash and cash equivalents
            
            
            (7
            )
            
            
            (23
            )Cash
      and cash equivalents at beginning of period
            
            
            25
            
            
            
            71Cash
      and cash equivalents at end of period
            
            $
            18
            
            
            $
            48Supplemental
      disclosuresSignificant
      noncash transactionsNuclear
      decommissioning trust funds unrealized loss (gain)
            
            $
            53
            
            
            $
            (26
            )Accrued
      property additions
            
            
            80
            
            
            
            81See
      Notes to PEC Unaudited Condensed Consolidated Interim Financial
      Statements.




15


FLORIDA
POWER CORPORATION


d/b/a
PROGRESS ENERGY FLORIDA, INC.


UNAUDITED
CONDENSED INTERIM FINANCIAL STATEMENTS


June
30, 2008





UNAUDITED CONDENSED STATEMENTS of
      INCOMEThree
      months ended June 30,
            
            
            Six
      months ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            
            $
            1,194
            
            
            $
            1,129
            
            
            $
            2,190
            
            
            $
            2,140Operating
      expensesFuel
      used in electric generation
            
            
            373
            
            
            
            411
            
            
            
            714
            
            
            
            796Purchased
      power
            
            
            258
            
            
            
            207
            
            
            
            441
            
            
            
            370Operation
      and maintenance
            
            
            217
            
            
            
            198
            
            
            
            420
            
            
            
            373Depreciation
      and amortization
            
            
            76
            
            
            
            100
            
            
            
            152
            
            
            
            197Taxes
      other than on income
            
            
            76
            
            
            
            76
            
            
            
            147
            
            
            
            150Other
            
            
            (4
            )
            
            
            12
            
            
            
            (4
            )
            
            
            12Total
      operating expenses
            
            
            996
            
            
            
            1,004
            
            
            
            1,870
            
            
            
            1,898Operating
      income
            
            
            198
            
            
            
            125
            
            
            
            320
            
            
            
            242Other
      income (expense)Interest
      income
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2Allowance
      for equity funds used during construction
            
            
            22
            
            
            
            8
            
            
            
            40
            
            
            
            16Other,
      net
            
            
            –
            
            
            
            –
            
            
            
            (1
            )
            
            
            (1
            )Total
      other income, net
            
            
            23
            
            
            
            9
            
            
            
            41
            
            
            
            17Interest
      chargesInterest
      charges
            
            
            45
            
            
            
            42
            
            
            
            95
            
            
            
            81Allowance
      for borrowed funds used during construction
            
            
            (6
            )
            
            
            (3
            )
            
            
            (12
            )
            
            
            (5
            )Total
      interest charges, net
            
            
            39
            
            
            
            39
            
            
            
            83
            
            
            
            76Income
      before income tax
            
            
            182
            
            
            
            95
            
            
            
            278
            
            
            
            183Income
      tax expense
            
            
            57
            
            
            
            27
            
            
            
            86
            
            
            
            54Net
      income
            
            
            125
            
            
            
            68
            
            
            
            192
            
            
            
            129Preferred
      stock dividend requirement
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Earnings
      for common stock
            
            $
            125
            
            
            $
            68
            
            
            $
            191
            
            
            $
            128





See
Notes to PEF Unaudited Condensed Interim Financial Statements.


16


FLORIDA
POWER CORPORATION


d/b/a
PROGRESS ENERGY FLORIDA, INC.


UNAUDITED CONDENSED BALANCE SHEETS(in
      millions)
            
            June
      30, 2008
            
            
            December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
            
            $
            10,263
            
            
            $
            10,025Accumulated
      depreciation
            
            
            (3,817
            )
            
            
            (3,738
            )Utility
      plant in service, net
            
            
            6,446
            
            
            
            6,287Held
      for future use
            
            
            35
            
            
            
            35Construction
      work in progress
            
            
            1,776
            
            
            
            1,199Nuclear
      fuel, net of amortization
            
            
            95
            
            
            
            79Total
      utility plant, net
            
            
            8,352
            
            
            
            7,600Current
      assetsCash
      and cash equivalents
            
            
            1,348
            
            
            
            23Receivables,
      net
            
            
            414
            
            
            
            351Receivables
      from affiliated companies
            
            
            8
            
            
            
            8Notes
      receivable from affiliated companies
            
            
            –
            
            
            
            149Inventory
            
            
            570
            
            
            
            484Deferred
      income taxes
            
            
            –
            
            
            
            39Income
      taxes receivable
            
            
            15
            
            
            
            41Derivative
      assets
            
            
            478
            
            
            
            83Prepayments
      and other current assets
            
            
            116
            
            
            
            9Total
      current assets
            
            
            2,949
            
            
            
            1,187Deferred
      debits and other assetsRegulatory
      assets
            
            
            283
            
            
            
            266Nuclear
      decommissioning trust funds
            
            
            535
            
            
            
            580Miscellaneous
      other property and investments
            
            
            44
            
            
            
            46Derivative
      assets
            
            
            504
            
            
            
            100Prepaid
      pension cost
            
            
            233
            
            
            
            221Other
      assets and deferred debits
            
            
            101
            
            
            
            63Total
      deferred debits and other assets
            
            
            1,700
            
            
            
            1,276Total
      assets
            
            $
            13,001
            
            
            $
            10,063CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 60 million shares authorized, 100 shares issued
      and outstanding
            
            $
            1,113
            
            
            $
            1,109Accumulated
      other comprehensive loss
            
            
            –
            
            
            
            (8
            )Retained
      earnings
            
            
            2,092
            
            
            
            1,901Total
      common stock equity
            
            
            3,205
            
            
            
            3,002Preferred
      stock – not subject to mandatory redemption
            
            
            34
            
            
            
            34Long-term
      debt, net
            
            
            4,181
            
            
            
            2,686Total
      capitalization
            
            
            7,420
            
            
            
            5,722Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            450
            
            
            
            532Notes
      payable to affiliated companies
            
            
            43
            
            
            
            –Accounts
      payable
            
            
            676
            
            
            
            473Payables
      to affiliated companies
            
            
            42
            
            
            
            87Interest
      accrued
            
            
            47
            
            
            
            57Customer
      deposits
            
            
            192
            
            
            
            185Derivative
      liabilities
            
            
            2
            
            
            
            38Regulatory
      liabilities
            
            
            17
            
            
            
            173Derivative
      collateral liabilities
            
            
            409
            
            
            
            –Deferred
      income tax liabilities
            
            
            160
            
            
            
            –Other
      current liabilities
            
            
            136
            
            
            
            92Total
      current liabilities
            
            
            2,174
            
            
            
            1,637Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            288
            
            
            
            401Accumulated
      deferred investment tax credits
            
            
            14
            
            
            
            17Regulatory
      liabilities
            
            
            2,164
            
            
            
            1,330Asset
      retirement obligations
            
            
            323
            
            
            
            315Accrued
      pension and other benefits
            
            
            304
            
            
            
            304Capital
      lease obligations
            
            
            221
            
            
            
            224Other
      liabilities and deferred credits
            
            
            93
            
            
            
            113Total
      deferred credits and other liabilities
            
            
            3,407
            
            
            
            2,704Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
            
            $
            13,001
            
            
            $
            10,063





See
Notes to PEF Unaudited Condensed Interim Financial Statements.


17


FLORIDA
POWER CORPORATION


d/b/a
PROGRESS ENERGY FLORIDA, INC.


UNAUDITED CONDENSED STATEMENTS of CASH
      FLOWS(in
      millions)Six
      months ended June 30
            
            2008
            
            
            2007Operating
      activitiesNet
      income
            
            $
            192
            
            
            $
            129Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
            
            
            153
            
            
            
            210Deferred
      income taxes and investment tax credits, net
            
            
            48
            
            
            
            (19
            )Deferred
      fuel (credit) cost
            
            
            (196
            )
            
            
            50Allowance
      for equity funds used during construction
            
            
            (40
            )
            
            
            (16
            )Other
      adjustments to net income
            
            
            4
            
            
            
            39Cash
      (used) provided by changes in operating assets and
    liabilitiesReceivables
            
            
            (65
            )
            
            
            (13
            )Receivables
      from affiliated companies
            
            
            –
            
            
            
            (1
            )Inventory
            
            
            (85
            )
            
            
            (42
            )Prepayments
      and other current assets
            
            
            (49
            )
            
            
            58Income
      taxes, net
            
            
            34
            
            
            
            82Accounts
      payable
            
            
            237
            
            
            
            104Payables
      to affiliated companies
            
            
            (45
            )
            
            
            (72
            )Derivative
      collateral liabilities
            
            
            409
            
            
            
            –Other
      current liabilities
            
            
            27
            
            
            
            54Other
      assets and deferred debits
            
            
            (10
            )
            
            
            (1
            )Other
      liabilities and deferred credits
            
            
            40
            
            
            
            (15
            )Net
      cash provided by operating activities
            
            
            654
            
            
            
            547Investing
      activitiesGross
      property additions
            
            
            (921
            )
            
            
            (489
            )Nuclear
      fuel additions
            
            
            (1
            )
            
            
            (22
            )Purchases
      of available-for-sale securities and other investments
            
            
            (418
            )
            
            
            (103
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            418
            
            
            
            103Changes
      in advances to affiliated companies
            
            
            149
            
            
            
            –Proceeds
      from sales of assets to affiliated companies
            
            
            10
            
            
            
            –Other
      investing activities
            
            
            (2
            )
            
            
            –Net
      cash used by investing activities
            
            
            (765
            )
            
            
            (511
            )Financing
      activitiesDividends
      paid on preferred stock
            
            
            (1
            )
            
            
            (1
            )Proceeds
      from issuance of long-term debt, net
            
            
            1,476
            
            
            
            –Retirement
      of long-term debt
            
            
            (82
            )
            
            
            (2
            )Changes
      in advances from affiliated companies
            
            
            43
            
            
            
            (43
            )Other
      financing activities
            
            
            –
            
            
            
            1Net
      cash provided (used) by financing activities
            
            
            1,436
            
            
            
            (45
            )Net
      increase (decrease) in cash and cash equivalents
            
            
            1,325
            
            
            
            (9
            )Cash
      and cash equivalents at beginning of period
            
            
            23
            
            
            
            23Cash
      and cash equivalents at end of period
            
            $
            1,348
            
            
            $
            14Supplemental
      disclosuresSignificant
      noncash transactionsCapital
      lease obligation incurred
            
            $
            –
            
            
            $
            182Nuclear
      decommissioning trust funds unrealized loss (gain)
            
            
            45
            
            
            
            (24
            )Accrued
      property additions
            
            
            180
            
            
            
            110See
      Notes to PEF Unaudited Condensed Interim Financial
    Statements.





18


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 through 9, and 11 through 13PEF
            1,
      2, 4 through 9, and 11 through
13


19


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





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.




1.
            ORGANIZATION AND
      SUMMARY OF SIGNIFICANT ACCOUNTING
  POLICIES




A.           ORGANIZATION




PROGRESS
ENERGY, INC.





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 separate business segment. See Note 10 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, 2007 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,
2007 (2007 Form 10-K).




20




In
accordance with the provisions of Accounting Principles Board Opinion No. 28,
“Interim Financial Reporting,” GAAP requires companies to apply a levelized
effective income tax rate to interim periods that is consistent with the
estimated annual effective tax rate. The tax levelization expense or benefit
recorded during the interim period, which will have no impact on total year net
income, maintains an effective tax rate consistent with the estimated annual
effective tax rate. The fluctuations in the effective tax rate for the three and
six months ended June 30, 2008, are primarily due to seasonal fluctuations in
energy sales and earnings from the Utilities. The fluctuations in the effective
tax rate for the three and six months ended June 30, 2007, are primarily due to
the recognition of synthetic fuels tax credits and seasonal fluctuations in
energy sales and earnings from the Utilities. Total tax levelization adjustments
increased (decreased) income tax expense for the Progress Registrants for the
three and six months ended June 30, 2008 and 2007, as follows:


Three
      Months Ended June 30,
              
              
              Six
      Months Ended June 30,(in
      millions)
              
              2008
              
              
              2007
              
              
              2008
              
              
              2007Progress
      Energy
              
              $
              3
              
              
              $
              31
              
              
              $
              (4
              )
              
              $
              23PEC
              
              
              2
              
              
              
              –
              
              
              
              (1
              )
              
              
              (1
              )PEF
              
              
              (4
              )
              
              
              1
              
              
              
              (3
              )
              
              
              1
  For the
three and six months ended June 30, 2007, $32 million and $22 million,
respectively, of the Progress Energy net tax levelization expense was related to
synthetic fuels tax credits recorded by the synthetic fuels businesses and is
included in discontinued operations on the Consolidated Statements of Income,
pursuant to the intraperiod tax allocation rules as set forth in Statement of
Financial Accounting Standard (SFAS) No. 109, “Accounting for Income Taxes”
(SFAS No. 109). When the synthetic fuels businesses were reclassified to
discontinued operations in the fourth quarter of 2007 (See Note 3A), the impacts
of the quarterly tax levelization adjustments associated with the synthetic
fuels tax credits were not also reclassified to discontinued operations in Note
24 in the 2007 Form 10-K, including the $32 million levelization expense for the
three months ended June 30, 2007 discussed above. Consequently, the presentation
of the unaudited summarized quarterly financial data previously reported for
Progress Energy in Note 24 in the 2007 Form 10-K was not correct. As a result,
the unaudited summarized quarterly financial data has been restated. This
correction does not affect our Consolidated Statements of Income for 2007 or
2006, as the quarterly tax levelization adjustments net to zero on an annual
basis. The following table presents specific line item amounts for the three
months ended June 30, 2007, included in Note 24 in the 2007 Form 10-K that have
been restated as a result of this correction:


Progress
      Energy(in
      millions except per share data)
            
            As
      originally reported
            
            
            As
      restatedIncome
      from continuing operations
            
            $
            106
            
            
            $
            138Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations
            
            
            0.42
            
            
            
            0.54Diluted
      earnings per common shareIncome
      from continuing operations
            
            
            0.41
            
            
            
            0.54





The
Utilities collect from customers certain excise taxes levied by the state or
local government upon the customers. The Utilities account for sales and use tax
on a net basis and gross receipts tax, franchise taxes and other excise taxes on
a gross basis. The amount of gross receipts tax, franchise taxes and other
excise taxes included in operating revenues and taxes other than on income in
the statements of income were as follows:


Three
      Months Ended June 30,
              
              
              Six
      Months Ended June 30,(in
      millions)
              
              2008
              
              
              2007
              
              
              2008
              
              
              2007Progress
      Energy
              
              $
              72
              
              
              $
              71
              
              
              $
              137
              
              
              $
              137PEC
              
              
              25
              
              
              
              24
              
              
              
              50
              
              
              
              48PEF
              
              
              47
              
              
              
              47
              
              
              
              87
              
              
              
              89





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




21




variations
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 2007 have been reclassified to conform to the 2008
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 for which we are the primary
beneficiary in accordance with Financial Accounting Standards Board (FASB)
Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
Interpretation of ARB No. 51” (FIN 46R).




PROGRESS
ENERGY




In March
2007, we disposed of our 100 percent ownership interest in Ceredo Synfuel LLC
(Ceredo), a coal-based solid synthetic fuels production facility that qualifies
for federal tax credits under Section 45K of the Internal Revenue Code (the
Code), to a third-party buyer. Progress Energy, through its subsidiary Progress
Fuels Corporation (Progress Fuels), is the primary beneficiary of, and continues
to consolidate Ceredo. See Note 3F for additional information on the disposal of
Ceredo.




In
addition to the variable interests listed below for PEC and PEF, we have
interests through other subsidiaries in several variable interest entities for
which we are not the primary beneficiary. These arrangements include equity
investments made prior to 2005 in five entities whose operations include
affordable housing and venture capital investments, research and development, or
real estate activities. At June 30, 2008, the aggregate maximum loss exposure
that we could be required to record in our statement of income as a result of
these arrangements was $5 million, which represents our net remaining investment
in the entities. The creditors of these variable interest entities do not have
recourse to our general credit in excess of the aggregate maximum loss
exposure.




PEC




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. At June 30, 2008, the assets of the two entities totaled $37
million, the majority of which are collateral for the entities’ obligations, and
were included in miscellaneous other property and investments in the
Consolidated Balance Sheets.




PEC has
an interest in and consolidates one limited partnership that invests in 17
low-income housing partnerships that qualify for federal and state tax credits.
PEC also has an interest in one power plant resulting from long-term power
purchase contracts. PEC has requested the necessary information to determine if
the 17 partnerships and the power plant owner are variable interest entities 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 in FIN 46R,
paragraph 4(g), 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 entities 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.




PEC also
has interests in several other variable interest entities for which PEC is not
the primary beneficiary. These arrangements include equity investments in 18
entities whose operations include affordable housing, venture capital
investments, research and development, or real estate activities and two
building leases with special-purpose entities. The majority of the arrangements
were entered into prior to 2003. At June 30, 2008, the aggregate maximum loss
exposure that PEC could be required to record on its statement of income as a
result of these arrangements was $18 million, which primarily represents its net
remaining investment in these entities. The




22




creditors
of these variable interest entities do not have recourse to the general credit
of PEC in excess of the aggregate maximum loss exposure.




PEF




PEF has
interests in four variable interest entities for which PEF is not the primary
beneficiary. These arrangements include equity investments in two entities whose
operations include venture capital investments or research and development
activities and one building lease and one railcar lease with special-purpose
entities. All interests were entered into prior to 2008. At June 30, 2008, the
aggregate maximum loss exposure that PEF could be required to record in its
statement of income as a result of these arrangements was $56 million. The
majority of this exposure is related to a prepayment clause in a building
capital lease, of which $3 million had been prepaid at June 30, 2008. The
creditors of these variable interest entities do not have recourse to the
general credit of PEF in excess of the aggregate maximum loss
exposure.




2.
            NEW ACCOUNTING
      STANDARDS




Fair
Value Measurements - Adoption of FASB Statements Nos. 157 and 159




Refer to
Note 7 for information regarding our first quarter 2008 implementation of SFAS
No. 157, “Fair Value Measurements” (SFAS No. 157).




In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB
Statement No. 115” (SFAS No. 159), which permits entities to choose to measure
many financial instruments and certain other items at fair value that are not
currently required to be measured at fair value. The decision about whether to
elect the fair value option is applied on an instrument by instrument basis, is
irrevocable (unless a new election date occurs) and is applied to the entire
financial instrument. SFAS No. 159 was effective for us and the Utilities on
January 1, 2008. We and the Utilities did not elect to adopt the fair value
option for any financial instruments.




FASB
Staff Position No. 39-1, An Amendment of FIN 39, Offsetting of Amounts Related
to Certain Contracts




FASB
Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (FIN
39), specifies what conditions must be met for an entity to have the right to
offset assets and liabilities in the balance sheet and clarifies when it is
appropriate to offset amounts recognized for forward, interest rate swap,
currency swap, option, and other conditional or exchange contracts. FIN 39 also
permits offsetting of fair value amounts recognized for multiple contracts
executed with the same counterparty under a master netting arrangement. On April
30, 2007, the FASB issued FASB Staff Position (FSP) No. FIN 39-1, “An Amendment
of FIN 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1),
which amended portions of FIN 39 to make certain terms consistent with those
used in SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (SFAS No. 133). FSP FIN 39-1 also amends FIN 39 to allow for the
offsetting of fair value amounts for the right to reclaim collateral assets or
liabilities arising from the same master netting arrangement as the derivative
instruments. We implemented the FSP as of January 1, 2008, as a retrospective
change in accounting principle for all financial statements presented. We and
the Utilities previously offset fair value amounts recognized for derivative
instruments under master netting arrangements. As allowed under FSP FIN 39-1, we
and the Utilities changed our accounting policy effective January 1, 2008, and
discontinued the offset of fair value amounts for such derivatives. The change
had no impact on our or the Utilities’ results of operations or equity and
resulted in increases in previously-reported December 31, 2007 assets and
liabilities, as follows:


(in
      millions)
              
              Progress
      Energy
              
              
              PEC
              
              
              PEFCurrent
      assets
              
              $
              54
              
              
              $
              19
              
              
              $
              35Noncurrent
      assets
              
              
              25
              
              
              
              1
              
              
              
              24Current
      liabilities
              
              
              54
              
              
              
              19
              
              
              
              35Noncurrent
      liabilities
              
              
              25
              
              
              
              1
              
              
              
              24


23


FASB
Statement No. 161, Disclosures About Derivative Instruments and Hedging
Activities — an amendment of FASB Statement No. 133




In March
2008, the FASB issued SFAS 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 SFAS No. 133, and how derivative
instruments and related hedged items affect an entity’s financial position,
financial performance, and cash flows. SFAS No. 161 requires significant
quantitative disclosures to be presented in a tabular format, including
disclosures of the location, by line item, of fair value amounts of derivative
instruments in the balance sheet and the location, by line item, of amounts of
derivative gains and losses reported in the income statement. SFAS No. 161 also
requires entities to disclose information regarding the existence and nature of
credit-risk-related contingent features included in derivative instruments that
require the instrument to be settled or collateral posted in the event of a
credit downgrade. SFAS No. 161 is effective for us and the Utilities on January
1, 2009. The adoption of SFAS No. 161 will change certain disclosures in the
notes to the financial statements, but will have no impact on our or the
Utilities' financial position or results of operations.





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 have been restated for all periods presented
to 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 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 have been
restated for all periods presented to reflect the abandoned operations of our
synthetic fuels businesses as discontinued operations.





In
addition, as discussed in Note 1B, the recognition of tax credits generated by
the production and sale of synthetic fuels historically resulted in significant
fluctuations in our effective tax rate for interim periods. Pursuant to the
intraperiod tax allocation rules of SFAS No. 109, $32 million and $22 million of
tax levelization expense, which is primarily related to the recognition of
synthetic fuels tax credits, is included in the discontinued operations income
tax benefit for the three and six months ended June 30, 2007,
respectively.





Results
of Terminals and the synthetic fuels businesses discontinued operations for the
three and six months ended June 30 were as follows:


Three
      Months Ended June 30,
            
            
            Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Revenues
            
            $
            –
            
            
            $
            276
            
            
            $
            17
            
            
            $
            538(Loss)
      earnings before income tax and minority interest
            
            
            –
            
            
            
            (73
            )
            
            
            11
            
            
            
            (58
            )Income
      tax benefit
            
            
            8
            
            
            
            39
            
            
            
            12
            
            
            
            93Minority
      interest portion of synthetic fuel losses (earnings)
            
            
            –
            
            
            
            27
            
            
            
            (1
            )
            
            
            29Net
      earnings (loss) from discontinued operations
            
            
            8
            
            
            
            (7
            )
            
            
            22
            
            
            
            64Gain
      on disposal of discontinued operations, including income tax expense of
      $7
            
            
            –
            
            
            
            –
            
            
            
            41
            
            
            
            –Earnings
      (loss) from discontinued operations
            
            $
            8
            
            
            $
            (7
            )
            
            $
            63
            
            
            $
            64




24




B.
            CCO
      – GEORGIA OPERATIONS




On March
9, 2007, our subsidiary, Progress Energy Ventures, Inc. (PVI), entered into a
series of transactions to sell or assign substantially all of its Competitive
Commercial Operations (CCO) physical and commercial assets and liabilities.
Assets divested include approximately 1,900 megawatts (MW) of gas-fired
generation assets in Georgia. The sale of the generation assets closed on June
11, 2007, for a net sales price of $615 million. We recorded an estimated loss
of $226 million in December 2006. Based on the terms of the final agreement,
during the three and six months ended June 30, 2007, we reversed $1 million and
$17 million, respectively, after-tax of the impairment recorded in
2006.




Additionally,
on June 1, 2007, PVI closed the transaction involving the assignment of a
contract portfolio consisting of full-requirements contracts with 16 Georgia
electric membership cooperatives (the Georgia Contracts), forward gas and power
contracts, gas transportation, structured power and other contracts to a third
party. This represents substantially all of our nonregulated energy marketing
and trading operations. As a result of the assignments, PVI made a net cash
payment of $347 million, which represents the net cost to assign the Georgia
Contracts and other related contracts. In the quarter ended June 30, 2007, we
recorded a charge associated with the costs to exit the Georgia Contracts, and
other related contracts, of $349 million after-tax (charge included in the net
loss from discontinued operations in the table below). We used the net proceeds
from these transactions for general corporate purposes.




The
accompanying consolidated financial statements reflect the operations of CCO as
discontinued operations. Interest expense has been allocated to discontinued
operations based on their respective net assets, assuming a uniform
debt-to-equity ratio across our operations. Pre-tax interest expense allocated
for the three and six months ended June 30, 2007, was $5 million and $11
million, respectively. We ceased recording depreciation upon classification of
the assets as discontinued operations in December 2006. Results of CCO
discontinued operations for the three and six months ended June 30 were as
follows:


Three
      Months Ended June 30,
            
            
            Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Revenues
            
            $
            –
            
            
            $
            154
            
            
            $
            –
            
            
            $
            406Loss
      before income tax
            
            
            (5
            )
            
            
            (513
            )
            
            
            (5
            )
            
            
            (443
            )Income
      tax benefit
            
            
            2
            
            
            
            191
            
            
            
            2
            
            
            
            164Net
      loss from discontinued operations
            
            
            (3
            )
            
            
            (322
            )
            
            
            (3
            )
            
            
            (279
            )Gain
      on disposal of discontinued operations, including income tax benefit of $5
      and $7, respectively
            
            
            –
            
            
            
            1
            
            
            
            –
            
            
            
            17Loss
      from discontinued operations
            
            $
            (3
            )
            
            $
            (321
            )
            
            $
            (3
            )
            
            $
            (262
            )





C.
            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 approximately 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.




25


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:


Three
      Months Ended June 30,
            
            
            Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Revenues
            
            $
            –
            
            
            $
            7
            
            
            $
            2
            
            
            $
            14Loss
      before income tax
            
            
            (2
            )
            
            
            (5
            )
            
            
            (6
            )
            
            
            (11
            )Income
      tax benefit
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            3Net
      loss from discontinued operations
            
            
            (1
            )
            
            
            (4
            )
            
            
            (4
            )
            
            
            (8
            )Gain
      on disposal of discontinued operations, including income tax expense of
      $2
            
            
            –
            
            
            
            –
            
            
            
            7
            
            
            
            –(Loss)
      earnings from discontinued operations
            
            $
            (1
            )
            
            $
            (4
            )
            
            $
            3
            
            
            $
            (8
            )





D.
            OTHER
      DIVERSIFIED BUSINESSES




Also
included in discontinued operations are amounts related to our sales of other
diversified businesses, primarily related to the sale of our natural gas
drilling and production business (Gas) and the sale of Progress Rail Services
Corporation (Progress Rail). These adjustments are mainly due to the
finalization of working capital adjustments and adjustments in connection with
guarantees and indemnifications provided by Progress Fuels and Progress Energy
for certain legal, tax and environmental matters (See Note 13B). The ultimate
resolution of these matters could result in additional adjustments in future
periods. For the three and six months ended June 30, 2008, we recorded
additional gains of $1 million and $2 million, respectively, net of tax. For
each of the three and six months ended June 30, 2007, we recorded additional
gains of $1 million, net of tax.





E.
            NET
      ASSETS OF DISCONTINUED OPERATIONS





At
December 31, 2007, the assets and liabilities of Terminals and the remaining
assets and liabilities of Coal Mining operations were included in net assets to
be divested. The major balance sheet classes included in assets and liabilities
to be divested in the Consolidated Balance Sheets were as follows:


(in
      millions)
            
            December
      31, 2007Inventory
            
            $
            6Other
      current assets
            
            
            2Total
      property, plant and equipment, net
            
            
            38Total
      other assets
            
            
            6Assets
      to be divested
            
            $
            52Accrued
      expenses
            
            $
            3Long-term
      liabilities
            
            
            5Liabilities
      to be divested
            
            $
            8





F.
            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 a final payment of $5
million during the three months ended March 31, 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.




26




During
the six months ended June 30, 2008, we recorded 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.





4.
            REGULATORY
      MATTERS




A.           PEC
RETAIL RATE MATTERS




BASE
RATES




PEC’s base rates are
subject to the regulatory jurisdiction of the NCUC and SCPSC. In June 2002, the
North Carolina Clean Smokestacks Act (Clean Smokestacks Act) was enacted in
North Carolina requiring the state's electric utilities to reduce the emissions
of nitrogen oxides (NOx) and sulfur dioxide (SO2) from their North Carolina
coal-fired power plants in  phases by 2013. The Clean Smokestacks Act froze
North Carolina electric utility  base rates for a five-year period, which
ended December 31, 2007, unless there were


extraordinary events
beyond the control of the utilities or unless the utilities persistently earned
a return substantially in excess of the rate of return established and found
reasonable by the NCUC in the respective utility’s last general rate case. There
were no adjustments to PEC’s base rates during the five-year period ended
December 31, 2007. Subsequent to 2007, PEC’s current North Carolina base rates
are continuing subject to traditional cost-based rate regulation.




During
the rate freeze period, the legislation provided for a minimum amortization and
recovery of 70 percent of the original estimated compliance costs of $813
million (or $569 million) while providing significant flexibility in the amount
of annual amortization recorded from none up to $174 million per year. On March
23, 2007, PEC filed a petition with the NCUC requesting that it be allowed to
amortize the remaining 30 percent (or $244 million) of the original estimated
compliance costs for the Clean Smokestacks Act during 2008 and 2009, with
discretion to amortize up to $174 million in either year. For the three months
ended June 30, 2008, PEC did not recognize any amortization. For the six months
ended June 30, 2008, PEC recognized amortization of $15 million. For the three
and six months ended June 30, 2007, PEC recognized amortization of $8 million
and $17 million, respectively. PEC has recognized $584 million in cumulative
amortization through June 30, 2008.




Additionally,
among other things, PEC requested in its March 23, 2007 petition that the NCUC
allow PEC to include in its rate base those eligible compliance costs exceeding
the original estimated compliance costs and that PEC be allowed to accrue
allowance for funds used during construction (AFUDC) on all eligible compliance
costs in excess of the original estimated compliance costs. PEC also requested
that any prudency review of PEC’s environmental compliance costs be deferred
until PEC’s next ratemaking proceeding in which PEC seeks to adjust its base
rates. On October 22, 2007, PEC filed with the NCUC a settlement agreement with
the NCUC Public Staff, the Carolina Utility Customers Association (CUCA) and the
Carolina Industrial Group for Fair Utility Rates II (CIGFUR) supporting PEC’s
proposal. The NCUC held a hearing on this matter on October 30, 2007. On
December 20, 2007, the NCUC approved the settlement agreement on a provisional
basis, with the NCUC indicating that it intended to initiate a review in 2009 to
consider all reasonable alternatives and proposals related to PEC’s recovery of
its Clean Smokestacks Act compliance costs in excess of the original estimated
costs of $813 million. Additionally, the NCUC ordered that no portion of Clean
Smokestacks Act compliance costs directly assigned, allocated or otherwise
attributable to another jurisdiction shall be recovered from PEC’s retail North
Carolina customers, even if recovery of these costs is disallowed or denied, in
whole or in part, in another jurisdiction.




On July
10, 2008, PEC filed a petition with the NCUC requesting that the NCUC reconsider
its order issued December 20, 2007, and terminate the requirement that PEC
amortize any Clean Smokestacks Act compliance costs in excess of $569 million,
and instead allow PEC to place into rate base all capital costs associated with
its compliance with the Clean Smokestacks Act in excess of $569 million. The
NCUC Public Staff, CUCA, CIGFUR and the North Carolina Attorney General have
advised PEC that they do not object to the relief PEC is requesting in the filed
petition. On July 18, 2008, the NCUC requested that all parties file a response
to PEC’s petition by August 1, 2008. The NCUC further established that PEC may
file reply comments to the initial comments by August 8, 2008, or, if there is
no opposition to the petition, the parties shall file a joint proposed order for
consideration by the NCUC by August 8, 2008. If the NCUC approves PEC’s
petition, PEC would not be required to amortize $244




27




million
of the original estimated compliance costs for the Clean Smokestacks Act during
2008 and 2009, but would record depreciation over the useful life of the assets.
However, we cannot predict the outcome of these matters.




See Note
12B for additional information about the Clean Smokestacks Act.




FUEL
COST RECOVERY




On April
30, 2008, PEC filed with the SCPSC for an increase in the fuel rate charged to
its South Carolina ratepayers. PEC asked the SCPSC to approve a $39 million
increase in fuel rates for under-recovered fuel costs associated with prior year
settlements and to meet future expected fuel costs. On June 26, 2008, the SCPSC
approved PEC’s request. Effective July 1, 2008, residential electric bills
increased by $5.86 per 1,000 kilowatt-hours (kWh), or 6.1 percent, for fuel cost
recovery.




On June
6, 2008, PEC filed with the NCUC for an increase in the fuel rate charged to its
North Carolina ratepayers. PEC asked the NCUC to approve a $424 million increase
in fuel rates for under-recovered fuel costs associated with prior year
settlements and to meet future expected fuel costs. In addition, PEC asked the
NCUC for approval of demand-side management (DSM) and energy-efficiency and
North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (REPS)
clauses to recover the costs of these programs as further discussed below. If
the filings are approved, the increases would take effect on or about December
1, 2008, and would increase residential electric bills in total by $15.71 per
1,000 kWh, or 16.2 percent. A hearing on the fuel filing has been scheduled by
the NCUC for September 16, 2008. We cannot predict the outcome of this
matter.




OTHER
MATTERS




During
2007, the North Carolina legislature passed comprehensive energy legislation,
which became law on August 20, 2007. Among other provisions, the law allows the
utility to recover the costs of new DSM and energy-efficiency programs through
an annual DSM clause. The law allows PEC to capitalize those costs that are
intended to produce future benefits and authorizes the NCUC to approve other
forms of financial incentives to the utility for DSM and energy-efficiency
programs. DSM programs include, but are not limited to, any program or
initiative that shifts the timing of electricity use from peak to nonpeak
periods and includes load management, electricity system and operating controls,
direct load control, interruptible load and electric system equipment and
operating controls. Energy-efficiency programs help our customers reduce energy
use and reduce the emissions that contribute to global climate change. PEC has
begun implementing a series of DSM and energy-efficiency programs and, as of
June 30, 2008, has deferred $4 million of implementation and program costs for
future recovery. On April 29 and May 1, 2008, PEC filed for NCUC approval of a
total of five DSM and energy-efficiency programs, including the EnergyWiseTM and
distribution system demand response programs discussed below.




On April
29, 2008, PEC filed for approval by the NCUC of its EnergyWiseTM program, which
is a residential program that offers customers an incentive to permit PEC to
remotely adjust central air conditioning and heat pumps in PEC’s eastern control
area and electric resistance heating and water heaters in PEC’s western control
area in order to reduce peak demand. PEC’s goal for EnergyWiseTM is to have the
capability to reduce peak electricity demand by 200 MW by 2017.





Also on
April 29, 2008, PEC filed for NCUC approval of its distribution system demand
response program, which will provide additional capability for reducing and
shifting peak electricity demand. The program also will reduce the level of
natural electricity loss experienced over long distribution feeder lines,
thereby eliminating the need for additional power generation to compensate for
the line losses. PEC anticipates that the program will require an investment of
approximately $260 million over five years and is expected to reduce peak
electricity demand by 250 MW. This distribution system investment is part of
PEC’s broader “Smart Grid” strategy and is expected to provide a foundation for
additional initiatives, including enhanced system reliability (through faster
outage isolation and response) and new capabilities for incorporating renewable
energy resources and other distributed generation into PEC’s energy mix. Such
costs are expected to be recovered under the provisions of the North Carolina
comprehensive energy legislation. A hearing for the application for approval of
the proposed distribution system demand response program has been scheduled by
the NCUC for September 17, 2008.





We cannot
predict the outcome of the April 29 and May 1, 2008 filings or whether the
proposed programs will produce the expected operational and economic
results.




28




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. As a result, PEC has deferred
an immaterial amount of implementation and program costs for future recovery in
the South Carolina jurisdiction. 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. We cannot predict the outcome of this matter.




On June
6, 2008, PEC filed an application with the NCUC for approval of a DSM and
energy-efficiency clause to recover the costs of these programs. If approved,
the increase would take effect on or about December 1, 2008, and would increase
customer electric bills by $1.96 per 1,000 kWh, or 2.0 percent. A hearing on the
matter has been scheduled by the NCUC for September 17, 2008. We cannot predict
the outcome of this matter.




On
February 29, 2008, the NCUC issued an order adopting final rules for
implementing North Carolina’s comprehensive energy legislation. These rules
provide filing requirements associated with the legislation. The order requires
PEC to submit its first annual REPS compliance plan by September 1, 2008, as
part of its integrated resource plan. Under the new rules, beginning in 2009,
PEC will also be required to file an annual REPS compliance report demonstrating
the actions it has taken to comply with the REPS requirement. The rules measure
compliance with the REPS requirement via renewable energy certificates (REC)
earned after January 1, 2008. The NCUC will pursue a third-party REC tracking
system, but will not develop or require participation in a REC trading platform
at this time. 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 REPS clause will be set based on
projected costs with true-up provisions. On June 6, 2008, PEC filed an
application with the NCUC for approval of a REPS clause to recover the costs of
this program. If approved, the increase would take effect on or about December
1, 2008, and would increase customer electric bills by $0.46 per 1,000 kWh, or
0.5 percent. A hearing on the matter has been scheduled by the NCUC for
September 17, 2008. We cannot predict the outcome of this matter.





On April
30, 2008, PEC filed an Application for Certificate of Public Convenience and
Necessity with the NCUC to construct a 600-MW combined cycle dual fuel capable
generating facility at its Richmond County generation site. A hearing on this
matter has been scheduled by the NCUC for September 3, 2008. We cannot predict
the outcome of this matter.





On April
30, 2008, PEC submitted a revised Open Access Transmission Tariff (OATT)
filing, including a settlement agreement, with the FERC requesting an increase
in transmission rates. The purpose of the filing was to implement formula rates
for the PEC OATT in order to more accurately reflect the costs that PEC incurs
in providing transmission service. In the filing, PEC proposed to move from a
fixed revenue requirement to a formula rate, which allows for transmission rates
to be updated each year based on the prior year’s actual costs. Settlement
discussions were held with major customers prior to the filing and a settlement
agreement was reached on all issues. The settlement proposed a formula rate with
a rate of return on equity of 10.8 percent as well as recovery of the wholesale
portion of the terminated GridSouth Transco, LLC (GridSouth) project startup
costs over five years. On June 27, 2008, the FERC approved the settlement. The
new rates were effective July 1, 2008, and PEC estimates the impact of the new
rates will increase 2008 revenues by $6 million to $8 million.





In 2000,
the FERC issued Order 2000, which set minimum characteristics and functions that
regional transmission organizations (RTOs) must meet, including independent
transmission service. In October 2000, as a result of Order 2000, PEC, along
with Duke Energy Corporation and South Carolina Electric & Gas Company,
filed an application with the FERC for approval of an RTO, GridSouth. In July
2001, the FERC issued an order provisionally approving GridSouth. However, in
July 2001, the FERC issued orders recommending that companies in the
southeastern United States engage in mediation to develop a plan for a single
RTO. PEC participated in the mediation; no consensus was reached on creating a
southeast RTO. On August 11, 2005, the GridSouth participants notified the FERC
that they had terminated the GridSouth project. By order issued October 20,
2005, the FERC terminated the GridSouth proceeding.




29




On
November 16, 2007, PEC petitioned the NCUC to allow it to establish a regulatory
asset for PEC’s development costs of GridSouth pending disposition in a general
rate proceeding. On January 14, 2008, the NCUC issued an order requesting
interested parties to file comments regarding PEC’s petition on or before
January 28, 2008. On February 11, 2008, PEC filed response comments. On December
20, 2007, the NCUC issued an order for one of the other GridSouth partners. As
part of that order, the NCUC ruled that the utility’s GridSouth development
costs should be amortized and recovered over a 10-year period beginning June
2002. On June 4, 2008, the NCUC issued an order granting PEC the same accounting
treatment to its GridSouth development costs. In accordance with the OATT
settlement discussed above, in July 2008, PEC began amortization and recovery of
the wholesale portion of PEC’s GridSouth development costs over a five-year
period. PEC estimates the impact of this amortization to be $1 million in 2008
and $2 million annually during the remaining amortization period. PEC’s recorded
investment in GridSouth totaled $21 million and $22 million at June 30, 2008 and
December 31, 2007, respectively.





The NCUC
and SCPSC approved proposals to accelerate cost recovery of PEC’s nuclear
generating assets beginning January 1, 2000, and continuing through 2009. The
aggregate minimum and maximum amounts of cost recovery are $530 million and $750
million, respectively, with flexibility in the amount of annual depreciation
recorded, from none to $150 million per year. Accelerated cost recovery of these
assets resulted in additional depreciation expense of $15 million for the three
and six months ended June 30, 2008. No additional depreciation expense from
accelerated cost recovery was recorded for the same periods in 2007. Through
June 30, 2008, PEC recorded total accelerated depreciation of $455 million, of
which $378 million was recorded for the North Carolina jurisdiction and $77
million was recorded for the South Carolina jurisdiction.




B.           PEF
RETAIL RATE MATTERS




PASS-THROUGH
CLAUSE COST RECOVERY




On August
10, 2006, Florida’s Office of Public Counsel (OPC) filed a petition with the
FPSC asking that the FPSC require PEF to refund to ratepayers $143 million, plus
interest, of alleged excessive past fuel recovery charges and SO2 allowance
costs during the period 1996 to 2005. The OPC subsequently revised its claim to
$135 million, plus interest. 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 July 31, 2007, the FPSC heard this matter. On October
10, 2007, the FPSC issued its order rejecting most of the OPC’s contentions.
However, the 4-1 majority found that PEF had not been prudent in purchasing a
portion of its coal requirements during the period from 2003 to 2005.
Accordingly, the FPSC ordered PEF to refund its ratepayers approximately $14
million, including interest, over a 12-month period beginning January 1, 2008.
For the year ended December 31, 2007, PEF recorded a pre-tax other operating
expense of $12 million, interest expense of $2 million and an associated $14
million regulatory liability included within PEF’s deferred fuel cost at
December 31, 2007. On October 25, 2007, the OPC requested the FPSC to reconsider
its October 10, 2007 order asserting that the FPSC erred in not ordering a
larger refund. PEF filed its opposition to the OPC’s request on November 1,
2007. On February 12, 2008, the FPSC denied the OPC’s request for
reconsideration. Neither PEF nor OPC filed an appeal to the Florida Supreme
Court of the FPSC’s October 10, 2007 order. 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. The OPC filed testimony in
support of its position to require PEF to refund at least $14 million for
alleged excessive fuel recovery charges for 2006 coal purchases. PEF believes
its coal procurement practices have been prudent. We anticipate that a hearing
will be held on the 2006 and 2007 coal purchases in 2009. We cannot predict the
outcome of this matter.




On May
30, 2008, PEF filed a petition with the FPSC requesting a mid-course correction
to its fuel cost recovery factors to recover an additional $213 million in 2008,
primarily due to rising fuel costs. In accordance with a FPSC order, investor
owned utilities must file a notice with the FPSC if the year-end projected over-
or under-recovery of fuel costs is expected to be greater than 10% of projected
fuel revenues. The mid-course correction would have resulted in a residential
fuel rate increase of $12.07 per 1,000 kWh for the period August through
December 2008. On  July 1, 2008, the FPSC approved recovery of the $213
million projected year-end under-recovery, but allowed PEF to  recover 50
percent in 2008 and 50 percent in 2009. Therefore, the increase in the fuel rate
for the period






30
 
  August
through December 2008 is $6.03 per 1,000 kWh. This increase is partially offset
by the expiration of PEF’s storm cost recovery surcharge of $3.61 per 1,000 kWh
effective August 2008. Consequently, beginning with the first billing
cycle in August and including gross receipts tax, residential electric bills
will increase by $2.48 per 1,000 kWh, or 2.29 percent.





On
September 22, 2006, PEF filed a petition with the FPSC for Determination of Need
to uprate Crystal River Unit No. 3 Nuclear Plant (CR3) and bid rule exemption.
The multi-stage uprate will increase CR3’s gross output by approximately 180 MW
by 2012. PEF received NRC approval for a license amendment and implemented the
first stage’s design modification on January 31, 2008, and will apply for the
required license amendment for the third stage’s design modification. The
petition filed with the FPSC included estimated project costs of approximately
$382 million. These cost estimates may continue to change depending upon the
results of more detailed engineering and development work and increased
material, labor and equipment costs. On February 8, 2007, the FPSC issued an
order approving the need certification petition and bid rule exemption. On
February 29, 2008, PEF filed a petition for recovery of costs incurred in 2007
and 2006 under Florida’s comprehensive energy legislation and the FPSC’s nuclear
cost-recovery rule based on the regulatory precedence established by a FPSC
order to an unaffiliated Florida utility for a nuclear uprate project. The FPSC
is expected to vote on this matter by October 2008. We cannot predict the
outcome of this matter.




On May 1,
2008, PEF filed with the FPSC for an increase in the capacity cost-recovery
charge of estimated costs incurred in 2008 and projected costs to be incurred in
2009 under the FPSC nuclear cost-recovery rule. PEF is asking the FPSC to
approve a $25 million increase in the capacity cost recovery revenue requirement
for costs associated with the CR3 uprate. If approved, the increase would take
effect with the first billing cycle for 2009 and would increase residential
electric bills by $0.70 per 1,000 kWh. After PEF’s completion of a transmission
study and additional engineering studies, the current project estimate of fully
loaded costs is $364 million. A hearing on the matter has been scheduled by the
FPSC for September 2008, and the FPSC is expected to vote on this matter by
October 2008. We cannot predict the outcome of this matter.




OTHER
MATTERS




On March
11, 2008, PEF filed a petition for an affirmative Determination of Need for its
proposed Levy Units 1 and 2 nuclear power plants, together with the associated
facilities, including transmission lines and substation facilities. Levy Units 1
and 2 are needed to maintain electric system reliability and integrity, fuel and
generating diversity and to continue to provide adequate electricity to its
ratepayers at a reasonable cost. Levy Units 1 and 2 will be advanced passive
light water nuclear reactors, each with a generating capacity of approximately
1,092 MW (summer rating). PEF proposes to place Levy Unit 1 in service by June
2016 and Levy Unit 2 in service by June 2017. The filed, non-binding project
cost estimate for Levy Units 1 and 2 is approximately $14 billion for generating
facilities and approximately $3 billion for associated transmission facilities.
The hearing was held on May 21-23, 2008, and the FPSC voted unanimously in favor
of the Determination of Need on July 15, 2008.




On March
11, 2008, PEF also filed a petition with the FPSC to open a discovery docket
regarding the actual and projected costs of the proposed Levy nuclear project.
PEF filed the petition to assist the FPSC in the timely and adequate review of
the project’s cost recoverable under the FPSC nuclear cost-recovery rule. On May
1, 2008, PEF filed a petition for recovery of both preconstruction and carrying
charges on construction costs incurred or anticipated to be incurred during 2008
and 2009. Additionally, the filing included site selection costs of $38 million.
Based on the affirmative vote by the FPSC on the Determination of Need for the
Levy nuclear project, PEF filed a petition on July 18, 2008, to recover all
prudently incurred costs under the FPSC nuclear cost-recovery rule. A decision
by the FPSC on PEF’s 2008 cost-recovery filing is expected by October 1, 2008.
We cannot predict the outcome of this matter.




31


5.
            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)
                
                2008
                
                
                2007
                
                
                2008
                
                
                2007Weighted-average
      common shares - basic
                
                
                260
                
                
                
                256
                
                
                
                259
                
                
                
                255Net
      effect of dilutive stock-based compensation plans
                
                
                –
                
                
                
                1
                
                
                
                1
                
                
                
                1Weighted-average
      shares – full dilutive
                
                
                260
                
                
                
                257
                
                
                
                260
                
                
                
                256


B.          COMPREHENSIVE
INCOME


Progress
      EnergyThree
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007Net
      income (loss)
            
            $
            205
            
            
            $
            (193
            )Other
      comprehensive incomeReclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $2)
            
            
            –
            
            
            
            3Change
      in unrecognized items for pension and other postretirement benefits (net
      of tax expense of $- and $-,
      respectively)
            
            
            1
            
            
            
            1Net
      unrealized gains on cash flow hedges (net of tax expense of $8 and $2,
      respectively)
            
            
            13
            
            
            
            2Other
      comprehensive income
            
            
            14
            
            
            
            6Comprehensive
      income (loss)
            
            $
            219
            
            
            $
            (187
            )





Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            414
            
            
            $
            82Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $1 and $2,
      respectively)
            
            
            1
            
            
            
            3Change
      in unrecognized items for pension and other postretirement benefits (net
      of tax expense of $- and $-,
      respectively)
            
            
            1
            
            
            
            2Net
      unrealized gains on cash flow hedges (net of tax expense of $2 and $2,
      respectively)
            
            
            4
            
            
            
            2Other
      (net of tax benefit of $3)
            
            
            –
            
            
            
            (2
            )Other
      comprehensive income
            
            
            6
            
            
            
            5Comprehensive
      income
            
            $
            420
            
            
            $
            87




32





PECThree
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            104
            
            
            $
            88Other
      comprehensive incomeNet
      unrealized gains on cash flow hedges (net of tax expense of
      $1)
            
            
            –
            
            
            
            2Other
      comprehensive income
            
            
            –
            
            
            
            2Comprehensive
      income
            
            $
            104
            
            
            $
            90





Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            227
            
            
            $
            212Other
      comprehensive (loss) incomeNet
      unrealized (losses) gains on cash flow hedges (net of tax benefit of $3
      and $-,
      respectively)
            
            
            (5
            )
            
            
            1Other
      (net of tax benefit of $1)
            
            
            –
            
            
            
            (4
            )Other
      comprehensive loss
            
            
            (5
            )
            
            
            (3
            )Comprehensive
      income
            
            $
            222
            
            
            $
            209





PEFThree
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            125
            
            
            $
            68Other
      comprehensive incomeNet
      unrealized gains on cash flow hedges (net of tax expense of $8 and $1,
      respectively)
            
            
            12
            
            
            
            2Other
      comprehensive income
            
            
            12
            
            
            
            2Comprehensive
      income
            
            $
            137
            
            
            $
            70





Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            192
            
            
            $
            129Other
      comprehensive incomeNet
      unrealized gains on cash flow hedges (net of tax expense of $5 and $1,
      respectively)
            
            
            8
            
            
            
            2Other
      comprehensive income
            
            
            8
            
            
            
            2Comprehensive
      income
            
            $
            200
            
            
            $
            131





C.           COMMON
STOCK




At
December 31, 2007, we had 500 million shares of common stock authorized under
our charter, of which approximately 260 million were outstanding. At December
31, 2007, we had approximately 50 million unissued shares of common stock
reserved, primarily to satisfy the requirements of our stock plans. In 2002, the
board of directors authorized meeting the requirements of the Progress Energy
401(k) Savings and Stock Ownership Plan (401(k)) and the Investor Plus Stock
Purchase Plan with original issue shares. For the three and six months ended
June 30, 2008, respectively, we issued approximately 0.5 million shares and 1.0
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. For the three and six months




33




ended
June 30, 2007, respectively, we issued approximately 1.2 million shares and 2.7
million shares of common stock resulting in approximately $57 million and $122
million in proceeds. Included in these amounts were approximately 0.3 million
shares and 0.5 million shares for proceeds of approximately $12 million and $23
million, respectively, to meet the requirements of the 401(k) Plan and the
Investor Plus Stock Purchase Plan.




6.
            DEBT AND CREDIT
      FACILITIES AND FINANCING
ACTIVITIES




Material
changes, if any, to Progress Energy’s, PEC’s and PEF’s debt and credit
facilities and financing activities since December 31, 2007, are described
below.




On
January 8, 2008, PEF’s shelf registration statement became effective with the
United States Securities and Exchange Commission (SEC). The registration
statement initially allowed PEF to issue up to $4 billion in first mortgage
bonds, debt securities and preferred stock in addition to $250 million of
previously registered but unsold securities.





On
February 1, 2008, PEF paid at maturity $80 million of its 6.875% First Mortgage
Bonds with available cash on hand and commercial paper borrowings.




On March
12, 2008, PEC and PEF amended their revolving credit agreements (RCA) with a
syndication of financial institutions to extend the termination date by one
year. The extensions were effective for both utilities on March 28, 2008. PEC’s
RCA is now scheduled to expire on June 28, 2011, and PEF’s RCA is now scheduled
to expire on March 28, 2011.




On March
13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due
2038. The proceeds were used to repay the maturity of PEC’s $300 million 6.65%
Medium-Term Notes, Series D, due April 1, 2008, and the remainder was placed in
temporary investments for general corporate use as needed.




On April
14, 2008, we amended our RCA with a syndication of financial institutions to
extend the termination date by one year. The extension was effective on May 3,
2008. Our RCA is now scheduled to expire on May 3, 2012.




On May
27, 2008, Progress Capital Holdings, Inc., one of our wholly owned subsidiaries,
paid at maturity its remaining outstanding debt of $45 million of 6.46%
Medium-Term Notes with available cash on hand.




On June
18, 2008, PEF issued $500 million of First Mortgage Bonds, 5.65% Series due 2018
and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038. A portion of
the proceeds was used to repay PEF’s utility money pool borrowings and the
remaining proceeds were placed in temporary investments for general corporate
use as needed. On July 14, 2008, PEF sent notice that it will redeem the entire
outstanding $450 million principal amount of its Series A Floating Rate Notes
due November 14, 2008 on August 14, 2008, at 100 percent of par plus accrued
interest. The redemption will be funded with a portion of the proceeds from the
June 18, 2008 debt issuance.




7.
            FAIR VALUE
      MEASUREMENTS




In
September 2006, the FASB issued SFAS No. 157, which defines fair value,
establishes a framework for measuring fair value under GAAP, and requires
enhanced disclosures about assets and liabilities carried at fair value. SFAS
No. 157 also establishes a fair value hierarchy that categorizes and prioritizes
the inputs that should be used to estimate fair value. In February 2008, the
FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which
delays for us the effective date of SFAS No. 157 until January 1, 2009, 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).




We
implemented SFAS No. 157 as of January 1, 2008, for all recurring financial
assets and liabilities. The adoption of SFAS No. 157 for recurring financial
assets and liabilities did not have a material impact on our or the Utilities'
financial position or results of operations. We utilized the deferral provision
of FSP No. FAS 157-2 for all nonrecurring nonfinancial assets and
liabilities within its scope. Major categories of our assets and liabilities to
which the deferral applies include reporting units and long-lived asset groups
measured at fair value for impairment purposes, asset retirement obligations
initially recognized at fair value, and nonfinancial liabilities for exit and
disposal costs and indemnifications initially measured at fair value. We do not
expect the January 1, 2009, adoption




34




of SFAS
No. 157 for nonrecurring nonfinancial assets and liabilities to have a material
impact on our or the Utilities' financial position or results of
operations.




SFAS No.
157 defines fair value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market
participants at the measurement date (i.e., an exit price). SFAS No. 157 permits
the use of a mid-market pricing convention (the mid-point price between bid and
ask prices) 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 readily observable, corroborated
by market data, or generally unobservable. SFAS No. 157 requires that valuation
techniques maximize the use of observable inputs and minimize the use of
unobservable inputs.




SFAS No.
157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value, and requires fair value measurements to be categorized based
on the observability of those inputs. The hierarchy gives the highest priority
to unadjusted quoted prices in active markets for identical assets or
liabilities (Level 1 inputs) and the lowest priority to unobservable inputs
(Level 3 inputs). The three levels of the fair value hierarchy defined by SFAS
No. 157 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. At each balance
sheet date, we perform an analysis of all instruments subject to SFAS No. 157
and include in Level 3 all of those whose fair value is based on significant
unobservable inputs.




35


The
following tables set forth by level within the fair value hierarchy our and the
Utilities’ financial assets and liabilities that were accounted for at fair
value on a recurring basis as of June 30, 2008. As required by SFAS No. 157,
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:Commodity
      derivatives
            
            $
            –
            
            
            $
            974
            
            
            $
            163
            
            
            $
            1,137Nuclear
      decommissioning trust funds
            
            
            786
            
            
            
            516
            
            
            
            –
            
            
            
            1,302Other
      marketable securities
            
            
            13
            
            
            
            44
            
            
            
            –
            
            
            
            57Total
      assets
            
            $
            799
            
            
            $
            1,534
            
            
            $
            163
            
            
            $
            2,496Liabilities:Commodity
      derivatives
            
            $
            –
            
            
            $
            (3
            )
            
            $
            –
            
            
            $
            (3
            )CVO
      derivatives
            
            
            –
            
            
            
            (36
            )
            
            
            –
            
            
            
            (36
            )Total
      liabilities
            
            $
            –
            
            
            $
            (39
            )
            
            $
            –
            
            
            $
            (39
            )





PEC(in
      millions)
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            TotalAssets:Commodity
      derivatives
            
            $
            –
            
            
            $
            119
            
            
            $
            36
            
            
            $
            155Nuclear
      decommissioning trust funds
            
            
            454
            
            
            
            313
            
            
            
            –
            
            
            
            767Other
      marketable securities
            
            
            6
            
            
            
            –
            
            
            
            –
            
            
            
            6Total
      assets
            
            $
            460
            
            
            $
            432
            
            
            $
            36
            
            
            $
            928





PEF(in
      millions)
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            TotalAssets:Commodity
      derivatives
            
            $
            –
            
            
            $
            855
            
            
            $
            127
            
            
            $
            982Nuclear
      decommissioning trust funds
            
            
            332
            
            
            
            203
            
            
            
            –
            
            
            
            535Other
      marketable securities
            
            
            2
            
            
            
            –
            
            
            
            –
            
            
            
            2Total
      assets
            
            $
            334
            
            
            $
            1,058
            
            
            $
            127
            
            
            $
            1,519Liabilities:Commodity
      derivatives
            
            $
            –
            
            
            $
            (3
            )
            
            $
            –
            
            
            $
            (3
            )





The
determination of the fair values above incorporates various factors required
under SFAS No. 157, 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
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 9 for
discussion of risk management activities and derivative
transactions.




36




Nuclear
decommissioning trust funds reflect the assets of the Utilities’ nuclear
decommissioning trusts, as discussed in Note 13 of the 2007 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.




We issued
Contingent Value Obligations (CVOs) in connection with the acquisition of
Florida Progress Corporation (Florida Progress), as discussed in Note 15 in the
2007 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, 2008.


Progress
      EnergyThree
      Months Ended
            
            
            Six
      Months Ended(in
      millions)
            
            June
      30, 2008
            
            
            June
      30, 2008Derivatives,
      net at beginning of period
            
            $
            55
            
            
            $
            26Total
      gains (losses), realized and unrealized:Included
      in earnings
            
            
            –
            
            
            
            –Included
      in other comprehensive income
            
            
            –
            
            
            
            –Deferred
      as regulatory assets and liabilities, net
            
            
            108
            
            
            
            137Purchases,
      issuances and settlements, net
            
            
            –
            
            
            
            –Transfers
      in (out) of Level 3, net
            
            
            –
            
            
            
            –Derivatives,
      net at end of period
            
            $
            163
            
            
            $
            163





PECThree
      Months Ended
            
            
            Six
      Months Ended(in
      millions)
            
            June
      30, 2008
            
            
            June
      30, 2008Derivatives,
      net at beginning of period
            
            $
            12
            
            
            $
            6Total
      gains (losses), realized and unrealized:Included
      in earnings
            
            
            –
            
            
            
            –Included
      in other comprehensive income
            
            
            –
            
            
            
            –Deferred
      as regulatory assets and liabilities, net
            
            
            24
            
            
            
            30Purchases,
      issuances and settlements, net
            
            
            –
            
            
            
            –Transfers
      in (out) of Level 3, net
            
            
            –
            
            
            
            –Derivatives,
      net at end of period
            
            $
            36
            
            
            $
            36





PEFThree
      Months Ended
            
            
            Six
      Months Ended(in
      millions)
            
            June
      30, 2008
            
            
            June
      30, 2008Derivatives,
      net at beginning of period
            
            $
            43
            
            
            $
            20Total
      gains (losses), realized and unrealized:Included
      in earnings
            
            
            –
            
            
            
            –Included
      in other comprehensive income
            
            
            –
            
            
            
            –Deferred
      as regulatory assets and liabilities, net
            
            
            84
            
            
            
            107Purchases,
      issuances and settlements, net
            
            
            –
            
            
            
            –Transfers
      in (out) of Level 3, net
            
            
            –
            
            
            
            –Derivatives,
      net at end of period
            
            $
            127
            
            
            $
            127





Unrealized
gains and losses on derivatives are deferred as regulatory liabilities or assets
consistent with ratemaking treatment.





37




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 three and six
months ended June 30, 2008.





8.
            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)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            12
            
            
            $
            11
            
            
            $
            2
            
            
            $
            2Interest
      cost
            
            
            31
            
            
            
            30
            
            
            
            8
            
            
            
            9Expected
      return on plan assets
            
            
            (41
            )
            
            
            (39
            )
            
            
            (2
            )
            
            
            (1
            )Amortization
      of actuarial loss (a)
            
            
            3
            
            
            
            4
            
            
            
            1
            
            
            
            1Other
      amortization, net (a)
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Net
      periodic cost
            
            $
            5
            
            
            $
            6
            
            
            $
            10
            
            
            $
            12





Pension
      Benefits
            
            
            Other
      PostretirementBenefitsSix
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            24
            
            
            $
            22
            
            
            $
            4
            
            
            $
            4Interest
      cost
            
            
            62
            
            
            
            61
            
            
            
            16
            
            
            
            18Expected
      return on plan assets
            
            
            (82
            )
            
            
            (78
            )
            
            
            (3
            )
            
            
            (3
            )Amortization
      of actuarial loss (a)
            
            
            5
            
            
            
            7
            
            
            
            1
            
            
            
            3Other
      amortization, net (a)
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2Net
      periodic cost
            
            $
            10
            
            
            $
            13
            
            
            $
            20
            
            
            $
            24





(a)   
Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2007 Form
10-K.


38





PECPension
      Benefits
            
            
            Other
      PostretirementBenefitsThree
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            6
            
            
            $
            5
            
            
            $
            1
            
            
            $
            1Interest
      cost
            
            
            14
            
            
            
            14
            
            
            
            4
            
            
            
            5Expected
      return on plan assets
            
            
            (16
            )
            
            
            (15
            )
            
            
            (1
            )
            
            
            (1
            )Amortization
      of actuarial loss
            
            
            2
            
            
            
            3
            
            
            
            –
            
            
            
            1Net
      periodic cost
            
            $
            6
            
            
            $
            7
            
            
            $
            4
            
            
            $
            6





Pension
      Benefits
            
            
            Other
      PostretirementBenefitsSix
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            12
            
            
            $
            11
            
            
            $
            2
            
            
            $
            2Interest
      cost
            
            
            28
            
            
            
            27
            
            
            
            8
            
            
            
            9Expected
      return on plan assets
            
            
            (32
            )
            
            
            (30
            )
            
            
            (2
            )
            
            
            (2
            )Amortization
      of actuarial loss
            
            
            4
            
            
            
            5
            
            
            
            –
            
            
            
            2Other
      amortization, net
            
            
            1
            
            
            
            1
            
            
            
            1
            
            
            
            1Net
      periodic cost
            
            $
            13
            
            
            $
            14
            
            
            $
            9
            
            
            $
            12





PEFPension
      Benefits
            
            
            Other
      PostretirementBenefitsThree
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            4
            
            
            $
            4
            
            
            $
            1
            
            
            $
            1Interest
      cost
            
            
            13
            
            
            
            13
            
            
            
            3
            
            
            
            3Expected
      return on plan assets
            
            
            (21
            )
            
            
            (21
            )
            
            
            –
            
            
            
            –Other
      amortization, net
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Net
      periodic (benefit) cost
            
            $
            (4
            )
            
            $
            (4
            )
            
            $
            5
            
            
            $
            5





Pension
      Benefits
            
            
            Other
      PostretirementBenefitsSix
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            9
            
            
            $
            8
            
            
            $
            1
            
            
            $
            1Interest
      cost
            
            
            26
            
            
            
            25
            
            
            
            7
            
            
            
            7Expected
      return on plan assets
            
            
            (44
            )
            
            
            (42
            )
            
            
            (1
            )
            
            
            (1
            )Amortization
      of actuarial loss
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Other
      amortization, net
            
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            2Net
      periodic (benefit) cost
            
            $
            (9
            )
            
            $
            (9
            )
            
            $
            10
            
            
            $
            10




39


9.
            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 reviews using, among other things, 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.




As
discussed in Note 7, in connection with the acquisition of Florida Progress
during 2000, the Parent issued 98.6 million CVOs. The CVOs are derivatives and
are recorded at fair value. The unrealized loss/gain recognized due to changes
in fair value is recorded in other, net on the Consolidated Statements of
Income. At June 30, 2008 and December 31, 2007, the CVO liability included in
other liabilities and deferred credits on our Consolidated Balance Sheets was
$36 million and $34 million, respectively.




A.           COMMODITYDERIVATIVES




GENERAL




Most of
our physical commodity contracts are not derivatives pursuant to SFAS No. 133 or
qualify and are elected as normal purchases or sales pursuant to SFAS No. 133.
Therefore, such contracts are not recorded at fair value.




In 2003,
PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss
transition adjustment pursuant to the provisions of FASB Derivatives
Implementation Group Issue C20, “Interpretation of the Meaning of Not Clearly
and Closely Related in Paragraph 10(b) regarding Contracts with a Price
Adjustment Feature” (DIG Issue C20). The related liability is being amortized to
earnings over the term of the related contract (See Note 11). At June 30, 2008,
and December 31, 2007, the remaining liability was $9 million and $10 million,
respectively.




DISCONTINUED
OPERATIONS




In
January 2007, we entered into derivative contracts to hedge economically a
portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil
prices over an average annual oil price range of $63 to $77 per barrel on a New
York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price
hedge instruments was 25 million barrels and provided protection for the
equivalent of approximately eight million tons of 2007 synthetic fuels
production. The cost of the hedges was approximately $65 million. The contracts
were marked-to-market with changes in fair value recorded through earnings.
Approximately 34 percent of the notional quantity of these contracts was entered
into by Ceredo. As discussed in Notes 1C and 3F, we disposed of our 100 percent
ownership interest in Ceredo in March 2007. Progress Energy remains the primary
beneficiary of, and consolidates Ceredo in accordance with FIN 46R, with a 100
percent minority interest. Consequently, subsequent to the disposal there was no
net earnings impact from Ceredo’s operations, which ceased as of December 31,
2007. At December 31, 2007, the $234 million fair value of these contracts,
including $79 million at Ceredo, was included in receivables, net on the
Consolidated Balance Sheet. The contracts ended on December 31, 2007, and were
settled for cash on January 8, 2008, with no material impact to 2008 earnings.
For the three months ended June 30, 2007, we recorded net pre-tax losses of $14
million related to these contracts, including $5 million attributable to Ceredo,
which was attributed to minority interest for the portion of the loss subsequent
to disposal. For the six months ended June 30, 2007, we recorded net pre-tax
gains of $31 million related to these contracts, including $10 million
attributable to Ceredo, of which losses of $5 million were attributed to
minority interest for the portion of the loss subsequent to
disposal.




ECONOMIC
DERIVATIVES




Derivative
products, primarily electricity and natural gas 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. We manage open positions with
strict policies that limit our exposure to market risk and require daily
reporting to management of potential financial exposures.




40




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 on the
Balance Sheets, respectively, until the contracts are settled. Once settled, any
realized gains or losses are passed through the fuel clause. During the three
and six months ended June 30, 2008, PEC recorded a net realized gain of $6
million. During the three and six months ended June 30, 2007, PEC recorded a net
realized loss of less than $1 million. During the three and six months ended
June 30, 2008, PEF recorded a net realized gain of $103 million and $119
million, respectively. During the three and six months ended June 30, 2007, PEF
recorded a net realized loss of $5 million and $22 million,
respectively.




The
December 31, 2007 balances presented below reflect the retrospective adoption of
FSP FIN 39-1 (See Note 2).




At June
30, 2008, the fair value of PEC’s commodity derivative instruments was recorded
as a $42 million short-term derivative asset position included in prepayments
and other current assets and a $113 million long-term derivative asset position
included in derivative assets on the PEC Consolidated Balance Sheet. At December
31, 2007, the fair value of such instruments was recorded as a $4 million
short-term derivative liability included in other current liabilities and a $19
million long-term derivative asset position included in derivative assets on the
PEC Consolidated Balance Sheet. Certain counterparties have posted cash
collateral with PEC in support of these instruments. PEC had an $11 million cash
collateral liability at June 30, 2008, included in other current liabilities on
the PEC Consolidated Balance Sheet, and no cash collateral position at December
31, 2007. At June 30, 2008, $5 million of the cash collateral was restricted as
to usage and was included in prepayments and other current assets on the PEC
Consolidated Balance Sheet. Collateral received is returned when counterparty
collateral thresholds are no longer exceeded.




At June
30, 2008, the fair value of PEF’s commodity derivative instruments was recorded
as a $478 million short-term derivative asset position included in current
derivative assets, a $504 million long-term derivative asset position included
in derivative assets, a $2 million short-term liability position included in
derivative liabilities, and a $1 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet. At
December 31, 2007, the fair value of such instruments was recorded as an $83
million short-term derivative asset position included in current derivative
assets, a $100 million long-term derivative asset position included in
derivative assets, a $38 million short-term liability position included in
derivative liabilities, and a $9 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet.
Certain counterparties have posted cash collateral with PEF in support of these
instruments. PEF had a $409 million cash collateral liability at June 30, 2008,
included in derivative collateral liabilities on the PEF Balance Sheet, and no
cash collateral position at December 31, 2007. At June 30, 2008, $46 million of
the cash collateral was restricted as to usage and was included in prepayments
and other current assets on the PEF Balance Sheet. Collateral received is
returned when counterparty thresholds are no longer exceeded.




CASH
FLOW HEDGES




PEC
designates a portion of commodity derivative instruments as cash flow hedges
under SFAS No. 133. The objective for holding these instruments is to 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. At June 30, 2008, and December 31, 2007, 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, 2008 and
2007.




At June
30, 2008 and December 31, 2007, neither we nor the Utilities had amounts
recorded in accumulated other comprehensive income related to commodity cash
flow hedges.




B. INTEREST
RATE DERIVATIVES – FAIR VALUE OR CASHFLOW
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.




41




CASH
FLOW HEDGES




There
were no open interest rate hedges at June 30, 2008. The fair values of open
interest rate hedges at December 31, 2007, were as follows:


(in
      millions)
            
            Progress
              Energy
            
            
            PEC
            
            
            PEFFair
      value of liabilities
            
            $
            (12
            )
            
            $
            (12
            )
            
            $
            –





Gains and
losses from cash flow hedges are recorded in accumulated other comprehensive
income and amounts reclassified to earnings are included in net interest charges
as the hedged transactions occur. Amounts in accumulated other comprehensive
income related to terminated hedges are reclassified to earnings as the interest
expense is recorded. The ineffective portion of interest rate cash flow hedges
for the three and six months ended June 30, 2008 and 2007, was not material to
our or the Utilities’ results of operations.




The
following table presents selected information related to our interest rate cash
flow hedges included in accumulated other comprehensive income at June 30,
2008:


(term
      in years/millions of dollars)
            
            Progress
              Energy
            
            
            PEC
            
            
            PEFMaximum
      term
            
            
            –
            
            
            
            –
            
            
            
            –Accumulated
      other comprehensive loss, net of tax(a)
            
            $
            (18
            )
            
            $
            (14
            )
            
            $
            –Portion
      expected to be reclassified to earnings during the next12
      months(b)
            
            $
            (3
            )
            
            $
            (1
            )
            
            $
            –





(a)     Includes
amounts related to terminated hedges.


(b)
            Actual
      amounts that will be reclassified to earnings may vary from the expected
      amounts presented above as a result of changes in interest
      rates.





At
December 31, 2007, including amounts related to terminated hedges, we had $24
million of after-tax deferred losses, including $12 million of after-tax
deferred losses at PEC and $8 million of after-tax deferred losses at PEF,
recorded in accumulated other comprehensive income related to interest rate cash
flow hedges.




At
December 31, 2007, PEC had $200 million notional of interest rate cash flow
hedges. All of PEC’s forward starting swaps were terminated on March 13, 2008,
in conjunction with PEC’s issuance of $325 million of First Mortgage Bonds,
6.30% Series due 2038. The effective portion of the hedges is included in
accumulated other comprehensive income and will be amortized to interest expense
over the life of the related debt.




In
January 2008, PEF entered into a combined $200 million notional of forward
starting swaps to mitigate exposure to interest rate risk in anticipation of
future debt issuance. In May 2008, PEF entered into a combined $250 million
notional of forward starting swaps to mitigate exposure to interest rate risk in
anticipation of future debt issuance. In June 2008, PEF entered into a combined
$100 million notional of forward starting swaps to mitigate exposure to interest
rate risk in anticipation of future debt issuance. All of PEF’s forward starting
swaps were terminated on June 11, 2008, in conjunction with PEF’s issuance of
$500 million of First Mortgage Bonds, 5.65% Series due 2018 and $1.000 billion
of First Mortgage Bonds, 6.40% Series due 2038.




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, 2008, and December 31, 2007, we
and the Utilities had no open interest rate fair value hedges.




10.
            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.




42




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 disclosure
requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and
Related Information,” as a separate business segment. 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. For
comparative purposes, the prior year results have been restated to conform to
the current segment presentation. 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, 2008PEC
            
            $
            1,048
            
            
            $
            –
            
            
            $
            1,048
            
            
            $
            104
            
            
            $
            12,308PEF
            
            
            1,194
            
            
            
            –
            
            
            
            1,194
            
            
            
            125
            
            
            
            13,001Corporate
      and Other
            
            
            2
            
            
            
            94
            
            
            
            96
            
            
            
            (29
            )
            
            
            16,969Eliminations
            
            
            –
            
            
            
            (94
            )
            
            
            (94
            )
            
            
            –
            
            
            
            (12,986
            )Totals
            
            $
            2,244
            
            
            $
            –
            
            
            $
            2,244
            
            
            $
            200
            
            
            $
            29,292Three Months Ended
      June 30, 2007PEC
            
            $
            996
            
            
            $
            –
            
            
            $
            996
            
            
            $
            88PEF
            
            
            1,129
            
            
            
            –
            
            
            
            1,129
            
            
            
            68Corporate
      and Other
            
            
            4
            
            
            
            103
            
            
            
            107
            
            
            
            (18
            )Eliminations
            
            
            –
            
            
            
            (103
            )
            
            
            (103
            )
            
            
            –Totals
            
            $
            2,129
            
            
            $
            –
            
            
            $
            2,129
            
            
            $
            138





Income
      (Loss)Revenues
            
            
            From
      Continuing(in
      millions)
            
            Unaffiliated
            
            
            Intersegment
            
            
            Total
            
            
            Operations
            
            
            AssetsSix Months Ended June
      30, 2008PEC
            
            $
            2,116
            
            
            $
            –
            
            
            $
            2,116
            
            
            $
            226
            
            
            $
            12,308PEF
            
            
            2,190
            
            
            
            –
            
            
            
            2,190
            
            
            
            191
            
            
            
            13,001Corporate
      and Other
            
            
            4
            
            
            
            176
            
            
            
            180
            
            
            
            (68
            )
            
            
            16,969Eliminations
            
            
            –
            
            
            
            (176
            )
            
            
            (176
            )
            
            
            –
            
            
            
            (12,986
            )Totals
            
            $
            4,310
            
            
            $
            –
            
            
            $
            4,310
            
            
            $
            349
            
            
            $
            29,292Six Months Ended June
      30, 2007PEC
            
            $
            2,054
            
            
            $
            –
            
            
            $
            2,054
            
            
            $
            211PEF
            
            
            2,140
            
            
            
            –
            
            
            
            2,140
            
            
            
            128Corporate
      and Other
            
            
            7
            
            
            
            189
            
            
            
            196
            
            
            
            (52
            )Eliminations
            
            
            –
            
            
            
            (189
            )
            
            
            (189
            )
            
            
            –Totals
            
            $
            4,201
            
            
            $
            –
            
            
            $
            4,201
            
            
            $
            287





11.
            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. CVOs unrealized gain or loss is due to changes in fair
value. See Note 15 in the 2007 Form 10-K for more information on CVOs. AFUDC
equity represents the estimated equity costs of capital funds necessary to
finance the construction of new regulated assets.


43


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)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Other
      incomeNonregulated
      energy and delivery services income
            
            $
            15
            
            
            $
            13
            
            
            $
            22
            
            
            $
            22DIG
      Issue C20 amortization (see Note 9A)
            
            
            –
            
            
            
            1
            
            
            
            1
            
            
            
            2CVOs
      unrealized gain
            
            
            –
            
            
            
            –
            
            
            
            –
            
            
            
            1Investment
      gains
            
            
            3
            
            
            
            2
            
            
            
            4
            
            
            
            3Income
      from equity investments
            
            
            –
            
            
            
            –
            
            
            
            –
            
            
            
            2Derivative
      mark-to-market gain
            
            
            4
            
            
            
            –
            
            
            
            4
            
            
            
            –Other
            
            
            3
            
            
            
            3
            
            
            
            6
            
            
            
            7Total
      other income
            
            
            25
            
            
            
            19
            
            
            
            37
            
            
            
            37Other
      expenseNonregulated
      energy and delivery services expenses
            
            
            5
            
            
            
            5
            
            
            
            9
            
            
            
            12Donations
            
            
            7
            
            
            
            5
            
            
            
            11
            
            
            
            9Loss
      on sale of property
            
            
            –
            
            
            
            1
            
            
            
            –
            
            
            
            1Investment
      losses
            
            
            4
            
            
            
            –
            
            
            
            7
            
            
            
            –Loss
      from equity investments
            
            
            1
            
            
            
            –
            
            
            
            3
            
            
            
            1CVOs
      unrealized loss
            
            
            2
            
            
            
            4
            
            
            
            2
            
            
            
            4Other
            
            
            3
            
            
            
            6
            
            
            
            7
            
            
            
            11Total
      other expense
            
            
            22
            
            
            
            21
            
            
            
            39
            
            
            
            38Other,
      net
            
            $
            3
            
            
            $
            (2
            )
            
            $
            (2
            )
            
            $
            (1
            )





PECThree
      Months Ended
              June
      30,
            
            
            Six
      Months Ended
              June
      30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Other
      incomeNonregulated
      energy and delivery services income
            
            $
            9
            
            
            $
            7
            
            
            $
            12
            
            
            $
            9DIG
      Issue C20 amortization (see Note 9A)
            
            
            –
            
            
            
            1
            
            
            
            1
            
            
            
            2Investment
      gains
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Income
      from equity investments
            
            
            –
            
            
            
            –
            
            
            
            –
            
            
            
            2AFUDC
      equity
            
            
            5
            
            
            
            2
            
            
            
            10
            
            
            
            4Derivative
      mark-to-market gain
            
            
            4
            
            
            
            –
            
            
            
            4
            
            
            
            –Other
            
            
            3
            
            
            
            2
            
            
            
            5
            
            
            
            5Total
      other income
            
            
            21
            
            
            
            12
            
            
            
            33
            
            
            
            23Other
      expenseNonregulated
      energy and delivery services expenses
            
            
            2
            
            
            
            1
            
            
            
            3
            
            
            
            3Donations
            
            
            4
            
            
            
            3
            
            
            
            6
            
            
            
            5Investment
      losses
            
            
            3
            
            
            
            –
            
            
            
            3
            
            
            
            –Loss
      from equity investments
            
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            1Other
            
            
            1
            
            
            
            1
            
            
            
            4
            
            
            
            4Total
      other expense
            
            
            10
            
            
            
            5
            
            
            
            18
            
            
            
            13Other,
      net
            
            $
            11
            
            
            $
            7
            
            
            $
            15
            
            
            $
            10


44





PEFThree
      Months Ended
              June
      30,
            
            
            Six
      Months Ended
              June
      30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Other
      incomeNonregulated
      energy and delivery services income
            
            $
            6
            
            
            $
            6
            
            
            $
            10
            
            
            $
            13Investment
      gains
            
            
            1
            
            
            
            2
            
            
            
            1
            
            
            
            2Other
            
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            –Total
      other income
            
            
            7
            
            
            
            8
            
            
            
            13
            
            
            
            15Other
      expenseNonregulated
      energy and delivery services expenses
            
            
            3
            
            
            
            4
            
            
            
            6
            
            
            
            9Donations
            
            
            3
            
            
            
            2
            
            
            
            5
            
            
            
            4Investment
      losses
            
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            –Loss
      from equity investments
            
            
            1
            
            
            
            –
            
            
            
            1
            
            
            
            1Other
            
            
            –
            
            
            
            2
            
            
            
            –
            
            
            
            2Total
      other expense
            
            
            7
            
            
            
            8
            
            
            
            14
            
            
            
            16Other,
      net
            
            $
            –
            
            
            $
            –
            
            
            $
            (1
            )
            
            $
            (1
            )





12.
            ENVIRONMENTAL
      MATTERS




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




A.           HAZARDOUS
AND SOLID WASTE




The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the United States
Environmental Protection Agency (EPA) to require the cleanup of hazardous waste
sites. This statute imposes retroactive joint and several liabilities. Some
states, including North Carolina, South Carolina and Florida, have similar types
of statutes. We are periodically notified by regulators, including the EPA and
various state agencies, of our involvement or potential involvement in sites
that may require investigation and/or remediation. There are presently several
sites with respect to which we have been notified of our potential liability by
the EPA, the state of North Carolina, the state of Florida, or potentially
responsible party (PRP) groups as described below in greater detail. Various
organic materials associated with the production of manufactured gas, generally
referred to as coal tar, are regulated under federal and state laws. PEC and PEF
are each PRPs at several manufactured gas plant (MGP) sites. We are also
currently in the process of assessing potential costs and exposures at other
sites. These costs are eligible for regulatory recovery through either base
rates or cost-recovery clauses. 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 these potential claims cannot be
predicted. No material claims are currently pending. 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.




45




The
following table contains information about accruals for environmental
remediation expenses described below. Accruals for probable and estimable costs
related to various environmental sites, which were primarily included in other
liabilities and deferred credits on the Balance Sheets, were:


(in
      millions)
            
            June
      30, 2008
            
            
            December
      31, 2007PECMGP
      and other sites(a)
            
            $
            18
            
            
            $
            16PEFRemediation
      of distribution and substation transformers
            
            
            29
            
            
            
            31MGP
      and other sites
            
            
            16
            
            
            
            17Total
      PEF environmental remediation accruals(b)
            
            
            45
            
            
            
            48Total
      Progress Energy environmental remediation accruals
            
            $
            63
            
            
            $
            64





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


(b)
            Expected
      to be paid out over one to fifteen
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 Note
13B).




PEC




Including
the Ward Transformer site and MGP sites discussed below, for the three months
ended June 30, 2008, PEC accrued approximately $5 million, primarily related to
the Ward Transformer site, and spent approximately $2 million, and for the six
months ended June 30, 2008, PEC accrued approximately $6 million, primarily
related to the Ward Transformer site, and spent approximately $4 million.
Including the Ward Transformer site and MGP sites discussed below, for the three
months ended June 30, 2007, PEC accrued approximately $1 million, primarily
related to the Ward Transformer site, and spent approximately $1 million and for
the six months ended June 30, 2007, PEC reduced its accrual by approximately $4
million, primarily related to the Ward Transformer site, and spent approximately
$2 million. PEC defers and amortizes certain environmental remediation expenses
in accordance with orders received from the NCUC and SCPSC.




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.




During
the fourth quarter of 2004, the EPA advised PEC that it had been identified as a
PRP at the Ward Transformer site located in Raleigh, N.C. The EPA offered PEC
and a number of other PRPs the opportunity to negotiate cleanup of the site and
reimbursement to the EPA for the EPA’s past expenditures in addressing
conditions at the site. Subsequently, PEC and other PRPs signed a settlement
agreement, which requires the participating PRPs to remediate the site. During
2007, the PRP agreement was amended to include an additional participating PRP,
which reduced PEC’s proportionate responsibility for funding the remediation.
During 2008, PEC increased its accrual due to an increase in the estimated scope
of work. At June 30, 2008 and December 31, 2007, PEC’s recorded liability for
the site was approximately $9 million and $6 million, respectively. Actual
experience may differ from current estimates, and it is probable that estimates
will continue to change in the future. The outcome of this matter cannot be
predicted.




The EPA
has also proposed, but not yet selected, a final remedial action plan to address
stream segments downstream from the Ward Transformer site. The outcome of this
matter cannot be predicted.




46


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 the majority of
distribution transformer sites and all substation sites for mineral oil impacted
soil caused by equipment integrity issues. PEF currently expects to have
completed this review by the end of 2008. Should further sites be identified
outside of this population, the expenses will not be recoverable through the
ECRC. Based on historical experience, PEF projects costs will be between
approximately $2 million and $3 million per year. 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. For the
three and six months ended June 30, 2007, PEF accrued approximately $3 million
and $5 million, respectively, due to an increase in estimated remediation costs
and spent approximately $6 million and $11 million, respectively, related to the
remediation of transformers. At June 30, 2008, PEF had recorded a regulatory
asset for the probable recovery of these costs through the ECRC.




The
amounts for MGP and other sites, in the table above, relate to two former MGP
sites and other sites associated with PEF that have required or are anticipated
to require investigation and/or remediation. The amounts include approximately
$12 million in insurance claim settlement proceeds received in 2004, which are
restricted for use in addressing costs associated with environmental
liabilities. For the three and six months ended June 30, 2008, PEF made no
additional accruals and spent approximately $1 million. For the three and six
months ended June 30, 2007, PEF made no additional accruals or material
expenditures.




B.           AIR
AND WATER QUALITY






At June
30, 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 NOx SIP Call Rule under Section 110 of
the Clean Air Act (NOx SIP Call), the 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,
2008, cumulative environmental compliance capital expenditures to date with
regard to these environmental laws and regulations were $1.944 billion,
including $1.319 billion at PEC of which $14 million related to in-process CAIR
projects, and $625 million at PEF, which related entirely to in-process CAIR
projects. At December 31, 2007, cumulative environmental compliance capital
expenditures to date with regard to these environmental laws and regulations
were $1.567 billion, including $1.244 billion at PEC and $323 million at
PEF.




On July
11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C.
Court of Appeals) issued its decision in litigation challenging the EPA’s CAIR.
The decision vacated the CAIR and the related federal implementation plan in
their entirety. The decision vacating the CAIR will negate the EPA's
determination that implementation of the CAIR satisfies best available retrofit
technology (BART) for SO2 and NOx
for BART-affected units under the CAVR. As a result, for BART-affected units,
CAVR compliance will require consideration of SO2 and NOx
emissions in addition to particulate matter emissions. On February 8, 2008,
the D. C. Court of Appeals vacated the delisting determination and the CAMR. We
are currently evaluating the impact of these decisions.




The
Utilities are considering continuing construction of in-process CAIR projects.
We believe our historical costs related to CAIR compliance are prudent and will
be recoverable under base rates or applicable cost recovery clauses as the costs
were incurred in pursuit of compliance with a mandatory law or regulation.
Although the Utilities have not made a final determination whether to continue
the in-process CAIR projects or whether the schedule for these projects should
be modified, it is likely that they will be completed. In making this decision,
the Utilities will take into account the status of the projects, the probability
of regulatory changes to replace the vacated CAIR requirements and the need to
comply with environmental rules and regulations other than the
CAIR.




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. As a result of the decision to vacate the CAIR, the SO2 and




47




annual
NOx emission allowances markets have been very volatile andthe
market prices for emission allowances have declined. At June 30, 2008, PEC had
approximately $1 million in NOx seasonal emission allowances, which will be
utilized to comply with existing NOx SIP Call requirements, and approximately
$29 million in SO2 emission
allowances, which will be utilized to comply with existing Clean Air Act
requirements. PEC currently has no purchased CAIR seasonal or annual NOx
allowances in its emission inventory balances. In order to achieve compliance
with the requirements of the CAIR pursuant to its Integrated Clean Air
Compliance Plan, PEF needed to purchase CAIR seasonal and annual NOx allowances.
At June 30, 2008, PEF had approximately $59 million in annual NOx emission
allowance inventory, approximately $7 million in seasonal NOx emission allowance
inventory and approximately $18 million in SO2emission
allowance inventory. PEF believes the purchases of NOx emission allowances to
comply with the requirements of the CAIR were prudent and continues to expect to
recover the costs of these allowances through its ECRC. PEF’s SO2 emission
allowances will be utilized to comply with existing Clean Air Act
requirements.




As
discussed in Note 4A, 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 SO2removal
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, 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. At June 30, 2008 and December 31, 2007, the amount of the
liability was $20 million and $30 million, respectively, based upon the
respective estimates for the remaining Clean Smokestacks Act compliance costs.
During the three months ended June 30, 2008, PEC made no additional accruals and
spent approximately $5 million that exceeded the joint owner limit. During the
six months ended June 30, 2008, PEC made no additional accruals and spent
approximately $10 million that exceeded the joint owner limit. 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 July 10, 2008, PEC filed a
petition with the NCUC requesting that the NCUC reconsider the settlement
agreement provisionally approved on December 20, 2007, and allow PEC to place
into rate base all capital costs associated with PEC’s compliance with the Clean
Smokestacks Act in excess of $569 million, including eligible compliance costs
in excess of the joint owner’s share (See Note 4A).




13.
            COMMITMENTS AND
      CONTINGENCIES




Contingencies
and significant changes to the commitments discussed in Note 22 in the 2007 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 2007
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. The commitment amounts discussed below are estimates and
therefore, actual purchase amounts will likely differ. Additional commitments
for fuel and related transportation will be required to supply the Utilities’
future needs.




48


PROGRESS
ENERGY




Through
June 30, 2008, contracts procured through our subsidiaries have increased our
aggregate purchase obligations for fuel and purchased power by $9.214 billion
from $17.644 billion, as stated in Note 22A in the 2007 Form 10-K. This increase
is discussed under “PEC” and “PEF” below.




PEC




Through
June 30, 2008, PEC’s fuel and purchased power commitments increased by $5.697
billion from $5.078 billion, as stated in Note 22A in the 2007 Form 10-K. This
increase is primarily related to coal purchase commitments, of which
approximately $3.199 billion will be incurred through 2012, with the remainder
incurred through 2018. The increase in coal purchase commitments includes new
contracts along with the impact of price increases on certain existing contracts
that are market price indexed.




In June
2008, PEC entered into a conditional contract with an interstate pipeline for
firm pipeline transportation capacity to support PEC’s gas supply needs for the
period from May 2011 through April 2031. The estimated total cost to PEC
associated with this agreement is approximately $461 million. The transaction is
subject to several conditions precedent, including various state regulatory
approvals, the completion and commencement of operation of necessary related
interstate natural gas pipeline system expansions, and other contractual
provisions. Due to the conditions of this agreement, the estimated costs
associated with this agreement are not included in the increase in PEC’s fuel
and purchased power commitments discussed above.




PEF




Through
June 30, 2008, PEF’s fuel and purchased power commitments increased by $3.517
billion from $12.566 billion as stated in Note 22A in the 2007 Form 10-K.
Approximately $1.689 billion of this increase is due to coal purchase
commitments, of which approximately $588 million will be incurred through 2012,
with the remainder incurred through 2030. The increase in coal purchase
commitments includes new contracts along with the impact of price increases on
certain existing contracts that are market price indexed. Additionally,
approximately $1.398 billion of the increase is due to the impact of rising
natural gas prices under a long-term gas supply agreement that was entered into
in December 2004. Approximately $216 million of this increase will be incurred
through 2012, with the remainder incurred through 2027. Payments under this
agreement are based on a published market price index. Contractual obligations
under this contract are based on estimated future market prices.




In April
2008, PEF entered into a conditional contract with Florida Gas Transmission
Company, L.L.C. (FGT) for firm pipeline transportation capacity to support PEF’s
gas supply needs for the period from April 2011 through March 2036. The total
cost to PEF associated with this agreement is estimated to be approximately
$2.000 billion. The transaction is subject to several conditions precedent,
including various state regulatory approvals, the completion and commencement of
operation of necessary related interstate natural pipeline system expansions,
and other contractual provisions. In addition to the FGT contract, during the
second quarter of 2008, PEF entered into additional gas supply and
transportation arrangements for the period from 2010 through 2025 that are
subject to certain conditions. The total current notional cost of these
additional agreements is estimated to be approximately $1.390 billion. Due to
the conditions of these agreements, the estimated costs associated with these
agreements are not included in the increase in PEF’s fuel and purchased power
commitments discussed above.




B.           GUARANTEES






As a part
of normal business, we enter into various agreements providing future financial
or performance assurances to third parties, which are outside the scope of FASB
Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45).
Such agreements include guarantees, standby letters of credit and surety bonds.
At June 30, 2008, 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, 2008, 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, which
are within the scope of FIN 45. Related to the sales of businesses, the latest
specified notice period extends




49




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 12B). PEC’s
maximum exposure cannot be determined. At June 30, 2008, the 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, 2008
and December 31, 2007, we have recorded liabilities related to guarantees and
indemnifications to third parties of approximately $71 million and $80 million,
respectively. These amounts include $20 million and $30 million, respectively,
for PEC and $8 million for PEF at June 30, 2008, and December 31, 2007. During
the three months ended June 30, 2008, PEC made no additional accruals and spent
approximately $5 million that exceeded the joint owner limit. During the six
months ended June 30, 2008, PEC made no additional accruals and spent
approximately $10 million 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 14 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 damages claims as they incur additional
costs.





A trial
was held in November 2007, and closing arguments presented on April 4, 2008. On
May 19, 2008, the Utilities received a ruling from the United States Court of
Federal Claims awarding $83 million in the claim against the DOE for failure to
abide by a contract for federal disposition of spent nuclear fuel. 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. The Utilities anticipate the DOE will appeal. 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.




In July
2002, Congress passed an override resolution to Nevada’s veto of the DOE’s
proposal to locate a permanent underground nuclear waste storage facility at
Yucca Mountain, Nev. In January 2003, the state of Nevada; Clark County, Nev.;
and the city of Las Vegas petitioned the D.C. Court of Appeals for review of the
Congressional override resolution. These same parties also challenged the EPA’s
radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the
challenge to the constitutionality of the resolution approving Yucca Mountain,
but ruled that the EPA was wrong to set a 10,000-year compliance period in the
radiation protection standard. In August 2005, the EPA issued new proposed
standards. The proposed standards include a 1,000,000-year compliance period in
the radiation protection standard. Comments were due November 21, 2005, and are
being reviewed by the EPA. The DOE submitted the license application on June 4,
2008. Following a 90-day acceptance review by the NRC, the DOE believes the
license application will be docketed, thus beginning the formal licensing phase
that is anticipated to take three to four years.




50




On
October 19, 2007, the DOE certified the regulatory compliance of the document
database that will be used by all parties involved in the federal licensing
process for the Yucca Mountain facility. The NRC did not uphold the DOE’s prior
certification in 2004 in response to challenges from the state of Nevada. The
state again is expected to challenge the DOE’s certification process. The DOE
has recently stated that the earliest date the repository may be able to start
accepting spent nuclear fuel is 2020. The Utilities cannot predict the outcome
of this matter.




On August
5, 2008, the DOE announced that its estimated cost to build and commence
operations at the Yucca Mountain facility has increased from $57.5 billion
to $96.2 billion due to an increase in material costs, an increase in the
quantity of spent fuel to store and a refinement of the repository's design.




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, PEC’s Brunswick Nuclear Plant and CR3, the Utilities’ spent nuclear fuel
storage facilities will be sufficient to provide storage space for spent fuel
generated on their respective systems through the expiration of the operating
licenses, including any license extensions, for their nuclear generating units.
PEC’s Shearon Harris Nuclear Plant (Harris) has sufficient storage capacity in
its spent fuel pools through the expiration of its operating license, including
any license extensions.




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, by and among U.S. Global,
LLC (Global); the four Earthco coal-based solid synthetic fuels facilities
purchased by subsidiaries of Florida Progress in October 1999 (Earthco); certain
affiliates of Earthco; EFC Synfuel LLC (which is 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 (currently named Sandy
River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an
amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase
Agreement). Global has asserted (1) that pursuant to the Asset Purchase
Agreement, it is entitled to an interest in two synthetic fuels facilities
currently 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 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 case is at issue, but neither party has
requested a trial. The parties are currently engaged in discovery in the Florida
Global Case.




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.




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 as of December 31, 2006, was paid to
Global in January 2007.




51




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 April 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 in accordance with SFAS No.
5, “Accounting for Contingencies,” 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.





14.
            CONDENSED
      CONSOLIDATING STATEMENTS




As
discussed in Note 23 in the 2007 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 12B in the 2007 Form 10-K, there were no
restrictions on PEC’s or PEF’s retained earnings.




The Trust
is a special-purpose entity and was deconsolidated in 2003 in accordance with
the provisions of FIN 46R. The deconsolidation was not material to our financial
statements. 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
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 Other column includes the
consolidated financial results of all other non-guarantor subsidiaries,
primarily our wholly owned subsidiary PEC, 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. The accompanying
condensed consolidating financial statements have been restated for all periods
presented to reflect the operations of Terminals and the synthetic fuels
businesses as discontinued operations as described in Note 3A.


52





Condensed
      Consolidating Statement of Income
              Three
      months ended June 30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            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
            
            
            
            269
            
            
            
            488Depreciation
      and amortization
            
            
            –
            
            
            
            76
            
            
            
            132
            
            
            
            208Taxes
      other than on income
            
            
            –
            
            
            
            76
            
            
            
            49
            
            
            
            125Other
            
            
            –
            
            
            
            (4
            )
            
            
            (5
            )
            
            
            (9
            )Total
      operating expenses
            
            
            2
            
            
            
            996
            
            
            
            840
            
            
            
            1,838Operating
      (loss) income
            
            
            (2
            )
            
            
            200
            
            
            
            208
            
            
            
            406Other
      income, net
            
            
            –
            
            
            
            24
            
            
            
            11
            
            
            
            35Interest
      charges, net
            
            
            50
            
            
            
            46
            
            
            
            50
            
            
            
            146(Loss)
      income from continuing operations before income tax, equity in
              earnings
      of consolidatedsubsidiaries
      and minority interest
            
            
            (52
            )
            
            
            178
            
            
            
            169
            
            
            
            295Income
      tax (benefit) expense
            
            
            (22
            )
            
            
            53
            
            
            
            64
            
            
            
            95Equity
      in earnings of consolidated subsidiaries
            
            
            235
            
            
            
            –
            
            
            
            (235
            )
            
            
            –Income
      (loss) from continuing operations
            
            
            205
            
            
            
            125
            
            
            
            (130
            )
            
            
            200Discontinued
      operations, net of tax
            
            
            –
            
            
            
            7
            
            
            
            (2
            )
            
            
            5Net
      income (loss)
            
            $
            205
            
            
            $
            132
            
            
            $
            (132
            )
            
            $
            205





53





Condensed
      Consolidating Statement of Income
              Three
      months ended June 30, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            Other
            
            
            Progress
              Energy,
      Inc.Operating
      revenues
            
            $
            –
            
            
            $
            1,132
            
            
            $
            997
            
            
            $
            2,129Operating
      expensesFuel
      used in electric generation
            
            
            –
            
            
            
            411
            
            
            
            305
            
            
            
            716Purchased
      power
            
            
            –
            
            
            
            207
            
            
            
            76
            
            
            
            283Operation
      and maintenance
            
            
            2
            
            
            
            198
            
            
            
            261
            
            
            
            461Depreciation
      and amortization
            
            
            –
            
            
            
            101
            
            
            
            122
            
            
            
            223Taxes
      other than on income
            
            
            –
            
            
            
            76
            
            
            
            49
            
            
            
            125Other
            
            
            –
            
            
            
            15
            
            
            
            5
            
            
            
            20Total
      operating expenses
            
            
            2
            
            
            
            1,008
            
            
            
            818
            
            
            
            1,828Operating
      (loss) income
            
            
            (2
            )
            
            
            124
            
            
            
            179
            
            
            
            301Other
      income, net
            
            
            3
            
            
            
            6
            
            
            
            5
            
            
            
            14Interest
      charges, net
            
            
            50
            
            
            
            38
            
            
            
            47
            
            
            
            135(Loss)
      income from continuing operations before income tax, equity in
              earnings
      of consolidatedsubsidiaries
      and minority interest
            
            
            (49
            )
            
            
            92
            
            
            
            137
            
            
            
            180Income
      tax (benefit) expense
            
            
            (23
            )
            
            
            11
            
            
            
            53
            
            
            
            41Equity
      in earnings of consolidated subsidiaries
            
            
            (170
            )
            
            
            –
            
            
            
            170
            
            
            
            –Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (1
            )
            
            
            –
            
            
            
            (1
            )(Loss)
      income from continuing operations
            
            
            (196
            )
            
            
            80
            
            
            
            254
            
            
            
            138Discontinued
      operations, net of tax
            
            
            3
            
            
            
            3
            
            
            
            (337
            )
            
            
            (331
            )Net
      (loss) income
            
            $
            (193
            )
            
            $
            83
            
            
            $
            (83
            )
            
            $
            (193
            )





54





Condensed
      Consolidating Statement of Income
              Six
      months ended June 30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            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
            
            
            
            509
            
            
            
            931Depreciation
      and amortization
            
            
            –
            
            
            
            152
            
            
            
            262
            
            
            
            414Taxes
      other than on income
            
            
            –
            
            
            
            147
            
            
            
            99
            
            
            
            246Other
            
            
            –
            
            
            
            (2
            )
            
            
            (5
            )
            
            
            (7
            )Total
      operating expenses
            
            
            2
            
            
            
            1,872
            
            
            
            1,665
            
            
            
            3,539Operating
      (loss) income
            
            
            (2
            )
            
            
            322
            
            
            
            451
            
            
            
            771Other
      income, net
            
            
            4
            
            
            
            39
            
            
            
            17
            
            
            
            60Interest
      charges, net
            
            
            98
            
            
            
            97
            
            
            
            104
            
            
            
            299(Loss)
      income from continuing operations before income tax, equity in
              earnings
      of consolidated subsidiaries and minority interest
            
            
            (96
            )
            
            
            264
            
            
            
            364
            
            
            
            532Income
      tax (benefit) expense
            
            
            (40
            )
            
            
            80
            
            
            
            139
            
            
            
            179Equity
      in earnings of consolidated subsidiaries
            
            
            470
            
            
            
            –
            
            
            
            (470
            )
            
            
            –Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (4
            )
            
            
            –
            
            
            
            (4
            )Income
      (loss) from continuing operations
            
            
            414
            
            
            
            180
            
            
            
            (245
            )
            
            
            349Discontinued
      operations, net of tax
            
            
            –
            
            
            
            63
            
            
            
            2
            
            
            
            65Net
      income (loss)
            
            $
            414
            
            
            $
            243
            
            
            $
            (243
            )
            
            $
            414





55





Condensed
      Consolidating Statement of Income
              Six
      months ended June 30, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            Other
            
            
            Progress
              Energy,
      Inc.Operating
      revenues
            
            $
            –
            
            
            $
            2,146
            
            
            $
            2,055
            
            
            $
            4,201Operating
      expensesFuel
      used in electric generation
            
            
            –
            
            
            
            796
            
            
            
            656
            
            
            
            1,452Purchased
      power
            
            
            –
            
            
            
            370
            
            
            
            134
            
            
            
            504Operation
      and maintenance
            
            
            7
            
            
            
            373
            
            
            
            501
            
            
            
            881Depreciation
      and amortization
            
            
            –
            
            
            
            198
            
            
            
            244
            
            
            
            442Taxes
      other than on income
            
            
            –
            
            
            
            150
            
            
            
            99
            
            
            
            249Other
            
            
            –
            
            
            
            14
            
            
            
            7
            
            
            
            21Total
      operating expenses
            
            
            7
            
            
            
            1,901
            
            
            
            1,641
            
            
            
            3,549Operating
      (loss) income
            
            
            (7
            )
            
            
            245
            
            
            
            414
            
            
            
            652Other
      income, net
            
            
            9
            
            
            
            14
            
            
            
            10
            
            
            
            33Interest
      charges, net
            
            
            99
            
            
            
            82
            
            
            
            96
            
            
            
            277(Loss)
      income from continuing operations before income tax, equity in
              earnings
      of consolidated subsidiaries and minority interest
            
            
            (97
            )
            
            
            177
            
            
            
            328
            
            
            
            408Income
      tax (benefit) expense
            
            
            (43
            )
            
            
            36
            
            
            
            120
            
            
            
            113Equity
      in earnings of consolidated subsidiaries
            
            
            132
            
            
            
            –
            
            
            
            (132
            )
            
            
            –Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (8
            )
            
            
            –
            
            
            
            (8
            )Income
      from continuing operations
            
            
            78
            
            
            
            133
            
            
            
            76
            
            
            
            287Discontinued
      operations, net of tax
            
            
            4
            
            
            
            32
            
            
            
            (241
            )
            
            
            (205
            )Net
      income (loss)
            
            $
            82
            
            
            $
            165
            
            
            $
            (165
            )
            
            $
            82


56





Condensed
      Consolidating Balance Sheet
              June
      30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            Other
            
            
            Progress
              Energy,
      Inc.ASSETSUtility
      plant, net
            
            $
            –
            
            
            $
            8,352
            
            
            $
            9,149
            
            
            $
            17,501Current
      assetsCash
      and cash equivalents
            
            
            20
            
            
            
            1,383
            
            
            
            20
            
            
            
            1,423Receivables,
      net
            
            
            –
            
            
            
            420
            
            
            
            514
            
            
            
            934Notes
      receivable from affiliated companies
            
            
            28
            
            
            
            118
            
            
            
            (146
            )
            
            
            –Derivative
      assets
            
            
            –
            
            
            
            478
            
            
            
            42
            
            
            
            520Prepayments
      and other current assets
            
            
            24
            
            
            
            698
            
            
            
            883
            
            
            
            1,605Total
      current assets
            
            
            72
            
            
            
            3,097
            
            
            
            1,313
            
            
            
            4,482Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
            
            
            11,582
            
            
            
            –
            
            
            
            (11,582
            )
            
            
            –Goodwill
            
            
            –
            
            
            
            –
            
            
            
            3,655
            
            
            
            3,655Derivative
      assets
            
            
            –
            
            
            
            504
            
            
            
            113
            
            
            
            617Other
      assets and deferred debits
            
            
            154
            
            
            
            1,544
            
            
            
            1,339
            
            
            
            3,037Total
      deferred debits and other assets
            
            
            11,736
            
            
            
            2,048
            
            
            
            (6,475
            )
            
            
            7,309Total
      assets
            
            $
            11,808
            
            
            $
            13,497
            
            
            $
            3,987
            
            
            $
            29,292CAPITALIZATION
      AND LIABILITIESCapitalizationCommon
      stock equity
            
            $
            8,607
            
            
            $
            3,390
            
            
            $
            (3,390
            )
            
            $
            8,607Preferred
      stock of subsidiaries – not subject to mandatory
redemption
            
            
            –
            
            
            
            34
            
            
            
            59
            
            
            
            93Minority
      interest
            
            
            –
            
            
            
            2
            
            
            
            4
            
            
            
            6Long-term
      debt, affiliate
            
            
            –
            
            
            
            309
            
            
            
            (38
            )
            
            
            271Long-term
      debt, net
            
            
            2,597
            
            
            
            4,181
            
            
            
            3,108
            
            
            
            9,886Total
      capitalization
            
            
            11,204
            
            
            
            7,916
            
            
            
            (257
            )
            
            
            18,863Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            –
            
            
            
            450
            
            
            
            400
            
            
            
            850Short-term
      debt
            
            
            343
            
            
            
            –
            
            
            
            –
            
            
            
            343Accounts
      payable
            
            
            –
            
            
            
            676
            
            
            
            402
            
            
            
            1,078Notes
      payable to affiliated companies
            
            
            –
            
            
            
            171
            
            
            
            (171
            )
            
            
            –Derivative
      collateral liabilities
            
            
            –
            
            
            
            409
            
            
            
            11
            
            
            
            420Other
      current liabilities
            
            
            215
            
            
            
            615
            
            
            
            346
            
            
            
            1,176Total
      current liabilities
            
            
            558
            
            
            
            2,321
            
            
            
            988
            
            
            
            3,867Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            1
            
            
            
            39
            
            
            
            212
            
            
            
            252Regulatory
      liabilities
            
            
            –
            
            
            
            2,164
            
            
            
            1,336
            
            
            
            3,500Other
      liabilities and deferred credits
            
            
            45
            
            
            
            1,057
            
            
            
            1,708
            
            
            
            2,810Total
      deferred credits and other liabilities
            
            
            46
            
            
            
            3,260
            
            
            
            3,256
            
            
            
            6,562Total
      capitalization and liabilities
            
            $
            11,808
            
            
            $
            13,497
            
            
            $
            3,987
            
            
            $
            29,292




57





Condensed
      Consolidating Balance Sheet
              December
      31, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            Other
            
            
            Progress
              Energy,
      Inc.ASSETSUtility
      plant, net
            
            $
            –
            
            
            $
            7,600
            
            
            $
            9,005
            
            
            $
            16,605Current
      assetsCash
      and cash equivalents
            
            
            185
            
            
            
            43
            
            
            
            27
            
            
            
            255Receivables,
      net
            
            
            –
            
            
            
            574
            
            
            
            593
            
            
            
            1,167Notes
      receivable from affiliated companies
            
            
            157
            
            
            
            149
            
            
            
            (306
            )
            
            
            –Derivative
      assets
            
            
            –
            
            
            
            83
            
            
            
            2
            
            
            
            85Assets
      to be divested
            
            
            –
            
            
            
            48
            
            
            
            4
            
            
            
            52Prepayments
      and other current assets
            
            
            21
            
            
            
            595
            
            
            
            654
            
            
            
            1,270Total
      current assets
            
            
            363
            
            
            
            1,492
            
            
            
            974
            
            
            
            2,829Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
            
            
            10,969
            
            
            
            –
            
            
            
            (10,969
            )
            
            
            –Goodwill
            
            
            –
            
            
            
            1
            
            
            
            3,654
            
            
            
            3,655Derivative
      assets
            
            
            –
            
            
            
            100
            
            
            
            19
            
            
            
            119Other
      assets and deferred debits
            
            
            149
            
            
            
            1,475
            
            
            
            1,533
            
            
            
            3,157Total
      deferred debits and other assets
            
            
            11,118
            
            
            
            1,576
            
            
            
            (5,763
            )
            
            
            6,931Total
      assets
            
            $
            11,481
            
            
            $
            10,668
            
            
            $
            4,216
            
            
            $
            26,365CAPITALIZATION
      AND LIABILITIESCapitalizationCommon
      stock equity
            
            $
            8,422
            
            
            $
            3,052
            
            
            $
            (3,052
            )
            
            $
            8,422Preferred
      stock of subsidiaries – not subject to mandatory
redemption
            
            
            –
            
            
            
            34
            
            
            
            59
            
            
            
            93Minority
      interest
            
            
            –
            
            
            
            81
            
            
            
            3
            
            
            
            84Long-term
      debt, affiliate
            
            
            –
            
            
            
            309
            
            
            
            (38
            )
            
            
            271Long-term
      debt, net
            
            
            2,597
            
            
            
            2,686
            
            
            
            3,183
            
            
            
            8,466Total
      capitalization
            
            
            11,019
            
            
            
            6,162
            
            
            
            155
            
            
            
            17,336Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            –
            
            
            
            577
            
            
            
            300
            
            
            
            877Short-term
      debt
            
            
            201
            
            
            
            –
            
            
            
            –
            
            
            
            201Accounts
      payable
            
            
            –
            
            
            
            484
            
            
            
            335
            
            
            
            819Notes
      payable to affiliated companies
            
            
            –
            
            
            
            227
            
            
            
            (227
            )
            
            
            –Derivative
      collateral liabilities
            
            
            –
            
            
            
            38
            
            
            
            70
            
            
            
            108Liabilities
      to be divested
            
            
            –
            
            
            
            8
            
            
            
            –
            
            
            
            8Other
      current liabilities
            
            
            215
            
            
            
            715
            
            
            
            359
            
            
            
            1,289Total
      current liabilities
            
            
            416
            
            
            
            2,049
            
            
            
            837
            
            
            
            3,302Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            –
            
            
            
            59
            
            
            
            302
            
            
            
            361Regulatory
      liabilities
            
            
            –
            
            
            
            1,330
            
            
            
            1,224
            
            
            
            2,554Other
      liabilities and deferred credits
            
            
            46
            
            
            
            1,068
            
            
            
            1,698
            
            
            
            2,812Total
      deferred credits and other liabilities
            
            
            46
            
            
            
            2,457
            
            
            
            3,224
            
            
            
            5,727Total
      capitalization and liabilities
            
            $
            11,481
            
            
            $
            10,668
            
            
            $
            4,216
            
            
            $
            26,365





58





Condensed
      Consolidating Statement of Cash Flows
              Six
      months ended June 30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            Other
            
            
            Progress
              Energy,
      Inc.Net
      cash (used) provided by operating activities
            
            $
            (53
            )
            
            $
            856
            
            
            $
            554
            
            
            $
            1,357Investing
      activitiesGross
      property additions
            
            
            –
            
            
            
            (921
            )
            
            
            (339
            )
            
            
            (1,260
            )Nuclear
      fuel additions
            
            
            –
            
            
            
            (1
            )
            
            
            (42
            )
            
            
            (43
            )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
            
            
            –
            
            
            
            61
            
            
            
            3
            
            
            
            64Proceeds
      from sales of assets to affiliated companies
            
            
            –
            
            
            
            10
            
            
            
            (10
            )
            
            
            –Purchases
      of available-for-sale securities and other investments
            
            
            –
            
            
            
            (418
            )
            
            
            (418
            )
            
            
            (836
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            –
            
            
            
            418
            
            
            
            398
            
            
            
            816Contributions
      to consolidated subsidiaries
            
            
            (98
            )
            
            
            –
            
            
            
            98
            
            
            
            –Changes
      in advances to affiliates
            
            
            129
            
            
            
            31
            
            
            
            (160
            )
            
            
            –Other
      investing activities
            
            
            (7
            )
            
            
            13
            
            
            
            (21
            )
            
            
            (15
            )Net
      cash provided (used) by investing activities
            
            
            24
            
            
            
            (807
            )
            
            
            (491
            )
            
            
            (1,274
            )Financing
      activitiesIssuance
      of common stock
            
            
            42
            
            
            
            –
            
            
            
            –
            
            
            
            42Dividends
      paid on common stock
            
            
            (320
            )
            
            
            –
            
            
            
            –
            
            
            
            (320
            )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 minority interests of consolidated
      subsidiaries
            
            
            –
            
            
            
            (85
            )
            
            
            –
            
            
            
            (85
            )Contributions
      from parent
            
            
            –
            
            
            
            85
            
            
            
            (85
            )
            
            
            –Dividends
      paid to parent
            
            
            –
            
            
            
            (3
            )
            
            
            3
            
            
            
            –Changes
      in advances from affiliates
            
            
            –
            
            
            
            (56
            )
            
            
            56
            
            
            
            –Other
      financing activities
            
            
            –
            
            
            
            1
            
            
            
            (66
            )
            
            
            (65
            )Net
      cash (used) provided by financing activities
            
            
            (136
            )
            
            
            1,291
            
            
            
            (70
            )
            
            
            1,085Net
      (decrease) increase in cash and cash equivalents
            
            
            (165
            )
            
            
            1,340
            
            
            
            (7
            )
            
            
            1,168Cash
      and cash equivalents at beginning of period
            
            
            185
            
            
            
            43
            
            
            
            27
            
            
            
            255Cash
      and cash equivalents at end of period
            
            $
            20
            
            
            $
            1,383
            
            
            $
            20
            
            
            $
            1,423




59





Condensed
      Consolidating Statement of Cash Flows
              Six
      months ended June 30, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
              Guarantor
            
            
            Other
            
            
            Progress
              Energy,
      Inc.Net
      cash provided (used) by operating activities
            
            $
            38
            
            
            $
            205
            
            
            $
            (66
            )
            
            $
            177Investing
      activitiesGross
      property additions
            
            
            –
            
            
            
            (491
            )
            
            
            (408
            )
            
            
            (899
            )Nuclear
      fuel additions
            
            
            –
            
            
            
            (22
            )
            
            
            (75
            )
            
            
            (97
            )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
            
            
            –
            
            
            
            25
            
            
            
            621
            
            
            
            646Purchases
      of available-for-sale securities and other investments
            
            
            –
            
            
            
            (103
            )
            
            
            (279
            )
            
            
            (382
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            21
            
            
            
            103
            
            
            
            309
            
            
            
            433Changes
      in advances to affiliates
            
            
            (187
            )
            
            
            37
            
            
            
            150
            
            
            
            –Other
      investing activities
            
            
            (4
            )
            
            
            (9
            )
            
            
            5
            
            
            
            (8
            )Net
      cash (used) provided by investing activities
            
            
            (170
            )
            
            
            (460
            )
            
            
            323
            
            
            
            (307
            )Financing
      activitiesIssuance
      of common stock
            
            
            122
            
            
            
            –
            
            
            
            –
            
            
            
            122Dividends
      paid on common stock
            
            
            (311
            )
            
            
            –
            
            
            
            –
            
            
            
            (311
            )Net
      increase in short-term debt
            
            
            169
            
            
            
            –
            
            
            
            –
            
            
            
            169Retirement
      of long-term debt
            
            
            –
            
            
            
            (2
            )
            
            
            –
            
            
            
            (2
            )Cash
      distributions to minority interests of consolidated
      subsidiaries
            
            
            –
            
            
            
            (10
            )
            
            
            –
            
            
            
            (10
            )Dividends
      paid to parent
            
            
            –
            
            
            
            (10
            )
            
            
            10
            
            
            
            –Changes
      in advances from affiliates
            
            
            –
            
            
            
            233
            
            
            
            (233
            )
            
            
            –Other
      financing activities
            
            
            (1
            )
            
            
            32
            
            
            
            (48
            )
            
            
            (17
            )Net
      cash (used) provided by financing activities
            
            
            (21
            )
            
            
            243
            
            
            
            (271
            )
            
            
            (49
            )Net
      decrease in cash and cash equivalents
            
            
            (153
            )
            
            
            (12
            )
            
            
            (14
            )
            
            
            (179
            )Cash
      and cash equivalents at beginning of period
            
            
            153
            
            
            
            40
            
            
            
            72
            
            
            
            265Cash
      and cash equivalents at end of period
            
            $
            –
            
            
            $
            28
            
            
            $
            58
            
            
            $
            86




60


ITEM
2.MANAGEMENT’S DISCUSSION AND
ANALYSIS OF 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, 2007 (2007 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 2007 Form
10-K.




PROGRESS
ENERGY




RESULTS OF
OPERATIONS




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 separate business segment.




As
discussed more fully in Note 3 and “Results of Operations – Discontinued
Operations,” in accordance with our business strategy to reduce our business
risk and to focus on the core operations of the Utilities, the majority of our
nonregulated business operations have been divested. These operations have been
classified as discontinued operations in the accompanying financial statements.
Consequently, the composition of other continuing segments has been impacted by
these divestitures. For comparative purposes, prior year results have been
restated to conform to the current presentation. In this section, earnings and
the factors affecting earnings for the three and six months ended June 30, 2008,
are compared to the same periods in 2007. The discussion begins with a
summarized overview of our consolidated earnings, which is followed by a more
detailed discussion and analysis by business segment.




61


OVERVIEW




For the
quarter ended June 30, 2008, our net income was $205 million, or $0.79 per
share, compared to net loss of $193 million, or $0.75 per share, for the same
period in 2007. For the quarter ended June 30, 2008, our income from continuing
operations was $200 million compared to $138 million for the same period in
2007. The increase in income from continuing operations as compared to prior
year was primarily due to:




·
            favorable
      allowance for funds used during construction (AFUDC) at the
      Utilities;


·
            higher
      wholesale revenues at the
Utilities;


·
            favorable
      weather at PEF;


·
            increased
      retail rates at PEF;


·
            lower
      other operating expenses due to disallowed fuel costs in 2007 at
      PEF;


·
            favorable
      retail customer growth and usage at
PEC;


·
            increased
      gains from land sales at the Utilities;
and


·
            lower
      purchased power expense at PEC due to the expiration of a power buyback
      agreement.





Partially
offsetting these items were:




·
            higher
      income tax expense due to the benefit from the closure of certain federal
      tax years and positions in 2007;


·
            higher
      depreciation and amortization expense at the Utilities excluding prior
      year recoverable storm amortization at PEF;
and


·
            unfavorable
      retail customer growth and usage at
PEF.





For the
six months ended June 30, 2008, our net income was $414 million, or $1.60 per
share, compared to net income of $82 million, or $0.32 per share, for the same
period in 2007. For the six months ended June 30, 2008, our income from
continuing operations was $349 million compared to $287 million for the same
period in 2007. The increase in income from continuing operations as compared to
prior year was primarily due to:




·
            favorable
      AFUDC at the Utilities;


·
            higher
      wholesale revenues at PEF;


·
            increased
      retail rates at PEF;


·
            favorable
      retail customer growth and usage at
PEC;


·
            lower
      purchased power expense at PEC due to the expiration of a power buyback
      agreement;


·
            decreased
      legal expenses at Corporate and Other;
and


·
            favorable
      weather at PEF.





Partially
offsetting these items were:




·
            higher
      income tax expense due to the benefit from the closure of certain federal
      tax years and positions in 2007;


·
            higher
      depreciation and amortization expense at the Utilities excluding prior
      year recoverable storm amortization at
PEF;


·
            unfavorable
      retail customer growth and usage at PEF;
and


·
            unfavorable
      weather at PEC.




62


Our
segments contributed the following profits or losses for the three and six
months ended June 30, 2008 and 2007:


Three
      Months Ended June 30,
            
            
            Six
      Months Ended June 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Business
      SegmentPEC
            
            $
            104
            
            
            $
            88
            
            
            $
            226
            
            
            $
            211PEF
            
            
            125
            
            
            
            68
            
            
            
            191
            
            
            
            128Total
      segment profit
            
            
            229
            
            
            
            156
            
            
            
            417
            
            
            
            339Corporate
      and Other
            
            
            (29
            )
            
            
            (18
            )
            
            
            (68
            )
            
            
            (52
            )Income
      from continuing operations
            
            
            200
            
            
            
            138
            
            
            
            349
            
            
            
            287Discontinued
      operations, net of tax
            
            
            5
            
            
            
            (331
            )
            
            
            65
            
            
            
            (205
            )Net
      income (loss)
            
            $
            205
            
            
            $
            (193
            )
            
            $
            414
            
            
            $
            82





PROGRESS
ENERGY CAROLINAS




PEC
contributed segment profits of $104 million and $88 million for the three months
ended June 30, 2008 and 2007, respectively. The increase in profits for the
three months ended June 30, 2008, compared to the same period in 2007, was
primarily due to the favorable impact of retail customer growth and usage,
higher wholesale revenues, lower purchased power expense due to the expiration
of a power buyback agreement, favorable AFUDC and higher gains from land sales,
partially offset by higher depreciation and amortization.




PEC
contributed segment profits of $226 million and $211 million for the six months
ended June 30, 2008 and 2007, respectively. The increase in profits for the six
months ended June 30, 2008, compared to the same period in 2007, was primarily
due to the favorable impact of retail customer growth and usage and lower
purchased power expense due to the expiration of a power buyback agreement,
partially offset by higher depreciation and amortization.




The
revenue tables below present the total amount and percentage change of revenues
excluding fuel. Revenues excluding fuel is defined as total electric revenues
less fuel revenues. We and PEC consider revenues excluding fuel a useful measure
to evaluate PEC’s electric operations because fuel revenues primarily represent
the recovery of fuel and a portion of purchased power expenses through
cost-recovery clauses and, therefore, do not have a material impact on 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 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.




63


Three Months Ended June 30,
2008, Compared to Three Months Ended June 30, 2007




REVENUES




PEC’s
electric revenues for the three months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions)
            
            Three
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            334
            
            
            $
            7
            
            
            
            2.1
            
            
            $
            327Commercial
            
            
            269
            
            
            
            8
            
            
            
            3.1
            
            
            
            261Industrial
            
            
            187
            
            
            
            13
            
            
            
            7.5
            
            
            
            174Governmental
            
            
            23
            
            
            
            1
            
            
            
            4.5
            
            
            
            22Total
      retail revenues
            
            
            813
            
            
            
            29
            
            
            
            3.7
            
            
            
            784Wholesale
            
            
            189
            
            
            
            31
            
            
            
            19.6
            
            
            
            158Unbilled
            
            
            24
            
            
            
            (4
            )
            
            
            –
            
            
            
            28Miscellaneous
            
            
            22
            
            
            
            (4
            )
            
            
            (15.4
            )
            
            
            26Total
      electric revenues
            
            
            1,048
            
            
            
            52
            
            
            
            5.2
            
            
            
            996Less:
      Fuel revenues
            
            
            (379
            )
            
            
            (36
            )
            
            
            –
            
            
            
            (343
            )Revenues
      excluding fuel
            
            $
            669
            
            
            $
            16
            
            
            
            2.5
            
            
            $
            653





PEC’s
electric energy sales for the three months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions of kWh)
            
            Three
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            3,586
            
            
            
            11
            
            
            
            0.3
            
            
            
            3,575Commercial
            
            
            3,384
            
            
            
            37
            
            
            
            1.1
            
            
            
            3,347Industrial
            
            
            3,122
            
            
            
            136
            
            
            
            4.6
            
            
            
            2,986Governmental
            
            
            335
            
            
            
            3
            
            
            
            0.9
            
            
            
            332Total
      retail energy sales
            
            
            10,427
            
            
            
            187
            
            
            
            1.8
            
            
            
            10,240Wholesale
            
            
            3,441
            
            
            
            275
            
            
            
            8.7
            
            
            
            3,166Unbilled
            
            
            245
            
            
            
            (158
            )
            
            
            –
            
            
            
            403Total
      kWh sales
            
            
            14,113
            
            
            
            304
            
            
            
            2.2
            
            
            
            13,809





PEC’s
revenues, excluding fuel revenues of $379 million and $343 million for the three
months ended June 30, 2008 and 2007, respectively, increased $16 million. The
increase in revenues excluding fuel is primarily due to the $11 million
favorable impact of retail customer growth and usage and $9 million higher
wholesale revenues, partially offset by lower miscellaneous revenues of $4
million and the $1 million unfavorable impact of weather. Favorable retail
customer growth and usage was driven by a net 25,000 customer increase in PEC’s
averagenumber
of customers for the three months ended June 30, 2008, compared to the same
period in 2007, and by an increase in the average usage per retail customer. The
higher wholesale revenues are primarily due to increased energy rates and sales
with a major customer. Miscellaneous revenues decreased due to lower
electric property rental revenues.




The
decline in general economic conditions, including weakness in the housing
markets in both Florida and the United States, has contributed to a slowdown in
customer growth and usage in PEF’s service territory (See “Progress Energy
Florida – Revenues”).PEC has not been as
significantly impacted by the decline in general economic conditions as PEF.
However, PEC has experienced a slight decline in residential and commercial
sales growth.




64




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 $395 million for the three months ended June 30,
2008, which represents a $14 million increase compared to the same period in
2007. Fuel used in electric generation increased $18 million to $323 million
compared to the same period in 2007. The increase was primarily due to higher
fuel costs. Additionally, deferred fuel expense decreased $12 million due to the
implementation of the North Carolina comprehensive energy legislation (See
“Other Matters – Regulatory Environment”), which was offset by an increase in
deferred fuel of $12 million primarily due to a change in the collection of the
current year’s under-recovery in each respective period. Current year purchased
power costs were $4 million lower than the three months ended June 30, 2007,
primarily due to the $9 million impact from the expiration of a power buyback
agreement with North Carolina Eastern Municipal Power Agency (Power Agency).
This decrease in purchased power costs was partially offset by $6 million
increased purchases in the current year compared to lower purchases in 2007 due
to an outage that impacted a purchased power contract.




Operation and
Maintenance




Operation
and maintenance (O&M) expenses were $275 million for the three months ended
June 30, 2008, which represents a $7 million increase compared to the same
period in 2007. O&M expenses increased primarily due to a $21 million
increase in nuclear expenses, of which $16 million relates to refurbishments,
preventative maintenance and incremental outage expenses at Brunswick Nuclear
Plant (Brunswick), and an increase in estimated environmental remediation
expenses (See Note 12A) of $4 million, partially offset by outage expenses of
$18 million at Robinson Nuclear Plant (Robinson) in 2007.




Depreciation and
Amortization




Depreciation
and amortization expense was $129 million for the three months ended June 30,
2008, which represents an $11 million increase compared to the same period in
2007. Depreciation and amortization expense increased primarily due to $15
million additional depreciation associated with the accelerated cost-recovery
program for nuclear generating assets (See Note 4A) and the $4 million impact of
depreciable asset base increases, partially offset by $8 million lower Clean
Smokestacks Act amortization.




Other




Other
operating expenses consisted of gains of $5 million for the three months ended
June 30, 2008, primarily due to land sales. There were no gains from land sales
for the same period in 2007.




Total Other Income,
net




Total
other income, net of $13 million increased $1 million for the three months ended
June 30, 2008, compared to the same period in 2007, primarily due to $4 million
derivative mark-to-market gains and $3 million favorable AFUDC equity related to
costs associated with eligible construction projects. These increases were
offset by $4 million investment losses and $3 million lower interest income. The
derivative mark-to-market gains relate to commodity instruments that are not
subject to retail regulatory treatment. We expect AFUDC equity to continue to
increase for the remainder of 2008, primarily due to increased spending on
eligible construction projects.




Income Tax
Expense




Income
tax expense increased $13 million for the three months ended June 30, 2008, as
compared to the same period in 2007, primarily due to the $12 million tax impact
of higher pre-tax earnings and the $2 million impact of tax levelization. GAAP
requires companies to apply a levelized effective income tax rate to interim
periods that is




65




consistent
with the estimated annual effective tax rate. PEC’s income tax expense was
increased by $2 million for the three months ended June 30, 2008, in order to
maintain an effective tax rate consistent with the estimated annual rate,
compared to no impact for the three months ended June 30, 2007. 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,
2008, Compared to Six Months Ended June 30, 2007




REVENUES




PEC’s
electric revenues for the six months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions)
            
            Six
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            760
            
            
            $
            9
            
            
            
            1.2
            
            
            $
            751Commercial
            
            
            531
            
            
            
            16
            
            
            
            3.1
            
            
            
            515Industrial
            
            
            355
            
            
            
            16
            
            
            
            4.7
            
            
            
            339Governmental
            
            
            46
            
            
            
            2
            
            
            
            4.5
            
            
            
            44Total
      retail revenues
            
            
            1,692
            
            
            
            43
            
            
            
            2.6
            
            
            
            1,649Wholesale
            
            
            370
            
            
            
            18
            
            
            
            5.1
            
            
            
            352Unbilled
            
            
            7
            
            
            
            4
            
            
            
            –
            
            
            
            3Miscellaneous
            
            
            46
            
            
            
            (3
            )
            
            
            (6.1
            )
            
            
            49Total
      electric revenues
            
            
            2,115
            
            
            
            62
            
            
            
            3.0
            
            
            
            2,053Less:
      Fuel revenues
            
            
            (773
            )
            
            
            (51
            )
            
            
            –
            
            
            
            (722
            )Revenues
      excluding fuel
            
            $
            1,342
            
            
            $
            11
            
            
            
            0.8
            
            
            $
            1,331





PEC’s
electric energy sales for the six months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions of kWh)
            
            Six
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            8,264
            
            
            
            (52
            )
            
            
            (0.6
            )
            
            
            8,316Commercial
            
            
            6,662
            
            
            
            71
            
            
            
            1.1
            
            
            
            6,591Industrial
            
            
            5,894
            
            
            
            87
            
            
            
            1.5
            
            
            
            5,807Governmental
            
            
            668
            
            
            
            9
            
            
            
            1.4
            
            
            
            659Total
      retail energy sales
            
            
            21,488
            
            
            
            115
            
            
            
            0.5
            
            
            
            21,373Wholesale
            
            
            7,213
            
            
            
            91
            
            
            
            1.3
            
            
            
            7,122Unbilled
            
            
            4
            
            
            
            (56
            )
            
            
            –
            
            
            
            60Total
      kWh sales
            
            
            28,705
            
            
            
            150
            
            
            
            0.5
            
            
            
            28,555





PEC’s
revenues, excluding fuel revenues of $773 million and $722 million for the six
months ended June 30, 2008 and 2007, respectively, increased $11 million. The
increase in revenues excluding fuel is primarily due to the $25 million
favorable impact of retail customer growth and usage and $7 million higher
wholesale revenues, partially offset by $8 million lower excess generation
revenues, the $8 million unfavorable impact of weather and $3 million lower
miscellaneous revenues. Favorable retail customer growth and usage was driven by
a net 25,000 customer increase in PEC’s average number of customers for the six
months ended June 30, 2008, compared to the same period in 2007, and by an
increase in the average usage per retail customer. Higher wholesale revenues are
primarily due to increased energy rates and sales with a major customer. Lower
excess generation revenues were primarily driven by unfavorable market
conditions in 2008 resulting from higher fuel costs compared to 2007. The
unfavorable impact of weather was driven by lower heating degree days than 2007.
Miscellaneous revenues decreased due to lower electric property rental
revenues.




As
discussed previously in “Revenues” for the three months ended June 30, 2008 and
2007, PEC has not been as significantly impacted by the decline in general
economic conditions as PEF. However, PEC has experienced a slight decline in
residential and commercial sales growth.




66




Residential
revenues increased for the six months ended June 30, 2008, despite a decrease in
residential energy sales for the same period primarily due to the impact of
increased fuel revenues as a result of higher energy costs and the recovery of
prior year fuel costs.




EXPENSES




Fuel and Purchased
Power




Fuel and
purchased power expenses were $800 million for the six months ended June 30,
2008, which represents a $10 million increase compared to the same period in
2007. Fuel used in electric generation increased $23 million to $679 million
compared to the same period in 2007. This increase was primarily due to higher
fuel costs. Additionally, deferred fuel expense decreased $24 million due to the
implementation of the North Carolina comprehensive energy legislation (See
“Other Matters – Regulatory Environment”), which was offset by an increase in
deferred fuel of $24 million due to a change in the collection of the current
year’s under-recovery in each respective period. Current year purchased power
costs were $13 million lower than the six months ended June 30, 2007, primarily
due to the $19 million impact from the expiration of a power buyback agreement
with Power Agency. This decrease in purchased power costs was partially offset
by $4 million increased purchases in the current year compared to lower
purchases in 2007 due to an outage that impacted a purchased power
contract.




Operation and
Maintenance




O&M
expenses were $523 million for the six months ended June 30, 2008, which
represents a $7 million increase compared to the same period in 2007. O&M
expenses increased primarily due to an $18 million increase in nuclear expenses,
of which $10 million relates to refurbishments, preventative maintenance and
incremental outage expenses at Brunswick, an increase in estimated environmental
remediation expenses (See Note 12A) of $5 million, increased spending of $3
million on vegetation management in compliance with federal regulations and
increased nuclear license fees of $3 million, partially offset by outage
expenses of $24 million at Robinson in 2007.




Depreciation and
Amortization




Depreciation
and amortization expense was $255 million for the six months ended June 30,
2008, which represents a $20 million increase compared to the same period in
2007. Depreciation and amortization expense increased primarily due to $15
million additional depreciation associated with the accelerated cost-recovery
program for nuclear generating assets (See Note 4A) and the $7 million impact of
depreciable asset base increases, partially offset by $2 million lower Clean
Smokestacks Act amortization.




Other




Other
operating expenses consisted of gains of $6 million and $1 million for the six
months ended June 30, 2008 and 2007, respectively, primarily due to land
sales.




Total Other Income,
net




Total
other income, net of $22 million increased $1 million for the six months ended
June 30, 2008, compared to the same period in 2007, primarily due to $5 million
favorable AFUDC equity related to costs associated with eligible construction
projects and $4 million derivative mark-to-market gains. These increases were
partially offset by $4 million investment losses and $4 million lower interest
income. The derivative mark-to-market gains relate to commodity instruments that
are not subject to retail regulatory treatment. We expect AFUDC equity to
continue to increase for the remainder of 2008, primarily due to increased
spending on eligible construction projects.




67




Income Tax
Expense




Income
tax expense increased $19 million for the six months ended June 30, 2008, as
compared to the same period in 2007, primarily due to the $14 million tax impact
of higher pre-tax earnings, $4 million prior year changes in tax estimates, and
the $3 million unfavorable tax impact of stock-based compensation.




PROGRESS
ENERGY FLORIDA




PEF
contributed segment profits of $125 million and $68 million for the three months
ended June 30, 2008 and 2007, respectively. The increase in profits for the
three months ended June 30, 2008, compared to the same period in 2007, was
primarily due to favorable AFUDC, higher wholesale revenues, the favorable
impact of weather, an increase
in retail rates and lower other operating expenses due to disallowed fuel costs
in 2007, partially offset by the unfavorable impact of retail customer growth
and usage.




PEF
contributed segment profits of $191 million and $128 million for the six months
ended June 30, 2008 and 2007, respectively. The increase in profits for the six
months ended June 30, 2008, compared to the same period in 2007, was primarily
due to favorable AFUDC, higher wholesale revenues, an increase in retail rates
and the favorable impact of weather, partially offset by the unfavorable impact
of retail customer growth and usage.




The
revenue tables below 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.
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,
2008, Compared to Three Months Ended June 30, 2007




REVENUES




PEF’s
electric revenues for the three months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions)
            
            Three
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            553
            
            
            $
            20
            
            
            
            3.8
            
            
            $
            533Commercial
            
            
            281
            
            
            
            –
            
            
            
            –
            
            
            
            281Industrial
            
            
            80
            
            
            
            2
            
            
            
            2.6
            
            
            
            78Governmental
            
            
            70
            
            
            
            (4
            )
            
            
            (5.4
            )
            
            
            74Total
      retail revenues
            
            
            984
            
            
            
            18
            
            
            
            1.9
            
            
            
            966Wholesale
            
            
            141
            
            
            
            39
            
            
            
            38.2
            
            
            
            102Unbilled
            
            
            27
            
            
            
            8
            
            
            
            –
            
            
            
            19Miscellaneous
            
            
            42
            
            
            
            –
            
            
            
            –
            
            
            
            42Total
      electric revenues
            
            
            1,194
            
            
            
            65
            
            
            
            5.8
            
            
            
            1,129Less:
      Fuel and other pass-through revenues
            
            
            (732
            )
            
            
            (8
            )
            
            
            –
            
            
            
            (724
            )Revenues
      excluding fuel and other pass-through revenues
            
            $
            462
            
            
            $
            57
            
            
            
            14.1
            
            
            $
            405





68




PEF’s
electric energy sales for the three months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions of kWh)
            
            Three
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            4,755
            
            
            
            253
            
            
            
            5.6
            
            
            
            4,502Commercial
            
            
            3,069
            
            
            
            122
            
            
            
            4.1
            
            
            
            2,947Industrial
            
            
            1,009
            
            
            
            71
            
            
            
            7.6
            
            
            
            938Governmental
            
            
            800
            
            
            
            (11
            )
            
            
            (1.4
            )
            
            
            811Total
      retail energy sales
            
            
            9,633
            
            
            
            435
            
            
            
            4.7
            
            
            
            9,198Wholesale
            
            
            1,930
            
            
            
            483
            
            
            
            33.4
            
            
            
            1,447Unbilled
            
            
            715
            
            
            
            (36
            )
            
            
            –
            
            
            
            751Total
      kWh sales
            
            
            12,278
            
            
            
            882
            
            
            
            7.7
            
            
            
            11,396




PEF’s
revenues, excluding fuel and other pass-through revenues of $732 million and
$724 million for the three months ended June 30, 2008 and 2007, respectively,
increased $57 million. The increase in revenues was primarily due to base rate
increases, increased wholesale revenues and the favorable impact of weather,
partially offset by unfavorable retail customer growth and usage. The increase
in base rates was $24 million; Hines 4 being placed in service contributed $14
million in additional revenues and the transfer of Hines 2 cost recovery from
the fuel clause to base rates contributed $10 million. These base rate changes
occurred in accordance with PEF’s most recent base rate agreement. Wholesale
revenues, excluding fuel and other pass-through revenues, increased $20 million
primarily due to two new contracts with one major customer. The $15 million
favorable impact of weather was driven by higher cooling degree days. PEF’s base
rate, wholesale revenue and weather favorability was partially offset by the
unfavorable retail customer growth and usage impact of $5 million.




PEF
believes that the decline in general economic conditions, including weakness in
the housing markets in both Florida and the United States, has contributed to a
slowdown in customer growth and usage in its service territory. In addition to
lower average usage per customer, PEF experienced significantly lower customer
growth in 2008 than had been experienced in recent periods. PEF’s average number
of customers for the three months ended June 30, 2008, compared to the same
period in 2007 increased a net 2,000 customers. In comparison, PEF’s average
number of customers for the three months ended June 30, 2007, compared to the
same period in 2006 increased a net 28,000 customers.




PEF has
secured and is pursuing additional wholesale contracts that will mitigate, to a
certain extent, the impact of lower retail revenues. PEF cannot predict whether
or to what extent the trends of declining usage per customer and lower customer
growth will continue to negatively impact retail revenues or, if they do
continue, the extent to which increased wholesale revenues may offset such a
negative impact.




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 $631 million for the three months ended June 30,
2008, which represents a $13 million increase compared to the same period in
2007. Purchased power costs were $51 million higher for the three months ended
June 30, 2008, primarily due to increased current year purchases of $39 million
as a result of higher fuel costs and an increase in the recovery of deferred
capacity costs of $11 million. Fuel used in electric generation decreased $38
million to $373 million compared to the same period in 2007. This decrease was
due to lower deferred fuel expense of $180 million, partially offset by
increased current year fuel costs of $142 million. The lower deferred fuel
expense was primarily due to the regulatory approval to lower the fuel factor
for customers effective January 2008 as a result of over-recovery of fuel costs
in the prior year. The increase in current year fuel




69




costs was
primarily due to an increase in the percentage of generation supplied by natural
gas, increased fuel prices and higher system requirements.




With the
higher fuel costs experienced in 2008 and the anticipated high fuel costs for
the remainder of 2008, PEF filed a petition with the Florida Public Service
Commission (FPSC) requesting a mid-course correction to its fuel cost recovery
factors (See Note 4B).




Operation and
Maintenance




O&M
expenses were $217 million for the three months ended June 30, 2008, which
represents a $19 million increase when compared to the same period in 2007.
O&M expenses increased $30 million related to an increase in storm damage
reserves, which began in August 2007 and will continue through August 2008,
partially offset by a $4 million sales and use tax audit adjustment and $4
million lower environmental cost recovery (ECRC) costs due to deferral of
expenses. The storm damage reserve and ECRC expenses are recovered through
cost-recovery clauses and,
therefore, have no material impact on earnings. Therefore, O&M expenses
recoverable through base rates decreased approximately $7 million compared to
the same period in 2007.




Depreciation and
Amortization




Depreciation
and amortization expense was $76 million for the three months ended June 30,
2008, which represents a $24 million decrease compared to the same period in
2007. Depreciation and amortization expense decreased $28 million due to lower
amortization of unrecovered storm restoration costs, partially offset by the $5
million impact of depreciable asset base increases. Storm restoration costs,
which were fully amortized in August 2007, were recovered through a
cost-recovery clause and, therefore, had no material impact on
earnings.




Other




Other
operating income of $4 million for the three months ended June 30, 2008,
compared to other operating expenses of $12 million for the same period in 2007,
represents a $16 million change. The other operating income of $4 million for
the three months ended June 30, 2008, consists of a gain on a land sale. The
other operating expenses of $12 million for the three months ended June 30,
2007, consist of the impact of a FPSC order requiring PEF to refund disallowed
fuel costs to its ratepayers (See Note 4B).




Total Other Income,
net




Total
other income, net of $23 million increased $14 million for the three months
ended June 30, 2008, compared to the same period in 2007, primarily due to $14
million favorable AFUDC equity related to costs associated with eligible
construction projects. We expect AFUDC equity to continue to increase for the
remainder of 2008, primarily due to increased spending on environmental
initiatives and other eligible construction projects.




Total Interest Charges,
net




Total
interest charges, net were $39 million for the three months ended June 30, 2008,
which represents no change compared to the same period in 2007. However, total
interest charges, net were impacted by a $7 million interest benefit resulting
from the resolution of tax matters and $3 million favorable AFUDC debt related
to costs associated with eligible construction projects, partially offset by $9
million higher interest as a result of higher average debt
outstanding.




Income Tax
Expense




Income
tax expense increased $30 million for the three months ended June 30, 2008,
compared to the same period in 2007, primarily due to the $34 million tax impact
of higher pre-tax income compared to the prior year and the $5 million prior
year benefit related to the closure of certain federal tax years and positions,
partially offset by the $5 million impact of the increase in AFUDC equity
discussed above and the $5 million impact of tax levelization discussed below.
AFUDC equity is excluded from the calculation of income tax expense. GAAP
requires companies to apply a levelized effective income tax rate to interim
periods that is consistent with the estimated annual effective tax rate. PEF’s
income tax expense was decreased by $4 million for the three months ended June
30, 2008 compared to an increase of $1 million for the three months ended June
30, 2007, in order to maintain an




70




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,
2008, Compared to Six Months Ended June 30, 2007




REVENUES




PEF’s
electric revenues for the six months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class were as follows:


(in
      millions)
            
            Six
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            1,016
            
            
            $
            (9
            )
            
            
            (0.9
            )
            
            $
            1,025Commercial
            
            
            524
            
            
            
            (4
            )
            
            
            (0.8
            )
            
            
            528Industrial
            
            
            148
            
            
            
            (4
            )
            
            
            (2.6
            )
            
            
            152Governmental
            
            
            137
            
            
            
            (4
            )
            
            
            (2.8
            )
            
            
            141Total
      retail revenues
            
            
            1,825
            
            
            
            (21
            )
            
            
            (1.1
            )
            
            
            1,846Wholesale
            
            
            245
            
            
            
            64
            
            
            
            35.4
            
            
            
            181Unbilled
            
            
            33
            
            
            
            6
            
            
            
            –
            
            
            
            27Miscellaneous
            
            
            87
            
            
            
            1
            
            
            
            1.2
            
            
            
            86Total
      electric revenues
            
            
            2,190
            
            
            
            50
            
            
            
            2.3
            
            
            
            2,140Less:
      Fuel and other pass-through revenues
            
            
            (1,340
            )
            
            
            29
            
            
            
            –
            
            
            
            (1,369
            )Revenues
      excluding fuel and other pass-through revenues
            
            $
            850
            
            
            $
            79
            
            
            
            10.2
            
            
            $
            771





PEF’s
electric energy sales for the six months ended June 30, 2008 and 2007, and the
amount and percentage change by customer class are as follows:


(in
      millions of kWh)
            
            Six
      Months Ended June 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            8,760
            
            
            
            103
            
            
            
            1.2
            
            
            
            8,657Commercial
            
            
            5,729
            
            
            
            159
            
            
            
            2.9
            
            
            
            5,570Industrial
            
            
            1,874
            
            
            
            41
            
            
            
            2.2
            
            
            
            1,833Governmental
            
            
            1,567
            
            
            
            7
            
            
            
            0.4
            
            
            
            1,560Total
      retail energy sales
            
            
            17,930
            
            
            
            310
            
            
            
            1.8
            
            
            
            17,620Wholesale
            
            
            3,320
            
            
            
            703
            
            
            
            26.9
            
            
            
            2,617Unbilled
            
            
            935
            
            
            
            (6
            )
            
            
            –
            
            
            
            941Total
      kWh sales
            
            
            22,185
            
            
            
            1,007
            
            
            
            4.8
            
            
            
            21,178





PEF’s
revenues, excluding fuel and other pass-through revenues of $1.340 billion and
$1.369 billion for the six months ended June 30, 2008 and 2007, respectively,
increased $79 million. The increase in revenues was primarily due to base rate
increases, increased wholesale revenues and the favorable impact of weather,
partially offset by unfavorable retail customer growth and usage. The increase
in base rates was $44 million; Hines 4 being placed in service contributed $26
million in additional revenues and the transfer of Hines 2 cost recovery from
the fuel clause to base rates contributed $18 million. These base rate changes
occurred in accordance with PEF’s most recent base rate agreement. Wholesale
revenues, excluding fuel and other pass-through revenues, increased $28 million
primarily due to two new contracts with one major customer and a contract
amendment with another major customer. The $16 million favorable impact of
weather was driven by higher cooling degree days. PEF’s base rate, wholesale
revenue and weather favorability was partially offset by the unfavorable retail
customer growth and usage impact of $12 million.




As
discussed above, PEF has experienced a slowdown in customer growth and usage in
its service territory. In addition to lower average usage per customer, PEF
experienced significantly lower customer growth in the first six months of 2008
than had been experienced in recent periods. 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. In comparison, PEF’s




71




average
number of customers for the six months ended June 30, 2007, compared to the same
period in 2006, increased a net 29,000 customers.




EXPENSES




Fuel and Purchased
Power




Fuel and
purchased power expenses were $1.155 billion for the six months ended June 30,
2008, which represents an $11 million decrease compared to the same period in
2007. Fuel used in electric generation decreased $82 million to $714 million
compared to the same period in 2007. This decrease was due to lower deferred
fuel expense of $268 million, partially offset by increased current year fuel
costs of $186 million. The lower deferred fuel expense was primarily due to the
regulatory approval to lower the fuel factor for customers effective January
2008 as a result of over-recovery of fuel costs in the prior year. The increase
in current year fuel costs was primarily due to an increase in the percentage of
generation supplied by natural gas, increased fuel prices and higher system
requirements. Purchased power costs were $71 million higher for the six months
ended June 30, 2008, primarily due to increased current year purchases of $58
million as a result of higher fuel costs and an increase in the recovery of
deferred capacity costs of $13 million.




As
discussed earlier, PEF filed a petition with the FPSC requesting a mid-course
correction to its fuel cost recovery factors (See Note 4B).




Operation and
Maintenance




O&M
expenses were $420 million for the six months ended June 30, 2008, which
represents a $47 million increase when compared to the same period in 2007.
O&M expenses increased $55 million related to an increase in storm damage
reserves, which began in August 2007 and will continue through August 2008, and
$5 million primarily related to higher outage restoration, partially offset by a
$9 million sales and use tax audit adjustment and $8 million lower ECRC costs
due to deferral of expenses. The storm damage reserve and ECRC expenses are
recovered through cost-recovery clauses and, therefore, have no material impact
on earnings. Therefore, O&M expenses recoverable through base rates were
approximately the same as 2007.




Depreciation and
Amortization




Depreciation
and amortization expense was $152 million for the six months ended June 30,
2008, which represents a $45 million decrease compared to the same period in
2007. Depreciation and amortization expense decreased $54 million due to lower
amortization of unrecovered storm restoration costs, partially offset by the $11
million impact of depreciable asset base increases. Storm restoration costs,
which were fully amortized in August 2007, were recovered through a
cost-recovery clause and, therefore, had no material impact on
earnings.




Other




Other
operating income of $4 million for the six months ended June 30, 2008, compared
to other operating expenses of $12 million for the same period in 2007,
represents a $16 million change. The other operating income of $4 million for
the six months ended June 30, 2008, consists of a gain on a land sale. The other
operating expenses of $12 million for the six months ended June 30, 2007,
consist of the impact of a FPSC order requiring PEF to refund disallowed fuel
costs to its ratepayers (See Note 4B).




Total Other Income,
net




Total
other income, net of $41 million increased $24 million for the six months ended
June 30, 2008, compared to the same period in 2007, primarily due to $24 million
favorable AFUDC equity related to costs associated with eligible construction
projects. We expect AFUDC equity to continue to increase for the remainder of
2008, primarily due to increased spending on environmental initiatives and other
eligible construction projects.




Total Interest Charges,
net




Total
interest charges, net were $83 million for the six months ended June 30, 2008,
which represents a $7 million increase compared to the same period in 2007. The
increase was primarily due to $18 million higher interest as a result of higher
average debt outstanding. Partially offsetting this increase was $7 million
favorable AFUDC debt




72


related
to costs associated with eligible construction projects and a $7 million
interest benefit resulting from the resolution of tax matters.




Income Tax
Expense




Income
tax expense increased $32 million for the six months ended June 30, 2008,
compared to the same period in 2007, primarily due to the $37 million tax impact
of higher pre-tax income compared to the prior year and the $5 million prior
year benefit related to the closure of certain federal tax years and positions,
partially offset by the $10 million impact of the increase in AFUDC equity
discussed above and the $4 million impact of tax levelization, discussed below.
AFUDC equity is excluded from the calculation of income tax expense. GAAP
requires companies to apply a levelized effective income tax rate to interim
periods that is consistent with the estimated annual effective tax rate. PEF’s
income tax expense was decreased by $3 million for the six months ended June 30,
2008 compared to an increase of $1 million for the six months ended June 30,
2007, 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 separate business segment.
Corporate and Other expense is summarized below:


Three
      Months Ended June 30,
              
              
              Six
      Months Ended June 30,(in
      millions)
              
              2008
              
              
              2007
              
              
              2008
              
              
              2007Other
      interest expense
              
              $
              (57
              )
              
              $
              (43
              )
              
              $
              (111
              )
              
              $
              (91
              )Contingent
      value obligations
              
              
              (2
              )
              
              
              (4
              )
              
              
              (2
              )
              
              
              (3
              )Tax
      levelization
              
              
              1
              
              
              
              1
              
              
              
              –
              
              
              
              (2
              )Other
      income tax benefit
              
              
              24
              
              
              
              36
              
              
              
              41
              
              
              
              58Other
              
              
              5
              
              
              
              (8
              )
              
              
              4
              
              
              
              (14
              )Corporate
      and Other after-tax expense
              
              $
              (29
              )
              
              $
              (18
              )
              
              $
              (68
              )
              
              $
              (52
              )





Other
interest expense increased $14 million for the three months ended June 30, 2008,
and increased $20 million for the six months ended June 30, 2008, compared to
the same periods in 2007. The increase for the three and six months ended June
30, 2008, was primarily due to a $6 million prior year benefit related to the
closure of certain federal tax years and positions and a decrease in the
interest allocated to discontinued operations. The decrease in interest expense
allocated to discontinued operations resulted from the allocations of interest
expense in early 2007 for operations that were sold later in 2007. No interest
expense was allocated to discontinued operations for the three or six months
ended June 30, 2008, compared to $5 million and $12 million of interest expense
allocated to discontinued operations for the three and six months ended June 30,
2007, respectively.




Progress
Energy issued 98.6 million Contingent Value Obligations (CVOs) in connection
with the acquisition of Florida Progress Corporation (Florida Progress) in 2000.
Each CVO represents the right of the holder to receive contingent payments based
on the performance of four Earthco coal-based solid synthetic fuels facilities
purchased by subsidiaries of Florida Progress in October 1999. The payments, if
any, are based on the net after-tax cash flows the facilities generate. At June
30, 2008 and 2007, the CVOs had fair values of approximately $36 million and $35
million, respectively, and average unit prices of $0.37 and $0.36 at June 30,
2008 and 2007, respectively. We recorded unrealized losses of $2 million and $4
million for the three months ended June, 2008 and 2007, respectively, to record
the changes in fair value of the CVOs. We recorded unrealized losses of $2
million and $3 million for the six months ended June 30, 2008 and 2007,
respectively.




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 decreased by $1 million for the three months ended June 30, 2008
and 2007, respectively, and had no impact for the six months ended June 30,
2008, compared to an increase of $2 million for the six months ended June 30,
2007, 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




73




income or
deduction can also 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.




Other
income tax benefit decreased $12 million and $17 million for the three and six
months ended June 30, 2008, respectively, primarily due to the $14 million prior
year benefit related to the closure of certain federal tax years and
positions.




Other
decreased $13 million for the three months ended June 30, 2008, compared to the
same period in 2007, primarily due to $5 million decreased indirect corporate
overhead due to divestitures completed in 2007, $2 million decreased legal
expenses, lower depreciation and increased investment gains. Other decreased $18
million for the six months ended June 30, 2008, compared to the same period in
2007, primarily due to $11 million decreased legal expenses and $8 million
decreased indirect corporate overhead due to divestitures completed in
2007.




DISCONTINUED
OPERATIONS




We
divested multiple nonregulated businesses during 2008 and 2007 in accordance
with our business strategy to reduce our business risk and to focus on the core
operations of the Utilities.




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.




Prior to
2008, we had substantial operations associated with the production of coal-based
solid synthetic fuels. 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. All
periods have been restated to reflect the abandoned operations of our synthetic
fuels businesses as discontinued operations.





Terminals
and the synthetic fuels businesses collectively generated net earnings from
discontinued operations of $8 million and net losses from discontinued
operations of $7 million for the three months ended June 30, 2008 and 2007,
respectively, and net earnings from discontinued operations of $22 million and
$64 million for the six months ended June 30, 2008 and 2007, respectively. The
decrease in net earnings from discontinued operations for the six months ended
June 30, 2008, is primarily due to the 2007 expiration of the tax credit
program.




CCO
– GEORGIA OPERATIONS




On March
9, 2007, our subsidiary, Progress Energy Ventures, Inc. (PVI), entered into a
series of transactions to sell or assign substantially all of its Competitive
Commercial Operations (CCO) physical and commercial assets and liabilities.
Assets divested include approximately 1,900 megawatts (MW) of gas-fired
generation assets in Georgia. The sale of the generation assets closed on June
11, 2007, for a net sales price of $615 million. We recorded an estimated loss
of $226 million in December 2006. Based on the terms of the final agreement,
during the three and six months ended June 30, 2007, we reversed $1 million and
$17 million, respectively, after-tax of the impairment recorded in
2006.




Additionally,
on June 1, 2007, PVI closed the transaction involving the assignment of a
contract portfolio consisting of full-requirements contracts with 16 Georgia
electric membership cooperatives (the Georgia Contracts), forward gas and power
contracts, gas transportation, structured power and other contracts to a third
party. This represents substantially all of our nonregulated energy marketing
and trading operations. As a result of the assignments, PVI made a net cash
payment of $347 million, which represented the net cost to assign the Georgia
Contracts and other related contracts. In the quarter ended June 30, 2007, we
recorded a charge associated with the costs to exit the Georgia Contracts, and
other related contracts, of $349 million after-tax. We used the net proceeds
from these transactions for general corporate purposes.




74




CCO’s
operations generated net losses from discontinued operations of $3 million and
$322 million for the three months ended June 30, 2008 and 2007, respectively,
and $3 million and $279 million for the six months ended June 30, 2008 and 2007,
respectively. The decrease in net losses from discontinued operations for both
the three and six months ended June 30, 2008, compared to the same period in
2007 is primarily due to the after-tax charge of $349 million
associated with the costs to exit the Georgia Contracts, and other related
contracts recorded in 2007, partially offset by the unrealized mark-to-market
gains related to the increase in natural gas prices in 2007.




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 approximately 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.




Net
losses from discontinued operations for Coal Mining, excluding gain on disposal,
were $1 million and $4 million for the three months ended June 30, 2008 and
2007, respectively, and $4 million and $8 million for the six months ended June
30, 2008 and 2007, respectively.





OTHER
DIVERSIFIED BUSINESSES





Also
included in discontinued operations are amounts related to our sales of other
diversified businesses, primarily related to the sale of our natural gas
drilling and production business (Gas) and the sale of Progress Rail Services
Corporation (Progress Rail). These adjustments are mainly due to the
finalization of working capital adjustments and adjustments in connection with
guarantees and indemnifications provided by Progress Fuels and Progress Energy
for certain legal, tax and environmental matters (See Note 13B). The ultimate
resolution of these matters could result in additional adjustments in future
periods. For the three and six months ended June 30, 2008, we recorded
additional gains of $1 million and $2 million, respectively, net of tax. For
each of the three and six months ended June 30, 2007, we recorded additional
gains of $1 million, net of tax.




LIQUIDITY AND CAPITAL
RESOURCES




OVERVIEW




Progress
Energy, Inc. is a holding company and, as such, has no revenue-generating
operations of its own. Our primary cash needs at the Parent level are our common
stock dividend and interest and principal payments on our $2.6 billion of senior
unsecured debt. Our ability to meet these needs is dependent on the earnings and
cash flows of the Utilities, and the ability of the Utilities to pay dividends
or repay funds to us. As discussed under “Future Liquidity and Capital
Resources” below, synthetic fuels tax credits provide an additional source of
liquidity as those credits are realized. Our other 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.




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 are not expected to materially affect
net income.




As a
registered holding company, we are subject to regulation by the Federal Energy
Regulatory Commission (FERC), including for the issuance and sale of securities
as well as the establishment of intercompany extensions of credit (utility and
non-utility money pools). PEC and PEF participate in the utility money pool,
which allows the two utilities to lend to and borrow from each other. A
non-utility money pool allows our nonregulated operations




75




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.




Cash from
operations, short-term and long-term debt, limited ongoing equity sales from our
Investor Plus Stock Purchase Plan and employee benefit and stock option plans,
and proceeds from the sale of the remainder of our nonregulated businesses
completed in the first quarter, are expected to fund capital expenditures and
common stock dividends for 2008. For the fiscal year 2008, we anticipate
realizing an aggregate amount of approximately $300 million from the sale of
stock through these plans.




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 in Item 1A, “Risk Factors” in the 2007 Form
10-K.




The
following discussion of our liquidity and capital resources is on a consolidated
basis.




HISTORICAL
FOR 2008 AS COMPARED TO 2007




CASH
FLOWS FROM OPERATIONS




Cash from
operations is the primary source used to meet operating requirements and capital
expenditures. Net cash provided by operating activities increased by $1.180
billion for the six months ended June 30, 2008, when compared to the
corresponding period in the prior year. The increase in operating cash flow was
primarily due to $448 million in income tax impacts, largely driven by the prior
year costs to exit the Georgia Contracts and income tax payments related to the
sale of Gas; the $401 million change in derivative collateral
liabilities largely driven by the increase at PEF due to
higher prices for fuel oil and natural gas; a $269 million increase
from the change in accounts payable primarily due to the timing and volume of
payments and purchases for fuel and purchased power at the Utilities; and the
settlement of $247 million of derivative receivables primarily related to
derivative contracts for our former synthetic fuels businesses (see Note 9A).
These impacts were partially offset by a $246 million decrease in the recovery
of fuel costs at PEF due to the current year under-recovery driven by rising
fuel costs, compared to an over-recovery of fuel costs during the corresponding
period in the prior year.




INVESTING
ACTIVITIES




Net cash
used by investing activities increased by $967 million for the six months ended
June 30, 2008, when compared to the corresponding period in the prior year. This
is due primarily to a $582 million decrease in proceeds from sales of
discontinued operations and other assets, net of cash divested; a $432 million
increase in capital expenditures for utility property additions at PEF,
partially offset by a $76 million decrease in utility property additions at PEC;
and a $71 million decrease in net proceeds from short-term investments included
in available-for-sale securities and other investments. These impacts were
partially offset by a $54 million decrease in nuclear fuel additions. At PEF,
the increase in utility property additions was primarily due to a $255 million
increase in environmental compliance expenditures and a $157 million increase in
nuclear project expenditures. Available-for-sale securities and other
investments include marketable debt and equity securities and investments held
in nuclear decommissioning and benefit investment trusts.




During
the six months ended June 30, 2008, proceeds from sales of discontinued
operations and other assets of $64 million primarily included proceeds from the
sale of Terminals and Coal Mining (see Notes 3A and 3C). During the six months
ended June 30, 2007, proceeds from sales of discontinued operations and other
assets, net of cash divested, primarily included approximately $615 million from
the sale of PVI’s CCO generation assets (See Note 3B), working capital
adjustments for Gas, and the sale of poles at Progress Telecommunications
Corporation.




FINANCING
ACTIVITIES




Net cash
provided by financing activities was $1.085 billion for the six months ended
June 30, 2008, compared to net cash used by financing activities of $49 million
for the six months ended June 30, 2007, for a net increase of $1.134 billion.
The increase in net cash provided by financing activities was primarily due to
PEF’s $1.476 billion net proceeds from issuance of long-term debt discussed
below, partially offset by $176 million in payments on short-term debt, and $85
million in cash distributions to minority interests of consolidated subsidiaries
primarily related to the settlement of Ceredo Synfuel LLC’s (Ceredo) synthetic
fuels derivatives contracts (See Note 9A).




76




On
January 8, 2008, PEF’s shelf registration statement became effective with the
SEC. The registration statement initially allowed PEF to issue up to $4 billion
in first mortgage bonds, debt securities and preferred stock in addition to $250
million of previously registered but unsold securities.





On
February 1, 2008, PEF paid at maturity $80 million of its 6.875% First Mortgage
Bonds with available cash on hand and commercial paper borrowings.





On March
12, 2008, PEC and PEF amended their revolving credit agreements (RCA) with a
syndication of financial institutions to extend the termination date by one
year. The extensions were effective for both utilities on March 28, 2008. PEC’s
RCA is now scheduled to expire on June 28, 2011, and PEF’s RCA is now scheduled
to expire on March 28, 2011.




On March
13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due
2038. The proceeds were used to repay the maturity of PEC’s $300 million 6.65%
Medium-Term Notes, Series D, due April 1, 2008, and the remainder was placed in
temporary investments for general corporate use as needed.




On April
14, 2008, we amended our RCA with a syndication of financial institutions to
extend the termination date by one year. The extension was effective on May 3,
2008. Our RCA is now scheduled to expire on May 3, 2012.




On May
27, 2008, Progress Capital Holdings, Inc., one of our wholly owned subsidiaries,
paid at maturity its remaining outstanding debt of $45 million of 6.46%
Medium-Term Notes with available cash on hand.




On June
18, 2008, PEF issued $500 million of First Mortgage Bonds, 5.65% Series due 2018
and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038. A portion of
the proceeds was used to repay PEF’s utility money pool borrowings and the
remaining proceeds were placed in temporary investments for general corporate
use as needed. On July 14, 2008, PEF sent notice that it will redeem the entire
outstanding $450 million principal amount of its Series A Floating Rate Notes
due November 14, 2008 on August 14, 2008, at 100 percent of par plus accrued
interest. The redemption will be funded with a portion of the proceeds from the
June 18, 2008 debt issuance.




At
December 31, 2007, we had 500 million shares of common stock authorized under
our charter, of which 260 million shares were outstanding. For the three and six
months ended June 30, 2008, respectively, we issued approximately 0.5 million
shares and 1.0 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. For
the three and six months ended June 30, 2007, respectively, we issued
approximately 1.2 million shares and 2.7 million shares of common stock
resulting in approximately $57 million and $122 million in proceeds. Included in
these amounts were approximately 0.3 million shares and 0.5 million shares for
proceeds of approximately $12 million and $23 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, 2008, 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 2007 Form
10-K, other than as described below and under “Credit Rating Matters”,
“Regulatory Matters and Recovery of Costs” and “Financing
Activities.”





The
Utilities produce substantially all of our consolidated cash from operations. We
expect that the Utilities will continue to produce substantially all of the
consolidated cash flows from operations over the next several years. Our
synthetic fuels businesses, whose operations have been abandoned and
reclassified to discontinued operations, have historically produced significant
earnings from the generation of tax credits (See “Other Matters – Synthetic
Fuels Tax Credits”). These tax credits have 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, 2008, we have
carried forward $773 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.





77




With the
exception of the proceeds in the first quarter of 2008 from the sale of
Terminals and Coal Mining (See Notes 3A and 3C), the absence of cash flow
resulting from divested businesses is not expected to impact our future
liquidity or capital resources as these businesses in the aggregate have been
largely cash flow neutral over the last several years.





Cash from
operations plus availability under our credit facilities and shelf registration
statements is expected to be sufficient to meet our requirements in the near
term. To the extent necessary, we may also use limited ongoing equity sales 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. In the latter half of 2007,
the short-term credit markets tightened, resulting in higher interest rate
spreads and shorter durations. In the latter half of the first quarter of 2008
and continuing into the second quarter of 2008, the market has improved;
however, there has been volatility on commercial paper spreads. If liquidity
conditions deteriorate 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 borrowing from our RCAs, issuing
short-term floating rate notes, and/or issuing long-term debt.





Progress
Energy has approximately $11.0 billion in outstanding debt. Currently, $860
million of our Utility debt obligations 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 (Ambac) insures approximately $620 million of the bonds
and XL Capital Assurance, Inc. (XL) insures the remaining $240 million. To date,
auctions for the Utilities’ bonds have seen an increase in failures and the
relative level of the interest rates that are periodically reset at each
auction. 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 standard
market index such as the Securities Industry and Financial Markets Association’s
Municipal Swap Index or the London Interbank Offer Rate (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 company’s rating falls below
the Utilities’ ratings then the bonds will be rated at the Utilities’ senior
secured debt rating, which is currently A2 by Moody’s and A- by S&P for both
Utilities. The downgrades of XL in February 2008 by Moody’s and S&P caused
an initial increase in market volatility and an increase in interest rates. When
most auctions in the market began failing in late February 2008, we experienced
higher interest rates due to failed auctions and the increase in the underlying
indices supporting our reset interest rates. Since then, we are continuing to
experience failed auctions, but the interest rates have decreased as the
underlying indices have decreased. The June 2008 downgrades of XL by Moody’s and
S&P to B2 and BBB-, respectively, and Ambac by Moody’s and S&P to Aa3
and AA, respectively, have not materially impacted the reset rates of the
Utilities’ tax-exempt bonds. Volatility in the indices that support our interest
rate resets and ratings downgrades that move our tax-exempt bonds below A3/A-
could result in higher interest rate resets. We will continue to monitor this
market and evaluate options to mitigate our exposure to future
volatility.





As
discussed in “Capital Expenditures,” under LIQUIDITY AND CAPITAL RESOURCES and
“Strategy” under INTRODUCTION in Item 7 to the 2007 Form 10-K and in “Other
Matters – Environmental Matters” of this Form 10-Q, 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 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 in "Environmental Matters
- Environmental Compliance Cost Estimates", we are evaluating the impact that
the July 11, 2008 court decision vacating the Clean Air Interstate Rule (CAIR)
will have on our compliance with other environmental regulations and will
reassess our plans and estimated costs to comply.





The
amount and timing of future sales of securities will depend on market
conditions, operating cash flow, asset sales 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.





78




At June
30, 2008, the current portion of our long-term debt was $850 million, which we
expect to fund with a combination of cash from operations, investments,
commercial paper borrowings and long-term debt.





REGULATORY
MATTERS AND RECOVERY OF COSTS




Regulatory
matters, as further discussed in Note 4 and “Other Matters – Regulatory
Environment”, and filings for recovery of environmental costs, as discussed in
Note 12 and in “Other Matters – Environmental Matters” of this filing and in
Note 21 and in “Other Matters – Regulatory Environment” and “Other Matters –
Environmental Matters” of the 2007 Form 10-K 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. Developments since our 2007 Form 10-K are discussed
below.




As
discussed further in Note 4 and in “Other Matters – Regulatory Environment,” the
Florida legislature passed comprehensive energy legislation that became law in
2008 and the South Carolina and North Carolina state legislatures passed energy
legislation that became law in 2007. These laws may impact our liquidity over
the long term. We cannot currently predict the impacts to our liquidity of
complying with Florida’s comprehensive energy legislation.





Among
other provisions, the North Carolina and South Carolina state energy laws
provide mechanisms for recovery of certain baseload generation construction
costs and expand annual fuel clause mechanisms so that additional costs may be
recovered annually. On February 29, 2008, the North Carolina Utilities
Commission (NCUC) issued an order adopting final rules for implementing North
Carolina’s comprehensive energy legislation. Rates for the demand-side
management (DSM) and energy-efficiency clause and the North Carolina Renewable
Energy and Energy Efficiency Portfolio Standard (REPS) clause will be set based
on projected costs with true-up provisions.





PEC Pass-through Clause Cost
Recovery




On June
26, 2008, the South Carolina Public Service Commission (SCPSC) approved PEC’s
request for an increase in the fuel rate charged to its South Carolina
ratepayers, which provided for a $39 million increase in fuel rates for
under-recovered fuel costs associated with prior year settlements and to meet
future expected fuel costs. Residential electric bills increased by $5.86 per
1,000 kWh, or 6.1 percent, for fuel cost recovery effective July 1,
2008.




On June
6, 2008, PEC filed with the NCUC for an increase in the fuel rate charged to its
North Carolina ratepayers. PEC asked the NCUC to approve a $424 million increase
in fuel rates for under-recovered fuel costs associated with prior year
settlements and to meet future expected fuel costs. In addition, in filings made
on June 6, 2008, PEC asked the NCUC for approval of DSM and energy-efficiency
and REPS clauses to recover the costs of these programs. If the filings are
approved, the increases would take effect on or about December 1, 2008, and
would increase residential electric bills in total by $15.71 per 1,000 kWh, or
16.2 percent. A hearing on the fuel filing has been scheduled by the NCUC for
September 16, 2008, followed by hearings on the DSM and REPS filings on
September 17, 2008. We cannot predict the outcome of this matter.




PEC has
begun implementing a series of DSM and energy-efficiency programs and has
deferred $4 million of implementation and program costs for future recovery. On
April 29 and May 1, 2008, PEC filed for NCUC approval of a total of five DSM and
energy-efficiency programs, including a distribution system demand response
program. PEC anticipates that the distribution system demand response
program will require an investment of approximately $260 million over five
years. As discussed above, PEC has filed an application to recover the cost of
the program. We cannot predict the outcome of these filings or whether the
proposed programs will produce the expected operational and economic
results.





On
December 21, 2007, the SCPSC issued an order granting PEC’s petition seeking
authorization to create a deferred account for DSM and energy-efficiency
expenses. As a result, PEC has deferred an immaterial amount of implementation
and program costs for future recovery in the South Carolina jurisdiction. 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. We cannot
predict the outcome of this matter.





79




PEC Other Regulatory
Matters





On April
30, 2008, PEC submitted a revised Open Access Transmission Tariff (OATT)
filing, including a settlement agreement, with the FERC requesting an increase
in transmission rates. The purpose of the filing was to implement formula rates
for the PEC OATT in order to more accurately reflect the costs that PEC incurs
in providing transmission service. In the filing, PEC proposed to move from a
fixed revenue requirement to a formula rate, which allows for transmission rates
to be updated each year based on the prior year’s actual costs. Settlement
discussions were held with major customers prior to the filing and a settlement
agreement was reached on all issues. The settlement proposed a formula rate with
a rate of return on equity of 10.8 percent as well as recovery of the wholesale
portion of the terminated GridSouth Transco, LLC (GridSouth) project startup
costs over five years. On June 27, 2008, the FERC approved the settlement. The
new rates were effective July 1, 2008, and PEC estimates the impact of the new
rates will increase 2008 revenues by $6 million to $8 million.





PEF Pass-through Clause Cost
Recovery





On
October 10, 2007, the Florida Public Service Commission (FPSC) issued an order
requiring PEF to refund its ratepayers approximately $14 million, including
interest, over a 12-month period beginning January 1, 2008. Neither PEF nor
Florida’s Office of the Public Counsel (OPC) filed an appeal to the Florida
Supreme Court of the FPSC’s October 10, 2007 order. The FPSC also ordered PEF to
address whether it was prudent in its 2006 and 2007 coal purchases for Crystal
River Units No. 4 and 5 coal-fired steam turbines (CR4 and CR5). PEF believes
its coal procurement practices have been prudent. We anticipate that a hearing
will be held on the 2006 and 2007 coal purchases in 2009. We cannot predict the
outcome of this matter.




On
February 29, 2008, PEF filed a petition for recovery of costs incurred to uprate
Crystal River Unit No. 3 Nuclear Plant (CR3) in 2007 and 2006 under Florida’s
comprehensive energy legislation and the FPSC’s nuclear cost-recovery rule based
on the regulatory precedence established by a FPSC order to an unaffiliated
Florida utility for a nuclear uprate project. The FPSC is scheduled to vote on
this matter by October 2008. We cannot predict the outcome of this
matter.




On May 1,
2008, PEF filed with the FPSC for an increase in the capacity cost-recovery
charge of estimated costs incurred in 2008 and projected costs to be incurred in
2009 under the FPSC nuclear cost-recovery rule. PEF is asking the FPSC to
approve a $25 million increase in the capacity cost recovery rate for costs
associated with the CR3 uprate. If approved, the increase would take effect with
the first billing cycle for 2009 and would increase residential electric bills
by $0.70 per 1,000 kWh. After PEF’s completion of a transmission study and
additional engineering studies, the current project estimate of fully loaded
costs is $364 million. A hearing on the matter has been scheduled by the FPSC
for September 2008, and the FPSC is expected to vote on this matter by October
2008. We cannot predict the outcome of this matter.




On May
30, 2008, PEF filed a petition with the FPSC requesting a mid-course correction
to its fuel cost recovery factors to recover an additional $213 million in 2008,
primarily due to rising fuel costs. In accordance with a FPSC order, investor
owned utilities must file a notice with the FPSC if the year-end projected over-
or under-recovery of fuel costs is expected to be greater than 10% of projected
fuel revenues. The mid-course correction would have resulted in a
residential fuel rate increase of $12.07 per 1,000 kWh for the period August
through December 2008. On July 1, 2008, the FPSC approved recovery of the $213
million projected year-end under-recovery, but allowed PEF to recover 50 percent
in 2008 and 50 percent in 2009. Therefore, the increase in the fuel rate
for the period August through December 2008 is $6.03 per 1,000 kWh. This
increase is partially offset by the expiration of PEF’s storm cost recovery
surcharge of $3.61 per 1,000 kWh effective August 2008. Consequently,
beginning with the first billing cycle in August and including gross receipts
tax, residential electric bills will increase by $2.48 per 1,000 kWh, or 2.29
percent.





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 $29 million at June 30, 2008.
Additionally, on November 6, 2006, the FPSC approved PEF’s petition for its
integrated strategy to address compliance with the CAIR, the Clean Air Mercury
Rule (CAMR) and the Clean Air Visibility Rule (CAVR) through the ECRC. The FPSC
also approved cost recovery of prudently incurred costs necessary
to achieve this




80




strategy,
which are currently estimated to be $1.2 billion for in-process CAIR projects
(see “Other Matters – Environmental Matters” for discussion regarding the CAIR,
CAMR and CAVR).




Nuclear Cost
Recovery





The FPSC
approved new rules on February 13, 2007, that allow PEF to recover prudently
incurred siting, preconstruction costs and AFUDC 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.





As
discussed further in Note 4 and “Other Matters – Nuclear”, on July 15,
2008,the FPSC voted unanimously in favor of PEF’s need
certification petition for its proposed Levy Units 1 and 2 nuclear power plants,
together with the associated facilities, including transmission lines and
substation facilities. The filed, non-binding project cost estimate for Levy
Units 1 and 2 is approximately $14 billion for generating facilities and
approximately $3 billion for associated transmission facilities. On March 11,
2008, PEF also filed a petition with the FPSC to open a discovery docket
regarding the actual and projected costs of the proposed Levy nuclear project.
PEF filed the petition to assist the FPSC in the timely and adequate review of
the projects costs recoverable under the FPSC nuclear cost-recovery rule. On May
1, 2008, PEF filed a petition for recovery of both preconstruction and carrying
charges on construction costs incurred or anticipated to be incurred during 2008
and 2009. Additionally, the filing included site selection costs of $38 million.
Based on the affirmative vote by the FPSC in the Determination of Need on the
Levy nuclear project, PEF filed a petition on July 18, 2008, to recover all
prudently incurred costs under the FPSC nuclear cost-recovery rule. A decision
by the FPSC on PEF’s 2008 cost-recovery filing is expected by October 1, 2008.
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




As a part
of normal business, we enter into various agreements providing future financial
or performance assurances to third parties that are outside the scope of FASB
Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These
agreements are entered into primarily to support or enhance the creditworthiness
otherwise attributed to Progress Energy or our subsidiaries on a stand-alone
basis, thereby facilitating the extension of sufficient credit to accomplish the
subsidiaries’ intended commercial purposes. Our guarantees include standby
letters of credit, surety bonds, performance obligations for trading operations
and guarantees of certain subsidiary credit obligations. At June 30, 2008, we
have issued $385 million of guarantees for future financial or performance
assurance, including $11 million at PEC and $2 million at PEF. Included in this
amount is $300 million of guarantees of certain payments of two wholly owned
indirect subsidiaries issued by the Parent (See Note 14). We do not believe
conditions are likely for significant performance under the guarantees of
performance issued by or on behalf of affiliates.




At June
30, 2008, we have issued guarantees and indemnifications of certain asset
performance, legal, tax and environmental matters to third parties, including
indemnifications made in connection with sales of businesses, and for timely
payment of obligations in support of our nonwholly owned synthetic fuels
operations (See Note 13B).




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 9 and Item 3, “Quantitative and Qualitative
Disclosures about Market Risk” of this Form 10-Q, for a discussion of market
risk and derivatives.




81




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 2007
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. The commitment amounts discussed below are estimates and
therefore, actual purchase amounts will likely differ. Additional commitments
for fuel and related transportation will be required to supply the Utilities’
future needs.




PROGRESS
ENERGY




Through
June 30, 2008, contracts procured though our subsidiaries have increased our
aggregate purchase obligations for fuel and purchased power by $9.214 billion
from $17.644 billion, as stated in Note 22A in the 2007 Form 10-K. In March
2008, PEC issued long-term debt totaling $325 million. In June 2008, PEF issued
long-term debt totaling $1.500 billion. These increases are discussed under
“PEC” and “PEF” below.




PEC




Through
June 30, 2008, PEC’s fuel and purchased power commitments increased by $5.697
billion from $5.078 billion, as stated in Note 22A in the 2007 Form 10-K. This
increase is primarily related to coal purchase commitments, of which
approximately $3.199 billion will be incurred through 2012, with the remainder
incurred through 2018. The increase in coal purchase commitments includes new
contracts along with the impact of price increases on certain existing contracts
that are market price indexed.




In June
2008, PEC entered into a conditional contract with an interstate pipeline for
firm pipeline transportation capacity to support PEC’s gas supply needs for the
period from May 2011 through April 2031. The estimated total cost to PEC
associated with this agreement is approximately $461 million. The transaction is
subject to several conditions precedent, including various state regulatory
approvals, the completion and commencement of operation of necessary related
interstate natural gas pipeline system expansions, and other contractual
provisions. Due to the conditions of this agreement, the estimated costs
associated with this agreement are not included in the increase in PEC’s fuel
and purchased power commitments discussed above.




On March
13, 2008, PEC issued $325 million of First Mortgage Bonds, 6.30% Series due 2038
(See Note 6).




PEF




Through
June 30, 2008, PEF’s fuel and purchased power commitments increased by $3.517
billion from $12.566 billion, as stated in Note 22A in the 2007 Form 10-K.
Approximately $1.689 billion of this increase is due to coal purchase
commitments, of which approximately $588 million will be incurred through 2012,
with the remainder incurred through 2030. The increase in coal purchase
commitments includes new contracts along with the impact of price increases on
certain existing contracts that are market price indexed. Additionally,
approximately $1.398 billion of the increase is due to the impact of rising
natural gas prices under a long-term gas supply agreement that was entered into
in December 2004. Approximately $216 million of this increase will be incurred
through 2012, with the remainder incurred through 2027. Payments under this
agreement are based on a published market price index. Contractual obligations
under this contract are based on estimated future market prices.




In April
2008, PEF entered into a conditional contract with Florida Gas Transmission
Company, L.L.C. (FGT) for firm pipeline transportation capacity to support PEF’s
gas supply needs for the period from April 2011 through March 2036. The total
cost to PEF associated with this agreement is estimated to be approximately
$2.000 billion. The transaction is subject to several conditions precedent,
including various state regulatory approvals, the completion and commencement of
operation of necessary related interstate natural pipeline system expansions,
and other contractual provisions. In addition to the FGT contract, during the
second quarter of 2008, PEF entered into additional gas supply and
transportation arrangements for the period from 2010 through 2025 that are
subject to certain conditions. The total current notional cost of these
additional agreements is estimated to be approximately $1.390 billion. Due to
the conditions of these agreements, the estimated costs associated with these
agreements are not
included in the increase in PEF’s fuel and purchased power commitments discussed
above.




82




On June
18, 2008, PEF issued $500 million of First Mortgage Bonds, 5.65% Series due 2018
and $1.000 billion of First Mortgage Bonds, 6.40% Series due 2038 (See Note
6).




OTHER
MATTERS




SYNTHETIC
FUELS TAX CREDITS




Prior to
2008, 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 (Section 45K and collectively, Section 29/45K) as discussed below. The
production and sale of these products qualified for federal income tax credits
so long as certain requirements were satisfied, including a requirement that the
synthetic fuels differ significantly in chemical composition from the coal used
to produce such synthetic fuels and that the fuel was produced from a facility
that was placed in service before July 1, 1998. 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 tax credits associated with synthetic fuels in a particular year
were phased out when annual average market prices for crude oil exceeded certain
prices. The synthetic fuels tax credit program expired at the end of
2007.




TAX
CREDITS




Legislation
enacted in 2005 redesignated the Section 29 tax credit as a general business
credit under Section 45K 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 through December 31, 2007 (including those
generated by Florida Progress prior to our acquisition), were $1.891 billion. As
of June 30, 2008, $1.118 billion of tax credits had been used to offset regular
federal income tax liability and $773 million are being carried forward as
deferred tax credits.




IMPACT
OF CRUDE OIL PRICES




Section
29 provided that if the average wellhead price per barrel for unregulated
domestic crude oil for the year (Annual Average Price) exceeded a certain
threshold value (the Threshold Price), the amount of Section 29/45K tax credits
were reduced for that year. Also, if the Annual Average Price exceeded the price
per barrel of unregulated domestic crude oil at which the value of Section
29/45K tax credits were fully eliminated (Phase-out Price), the Section 29/45K
tax credits were eliminated for that year. The Threshold Price and the Phase-out
Price were adjusted annually for inflation.




When the
Annual Average Price fell between the Threshold Price and the Phase-out Price
for a year, the amount by which Section 29/45K tax credits were reduced depended
on where the Annual Average Price fell in that continuum. The Department of the
Treasury calculated the Annual Average Price based on the Domestic Crude Oil
First Purchases Prices published by the Energy Information Agency (EIA). Because
the EIA published its information on a three-month lag, the secretary of the
Treasury finalized the calculations three months after the year in question
ended. Thus, the Annual Average Price for calendar year 2007 was published on
April 1, 2008. Based on the Annual Average Price for calendar year 2007 of
$66.52, our $205 million of synthetic fuels tax credits generated during 2007
were reduced by 67 percent, or approximately $138 million.




In
January 2007, we entered into derivative contracts to hedge economically a
portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil
prices over an average annual oil price range of $63 to $77 per barrel on a New
York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price
hedge instruments was 25 million barrels and provided protection for the
equivalent of approximately eight million tons of 2007 synthetic fuels
production and was marked-to-market with changes in fair value recorded through
earnings. Approximately 34 percent of the notional quantity of these contracts
was entered into by Ceredo. As discussed below in “Sales of Partnership
Interests” and in Notes 1C and 3F, we disposed of our 100 percent ownership
interest in Ceredo in




83




March
2007. For the three months ended June 30, 2007, we recorded net pre-tax losses
of $14 million related to these contracts, including $5 million attributable to
Ceredo which was attributed to minority interest for the portion of the loss
subsequent to disposal. For the six months ended June 30, 2007, we recorded net
pre-tax gains of $31 million related to these contracts, including $10 million
attributable to Ceredo, of which losses of $5 million were attributed to
minority interest for the portion of the loss subsequent to disposal. The
derivative contracts ended on December 31, 2007, and were settled for cash on
January 8, 2008, with no material impact on 2008 earnings.




SALES
OF PARTNERSHIP INTERESTS




In March
2007, we disposed of, through our subsidiary Progress Fuels, our 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 received as we produced and
sold qualifying coal-based solid synthetic fuels on behalf of the buyer. We
received final payment on the note related to 2007 production of $5 million
during the three months ended March 31, 2008. The total amount of the proceeds
was subject to adjustment once the final value of the 2007 Section 29/45K
credits was known. This adjustment resulted in a $7 million reduction of the
purchase price during the three months ended March 31, 2008. For the six months
ended June 30, 2008, we recorded gains on disposal of $5 million based on the
value of the 2007 Section 29/45K tax credits. The operations of Ceredo were
reclassified to discontinued operations, net of tax on the Consolidated
Statements of Income. Subsequent to the disposal, we remain the primary
beneficiary of Ceredo and consolidate Ceredo in accordance with FASB
Interpretation No. 46R, “Consolidation of Variable Interest Entities – an
Interpretation of ARB No. 51”, but we have recorded a 100 percent minority
interest. Consequently, subsequent to the disposal there was no net earnings
impact from Ceredo’s operations, which ceased as of December 31, 2007. In
connection with the disposal, Progress Fuels and Progress Energy provided
guarantees and indemnifications for certain legal and tax matters to the buyer,
which reduces any gain. The ultimate resolution of these matters could result in
adjustments to the gain on disposal in future periods. See Note 3F for
additional discussion of this transaction and Note 13B for a general discussion
of guarantees.




See Note
13C for additional discussion related to our synthetic fuels
businesses.




REGULATORY
ENVIRONMENT




The
Utilities’ operations in North Carolina, South Carolina and Florida are
regulated by the NCUC, 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
retail rate matters affected by state regulatory authorities are discussed in
detail 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.




During
the 2008 session, the Florida legislature passed comprehensive energy
legislation, which became law on June 26, 2008. The legislation 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 greenhouse gas emissions that the FDEP would present to the legislature
no earlier than January 2010 for ratification by the legislature; (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; and (5) require
the FPSC to analyze utility revenue decoupling and provide a report and
recommendation to




84




the
Governor and legislature by January 1, 2009. PEF would be able to recover its
reasonable prudent compliance costs. Until the rulemaking processes are
completed, we cannot predict the costs of complying with the law.




During
2007, the North Carolina legislature passed comprehensive energy legislation,
which became law on August 20, 2007. The law includes provisions for renewable
energy portfolio standards, 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 comprehensive energy legislation. These rules
provide filing requirements associated with the legislation. The order requires
PEC to submit its first annual REPS compliance plan by September 1, 2008, as
part of its integrated resource plan. Under the new rules, beginning in 2009,
PEC will also be required to file an annual REPS compliance report demonstrating
the actions it has taken to comply with the REPS requirement. The rules measure
compliance with the REPS requirement via renewable energy certificates (REC)
earned after January 1, 2008. The NCUC will pursue a third-party REC tracking
system, but will not develop or require participation in a REC trading platform
at this time. 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 REPS clause will be set based on
projected costs with true-up provisions. On April 29 and May 1, 2008, PEC filed
for NCUC approval of a total of five DSM and energy-efficiency programs,
including the EnergyWiseTM and distribution system demand response programs
discussed below.





On April
29, 2008, PEC filed for approval by the NCUC of its EnergyWiseTM program, which
is a residential program that offers customers an incentive to permit PEC to
remotely adjust central air conditioning and heat pumps in PEC’s eastern control
area and electric resistance heating and water heaters in PEC’s western control
area in order to reduce peak demand. PEC’s goal for EnergyWiseTM is to have the
capability to reduce peak electricity demand by 200 MW by 2017.





Also on
April 29, 2008, PEC filed for NCUC approval of its distribution system demand
response program, which will provide additional capability for reducing and
shifting peak electricity demand. The program also will reduce the level of
natural electricity loss experienced over long distribution feeder lines,
thereby eliminating the need for additional power generation to compensate for
the line losses. PEC anticipates that the program will require an investment of
approximately $260 million over five years and is expected to reduce peak
electricity demand by 250 MW. This distribution system investment is part of
PEC’s broader “Smart Grid” strategy and is expected to provide a foundation for
additional initiatives, including enhanced system reliability (through faster
outage isolation and response) and new capabilities for incorporating renewable
energy resources and other distributed generation into PEC’s energy mix. Such
costs are expected to be recovered under the provisions of the North Carolina
comprehensive energy legislation. A hearing for the application for approval of
the proposed distribution system demand response program has been scheduled by
the NCUC for September 17, 2008.





We cannot
predict the outcome of the April 29 and May 1, 2008 filings or whether the
proposed programs will produce the expected operational and economic
results.





On July
13, 2007, the governor of Florida issued executive orders to address reduction
of greenhouse gas emissions. The executive orders call for the first
Southeastern state cap-and-trade program and include adoption of a maximum
allowable emissions level of greenhouse gases 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 greater than Year 1990 utility sector emissions; and by 2050,
emissions not greater than 20 percent of Year 1990 utility sector
emissions.




Among
other things, 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 backwards when
they generate electricity (net metering). The FPSC has held meetings regarding
the renewable portfolio




85




standard
but no actions have been taken or rules issued. The Energy and Climate Action
Team appointed by the governor submitted its initial recommendations for
implementation of the governor’s executive orders on November 1, 2007. The
recommendations encourage the development and implementation of
energy-efficiency and conservation measures, implementation of a climate
registry, and consideration of a cap-and-trade approach to reducing the state’s
greenhouse gas emissions. Additional development and discussion of the
recommendations will occur through a stakeholder process in 2008.The FDEP held its first
workshop on the greenhouse gas emissions cap on August 22, 2007, but we
anticipate drafts of the rule to be issued later in 2008. We cannot currently
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.




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 13C.




INCREASING
ENERGY DEMAND




Meeting
the anticipated 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 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. Our
energy-efficiency program provides simple, low-cost options for residential
customers to reduce energy use, promotes home energy checks, provides tools and
programs for large and small businesses to minimize their energy use and
provides an interactive internet Web site with online calculators, programs and
efficiency tips.




We are
actively engaged in a variety of alternative energy projects, including solar,
hydrogen, biomass and landfill-gas technologies. We are evaluating the
feasibility of producing electricity from hog waste and other plant or animal
sources.




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. While we pursue
expansion of energy- efficiency and conservation programs, PEC announced in 2007
a two-year moratorium on constructing new coal-fired plants and that if PEC goes
ahead with a new nuclear plant, the new plant would not be online until at least
2018 (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. We cannot predict if we will pursue these loan
guarantees.




86




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 greenhouse gas emissions and advanced nuclear facilities for the
“front-end” of the nuclear fuel cycle.




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.




On
November 14, 2006, PEC filed an application with the NRC for a 20-year extension
of the Shearon Harris Nuclear Plant (Harris) operating license. The license
renewal application for Harris is currently under review by the NRC with a
decision expected in 2008.




Our
nuclear units are periodically removed from service to accommodate normal
refueling and maintenance outages, repairs and certain other
modifications.




We
previously announced that we are pursuing development of combined license (COL)
applications to potentially construct new nuclear plants in North Carolina and
Florida. Filing of a COL application is not a commitment to build a nuclear
plant but is a necessary step to keep open the option of building a plant or
plants. 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 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. On June 4, 2008, the NRC
published the Petition for Leave to Intervene. Petitions to intervene may be
filed within 60 days of the notice by anyone whose interest may be affected by
the proposed license and who wishes to participate as a party in the
proceeding. One petition to intervene was filed with the NRC within the
60-day notice period. 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 2018
(See “Increasing Energy Demand” above).




On
December 12, 2006, we announced that PEF selected a site in Levy County, Fla.,
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. On July 30, 2008, PEF filed its COL application with the
NRC for two reactors. In 2007, PEF completed the purchase of approximately 5,000
acres for the Levy County site and associated transmission needs. PEF filed a
Determination of Need petition with the FPSC on March 11, 2008. The hearing was
held on May 21-23, 2008, and the FPSC voted unanimously in favor of the
Determination of Need on July 15, 2008. If we receive approval from the NRC and
applicable state agencies, and if the decisions to build are made,
safety-related construction activities could begin as early as 2012, and a new
plant could be online in 2016 (See “Increasing Energy Demand”
above).




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. The
Florida Departmentof Community Affairs (FDCA) reviewed the proposed
changes to the comprehensive land use plan and in their report, the FDCA
expressed concerns related to the intensity of use and environmental suitability
for some of the proposed amendments impacting PEF’s proposed Levy County nuclear
site. We anticipate that the Levy County Planning Commission will resolve the
FDCA’s concerns without impact to the potential project schedule. We cannot
predict the outcome of this matter.




In
addition, PEF filed its application for Site Certification with the FDEP on June
2, 2008. A decision on PEF’s FDEP Site Certification Application is expected in
2009.




87




On March
11, 2008, PEF also filed a petition with the FPSC to open a discovery docket
regarding the actual and projected costs of the proposed Levy nuclear project.
PEF filed the petition to assist the FPSC in the timely and adequate review of
the projects costs recoverable under the FPSC nuclear cost-recovery rule. On May
1, 2008, PEF filed a petition for recovery of both preconstruction and carrying
charges on construction costs incurred or anticipated to be incurred during 2008
and 2009. Additionally, the filing included site selection costs of $38 million.
Based on the affirmative vote by the FPSC on the Determination of Need for the
Levy nuclear project, PEF filed a petition on July 18, 2008, to recover all
prudently incurred costs under the FPSC nuclear cost-recovery rule. A decision
by the FPSC on PEF’s 2008 cost-recovery filing is expected by October 1, 2008.
We cannot predict the outcome of this matter.




PEF
signed a letter of intent dated March 28, 2008, with the Shaw Group Inc. and
Westinghouse Electric Co. to complete negotiations toward an engineering,
procurement and construction (EPC) agreement for up to two Westinghouse AP1000
nuclear reactors planned for construction at the Levy County, Fla. site. The
letter of intent authorizes the purchase of long-lead materials for the
reactors. In 2008, PEF has made payments toward long-lead equipment related to
the EPC agreement. At this time, no definitive decisions have been made to
construct new nuclear plants.




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 Internal Revenue
Service (IRS) provided interim guidance that the 6,000 MW of production tax
credits generally will be allocated to new nuclear facilities that file 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.




In
accordance with provisions of Florida’s energy legislation enacted in 2006, the
FPSC ordered new rules in December 2006 that would allow investor-owned
utilities such as PEF to request recovery of certain planning and construction
costs of a nuclear power plant prior to commercial operation. The FPSC issued a
final rule on February 13, 2007, under which utilities will be allowed to
recover prudently incurred siting, preconstruction costs and AFUDC 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 will require 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. Also, on February
1, 2007, the FPSC amended its power plant bid rules to, among other things,
exempt nuclear power plants from existing bid requirements.




In 2007,
the South Carolina legislature ratified new energy legislation, which includes
provisions for cost-recovery mechanisms associated with nuclear baseload
generation. In 2007, the North Carolina legislature also passed new energy
legislation, which 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”).




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.




88




HAZARDOUS
AND SOLID WASTE MANAGEMENT




The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the Environmental
Protection Agency (EPA) to require the cleanup of hazardous waste sites. This
statute imposes retroactive joint and several liabilities. Some states,
including North Carolina, South Carolina and Florida, have similar types of
statutes. We are periodically notified by regulators, including the EPA and
various state agencies, of our involvement or potential involvement in sites
that may require investigation and/or remediation. There are presently several
sites with respect to which we have been notified of our potential liability by
the EPA, the state of North Carolina, the state of Florida or potentially
responsible 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 12). 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 these potential claims cannot be predicted. No
material claims are currently pending. Hazardous and solid waste management
matters are discussed in detail in Note 12A.




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.




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 additional reductions in air
emissions of nitrogen oxides (NOx), sulfur dioxide (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 that is
installed pursuant to the provisions of the Clean Smokestacks Act, the Clean Air
Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR) and mercury
regulation, which are discussed below, may address some of the issues outlined
above. PEC and PEF have each 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 Clean Air Mercury Rule (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. In March 2008, 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 $1.5 billion to $1.6 billion at the time of the filing. The
increase in estimated total capital expenditures from the original 2002 estimate
of $813 million is primarily due to the higher cost and revised quantities of
construction materials, such as concrete and steel, refinement of cost and scope
estimates for the current projects, increases in the estimated inflation factor
applied to future project costs, and the impact of additional planning for
Sutton Unit No. 3 and Cape Fear Units No. 5 and No. 6. We are continuing to
evaluate various design, technology and new generation options that could
further change expenditures required by the Clean Smokestacks Act. 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. O&M expenses
will significantly increase due to the cost of reagents, additional personnel
and general maintenance associated with the pollution control equipment. Recent
legislation in North




89




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. See discussion regarding future recovery of costs to comply
with the Clean Smokestacks Act in Note 4A. We cannot predict the outcome of this
matter.




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
12B).




Pursuant
to the Clean Smokestacks Act, PEC entered into an agreement with the state of
North Carolina to transfer to the state certain NOx and SO2 emissions
allowances that result from compliance with the collective NOx and SO2 emissions
limitations set in the Clean Smokestacks Act. The Clean Smokestacks Act also
required the state to undertake a study of mercury and CO2 emissions
in North Carolina. The future regulatory interpretation, implementation or
impact of the Clean Smokestacks Act cannot be predicted.




Clean Air Interstate
Rule




On March
10, 2005, the EPA issued the final CAIR. The EPA’s rule required the District of
Columbia and 28 states, including North Carolina, South Carolina and Florida, to
reduce NOx and SO2 emissions
in order to reduce levels of fine particulate matter and impacts to visibility.
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
joined a coalition of Florida utilities that filed a challenge to the CAIR as it
applied to Florida. 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. The Court will not issue its mandate for at least 45 days following
the date of the decision, pending whether petitions for rehearing are submitted
and granted. The outcome of this matter cannot be predicted.




The
Utilities are considering continuing construction of in-process CAIR projects.
We believe our historical costs related to CAIR compliance are prudent and will
be recoverable under base rates or applicable cost recovery clauses as the costs
were incurred in pursuit of compliance with a mandatory law or regulation.
Although the Utilities have not made a final determination whether to continue
the in-process CAIR projects or whether the schedule for these projects should
be modified, it is likely that they will be completed. In making this decision,
the Utilities will take into account the status of the projects, the probability
of regulatory changes to replace the vacated CAIR requirements and the need to
comply with environmental rules and regulations other than the
CAIR.




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. As a result of the decision to vacate the CAIR, the SO2 and annual
NOx emission allowances markets have been very volatile andthe
market prices for emission allowances have declined. At June 30, 2008, PEC had
approximately $1 million in NOx seasonal emission allowances, which will be
utilized to comply with existing requirements for the NOx SIP Call Rule under
Section 110 of the Clean Air Act (NOx SIP Call), and approximately $29 million
in SO2
emission allowances, which will be utilized to comply with existing Clean Air
Act requirements. PEC currently has no purchased CAIR seasonal or annual NOx
allowances in its emission inventory balances. In order to achieve compliance
with the requirements of the CAIR pursuant to its Integrated Clean Air
Compliance Plan, PEF needed to purchase CAIR seasonal and annual NOx allowances.
At June 30, 2008, PEF had approximately $59 million in annual NOx emission
allowance inventory, approximately $7 million in seasonal NOx emission allowance
inventory and approximately $18 million in SO2emission
allowance inventory. PEF believes the purchases of NOx emission allowances to
comply with the requirements of the CAIR were prudent and continues to expect to
recover the costs of these allowances through its ECRC. PEF’s SO2 emission
allowances will be utilized to comply with existing Clean Air Act
requirements.




90


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 approach for limiting mercury emissions from
coal-fired power plants. Sixteen states subsequently petitioned for a review of
the EPA’s determination confirming the delisting. On February 8, 2008, the D. C.
Court of Appeals decided in favor of the petitioners and vacated the delisting
determination and the CAMR. On March 24, 2008, the EPA and the Utility Air
Regulatory Group, of which PEC and PEF are members, filed petitions for
rehearing by the full court of appeals, which were denied on May 20, 2008. 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 and the petitions
for rehearing 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. 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, Bartow Unit No. 3 and Crystal River
Units No. 1 and No. 2. The reductions associated with BART begin in 2013. 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 decision vacating the CAIR will negate the EPA's
determination that implementation of the CAIR satisfies BART for SO2 and NOx
for BART-affected units under the CAVR. As a result, for BART-affected units,
CAVR compliance will require consideration of NOx and SO2 emissions
in addition to particulate matter emissions. As a result, BART for SO2 and NOx
may now specifically apply to PEC's and PEF's affected 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 requires 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.




Compliance
Strategy




Both PEC
and PEF have been developing an integrated compliance strategy to meet the
requirements of the CAIR, CAVR and mercury regulation. The air quality controls
installed to comply with the 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 Florida. Expenditures for the NOx SIP Call
included the cost to install NOx controls under North Carolina’s and South
Carolina’s programs to comply with the federal eight-hour ozone
standard.




On
October 14, 2005, the FPSC approved PEF’s petition for the recovery of costs
associated with the development and implementation of an Integrated Clean Air
Compliance Plan to comply with the CAIR, CAMR and CAVR through the ECRC (see
discussion above regarding the vacating of the CAIR and CAMR). On March 31,
2006, PEF filed a series of compliance alternatives with the FPSC to meet these
federal environmental rules. At the time, PEF’s recommended proposed compliance
plan included approximately $740 million of estimated capital costs expected to
be spent through 2016, to plan, design, build and install pollution control
equipment at the Anclote and Crystal River plants. On November 6, 2006, the FPSC
approved PEF’s petition for its integrated strategy to address compliance with
the CAIR, CAMR and CAVR. They also approved cost recovery of prudently incurred
costs necessary to achieve this strategy. On June 1, 2007, PEF filed a
supplemental petition for approval of its




91




recommended compliance
plan and associated contracts and recovery of costs for air pollution control
projects. The estimated capital cost for the recommended plan was $1.26 billion
in the June 1, 2007 filing. The increase from the estimates filed in March 2006
is primarily due to the higher cost of labor and construction materials, such as
concrete and steel, and refinement of cost and scope estimates for the current
projects. On April 2, 2008, PEF filed a petition for approval true-up of final
environmental costs for the period January 2007 to December 2007 and a review of
the integrated clean air compliance plan, which reconfirmed the efficacy of the
recommended plan. 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 compliance requirements of a revised or new implementing rule
for clean air. 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. The following tables contain information about our
current estimates of capital expenditures to comply with environmental laws and
regulations described above. 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 are evaluating the impact that vacating the CAIR will have on
our compliance with the CAVR requirements and will reassess our plans and
estimated costs to comply with the CAVR. Our previous estimated costs to comply
with the CAVR were approximately $100 million at PEC and $1.0 billion at PEF.
The timing and extent of the costs for future projects will depend upon final
compliance strategies.


Progress
      EnergyAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
            
            Estimated
              Timetable
            
            
            Total
      Estimated
              Expenditures
            
            
            Cumulative
      Spent through
              June
      30, 2008Clean
      Smokestacks Act
            
            
            2002–2013
            
            
            $
            1,500
      – 1,600
            
            
            $
            958In-process
      CAIR projects(a)
            
            
            2005–2010
            
            
            
            1,200
            
            
            
            639CAVR(b)
            
            
            –2017
            
            
            
            –
            
            
            
            –Mercury
      regulation(c)
            
            
            2006–2017
            
            
            
            –
            
            
            
            4Total
      air quality
            
            
            
            
            
            
            2,700
      – 2,800
            
            
            
            1,601Clean
      Water Act Section 316(b)(d)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air and water quality
            
            
            
            
            
            $
            2,700
      – 2,800
            
            
            $
            1,601





PECAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
            
            Estimated
              Timetable
            
            
            Total
      Estimated
              Expenditures
            
            
            Cumulative
      Spent through
              June
      30, 2008Clean
      Smokestacks Act
            
            
            2002–2013
            
            
            $
            1,500
      – 1,600
            
            
            $
            958In-process
      CAIR projects(a)
            
            
            2005–2008
            
            
            
            –
            
            
            
            14CAVR(b)
            
            
            –2017
            
            
            
            –
            
            
            
            –Mercury
      regulation(c)
            
            
            2006–2017
            
            
            
            –
            
            
            
            4Total
      air quality
            
            
            
            
            
            
            1,500
      – 1,600
            
            
            
            976Clean
      Water Act Section 316(b)(d)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air and water quality
            
            
            
            
            
            $
            1,500
      – 1,600
            
            
            $
            976




92





PEFAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
            
            Estimated
              Timetable
            
            
            Total
      Estimated
              Expenditures
            
            
            Cumulative
      Spent through
              June
      30, 2008In-process
      CAIR projects(a)
            
            
            2005–2010
            
            
            $
            1,200
            
            
            $
            625CAVR(b)
            
            
            –2017
            
            
            
            –
            
            
            
            –Mercury
      regulation(c)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air quality
            
            
            
            
            
            
            1,200
            
            
            
            625Clean
      Water Act Section 316(b)(d)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air and water quality
            
            
            
            
            
            $
            1,200
            
            
            $
            625





(a)
            The
      Utilities are considering continuing construction on in-process CAIR
      projects. Additional 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 AirInterstate
      Rule.”


(b)
            As
      a result of the decision vacating the CAIR, compliance plans and costs to
      meet the requirements of the CAVR are being reassessed. See discussion
      under “Clean Air Visibility Rule.”


(c)
            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.”


(d)
            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.”





To date,
under the first phase of Clean Smokestacks Act emission reductions, all
environmental compliance projects at PEC’s Asheville and Lee plants and several
projects at PEC’s Roxboro plant have been placed in service. The remaining
projects at PEC’s two largest plants, Roxboro and Mayo, are under construction
and are expected to be completed in 2008 and 2009, respectively. 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. As discussed above, our Clean Smokestacks Act compliance
costs have increased from December 31, 2007.PEC's in-process CAIR
project is not expected to require additional material expenditures. However,
additional compliance projects requiring material environmental compliance costs
may be implemented in the future.




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 court decisions that vacated the CAIR, the delisting determination and the
CAMR discussed above, PEF is currently unable to estimate certain costs of
compliance and consequently, its estimated total air and water quality
compliance expenditures have decreased from December 31, 2007. 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
coal-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 air quality standards for ozone and
particulate matter. On March 16, 2006, the EPA issued a final response denying
the petition. The EPA's rationale for denial is that compliance with the CAIR
will reduce the emissions from surrounding states sufficiently to address North
Carolina's concerns. On June 26, 2006, the North Carolina attorney general filed
a petition in the D.C. Court of Appeals seeking a review of the agency’s final
action on the petition. This case is being held in abeyance until the challenges
to the CAIR have been resolved. The outcome of this matter cannot be
predicted.




National Ambient Air Quality
Standards




On
December 21, 2005, the EPA announced proposed changes to the National Ambient
Air Quality Standards (NAAQS) for particulate matter. The EPA proposed to lower
the 24-hour standard for particulate matter less than




93


2.5 microns
in diameter (PM 2.5) from 65 micrograms per cubic meter to 35 micrograms per
cubic meter. In addition, the EPA proposed to establish a new 24-hour standard
of 70 micrograms per cubic meter for particulate matter that is between 2.5 and
10 microns in diameter (PM 2.5-10). The EPA also proposed to eliminate the
current standards for particulate matter less than 10 microns in diameter (PM
10). On September 20, 2006, the EPA announced that it is finalizing the PM 2.5
NAAQS as proposed. In addition, the EPA decided not to establish a PM 2.5-10
NAAQS, and it is eliminating the annual PM 10 NAAQS, but the EPA is retaining
the 24-hour PM 10 NAAQS. These changes are not expected to result in designation
of any additional nonattainment areas in PEC’s or PEF’s service territories. On
December 18, 2006, environmental groups and 13 states filed a joint petition
with the D.C. Court of Appeals arguing that the EPA's new particulate matter
rule does not adequately restrict levels of particulate matter. 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. Depending on air quality improvements expected over
the next several years as current federal requirements are implemented,
additional nonattainment areas may be designated in PEC’s and PEF’s service
territories. 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 outcome of this matter cannot be predicted.




On May
20, 2008, the EPA proposed a revision to the NAAQS for lead to a level in the
0.10 to 0.30 micrograms per cubic meter range. The current standard is 1.5
micrograms per cubic meter, calendar quarter average. The EPA is also requesting
comment on the averaging time options of calendar quarter or monthly. The
outcome of this matter cannot be predicted; however, the proposed revision is
not expected to have a material impact on our or the Utilities results of
operations or financial position.




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 (NSR) 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 were in excess of $1.0 billion. These settlement
agreements have generally called for expenditures to be made over extended time
periods, and some of the companies may seek recovery of the related costs
through rate adjustments or similar mechanisms.




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 may be generated at the
affected facilities. Integration of these new wastewater streams into the
existing wastewater treatment processes may result in permitting, construction
and treatment requirements imposed on the Utilities in the immediate and
extended future.




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. The July 2004 rule required
assessment of the baseline environmental effect of withdrawal of cooling water
and development of technologies and measures for reducing environmental effects
by certain percentages. Additionally, the rule authorized establishment of
alternative performance standards where the site-specific costs of achieving the
otherwise applicable standards would have been substantially greater than either
the benefits achieved or the costs considered by the EPA during the
rulemaking.




94




Subsequent
to promulgation of the rule, a number of states, environmental groups and others
sought judicial review of the rule. On January 25, 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. On July 9, 2007, 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. On
April 14, 2008, the U.S. Supreme Court agreed to review a portion of the U.S.
Court of Appeals decision and hear arguments related to whether the EPA is
authorized to compare costs with benefits in determining the “best technology
available for minimizing adverse environmental impact” at cooling water intake
structures. 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 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 implementing 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




The Kyoto
Protocol was adopted in 1997 by the United Nations to address global climate
change by reducing emissions of CO2 and other
greenhouse gases. The treaty went into effect on February 16, 2005. The United
States has not adopted the Kyoto Protocol. There are proposals and ongoing
studies at the state and federal levels, including the state of Florida, to
address global climate change that would regulate CO2 and other
greenhouse gases. See further discussion of the executive orders issued by the
governor of Florida to address reduction of greenhouse gas emissions under
“Other Matters – Regulatory Environment.”




Reductions
in CO2
emissions to the levels specified by the Kyoto Protocol and some additional
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. 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 greenhouse gas emissions that
would be presented to the legislature no earlier than January 2010. We have
articulated principles that we believe should be incorporated into any global
climate change policy. While the outcome of this matter cannot be predicted, we
are taking action on this important issue as discussed under “Other Matters –
Increasing Energy Demand.” In addition to a report issued in 2006, we issued an
updated report on global climate change in the second quarter of 2008, which
further evaluates and states our position on this dynamic issue. While we
participate in the development of a national climate change policy framework, we
will continue to actively engage others in our region to develop consensus-based
solutions, as we did with the Clean Smokestacks Act.




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. Circuit Court against the EPA Administrator seeking
an order requiring EPA to make a determination within 60 days of whether
greenhouse gas emissions endanger public health and welfare. The D. C. Circuit
Court denied the petition on June 26, 2008. On July 11, 2008, the EPA issued an
Advance Notice of Proposed Rulemaking inviting public comment on the issues and
options that should be considered in development of comprehensive greenhouse gas
regulation under the Clean Air Act. The impact of these developments cannot be
predicted.




NEW
ACCOUNTING STANDARDS




See Note
2 for a discussion of the impact of new accounting standards.




95


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 2007 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.




Cash
provided by operating activities increased $109 million for the six months ended
June 30, 2008, when compared to the corresponding period in the prior year. The
increase in operating cash flow was primarily due to the $75 million increase
from the change in accounts payable largely driven by the timing and volume of
payments and purchases for fuel and the $60 million increase from payables to
affiliated companies primarily related to timing of settlements with
affiliates.




Cash used
by investing activities increased $8 million for the six months ended June 30,
2008, when compared to the corresponding period in the prior year. The increase
in cash used in investing activities was primarily due to a $63 million change
in advances to affiliated companies and a $50 million decrease in net proceeds
from short-term investments included in available-for-sale securities and other
investments. These impacts were partially offset by a $76 million decrease in
utility property additions, primarily related to lower environmental compliance
expenditures, and a $33 million decrease in nuclear fuel additions.
Available-for-sale securities and other investments include marketable debt and
equity securities and investments held in nuclear decommissioning and benefit
investment trusts.




Net cash
used by financing activities increased by $85 million for the six months ended
June 30, 2008, when compared to the corresponding period in the prior year. The
increase in net cash used by financing activities was due primarily to a $159
million decrease related to advances from affiliates, partially offset by the
$72 million in dividends paid to the Parent in 2007. PEC’s 2008 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 9 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.




96


OTHER
MATTERS




This
information is incorporated herein by reference to “Other Matters” in Progress
Energy’s MD&A, insofar as it relates to PEC.




97


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 2007 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.




Cash
provided by operating activities increased $107 million for the six months ended
June 30, 2008, when compared to the corresponding period in the prior year. The
increase in operating cash flow was primarily due to the $409
million change in derivative collateral liabilities largely driven by
increases in the prices of fuel oil and natural gas, and a $133 million increase
from the change in accounts payable primarily due to the timing and volume of
payments and purchases for fuel and purchased power. These impacts were
partially offset by a $246 million decrease in the recovery of fuel costs due to
the current year under-recovery driven by rising fuel costs, compared to an
over-recovery of fuel costs during the corresponding period in the prior year; a
$107 million decrease from prepayments and other current assets primarily
related to derivative collateral; and a $52 million decrease from the
change in receivables driven by the timing of receipts and increased
revenues.




Cash used
by investing activities increased $254 million for the six months ended June 30,
2008, when compared to the corresponding period in the prior year. The increase
in cash used in investing activities was primarily due to a $432 million
increase in capital expenditures for utility property additions, including a
$255 million increase in environmental compliance expenditures and a $157
million increase in nuclear project expenditures, partially offset by a $149
million decrease from changes in advances to affiliated companies.




Net cash
provided by financing activities was $1.436 billion for the six months ended
June 30, 2008, compared to net cash used by financing activities of $45 million
for the six months ended June 30, 2007, for a net increase of $1.481 billion.
The increase in cash provided by financing activities was primarily due to PEF’s
$1.476 billion net proceeds from issuance of long-term debt as 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 9 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 PEF.




98




OTHER
MATTERS




This
information is incorporated herein by reference to “Other Matters” in Progress
Energy’s MD&A, insofar as it relates to PEF.




99


ITEM
3.QUANTITATIVE ANDQUALITATIVE DISCLOSURES ABOUT
MARKETRISK




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 mitigate such risk by performing credit reviews using, among other
things, publicly available credit ratings of such counterparties (See Note
9).




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 “Safe
Harbor for Forward-Looking Statements” and Item 1A, “Risk Factors” included
within this Form 10-Q and Item 1A, “Risk Factors” to the 2007 Form 10-K 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 nuclear decommissioning trust 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, 2007.




INTEREST RATE
RISK




Our
exposure to changes in interest rates from fixed rate and variable rate
long-term debt at June 30, 2008, has changed from December 31, 2007. The total
notional amount of fixed rate long-term debt at June 30, 2008, was $9.345
billion, with an average interest rate of 6.17% and fair market value of $9.5
billion. The total notional amount of fixed rate long-term debt at December 31,
2007, was $7.947 billion, with an average interest rate of 6.20% and fair market
value of $8.2 billion. The total notional amount of variable rate long-term debt
at June 30, 2008, was $1.411 billion, with an average interest rate of 3.45% and
fair market value of $1.4 billion. The total notional amount of variable rate
long-term debt at December 31, 2007, was $1.411 billion, with an average
interest rate of 4.80% and fair market value of $1.4 billion.




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, 2008 and December 31, 2007, approximately
15 percent of consolidated debt was in floating rate mode, including interest
rate swaps.




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.




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 agreements
with banks with credit ratings of single A or better.




100




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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (SFAS No. 133), 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.




The
following tables summarize the terms, fair market values and exposures of our
interest rate derivative instruments.




CASH FLOW
HEDGES




PEC had
no open interest rate cash flow hedges at June 30, 2008. At December 31, 2007,
PEC had $200 million notional of pay-fixed forward starting swaps to hedge cash
flow risk with regard to future financing transactions. Under terms of these
swap agreements, we will pay a fixed rate and receive a floating rate based on
the 3-month LIBOR. PEF and the Parent had no open interest rate cash flow hedges
at June 30, 2008, and December 31, 2007.


(dollars
      in millions)
            
            Notional
      Amount
            
            
            Pay
            
            Receive
      (a)
            
            Fair
      Value
            
            
            Exposure
      (b)PECRisk hedged at June
      30, 2008
            
            NoneRisk hedged at
      December 31, 2007Anticipated
      10-year debt issue (c)
            
            $
            100
            
            
            
            5.32
            %
            3-month
      LIBOR
            
            $
            (5
            )
            
            $
            (2
            )Anticipated
      30-year debt issue (d)
            
            
            100
            
            
            
            5.50
            %
            3-month
      LIBOR
            
            
            (7
            )
            
            
            (4
            )Total
            
            $
            200
            
            
            
            5.41
            %
            
            
            $
            (12
            )
            
            $
            (6
            )


(a)
            3-month
      LIBOR rate was 4.70% at December 31,
2007.


(b)
            Exposure
      indicates change in value due to 25 basis point unfavorable shift in
      interest rates.


(c)
            Anticipated
      10-year debt issue hedges were terminated on March 10, 2008, in
      conjunction with PEC’s issuance of $325 million 6.30% First Mortgage
      Bonds.


(d)
            Anticipated
      30-year debt issue hedges were terminated on March 10, 2008, in
      conjunction with PEC’s issuance of $325 million 6.30% First Mortgage
      Bonds.





During
2008, PEF entered into a series of forward starting swaps to mitigate exposure
to interest rate risk in anticipation of future debt issuances. On January 8,
2008, PEF entered into a $100 million notional 10-year forward starting swap and
a $100 million notional 30-year forward starting swap. On May 1, 2008, PEF
entered into a $50 million notional 10-year forward starting swap and a $100
million notional 30-year forward starting swap. On May 16, 2008, PEF entered
into a $50 million notional 10-year forward starting swap and a $50 million
notional 30-year forward starting swap. On June 2, 2008, PEF entered into a $50
million notional 30-year forward starting swap. On June 3, 2008, PEF entered
into a $50 million notional 30-year forward starting swap. On June 11, 2008, PEF
terminated the anticipated 10-year and 30-year debt issue hedges in conjunction
with PEF’s issuance of $500 million 5.65% 10-year First Mortgage Bonds and
$1.000 billion 6.40% 30-year First Mortgage Bonds.




MARKETABLE SECURITIES PRICE
RISK




At June
30, 2008 and December 31, 2007, the fair value of our nuclear decommissioning
trust funds was $1.302 billion and $1.384 billion, respectively, including $767
million and $804 million, respectively, for PEC and $535 million and $580
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.




101


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, 2008 and December 31, 2007, the
fair value of CVOs was $36 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, 2008, market price would
result in a $4 million increase in the fair value of the CVOs.




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 physical commodity contracts are not derivatives pursuant to SFAS No. 133 or
qualify and are elected as normal purchases or sales pursuant to SFAS No. 133.
Therefore, such contracts 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 subject to retail regulatory
treatment. At June 30, 2008, substantially all derivative commodity instrument
positions were subject to retail regulatory treatment.




See Note
9 for additional information with regard to our commodity contracts and use of
derivative financial instruments.




DISCONTINUED
OPERATIONS




In
January 2007, we entered into derivative contracts to hedge economically a
portion of our 2007 synthetic fuels cash flow exposure to the risk of rising oil
prices over an average annual oil price range of $63 to $77 per barrel on a New
York Mercantile Exchange (NYMEX) basis. The notional quantity of these oil price
hedge instruments was 25 million barrels and provided protection for the
equivalent of approximately eight million tons of 2007 synthetic fuels
production. The cost of the hedges was approximately $65 million. The contracts
were marked-to-market with changes in fair value recorded through earnings.
Approximately 34 percent of the notional quantity of these contracts was entered
into by Ceredo. As discussed in Notes 1C and 3F, we disposed of our 100 percent
ownership interest in Ceredo in March 2007. Progress Energy remains the primary
beneficiary of, and consolidates Ceredo in accordance with FIN 46R, with a 100
percent minority interest. Consequently, subsequent to the disposal there was no
net earnings impact from Ceredo’s operations, which ceased as of December 31,
2007. At December 31, 2007, the $234 million fair value of these contracts,
including $79 million at Ceredo, was included in receivables, net on the
Consolidated Balance Sheet. The contracts ended on December 31, 2007, and were
settled for cash on January 8, 2008, with no material impact to 2008 earnings.
For the three months ended June 30, 2007, we recorded net pre-tax losses of $14
million related to these contracts, including $5 million attributable to Ceredo,
which was attributed to minority interest for the portion of the loss subsequent
to disposal. For the six months ended June 30, 2007, we recorded net pre-tax
gains of $31 million related to these contracts, including $10 million
attributable to Ceredo, of which losses of $5 million were attributed to
minority interest for the portion of the loss subsequent to
disposal.




ECONOMIC
DERIVATIVES




Derivative
products, primarily electricity and natural gas 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




102




consistent
with trading positions. We manage open positions with strict policies that limit
our exposure to market risk and require daily reporting to management of
potential financial exposures.




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 on the
Balance Sheets, respectively, until the contracts are settled. Once settled, any
realized gains or losses are passed through the fuel clause. During the three
and six months ended June 30, 2008, PEC recorded a net realized gain of $6
million. During the three and six months ended June 30, 2007, PEC recorded a net
realized loss of less than $1 million. During the three and six months ended
June 30, 2008, PEF recorded net realized gains of $103 million and $119 million,
respectively. During the three and six months ended June 30, 2007, PEF recorded
net realized losses of $5 million and $22 million, respectively.




The
December 31, 2007 balances presented below reflect the retrospective adoption of
FSP FIN 39-1 (See Note 2).




At June
30, 2008, the fair value of PEC’s commodity derivative instruments was recorded
as a $42 million short-term derivative asset position included in prepayments
and other current assets and a $113 million long-term derivative asset position
included in derivative assets on the PEC Consolidated Balance Sheet. At December
31, 2007, the fair value of such instruments were recorded as a $4 million
short-term derivative liability included in other current liabilities and a $19
million long-term derivative asset position included in derivative assets on the
PEC Consolidated Balance Sheet. Certain counterparties have posted cash
collateral with PEC in support of these instruments. PEC had an $11 million cash
collateral liability at June 30, 2008, included in other current liabilities on
the PEC Consolidated Balance sheet, and no cash collateral position at December
31, 2007.




At June
30, 2008, the fair value of PEF’s commodity derivative instruments was recorded
as a $478 million short-term derivative asset position included in current
derivative assets, a $504 million long-term derivative asset position included
in derivative assets, a $2 million short-term liability position included in
derivative liabilities, and a $1 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet. At
December 31, 2007, the fair value of such instruments were recorded as an $83
million short-term derivative asset position included in current derivative
assets, a $100 million long-term derivative asset position included in
derivative assets, a $38 million short-term liability position included in
derivative liabilities, and a $9 million long-term derivative liability position
included in other liabilities and deferred credits on the PEF Balance Sheet.
Certain counterparties have posted cash collateral with PEF in support of these
instruments. PEF had a $409 million cash collateral liability at June 30, 2008,
included in derivative collateral liabilities on the PEF Balance Sheet, and no
cash collateral position at December 31, 2007.




CASH
FLOW HEDGES




PEC
designates a portion of commodity derivative instruments as cash flow hedges
under SFAS No. 133. The objective for holding these instruments is to 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. At June 30, 2008 and December 31, 2007, 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, 2008 and
2007.




At June
30, 2008 and December 31, 2007, neither we nor the Utilities had amounts
recorded in accumulated other comprehensive income related to commodity cash
flow hedges.




103


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 nuclear decommissioning trust funds, and changes in energy
related commodity prices. Other than as discussed above, PEC’s exposure to these
risks has not materially changed since December 31, 2007.




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).




104


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, 2008, 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, 2008, 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, and 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, 2008, that has materially affected, or is reasonably
likely to materially affect, its internal control over financial
reporting.




105




PART
II.  OTHER INFORMATION





ITEM
1.LEGAL
PROCEEDINGS




Legal
aspects of certain matters are set forth in PART I, Item 1 (See Note
13C).




ITEM
1A.RISK FACTORS




In
addition to the other information set forth in this report, you should carefully
consider the factors discussed in Part I, Item 1A. Risk Factors to the 2007 Form
10-K, which could materially affect our business, financial condition or future
results. The risks described in the 2007 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.




With the
2008 divestiture of Terminals and Coal Mining, we are no longer subject to
operational and financial risks from operating nonregulated businesses as
disclosed in the 2007 Form 10-K.




ITEM
2.                      UNREGISTERED
SALE OF EQUITY SECURITIES AND USE OF PROCEEDS




RESTRICTED
STOCK UNIT AWARD PAYOUTS




(a)
            Securities
      Delivered. On June 30, 2008, 1,018 shares of our common stock were
      delivered to a former employee pursuant to the terms of the Progress
      Energy 2002 Equity Incentive Plan (EIP), which was approved by the
      Progress Energy’s shareholders on May 8, 2002. Additionally, on June 23,
      2008, 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 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.





ISSUER
PURCHASES OF EQUITY SECURITIES FOR SECOND QUARTER OF 2008




No purchases of our common stock were made by or on behalf
of Progress Energy pursuant to a publicly announced plan or otherwise during the
period ended June 30, 2008.




106


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 14, 2008.





(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.
            212,031,798
            2,884,311
            3,152,163David
      L. Burner
            211,680,031
            3,236,751
            3,151,490Harris
      E. DeLoach, Jr.
            211,250,636
            3,652,473
            3,165,163William
      D. Johnson
            211,529,523
            3,404,311
            3,134,438Robert
      W. Jones
            211,665,570
            3,245,676
            3,157,026W.
      Steven Jones
            211,424,984
            3,454,718
            3,188,570E.
      Marie McKee
            198,152,557
            16,746,374
            3,169,341John
      H. Mullin, III
            211,524,715
            3,347,779
            3,195,778Charles
      W. Pryor, Jr.
            211,786,481
            3,114,968
            3,166,823Carlos
      A. Saladrigas
            211,884,374
            3,030,450
            3,153,448Theresa
      M. Stone
            211,783,964
            2,666,624
            3,617,684Alfred
      C. Tollison, Jr.
            211,755,092
            3,156,595
            3,156,585





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 213,254,479


The
number of shares voted against the proposal was 2,095,923


The
number of abstaining votes was 2,717,870





The
shareholder proposal relating to the policy regarding executive compensation was
rejected by the shareholders.





The
number of shares voted for the proposal was 68,199,339


The
number of shares voted against the proposal was 96,451,104


The
number of abstaining votes was 6,668,829


The
number of broker non-votes was 46,749,000





PEC




(a)
            The
      Annual Meeting of the Shareholders of Carolina Power & Light Company
      was held on May 14, 2008.





(b)
            The
      meeting involved the election of two Class I directors (term expiring in
      2011). 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 I (Term Expiring
      in 2011)John
      R. McArthur
            160,107,236
            2,506Peter
      M. Scott III
            160,107,083
            2,659




107


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 160,107,981


The
number of shares voted against the proposal was 591


The
number of abstaining votes was 1,170




108


ITEM 6.      EXHIBITS




(a)
            Exhibits


Exhibit
              Number
            Description
            Progress
              Energy
            PEC
            PEF31(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




109





SIGNATURES




Pursuant
to requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its 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 8, 2008
            (Registrants)By: /s/ Peter M. Scott
      IIIPeter
      M. Scott IIIExecutive
      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.





110