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 September 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 Number1-15929
            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
October 31, 2008, each registrant had the following shares of common stock
outstanding:





Registrant
            Description
            SharesProgress
      Energy
            Common
      Stock (Without Par Value)
            263,087,236PEC
            Common
      Stock (Without Par Value)
            159,608,055
      (all of which were held directly by Progress Energy,
  Inc.)PEF
            Common
      Stock (Without Par Value)
            100
      (all of which were held indirectly by Progress Energy,
    Inc.)





This
combined Form 10-Q is filed separately by three registrants: Progress Energy,
PEC and PEF (collectively, the Progress Registrants). Information contained
herein relating to any individual registrant is filed by such registrant solely
on its own behalf. Each registrant makes no representation as to information
relating exclusively to the other registrants.





PEF meets the conditions set forth in
General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this
form with the reduced disclosure format.


2





TABLE
      OF CONTENTSGLOSSARY OF TERMSSAFE HARBOR FOR FORWARD-LOOKING
      STATEMENTSPART
      I.  FINANCIAL INFORMATIONITEM
      1.
            FINANCIAL STATEMENTSUnaudited
      Condensed Interim Financial Statements:Progress Energy, Inc.
      (Progress Energy)Unaudited Condensed Consolidated Statements of
      IncomeUnaudited Condensed Consolidated Balance
      SheetsUnaudited Condensed Consolidated Statements of Cash
      FlowsCarolina Power &
      Light Company d/b/a Progress Energy Carolinas, Inc.
      (PEC)Unaudited Condensed Consolidated Statements of
      IncomeUnaudited Condensed Consolidated Balance
      SheetsUnaudited Condensed Consolidated Statements of Cash
      FlowsFlorida Power
      Corporation d/b/a Progress Energy Florida, Inc.
    (PEF)Unaudited Condensed Statements of
      IncomeUnaudited Condensed Balance
  SheetsUnaudited Condensed Statements of Cash
      FlowsCombined Notes to Unaudited Condensed Interim Financial
      Statements for Progress Energy, Inc., Carolina Power & Light Company
      d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a
      Progress Energy Florida, Inc.ITEM
      2.
            MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
      AND RESULTS OF OPERATIONSITEM
      3.
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISKITEM
      4.
            CONTROLS AND PROCEDURESITEM
      4T.
            CONTROLS AND PROCEDURESPART
      II.  OTHER INFORMATIONITEM
      1.
            LEGAL PROCEEDINGSITEM
      1A.
            RISK FACTORSITEM
      2.
            UNREGISTERED SALES OF EQUITY SECURITIES AND USE
      OF PROCEEDSITEM
      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 investmentAmbac
            Ambac
      Assurance CorporationARO
            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


DSDR
              DSM
            Distribution
      system demand response
              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 No. FIN 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
      Interbank Offered 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
    2003MGP
            Manufactured
      gas plant




5




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
            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, LLCRPS
            Renewable
      portfolio standardRSA
            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”SIFMA
            Securities
      Industry and Financial Markets Association’s Municipal Swap
      Index




7




SNG
            Southern
      Natural Gas CompanySO2
            Sulfur
      dioxideSubordinated
      Notes
            7.10%
      Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding
      Corp.Syncora
            Syncora
      Guarantee Inc., formerly XL Capital Assurance, Inc.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 PEFWard
            Ward
      Transformer site located in Raleigh, N.C.Ward
      OU1
            Operable
      unit for stream segments downstream from the Ward siteWard
      OU2
            Operable
      unit for further investigation at the Ward facility and certain adjacent
      areasWinchester
      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 length and severity of the current financial
market distress that began in September 2008; the ability to successfully access
capital markets on favorable terms; the stability of commercial credit markets
and our access to short-term and long-term credit; the impact that increases in
leverage may have on each of the Progress Registrants; the Progress Registrants’
ability to maintain their current credit ratings and the impact on the Progress
Registrants’ financial condition and ability to meet their cash and other
financial obligations in the event their credit ratings are downgraded; our
ability to fully utilize tax credits generated from the previous production and
sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K
(Section 29/45K); the investment performance of our nuclear decommissioning
trust 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


September
30, 2008





UNAUDITED
      CONDENSED CONSOLIDATED STATEMENTS of INCOMEThree
      months ended September 30,
            
            
            Nine
      months ended September 30,(in
      millions except per share data)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            
            $
            2,696
            
            
            $
            2,750
            
            
            $
            7,006
            
            
            $
            6,951Operating
      expensesFuel
      used in electric generation
            
            
            869
            
            
            
            929
            
            
            
            2,262
            
            
            
            2,381Purchased
      power
            
            
            450
            
            
            
            390
            
            
            
            1,012
            
            
            
            894Operation
      and maintenance
            
            
            439
            
            
            
            456
            
            
            
            1,370
            
            
            
            1,337Depreciation
      and amortization
            
            
            205
            
            
            
            223
            
            
            
            619
            
            
            
            665Taxes
      other than on income
            
            
            141
            
            
            
            135
            
            
            
            387
            
            
            
            384Other
            
            
            1
            
            
            
            7
            
            
            
            (6
            )
            
            
            28Total
      operating expenses
            
            
            2,105
            
            
            
            2,140
            
            
            
            5,644
            
            
            
            5,689Operating
      income
            
            
            591
            
            
            
            610
            
            
            
            1,362
            
            
            
            1,262Other
      income (expense)Interest
      income
            
            
            8
            
            
            
            6
            
            
            
            20
            
            
            
            20Allowance
      for equity funds used during construction
            
            
            34
            
            
            
            14
            
            
            
            84
            
            
            
            34Other,
      net
            
            
            (7
            )
            
            
            (5
            )
            
            
            (9
            )
            
            
            (6
            )Total
      other income, net
            
            
            35
            
            
            
            15
            
            
            
            95
            
            
            
            48Interest
      chargesInterest
      charges
            
            
            178
            
            
            
            159
            
            
            
            493
            
            
            
            443Allowance
      for borrowed funds used during construction
            
            
            (11
            )
            
            
            (5
            )
            
            
            (27
            )
            
            
            (12
            )Total
      interest charges, net
            
            
            167
            
            
            
            154
            
            
            
            466
            
            
            
            431Income
      from continuing operations before income tax and minority
      interest
            
            
            459
            
            
            
            471
            
            
            
            991
            
            
            
            879Income
      tax expense
            
            
            150
            
            
            
            160
            
            
            
            329
            
            
            
            273Income
      from continuing operations before minority interest
            
            
            309
            
            
            
            311
            
            
            
            662
            
            
            
            606Minority
      interest in subsidiaries’ income, net of tax
            
            
            (1
            )
            
            
            –
            
            
            
            (5
            )
            
            
            (8
            )Income
      from continuing operations
            
            
            308
            
            
            
            311
            
            
            
            657
            
            
            
            598Discontinued
      operations, net of tax
            
            
            1
            
            
            
            8
            
            
            
            66
            
            
            
            (197
            )Net
      income
            
            $
            309
            
            
            $
            319
            
            
            $
            723
            
            
            $
            401Average
      common shares outstanding – basic
            
            
            261
            
            
            
            257
            
            
            
            260
            
            
            
            256Basic
      earnings per common shareIncome
      from continuing operations
            
            $
            1.18
            
            
            $
            1.21
            
            
            $
            2.52
            
            
            $
            2.34Discontinued
      operations, net of tax
            
            
            0.01
            
            
            
            0.03
            
            
            
            0.26
            
            
            
            (0.77
            )Net
      income
            
            $
            1.19
            
            
            $
            1.24
            
            
            $
            2.78
            
            
            $
            1.57Diluted
      earnings per common shareIncome
      from continuing operations
            
            $
            1.18
            
            
            $
            1.21
            
            
            $
            2.52
            
            
            $
            2.33Discontinued
      operations, net of tax
            
            
            –
            
            
            
            0.03
            
            
            
            0.26
            
            
            
            (0.77
            )Net
      income
            
            $
            1.18
            
            
            $
            1.24
            
            
            $
            2.78
            
            
            $
            1.56Dividends
      declared per common share
            
            $
            0.615
            
            
            $
            0.610
            
            
            $
            1.845
            
            
            $
            1.830




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


10




PROGRESS
ENERGY, INC.


UNAUDITED CONDENSED CONSOLIDATED BALANCE
      SHEETS(in
      millions)
            
            September
      30, 2008
            
            December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
            
            $
            25,987
            
            $
            25,327Accumulated
      depreciation
            
            
            (11,208
            )
            
            (10,895
            )Utility
      plant in service, net
            
            
            14,779
            
            
            14,432Held
      for future use
            
            
            38
            
            
            37Construction
      work in progress
            
            
            2,672
            
            
            1,765Nuclear
      fuel, net of amortization
            
            
            426
            
            
            371Total
      utility plant, net
            
            
            17,915
            
            
            16,605Current
      assetsCash
      and cash equivalents
            
            
            403
            
            
            255Receivables,
      net
            
            
            996
            
            
            1,167Inventory
            
            
            1,117
            
            
            994Deferred
      fuel cost
            
            
            291
            
            
            154Derivative
      assets
            
            
            64
            
            
            85Assets
      to be divested
            
            
            –
            
            
            52Prepayments
      and other current assets
            
            
            278
            
            
            122Total
      current assets
            
            
            3,149
            
            
            2,829Deferred
      debits and other assetsRegulatory
      assets
            
            
            1,347
            
            
            946Nuclear
      decommissioning trust funds
            
            
            1,210
            
            
            1,384Miscellaneous
      other property and investments
            
            
            460
            
            
            448Goodwill
            
            
            3,655
            
            
            3,655Derivative
      assets
            
            
            109
            
            
            119Other
      assets and deferred debits
            
            
            392
            
            
            379Total
      deferred debits and other assets
            
            
            7,173
            
            
            6,931Total
      assets
            
            $
            28,237
            
            $
            26,365CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 500 million shares authorized, 263 million and
      260 million shares issued and outstanding, respectively
            
            $
            6,173
            
            $
            6,028Unearned
      ESOP shares (1 million and 2 million shares, respectively)
            
            
            (25
            )
            
            (37
            )Accumulated
      other comprehensive loss
            
            
            (26
            )
            
            (34
            )Retained
      earnings
            
            
            2,705
            
            
            2,465Total
      common stock equity
            
            
            8,827
            
            
            8,422Preferred
      stock of subsidiaries – not subject to mandatory
redemption
            
            
            93
            
            
            93Minority
      interest
            
            
            6
            
            
            84Long-term
      debt, affiliate
            
            
            272
            
            
            271Long-term
      debt, net
            
            
            9,886
            
            
            8,466Total
      capitalization
            
            
            19,084
            
            
            17,336Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            400
            
            
            877Short-term
      debt
            
            
            495
            
            
            201Accounts
      payable
            
            
            944
            
            
            819Interest
      accrued
            
            
            144
            
            
            173Dividends
      declared
            
            
            162
            
            
            160Customer
      deposits
            
            
            272
            
            
            255Regulatory
      liabilities
            
            
            15
            
            
            173Liabilities
      to be divested
            
            
            –
            
            
            8Other
      current liabilities
            
            
            635
            
            
            636Total
      current liabilities
            
            
            3,067
            
            
            3,302Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            726
            
            
            361Accumulated
      deferred investment tax credits
            
            
            130
            
            
            139Regulatory
      liabilities
            
            
            2,457
            
            
            2,554Asset
      retirement obligations
            
            
            1,437
            
            
            1,378Accrued
      pension and other benefits
            
            
            761
            
            
            763Capital
      lease obligations
            
            
            231
            
            
            239Other
      liabilities and deferred credits
            
            
            344
            
            
            293Total
      deferred credits and other liabilities
            
            
            6,086
            
            
            5,727Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
            
            $
            28,237
            
            $
            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)Nine
      months ended September 30
            
            2008
            
            
            2007Operating
      activitiesNet
      income
            
            $
            723
            
            
            $
            401Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
            
            
            703
            
            
            
            756Deferred
      income taxes and investment tax credits, net
            
            
            270
            
            
            
            157Deferred
      fuel (credit) cost
            
            
            (330
            )
            
            
            28Deferred
      income
            
            
            –
            
            
            
            (98
            )Allowance
      for equity funds used during construction
            
            
            (84
            )
            
            
            (34
            )Other
      adjustments to net income
            
            
            29
            
            
            
            127Cash
      provided (used) by changes in operating assets and
    liabilitiesReceivables
            
            
            150
            
            
            
            (153
            )Inventory
            
            
            (124
            )
            
            
            (14
            )Prepayments
      and other current assets
            
            
            26
            
            
            
            (73
            )Income
      taxes, net
            
            
            (92
            )
            
            
            (343
            )Accounts
      payable
            
            
            181
            
            
            
            63Other
      current liabilities
            
            
            (24
            )
            
            
            103Other
      assets and deferred debits
            
            
            (62
            )
            
            
            (148
            )Other
      liabilities and deferred credits
            
            
            (7
            )
            
            
            (34
            )Net
      cash provided by operating activities
            
            
            1,359
            
            
            
            738Investing
      activitiesGross
      property additions
            
            
            (1,760
            )
            
            
            (1,411
            )Nuclear
      fuel additions
            
            
            (158
            )
            
            
            (198
            )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
            
            
            63
            
            
            
            658Purchases
      of available-for-sale securities and other investments
            
            
            (1,190
            )
            
            
            (1,072
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            1,154
            
            
            
            939Other
      investing activities
            
            
            (3
            )
            
            
            16Net
      cash used by investing activities
            
            
            (1,894
            )
            
            
            (1,068
            )Financing
      activitiesIssuance
      of common stock
            
            
            106
            
            
            
            134Dividends
      paid on common stock
            
            
            (481
            )
            
            
            (469
            )Payments
      of short-term debt with original maturities greater than 90
      days
            
            
            (176
            )
            
            
            –Net
      increase in short-term debt
            
            
            470
            
            
            
            550Proceeds
      from issuance of long-term debt, net
            
            
            1,797
            
            
            
            742Retirement
      of long-term debt
            
            
            (877
            )
            
            
            (287
            )Cash
      distributions to minority interests of consolidated
      subsidiaries
            
            
            (85
            )
            
            
            (10
            )Other
      financing activities
            
            
            (71
            )
            
            
            22Net
      cash provided by financing activities
            
            
            683
            
            
            
            682Net increase
      in cash and cash equivalents
            
            
            148
            
            
            
            352Cash
      and cash equivalents at beginning of period
            
            
            255
            
            
            
            265Cash
      and cash equivalents at end of period
            
            $
            403
            
            
            $
            617Supplemental
      disclosuresSignificant
      noncash transactionsCapital
      lease obligation incurred
            
            $
            –
            
            
            $
            182Note
      receivable for disposal of ownership interest in Ceredo
            
            
            –
            
            
            
            48Nuclear
      decommissioning trust funds unrealized loss (gain)
            
            
            198
            
            
            
            (14
            )Accrued
      property additions
            
            
            266
            
            
            
            239


See
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


September
30, 2008





UNAUDITED
      CONDENSED CONSOLIDATED STATEMENTS of INCOMEThree
      months endedSeptember
      30,
            
            
            Nine months endedSeptember
      30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            
            $
            1,266
            
            
            $
            1,286
            
            
            $
            3,382
            
            
            $
            3,340Operating
      expensesFuel
      used in electric generation
            
            
            348
            
            
            
            385
            
            
            
            1,027
            
            
            
            1,041Purchased
      power
            
            
            145
            
            
            
            109
            
            
            
            266
            
            
            
            243Operation
      and maintenance
            
            
            243
            
            
            
            246
            
            
            
            766
            
            
            
            762Depreciation
      and amortization
            
            
            124
            
            
            
            118
            
            
            
            379
            
            
            
            353Taxes
      other than on income
            
            
            53
            
            
            
            52
            
            
            
            152
            
            
            
            151Other
            
            
            –
            
            
            
            1
            
            
            
            (6
            )
            
            
            –Total
      operating expenses
            
            
            913
            
            
            
            911
            
            
            
            2,584
            
            
            
            2,550Operating
      income
            
            
            353
            
            
            
            375
            
            
            
            798
            
            
            
            790Other
      income (expense)Interest
      income
            
            
            2
            
            
            
            5
            
            
            
            9
            
            
            
            16Allowance
      for equity funds used during construction
            
            
            9
            
            
            
            2
            
            
            
            19
            
            
            
            7Other,
      net
            
            
            (5
            )
            
            
            (3
            )
            
            
            –
            
            
            
            2Total
      other income, net
            
            
            6
            
            
            
            4
            
            
            
            28
            
            
            
            25Interest
      chargesInterest
      charges
            
            
            54
            
            
            
            58
            
            
            
            164
            
            
            
            169Allowance
      for borrowed funds used during construction
            
            
            (4
            )
            
            
            (2
            )
            
            
            (8
            )
            
            
            (4
            )Total
      interest charges, net
            
            
            50
            
            
            
            56
            
            
            
            156
            
            
            
            165Income
      before income tax
            
            
            309
            
            
            
            323
            
            
            
            670
            
            
            
            650Income
      tax expense
            
            
            108
            
            
            
            119
            
            
            
            242
            
            
            
            234Net
      income
            
            
            201
            
            
            
            204
            
            
            
            428
            
            
            
            416Preferred
      stock dividend requirement
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2Earnings
      for common stock
            
            $
            200
            
            
            $
            203
            
            
            $
            426
            
            
            $
            414





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)
            
            September
      30, 2008
            
            
            December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
            
            $
            15,491
            
            
            $
            15,117Accumulated
      depreciation
            
            
            (7,292
            )
            
            
            (7,097
            )Utility
      plant in service, net
            
            
            8,199
            
            
            
            8,020Held
      for future use
            
            
            3
            
            
            
            2Construction
      work in progress
            
            
            641
            
            
            
            566Nuclear
      fuel, net of amortization
            
            
            331
            
            
            
            292Total
      utility plant, net
            
            
            9,174
            
            
            
            8,880Current
      assetsCash
      and cash equivalents
            
            
            145
            
            
            
            25Receivables,
      net
            
            
            532
            
            
            
            491Receivables
      from affiliated companies
            
            
            19
            
            
            
            42Inventory
            
            
            573
            
            
            
            510Deferred
      fuel cost
            
            
            143
            
            
            
            148Prepayments
      and other current assets
            
            
            53
            
            
            
            50Total
      current assets
            
            
            1,465
            
            
            
            1,266Deferred
      debits and other assetsRegulatory
      assets
            
            
            769
            
            
            
            680Nuclear
      decommissioning trust funds
            
            
            723
            
            
            
            804Miscellaneous
      other property and investments
            
            
            197
            
            
            
            192Other
      assets and deferred debits
            
            
            164
            
            
            
            160Total
      deferred debits and other assets
            
            
            1,853
            
            
            
            1,836Total
      assets
            
            $
            12,492
            
            
            $
            11,982CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 200 million shares authorized, 160 million shares
      issued and outstanding
            
            $
            2,079
            
            
            $
            2,054Unearned
      ESOP common stock
            
            
            (25
            )
            
            
            (37
            )Accumulated
      other comprehensive loss
            
            
            (13
            )
            
            
            (10
            )Retained
      earnings
            
            
            2,200
            
            
            
            1,772Total
      common stock equity
            
            
            4,241
            
            
            
            3,779Preferred
      stock – not subject to mandatory redemption
            
            
            59
            
            
            
            59Long-term
      debt, net
            
            
            3,109
            
            
            
            3,183Total
      capitalization
            
            
            7,409
            
            
            
            7,021Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            400
            
            
            
            300Notes
      payable to affiliated companies
            
            
            1
            
            
            
            154Accounts
      payable
            
            
            354
            
            
            
            308Payables
      to affiliated companies
            
            
            71
            
            
            
            71Interest
      accrued
            
            
            52
            
            
            
            58Customer
      deposits
            
            
            79
            
            
            
            70Other
      current liabilities
            
            
            229
            
            
            
            209Total
      current liabilities
            
            
            1,186
            
            
            
            1,170Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            1,065
            
            
            
            936Accumulated
      deferred investment tax credits
            
            
            117
            
            
            
            122Regulatory
      liabilities
            
            
            1,053
            
            
            
            1,098Asset
      retirement obligations
            
            
            1,109
            
            
            
            1,063Accrued
      pension and other benefits
            
            
            448
            
            
            
            459Other
      liabilities and deferred credits
            
            
            105
            
            
            
            113Total
      deferred credits and other liabilities
            
            
            3,897
            
            
            
            3,791Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
            
            $
            12,492
            
            
            $
            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)Nine
      months ended September 30
            
            2008
            
            
            2007Operating
      activitiesNet
      income
            
            $
            428
            
            
            $
            416Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
            
            
            454
            
            
            
            419Deferred
      income taxes and investment tax credits, net
            
            
            113
            
            
            
            62Deferred
      fuel (credit) cost
            
            
            (30
            )
            
            
            7Allowance
      for equity funds used during construction
            
            
            (19
            )
            
            
            (7
            )Other
      adjustments to net income
            
            
            42
            
            
            
            (30
            )Cash
      (used) provided by changes in operating assets and
    liabilitiesReceivables
            
            
            (48
            )
            
            
            (65
            )Receivables
      from affiliated companies
            
            
            23
            
            
            
            (34
            )Inventory
            
            
            (55
            )
            
            
            (2
            )Prepayments
      and other current assets
            
            
            23
            
            
            
            (2
            )Income
      taxes, net
            
            
            (35
            )
            
            
            64Accounts
      payable
            
            
            48
            
            
            
            19Payables
      to affiliated companies
            
            
            –
            
            
            
            23Other
      current liabilities
            
            
            47
            
            
            
            13Other
      assets and deferred debits
            
            
            (7
            )
            
            
            (19
            )Other
      liabilities and deferred credits
            
            
            (52
            )
            
            
            11Net
      cash provided by operating activities
            
            
            932
            
            
            
            875Investing
      activitiesGross
      property additions
            
            
            (518
            )
            
            
            (587
            )Nuclear
      fuel additions
            
            
            (131
            )
            
            
            (159
            )Purchases
      of available-for-sale securities and other investments
            
            
            (464
            )
            
            
            (472
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            433
            
            
            
            498Other
      investing activities
            
            
            3
            
            
            
            3Net
      cash used by investing activities
            
            
            (677
            )
            
            
            (717
            )Financing
      activitiesDividends
      paid on preferred stock
            
            
            (2
            )
            
            
            (2
            )Dividends
      paid to parent
            
            
            –
            
            
            
            (108
            )Net
      increase in short-term debt
            
            
            –
            
            
            
            150Proceeds
      from issuance of long-term debt, net
            
            
            322
            
            
            
            –Retirement
      of long-term debt
            
            
            (300
            )
            
            
            (200
            )Changes
      in advances from affiliated companies
            
            
            (153
            )
            
            
            –Other
      financing activities
            
            
            (2
            )
            
            
            20Net
      cash used by financing activities
            
            
            (135
            )
            
            
            (140
            )Net
      increase in cash and cash equivalents
            
            
            120
            
            
            
            18Cash
      and cash equivalents at beginning of period
            
            
            25
            
            
            
            71Cash
      and cash equivalents at end of period
            
            $
            145
            
            
            $
            89Supplemental
      disclosuresSignificant
      noncash transactionsNuclear
      decommissioning trust funds unrealized loss (gain)
            
            $
            104
            
            
            $
            (9
            )Accrued
      property additions
            
            
            87
            
            
            
            74


See
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


September
30, 2008





UNAUDITED
      CONDENSED STATEMENTS of INCOMEThree
      months endedSeptember
      30,
            
            
            Nine
      months endedSeptember
      30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            
            $
            1,428
            
            
            $
            1,456
            
            
            $
            3,618
            
            
            $
            3,596Operating
      expensesFuel
      used in electric generation
            
            
            521
            
            
            
            544
            
            
            
            1,235
            
            
            
            1,340Purchased
      power
            
            
            305
            
            
            
            281
            
            
            
            746
            
            
            
            651Operation
      and maintenance
            
            
            201
            
            
            
            213
            
            
            
            621
            
            
            
            586Depreciation
      and amortization
            
            
            77
            
            
            
            100
            
            
            
            229
            
            
            
            297Taxes
      other than on income
            
            
            88
            
            
            
            83
            
            
            
            235
            
            
            
            233Other
            
            
            –
            
            
            
            –
            
            
            
            (4
            )
            
            
            12Total
      operating expenses
            
            
            1,192
            
            
            
            1,221
            
            
            
            3,062
            
            
            
            3,119Operating
      income
            
            
            236
            
            
            
            235
            
            
            
            556
            
            
            
            477Other
      income (expense)Interest
      income
            
            
            5
            
            
            
            1
            
            
            
            7
            
            
            
            3Allowance
      for equity funds used during construction
            
            
            25
            
            
            
            12
            
            
            
            65
            
            
            
            27Other,
      net
            
            
            –
            
            
            
            –
            
            
            
            (1
            )
            
            
            –Total
      other income, net
            
            
            30
            
            
            
            13
            
            
            
            71
            
            
            
            30Interest
      chargesInterest
      charges
            
            
            68
            
            
            
            45
            
            
            
            163
            
            
            
            126Allowance
      for borrowed funds used during construction
            
            
            (7
            )
            
            
            (3
            )
            
            
            (19
            )
            
            
            (8
            )Total
      interest charges, net
            
            
            61
            
            
            
            42
            
            
            
            144
            
            
            
            118Income
      before income tax
            
            
            205
            
            
            
            206
            
            
            
            483
            
            
            
            389Income
      tax expense
            
            
            62
            
            
            
            68
            
            
            
            148
            
            
            
            122Net
      income
            
            
            143
            
            
            
            138
            
            
            
            335
            
            
            
            267Preferred
      stock dividend requirement
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Earnings
      for common stock
            
            $
            143
            
            
            $
            138
            
            
            $
            334
            
            
            $
            266





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)
            
            September
      30, 2008
            
            
            December
      31, 2007ASSETSUtility
      plantUtility
      plant in service
            
            $
            10,312
            
            
            $
            10,025Accumulated
      depreciation
            
            
            (3,854
            )
            
            
            (3,738
            )Utility
      plant in service, net
            
            
            6,458
            
            
            
            6,287Held
      for future use
            
            
            35
            
            
            
            35Construction
      work in progress
            
            
            2,031
            
            
            
            1,199Nuclear
      fuel, net of amortization
            
            
            95
            
            
            
            79Total
      utility plant, net
            
            
            8,619
            
            
            
            7,600Current
      assetsCash
      and cash equivalents
            
            
            223
            
            
            
            23Receivables,
      net
            
            
            460
            
            
            
            351Receivables
      from affiliated companies
            
            
            9
            
            
            
            8Notes
      receivable from affiliated companies
            
            
            –
            
            
            
            149Inventory
            
            
            544
            
            
            
            484Deferred
      income taxes
            
            
            71
            
            
            
            39Derivative
      assets
            
            
            59
            
            
            
            83Prepayments
      and other current assets
            
            
            175
            
            
            
            50Total
      current assets
            
            
            1,541
            
            
            
            1,187Deferred
      debits and other assetsRegulatory
      assets
            
            
            578
            
            
            
            266Nuclear
      decommissioning trust funds
            
            
            487
            
            
            
            580Miscellaneous
      other property and investments
            
            
            43
            
            
            
            46Derivative
      assets
            
            
            90
            
            
            
            100Prepaid
      pension cost
            
            
            240
            
            
            
            221Other
      assets and deferred debits
            
            
            60
            
            
            
            63Total
      deferred debits and other assets
            
            
            1,498
            
            
            
            1,276Total
      assets
            
            $
            11,658
            
            
            $
            10,063CAPITALIZATION
      AND LIABILITIESCommon
      stock equityCommon
      stock without par value, 60 million shares authorized, 100 shares issued
      and outstanding
            
            $
            1,115
            
            
            $
            1,109Accumulated
      other comprehensive loss
            
            
            –
            
            
            
            (8
            )Retained
      earnings
            
            
            2,234
            
            
            
            1,901Total
      common stock equity
            
            
            3,349
            
            
            
            3,002Preferred
      stock – not subject to mandatory redemption
            
            
            34
            
            
            
            34Long-term
      debt, net
            
            
            4,182
            
            
            
            2,686Total
      capitalization
            
            
            7,565
            
            
            
            5,722Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            –
            
            
            
            532Notes
      payable to affiliated companies
            
            
            2
            
            
            
            –Accounts
      payable
            
            
            571
            
            
            
            473Payables
      to affiliated companies
            
            
            49
            
            
            
            87Interest
      accrued
            
            
            51
            
            
            
            57Customer
      deposits
            
            
            193
            
            
            
            185Derivative
      liabilities
            
            
            133
            
            
            
            38Regulatory
      liabilities
            
            
            15
            
            
            
            173Other
      current liabilities
            
            
            195
            
            
            
            92Total
      current liabilities
            
            
            1,209
            
            
            
            1,637Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            578
            
            
            
            401Accumulated
      deferred investment tax credits
            
            
            13
            
            
            
            17Regulatory
      liabilities
            
            
            1,282
            
            
            
            1,330Asset
      retirement obligations
            
            
            328
            
            
            
            315Accrued
      pension and other benefits
            
            
            303
            
            
            
            304Capital
      lease obligations
            
            
            216
            
            
            
            224Other
      liabilities and deferred credits
            
            
            164
            
            
            
            113Total
      deferred credits and other liabilities
            
            
            2,884
            
            
            
            2,704Commitments
      and contingencies (Notes 12 and 13)Total
      capitalization and liabilities
            
            $
            11,658
            
            
            $
            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)Nine
      months ended September 30
            
            2008
            
            
            2007Operating
      activitiesNet
      income
            
            $
            335
            
            
            $
            267Adjustments
      to reconcile net income to net cash provided by operating
      activitiesDepreciation
      and amortization
            
            
            234
            
            
            
            313Deferred
      income taxes and investment tax credits, net
            
            
            90
            
            
            
            (50
            )Deferred
      fuel (credit) cost
            
            
            (300
            )
            
            
            21Allowance
      for equity funds used during construction
            
            
            (65
            )
            
            
            (27
            )Other
      adjustments to net income
            
            
            17
            
            
            
            54Cash
      (used) provided by changes in operating assets and
    liabilitiesReceivables
            
            
            (120
            )
            
            
            (100
            )Receivables
      from affiliated companies
            
            
            (1
            )
            
            
            (2
            )Inventory
            
            
            (73
            )
            
            
            (22
            )Prepayments
      and other current assets
            
            
            (9
            )
            
            
            56Income
      taxes, net
            
            
            48
            
            
            
            98Accounts
      payable
            
            
            147
            
            
            
            127Payables
      to affiliated companies
            
            
            (38
            )
            
            
            (46
            )Other
      current liabilities
            
            
            74
            
            
            
            69Other
      assets and deferred debits
            
            
            (21
            )
            
            
            (25
            )Other
      liabilities and deferred credits
            
            
            37
            
            
            
            (6
            )Net
      cash provided by operating activities
            
            
            355
            
            
            
            727Investing
      activitiesGross
      property additions
            
            
            (1,229
            )
            
            
            (819
            )Nuclear
      fuel additions
            
            
            (27
            )
            
            
            (39
            )Purchases
      of available-for-sale securities and other investments
            
            
            (616
            )
            
            
            (457
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            618
            
            
            
            279Changes
      in advances to affiliated companies
            
            
            149
            
            
            
            –Proceeds
      from sales of assets to affiliated companies
            
            
            12
            
            
            
            –Other
      investing activities
            
            
            (6
            )
            
            
            –Net
      cash used by investing activities
            
            
            (1,099
            )
            
            
            (1,036
            )Financing
      activitiesDividends
      paid on preferred stock
            
            
            (1
            )
            
            
            (1
            )Proceeds
      from issuance of long-term debt, net
            
            
            1,475
            
            
            
            742Retirement
      of long-term debt
            
            
            (532
            )
            
            
            (87
            )Changes
      in advances from affiliated companies
            
            
            2
            
            
            
            (45
            )Other
      financing activities
            
            
            –
            
            
            
            2Net
      cash provided by financing activities
            
            
            944
            
            
            
            611Net
      increase in cash and cash equivalents
            
            
            200
            
            
            
            302Cash
      and cash equivalents at beginning of period
            
            
            23
            
            
            
            23Cash
      and cash equivalents at end of period
            
            $
            223
            
            
            $
            325Supplemental
      disclosuresSignificant
      noncash transactionsCapital
      lease obligation incurred
            
            $
            –
            
            
            $
            182Nuclear
      decommissioning trust funds unrealized loss (gain)
            
            
            94
            
            
            
            (5
            )Accrued
      property additions
            
            
            176
            
            
            
            165




See
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), the 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 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
nine months ended September 30, 2008, are primarily due to timing of permanent
tax items and seasonal fluctuations in energy sales and earnings from the
Utilities. The fluctuations in the effective tax rate for the three and nine
months ended September 30, 2007, are primarily due to the recognition of
synthetic fuels tax credits, timing of permanent tax items 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 nine months ended September 30, 2008 and
2007, as follows:


Three
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Progress
      Energy
            
            $
            (2
            )
            
            $
            (26
            )
            
            $
            (6
            )
            
            $
            (3
            )PEC
            
            
            3
            
            
            
            (1
            )
            
            
            2
            
            
            
            (2
            )PEF
            
            
            (4
            )
            
            
            (4
            )
            
            
            (7
            )
            
            
            (3
            )





For the
three and nine months ended September 30, 2007, $16 million income and $6
million expense, respectively, of the Progress Energy net tax levelization 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 $16 million
levelization income for the three months ended September 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 September 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
            
            $
            327
            
            
            $
            311Common
      stock dataBasic
      earnings per common shareIncome
      from continuing operations
            
            
            1.27
            
            
            
            1.21Diluted
      earnings per common shareIncome
      from continuing operations
            
            
            1.27
            
            
            
            1.21





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


Three
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Progress
      Energy
            
            $
            89
            
            
            $
            92
            
            
            $
            226
            
            
            $
            229PEC
            
            
            30
            
            
            
            30
            
            
            
            80
            
            
            
            78PEF
            
            
            59
            
            
            
            62
            
            
            
            146
            
            
            
            151





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 September 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 September 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 September 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 $17 million, which primarily represents its
net remaining investment in these entities. The creditors of these variable
interest entities do not have recourse to the general credit of PEC in excess of
the aggregate maximum loss exposure.




22


PEF




PEF has
interests in five variable interest entities for which PEF is not the primary
beneficiary. These arrangements include equity investments or commitments to
invest in three entities whose operations include venture capital investments,
research and development or environmental remediation activities, and one
building lease and one railcar lease with special-purpose entities. The majority
of these interests were entered into prior to 2008. At September 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 $71 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 September 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. FIN 39-1, An Amendment of FIN 39, Offsetting of Amounts
Related to Certain Contracts




On
January 1, 2008, Progress Energy, PEC and PEF implemented FASB Staff Position
No. FIN 39-1, “An Amendment of FIN 39, Offsetting of Amounts Related to Certain
Contracts” (FSP FIN 39-1), which allows a reporting entity to make an accounting
election whether or not to offset fair value amounts recognized for derivative
instruments and related collateral assets and liabilities with the same
counterparty under a master netting agreement. Prior to the adoption of FSP FIN
39-1, we and the Utilities offset fair value amounts recognized for derivative
instruments under master netting arrangements. FSP FIN 39-1 was implemented as a
retrospective change in accounting principle and, upon adoption, Progress
Energy, PEC and PEF 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 nine months ended September 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, $(16) million and $6 million
of tax levelization (benefit) 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 nine months ended September 30,
2007, respectively.





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


Three
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Revenues
            
            $
            –
            
            
            $
            350
            
            
            $
            17
            
            
            $
            888(Loss)
      earnings before income tax and minority interest
            
            
            (1
            )
            
            
            15
            
            
            
            9
            
            
            
            (43
            )Income
      tax benefit
            
            
            1
            
            
            
            5
            
            
            
            13
            
            
            
            98Minority
      interest portion of synthetic fuel (earnings) losses
            
            
            –
            
            
            
            (12
            )
            
            
            (1
            )
            
            
            17Net
      earnings from discontinued operations
            
            
            –
            
            
            
            8
            
            
            
            21
            
            
            
            72Gain
      on disposal of discontinued operations, including income tax expense of
      $7
            
            
            –
            
            
            
            –
            
            
            
            41
            
            
            
            –Earnings
      from discontinued operations
            
            $
            –
            
            
            $
            8
            
            
            $
            62
            
            
            $
            72


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 nine months ended September 30, 2007, we reversed $1
million and $18 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 loss associated with the costs to exit the Georgia Contracts, and
other related contracts, of $349 million after-tax (loss included in the net
earnings (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 nine months ended September 30, 2007, was $11 million. We ceased
recording depreciation upon classification of the assets as discontinued
operations in December 2006. Results of CCO discontinued operations for the
three and nine months ended September 30 were as follows:


Three
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Revenues
            
            $
            –
            
            
            $
            1
            
            
            $
            –
            
            
            $
            407Loss
      before income tax
            
            
            –
            
            
            
            (1
            )
            
            
            (5
            )
            
            
            (444
            )Income
      tax benefit
            
            
            2
            
            
            
            –
            
            
            
            4
            
            
            
            164Net
      earnings (loss) from discontinued operations
            
            
            2
            
            
            
            (1
            )
            
            
            (1
            )
            
            
            (280
            )Gain
      on disposal of discontinued operations, including income tax benefit of $1
      and $8, respectively
            
            
            –
            
            
            
            1
            
            
            
            –
            
            
            
            18Earnings
      (loss) from discontinued operations
            
            $
            2
            
            
            $
            –
            
            
            $
            (1
            )
            
            $
            (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 nine months ended September 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 nine months ended September 30 were as follows:


Three
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Revenues
            
            $
            –
            
            
            $
            8
            
            
            $
            2
            
            
            $
            22Loss
      before income tax
            
            
            (1
            )
            
            
            (2
            )
            
            
            (7
            )
            
            
            (13
            )Income
      tax benefit
            
            
            –
            
            
            
            1
            
            
            
            2
            
            
            
            4Net
      loss from discontinued operations
            
            
            (1
            )
            
            
            (1
            )
            
            
            (5
            )
            
            
            (9
            )Gain
      on disposal of discontinued operations, including income tax expense of
      $2
            
            
            –
            
            
            
            –
            
            
            
            7
            
            
            
            –(Loss)
      earnings from discontinued operations
            
            $
            (1
            )
            
            $
            (1
            )
            
            $
            2
            
            
            $
            (9
            )





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 nine months ended September 30, 2008, we recorded additional
gains of $3 million, net of tax. For the three and nine months ended September
30, 2007, we recorded additional gains of $1 million and $2 million,
respectively, 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 Interbank Offered 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 nine months ended September 30, 2008, based on the final
value of the 2007 Section 29/45K tax credits.




26




During
the nine months ended September 30, 2008, we recognized previously deferred
gains on disposal of $5 million based on the final value of the 2007 Section
29/45K tax credits. The operations of Ceredo ceased as of December 31, 2007, and
are recorded as discontinued operations for all periods presented. See
discussion of the abandonment of our synthetic fuels operations at Note
3A.







4. REGULATORY MATTERS




A.           PEC
RETAIL RATE MATTERS




BASE
RATES




PEC’s
base rates are subject to the regulatory jurisdiction of the NCUC and the 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. 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 compliance
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.




On
September 5, 2008, the NCUC approved PEC’s request to terminate any further
accelerated amortization of its Clean Smokestacks Act compliance costs. The NCUC
ordered that PEC shall be allowed to include in rate base all reasonable and
prudently incurred environmental compliance costs in excess of $584 million as
the projects are closed to plant in service. As a result of this order, PEC will
not amortize $229 million of the original estimated compliance costs for the
Clean Smokestacks Act during 2008 and 2009, but will record depreciation over
the useful life of the assets.




For the
three months ended September 30, 2008, PEC did not recognize any amortization.
For the nine months ended September 30, 2008, PEC recognized amortization of $15
million. For the three and nine months ended September 30, 2007, PEC recognized
amortization of $8 million and $25 million, respectively. PEC has recognized
$584 million in cumulative amortization through September 30, 2008.




27




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. Subsequently, PEC jointly filed a settlement
agreement with CIGFUR, CUCA and the NCUC Public Staff. Under the terms of the
settlement agreement, PEC would collect $203 million of deferred fuel costs
ratably over a three-year period beginning December 1, 2008, compared with a
one-year recovery period proposed in PEC’s original request. Amounts to be
collected in years beginning December 1, 2009 and 2010, will bear interest at a
rate equal to the five-year United States Treasury Note plus 150 basis points.
If the settlement agreement is approved, the increase would take effect on or
about December 1, 2008, and would increase residential electric bills by $8.79
per 1,000 kWh, or 9.1 percent. A hearing on the settlement agreement was held on
September 16, 2008, and an order is expected in November 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 demand-side management (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. PEC has begun implementing a
series of DSM and energy-efficiency programs and, as of September 30, 2008, has
deferred $6 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 (DSDR) 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. On October 14,
2008, the NCUC approved PEC’s request for its EnergyWiseTM program as well as
three other DSM and energy-efficiency programs.





Also on
April 29, 2008, PEC filed for NCUC approval of its DSDR 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 DSDR program has been scheduled by
the NCUC for December 17, 2008.




On October 31,
2008, PEC filed with the NCUC for approval of two energy-efficiency programs and
request for modifications to three of its approved energy-efficiency
programs.





We cannot
predict the outcome of PEC's DSM and energy-efficiency filings or whether
the programs will produce the expected operational and economic
results.




28




On June
6, 2008, and as amended on August 20, 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, residential electric bills would
increase by $1.92 per 1,000 kWh, or 2.0 percent. A hearing on the matter has
been scheduled by the NCUC for December 17, 2008. Although the NCUC is not
expected to make a decision on this filing until the first quarter of 2009, PEC
has petitioned the NCUC to allow PEC to begin collecting the DSM and
energy-efficiency related costs of these programs on December 1, 2008 subject to
true-up in future proceedings. We cannot predict the outcome of this matter.




PEC filed
a petition on November 30, 2007, with the SCPSC seeking authorization to create
a deferred account for DSM and energy-efficiency expenses. On December 21, 2007,
the SCPSC issued an order granting PEC’s petition. 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. A hearing on this matter is anticipated to occur in the first
quarter of 2009. 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 required
PEC to submit its first annual renewable energy and energy efficiency portfolio
standard (REPS) compliance plan as part of its integrated resource plan, which
was filed on September 2, 2008. 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, and as amended on
August 22, 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 residential
electric bills by $0.45 per 1,000 kWh, or 0.5 percent. A hearing on the matter
was held on September 17, 2008. The NCUC is expected to make a decision on this
matter in November 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 public hearing on
this matter was held by the NCUC on September 3, 2008. On October 13, 2008, the
NCUC issued a Certificate of Public Convenience and Necessity allowing PEC to
proceed with plans to provide additional generating and transmission capacity to
meet the growing energy demands of southern and eastern North Carolina. PEC
expects that the new generating and transmission capacity will be online by the
second quarter of 2011.





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




29




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.





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 wholesale amortization to be $1 million
in 2008 and $2 million annually during the remaining amortization period. PEC’s
recorded investment in GridSouth totaled $20 million and $22 million at
September 30, 2008 and December 31, 2007, respectively.





The NCUC
and the 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 $10 million and $25
million for the three and nine months ended September 30, 2008, respectively. No
additional depreciation expense from accelerated cost recovery was recorded for
the same periods in 2007. Through September 30, 2008, PEC recorded cumulative
accelerated depreciation of $465 million, of which $388 million was recorded for
the North Carolina jurisdiction and $77 million was recorded for the South
Carolina jurisdiction.




In
October 2008, PEC filed, and the SCPSC approved, a petition to terminate PEC’s
remaining obligation to accelerate the cost recovery of PEC’s nuclear generating
assets. As a result of the approval of this petition, PEC will not be required
to recognize the remaining $38 million of accelerated depreciation required to
reach the minimum amount of cost recovery for the South Carolina jurisdiction,
but will record depreciation over the useful life of the assets.




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




30




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. A
hearing on PEF’s 2006 and 2007 coal purchases has been scheduled for April
13-15, 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 percent 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 increased by $2.48 per 1,000 kWh, or 2.29
percent.





On
October 15, 2008, PEF filed a request with the FPSC to seek approval of a cost
adjustment for the under-recovery of fuel costs in 2008 and other
recovery-clause factors. PEF asked the FPSC to approve an increase in
residential electric bills by $27.28 per 1,000 kWh, or 24.7 percent, effective
January 1, 2009. The increase in residential bills is primarily due to increases
of $14.09 per 1,000 kWh for the projected recovery of fuel costs, $9.74 per
1,000 kWh for the projected recovery through the capacity cost-recovery clause
and $2.50 per 1,000 kWh for the projected recovery through the environmental
cost-recovery clause (ECRC). The increase in the capacity cost-recovery clause
is primarily the result of projected costs to be incurred in 2009 under the
nuclear cost-recovery rule discussed below for the proposed Levy Units 1 and 2
and the Crystal River Unit No. 3 Nuclear Plant (CR3) uprate less the projected
reduction in capacity costs. The increase in the ECRC is primarily due to the
recovery of emission allowance costs (See Note 12B) and the return on assets
expected to be placed in service in 2009. The FPSC
is scheduled to hold hearings on the cost adjustment proposal November 4-6,
2008. We cannot predict the outcome of this matter.





CR3
Uprate




On
September 22, 2006, PEF filed a petition with the FPSC for Determination of Need
to uprate CR3 and bid rule exemption, and for recovery of the revenue
requirements of the uprate through PEF’s fuel recovery clause. To the extent the
expenditures are prudently incurred, PEF’s investment in the CR3 uprate is
eligible for recovery through base rates. PEF’s petition would allow for more
prompt recovery. 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. The multi-stage uprate will
increase CR3’s gross output by approximately 180 MW by 2012. On February 8,
2007, the FPSC issued an order approving the need certification petition and bid
rule exemption. PEF received NRC approval for a license amendment and
implemented the first stage’s design modification on January 31, 2008, at a cost
of $9 million. PEF will apply for the required license amendment for the third
stage’s design modification.




On
February 29, 2008, PEF filed a petition amending its recovery request and asked
for recovery of costs incurred in 2007 and 2006 through the capacity
cost-recovery clause under Florida’s comprehensive energy legislation and the
FPSC’s nuclear cost-recovery rule. This request was based on the regulatory
precedence established by a FPSC order to an unaffiliated Florida utility for a
nuclear uprate project. On May 1, 2008, PEF filed with the FPSC for an increase
in the capacity cost-recovery clause for estimated costs incurred in 2008 and
projected costs to be incurred in 2009 under the FPSC nuclear cost-recovery
rule. PEF petitioned the FPSC to approve a $25 million increase in the capacity
cost-recovery revenue requirement for costs associated with subsequent stages of
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. On August 19, 2008, the FPSC granted PEF’s petition to amend its
request to recover costs for the nuclear uprate project under the nuclear
cost-recovery rule.




On September
19, 2008, PEF filed a petition with the FPSC to approve a base rate increase for
the remaining revenue requirements for the first stage costs. PEF’s 2008 revenue
requirements for recovery of the first stage’s




31




costs were
included in the capacity cost-recovery clause. On October 28, 2008, the FPSC
approved a $1 million base rate increase for costs associated with the first
stage of the CR3 uprate. Base rates will increase for residential customers
by $0.04 per 1,000 kWh, or 0.1 percent, beginning in January 2009.  On
October 14, 2008, the FPSC voted to approve $24 million for costs associated
with the CR3 uprate in establishing PEF's 2009 capacity cost-recovery clause
factor.




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 issued the final order
granting the petition for the Determination of Need for the proposed nuclear
power plants on August 12, 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 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 under the nuclear cost-recovery rule. 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
nuclear cost-recovery rule. On October 14, 2008, the FPSC voted
to approve the inclusion of preconstruction and carrying charges of $357
million as well as site selection costs of $38 million in establishing PEF's
2009 capacity cost-recovery clause factor.




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 EndedSeptember
      30,
            
            
            Nine Months EndedSeptember
      30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Weighted-average
      common shares – basic
            
            
            261
            
            
            
            257
            
            
            
            260
            
            
            
            256Net
      effect of dilutive stock-based compensation plans
            
            
            –
            
            
            
            –
            
            
            
            –
            
            
            
            –Weighted-average
      shares – fully dilutive
            
            
            261
            
            
            
            257
            
            
            
            260
            
            
            
            256





32


B.           COMPREHENSIVE
INCOME


Progress
      EnergyThree
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            309
            
            
            $
            319Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $-and $-,
      respectively)
            
            
            1
            
            
            
            1Net
      unrealized gains (losses) on cash flow hedges (net of tax (expense)
      benefit of ($1) and $7, respectively)
            
            
            1
            
            
            
            (11
            )Other
      comprehensive income (loss)
            
            
            2
            
            
            
            (10
            )Comprehensive
      income
            
            $
            311
            
            
            $
            309




Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            723
            
            
            $
            401Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $1 and $2,
      respectively)
            
            
            2
            
            
            
            4Change
      in unrecognized items for pension and other postretirement benefits (net
      of tax expense of $1 and $-,
      respectively)
            
            
            1
            
            
            
            2Net
      unrealized gains (losses) on cash flow hedges (net of tax (expense)
      benefit of ($3) and $5, respectively)
            
            
            5
            
            
            
            (9
            )Other
      (net of tax benefit of $3)
            
            
            –
            
            
            
            (2
            )Other
      comprehensive income (loss)
            
            
            8
            
            
            
            (5
            )Comprehensive
      income
            
            $
            731
            
            
            $
            396





33


PECThree
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            201
            
            
            $
            204Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $-)
            
            
            1
            
            
            
            –Net
      unrealized gains (losses) on cash flow hedges (net of tax benefit of
      $-and $1,
      respectively)
            
            
            1
            
            
            
            (2
            )Other
      comprehensive income (loss)
            
            
            2
            
            
            
            (2
            )Comprehensive
      income
            
            $
            203
            
            
            $
            202





Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            428
            
            
            $
            416Other
      comprehensive income (loss)Reclassification
      adjustments included in net incomeChange
      in cash flow hedges (net of tax expense of $-)
            
            
            1
            
            
            
            –Net
      unrealized losses on cash flow hedges (net of tax benefit of $2 and $1,
      respectively)
            
            
            (4
            )
            
            
            (1
            )Other
      (net of tax benefit of $1)
            
            
            –
            
            
            
            (4
            )Other
      comprehensive loss
            
            
            (3
            )
            
            
            (5
            )Comprehensive
      income
            
            $
            425
            
            
            $
            411




PEFThree
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            143
            
            
            $
            138Other
      comprehensive lossNet
      unrealized losses on cash flow hedges (net of tax benefit of
      $6)
            
            
            –
            
            
            
            (10
            )Other
      comprehensive loss
            
            
            –
            
            
            
            (10
            )Comprehensive
      income
            
            $
            143
            
            
            $
            128





Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007Net
      income
            
            $
            335
            
            
            $
            267Other
      comprehensive income (loss)Net
      unrealized gains (losses) on cash flow hedges (net of tax (expense)
      benefit of ($5) and $5, respectively)
            
            
            8
            
            
            
            (8
            )Other
      comprehensive income (loss)
            
            
            8
            
            
            
            (8
            )Comprehensive
      income
            
            $
            343
            
            
            $
            259





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 nine months ended
September 30, 2008, respectively, we issued approximately 1.5 million shares and
2.5 million shares of common




34




stock
resulting in approximately $64 million and $106 million in proceeds. Included in
these amounts were approximately 1.5 million shares and 2.4 million shares for
proceeds of approximately $63 million and $104 million, respectively, to meet
the requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan.
For the three and nine months ended September 30, 2007, respectively, we issued
approximately 0.3 million shares and 3.0 million shares of common stock
resulting in approximately $12 million and $134 million in proceeds. Included in
these amounts were approximately 0.2 million shares and 0.7 million shares for
proceeds of approximately $12 million and $35 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, the Parent amended its RCA with a syndication of financial
institutions to extend the termination date by one year. The extension was
effective on May 2, 2008. The 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 August 14, 2008, PEF redeemed the entire outstanding $450
million principal amount of its Series A Floating Rate Notes due November 14,
2008, at 100 percent of par plus accrued interest. The redemption was funded
with a portion of the proceeds from the June 18, 2008 debt
issuance.




On
November 3, 2008, the Parent borrowed $600 million under its RCA to reduce
rollover risk in the commercial paper markets. We will continue to monitor the
commercial paper and short-term credit markets to determine when to repay the
outstanding balance of the RCA loan, while maintaining an appropriate level of
liquidity.






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).




35




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 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.




36




The
following tables set forth by level within the fair value hierarchy our and the
Utilities’ financial assets and liabilities that were accounted for at fair
value on a recurring basis as of September 30, 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
            
            $
            –
            
            
            $
            130
            
            
            $
            39
            
            
            $
            169Interest
      rate derivatives
            
            
            –
            
            
            
            4
            
            
            
            –
            
            
            
            4Nuclear
      decommissioning trust funds
            
            
            713
            
            
            
            497
            
            
            
            –
            
            
            
            1,210Other
      marketable securities
            
            
            20
            
            
            
            41
            
            
            
            –
            
            
            
            61Total
      assets
            
            $
            733
            
            
            $
            672
            
            
            $
            39
            
            
            $
            1,444Liabilities:Commodity
      derivatives
            
            $
            –
            
            
            $
            (228
            )
            
            $
            (20
            )
            
            $
            (248
            )Interest
      rate derivatives
            
            
            –
            
            
            
            (2
            )
            
            
            –
            
            
            
            (2
            )CVO
      derivatives
            
            
            –
            
            
            
            (36
            )
            
            
            –
            
            
            
            (36
            )Total
      liabilities
            
            $
            –
            
            
            $
            (266
            )
            
            $
            (20
            )
            
            $
            (286
            )




PEC(in
      millions)
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            TotalAssets:Commodity
      derivatives
            
            $
            –
            
            
            $
            14
            
            
            $
            6
            
            
            $
            20Interest
      rate derivatives
            
            
            –
            
            
            
            2
            
            
            
            –
            
            
            
            2Nuclear
      decommissioning trust funds
            
            
            423
            
            
            
            300
            
            
            
            –
            
            
            
            723Other
      marketable securities
            
            
            4
            
            
            
            –
            
            
            
            –
            
            
            
            4Total
      assets
            
            $
            427
            
            
            $
            316
            
            
            $
            6
            
            
            $
            749


Liabilities:Commodity
      derivatives
            
            $
            –
            
            
            $
            (32
            )
            
            $
            (10
            )
            
            $
            (42
            )Interest
      rate derivatives
            
            
            –
            
            
            
            (1
            )
            
            
            –
            
            
            
            (1
            )Total
      liabilities
            
            $
            –
            
            
            $
            (33
            )
            
            $
            (10
            )
            
            $
            (43
            )




PEF(in
      millions)
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            TotalAssets:Commodity
      derivatives
            
            $
            –
            
            
            $
            116
            
            
            $
            33
            
            
            $
            149Nuclear
      decommissioning trust funds
            
            
            290
            
            
            
            197
            
            
            
            –
            
            
            
            487Other
      marketable securities
            
            
            1
            
            
            
            –
            
            
            
            –
            
            
            
            1Total
      assets
            
            $
            291
            
            
            $
            313
            
            
            $
            33
            
            
            $
            637


Liabilities:Commodity
      derivatives
            
            $
            –
            
            
            $
            (196
            )
            
            $
            (10
            )
            
            $
            (206
            )


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




37


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.




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 primarily 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 nine months ended September 30, 2008.


Progress
      EnergyThree
      Months Ended
            
            
            Nine
      Months Ended(in
      millions)
            
            September
      30, 2008
            
            
            September
      30, 2008Derivatives,
      net at beginning of period
            
            $
            163
            
            
            $
            26Total
      gains (losses), realized and unrealized:Included
      in earnings
            
            
            –
            
            
            
            –Included
      in other comprehensive income
            
            
            –
            
            
            
            –Deferred
      as regulatory assets and liabilities, net
            
            
            (145
            )
            
            
            (8
            )Purchases,
      issuances and settlements, net
            
            
            –
            
            
            
            –Transfers
      out of Level 3, net
            
            
            1
            
            
            
            1Derivatives,
      net at end of period
            
            $
            19
            
            
            $
            19




PECThree
      Months Ended
            
            
            Nine
      Months Ended(in
      millions)
            
            September
      30, 2008
            
            
            September
      30, 2008Derivatives,
      net at beginning of period
            
            $
            36
            
            
            $
            6Total
      gains (losses), realized and unrealized:Included
      in earnings
            
            
            –
            
            
            
            –Included
      in other comprehensive income
            
            
            –
            
            
            
            –Deferred
      as regulatory assets and liabilities, net
            
            
            (42
            )
            
            
            (12
            )Purchases,
      issuances and settlements, net
            
            
            –
            
            
            
            –Transfers
      out of Level 3, net
            
            
            2
            
            
            
            2Derivatives,
      net at end of period
            
            $
            (4
            )
            
            $
            (4
            )





PEFThree
      Months Ended
            
            
            Nine
      Months Ended(in
      millions)
            
            September
      30, 2008
            
            
            September
      30, 2008Derivatives,
      net at beginning of period
            
            $
            127
            
            
            $
            20Total
      gains (losses), realized and unrealized:Included
      in earnings
            
            
            –
            
            
            
            –Included
      in other comprehensive income
            
            
            –
            
            
            
            –Deferred
      as regulatory assets and liabilities, net
            
            
            (103
            )
            
            
            4Purchases,
      issuances and settlements, net
            
            
            –
            
            
            
            –Transfers
      out of Level 3, net
            
            
            (1
            )
            
            
            (1
            )Derivatives,
      net at end of period
            
            $
            23
            
            
            $
            23





38


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





Transfers
out of Level 3 represent existing assets or liabilities that were previously
classified as Level 3 for which the lowest significant input became observable
during the period.





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
nine months ended September 30 were:




Progress
      EnergyPension
      Benefits
            
            
            Other
      Postretirement BenefitsThree
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            11
            
            
            $
            13
            
            
            $
            2
            
            
            $
            2Interest
      cost
            
            
            33
            
            
            
            31
            
            
            
            9
            
            
            
            6Expected
      return on plan assets
            
            
            (45
            )
            
            
            (38
            )
            
            
            (1
            )
            
            
            (1
            )Amortization
      of actuarial loss (gain) (a)
            
            
            –
            
            
            
            4
            
            
            
            –
            
            
            
            (2
            )Other
      amortization, net (a)
            
            
            1
            
            
            
            –
            
            
            
            1
            
            
            
            1Net
      periodic cost
            
            $
            –
            
            
            $
            10
            
            
            $
            11
            
            
            $
            6





Pension
      Benefits
            
            
            Other
      Postretirement BenefitsNine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            35
            
            
            $
            35
            
            
            $
            6
            
            
            $
            5Interest
      cost
            
            
            95
            
            
            
            92
            
            
            
            25
            
            
            
            24Expected
      return on plan assets
            
            
            (127
            )
            
            
            (116
            )
            
            
            (4
            )
            
            
            (4
            )Amortization
      of actuarial loss (a)
            
            
            5
            
            
            
            11
            
            
            
            1
            
            
            
            1Other
      amortization, net (a)
            
            
            2
            
            
            
            1
            
            
            
            3
            
            
            
            4Net
      periodic cost
            
            $
            10
            
            
            $
            23
            
            
            $
            31
            
            
            $
            30





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





39


PECPension
      Benefits
            
            
            Other
      Postretirement BenefitsThree
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            5
            
            
            $
            7
            
            
            $
            1
            
            
            $
            2Interest
      cost
            
            
            15
            
            
            
            14
            
            
            
            5
            
            
            
            2Expected
      return on plan assets
            
            
            (17
            )
            
            
            (14
            )
            
            
            (1
            )
            
            
            (1
            )Amortization
      of actuarial loss (gain)
            
            
            –
            
            
            
            4
            
            
            
            –
            
            
            
            (2
            )Other
      amortization, net
            
            
            1
            
            
            
            –
            
            
            
            –
            
            
            
            –Net
      periodic cost
            
            $
            4
            
            
            $
            11
            
            
            $
            5
            
            
            $
            1





Pension
      Benefits
            
            
            Other
      Postretirement BenefitsNine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            17
            
            
            $
            17
            
            
            $
            3
            
            
            $
            4Interest
      cost
            
            
            43
            
            
            
            42
            
            
            
            13
            
            
            
            11Expected
      return on plan assets
            
            
            (49
            )
            
            
            (45
            )
            
            
            (3
            )
            
            
            (3
            )Amortization
      of actuarial loss
            
            
            4
            
            
            
            9
            
            
            
            –
            
            
            
            –Other
      amortization, net
            
            
            2
            
            
            
            2
            
            
            
            1
            
            
            
            1Net
      periodic cost
            
            $
            17
            
            
            $
            25
            
            
            $
            14
            
            
            $
            13




PEFPension
      Benefits
            
            
            Other
      Postretirement BenefitsThree
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            4
            
            
            $
            5
            
            
            $
            1
            
            
            $
            –Interest
      cost
            
            
            14
            
            
            
            13
            
            
            
            4
            
            
            
            4Expected
      return on plan assets
            
            
            (24
            )
            
            
            (21
            )
            
            
            –
            
            
            
            –Other
      amortization, net
            
            
            –
            
            
            
            –
            
            
            
            –
            
            
            
            1Net
      periodic (benefit) cost
            
            $
            (6
            )
            
            $
            (3
            )
            
            $
            5
            
            
            $
            5





Pension
      Benefits
            
            
            Other
      Postretirement BenefitsNine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            13
            
            
            $
            12
            
            
            $
            2
            
            
            $
            1Interest
      cost
            
            
            40
            
            
            
            39
            
            
            
            11
            
            
            
            11Expected
      return on plan assets
            
            
            (68
            )
            
            
            (63
            )
            
            
            (1
            )
            
            
            (1
            )Amortization
      of actuarial loss
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Other
      amortization, net
            
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            3Net
      periodic (benefit) cost
            
            $
            (15
            )
            
            $
            (12
            )
            
            $
            15
            
            
            $
            15





40


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 September 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.           COMMODITY
DERIVATIVES




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 September 30,
2008, and December 31, 2007, the remaining liability was $8 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. We had a $108 million cash collateral liability
related to these contracts at December 31, 2007, included in other current
liabilities 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 September 30, 2007, we recorded net
pre-tax gains of $74 million related to these contracts, including $26 million
attributable to Ceredo, which was attributed to minority interest for the
portion of the gain subsequent to disposal. For the nine months ended September
30, 2007, we recorded net pre-tax gains of $105 million related to these
contracts, including $36 million attributable to Ceredo, of which $21 million
were attributed to minority interest for the portion of the gain 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




41




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 nine months ended September 30, 2008, PEC recorded a net realized gain of $6
million and $12 million, respectively. During each of the three and nine months
ended September 30, 2007, PEC recorded a net realized loss of $6 million. During
the three and nine months ended September 30, 2008, PEF recorded a net realized
gain of $118 million and $237 million, respectively. During the three and nine
months ended September 30, 2007, PEF recorded a net realized loss of $23 million
and $45 million, respectively.




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




At
September 30, 2008, the fair value of PEC’s commodity derivative instruments was
recorded as a $1 million short-term derivative asset position included in
prepayments and other current assets, a $19 million long-term derivative asset
position included in other assets and deferred debits, a $24 million short-term
liability position included in other current liabilities, and a $18 million
long-term derivative liability position included in other liabilities and
deferred credits on the PEC Consolidated Balance Sheet. At December 31, 2007,
the fair value of such instruments was recorded as a $19 million long-term
derivative asset position included in other assets and deferred debits and a $4
million short-term derivative liability position included in other current
liabilities on the PEC Consolidated Balance Sheet. PEC had no cash collateral
position at September 30, 2008 or December 31, 2007.




At
September 30, 2008, the fair value of PEF’s commodity derivative instruments was
recorded as a $59 million short-term derivative asset position included in
current derivative assets, a $90 million long-term derivative asset position
included in derivative assets, a $133 million short-term liability position
included in derivative liabilities, and a $73 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 $14 million
cash collateral receivable included in prepayments and other current assets and
a $14 million cash collateral liability included in other current liabilities at
September 30, 2008, 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 September 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 nine months ended September 30, 2008 and
2007.




At
September 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 CASH FLOW HEDGES




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




42




CASH
FLOW HEDGES




The fair
values of open interest rate hedges at September 30, 2008, and December 31,
2007, were as follows:


September
      30, 2008
            
            
            December
      31, 2007(in
      millions)
            
            Progress
      Energy
            
            
            PEC
            
            
            PEF
            
            
            Progress
      Energy
            
            
            PEC
            
            
            PEFFair
      value of assets
            
            $
            4
            
            
            $
            2
            
            
            $
            –
            
            
            $
            –
            
            
            $
            –
            
            
            $
            –Fair
      value of liabilities
            
            
            (2
            )
            
            
            (1
            )
            
            
            –
            
            
            
            (12
            )
            
            
            (12
            )
            
            
            –Fair
      value, net
            
            $
            2
            
            
            $
            1
            
            
            $
            –
            
            
            $
            (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 effective portion of the hedges is included in
accumulated other comprehensive income and will be amortized to interest expense
over the term of the related debt. The ineffective portion of interest rate cash
flow hedges for the three and nine months ended September 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 September 30,
2008:


(term
      in years/millions of dollars)
            
            Progress
      Energy
            
            
            PEC
            
            
            PEFMaximum
      term
            
            Less
      than 1
            
            
            Less
      than 1
            
            
            
            –Accumulated
      other comprehensive loss, net of tax(a)
            
            $
            (16
            )
            
            $
            (14
            )
            
            $
            –Portion
      expected to be reclassified to earnings during the next 12
      months(b)
            
            $
            –
            
            
            $
            1
            
            
            $
            –





(a)Includes amounts related to terminated hedges.


(b) Actual amounts that will
be reclassified to earnings may vary from the expected amounts presented abouve
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.




In August
2008, the Parent entered into a $50 million notional of forward starting swaps
to mitigate exposure to interest rate risk in anticipation of future debt
issuance. In September 2008, the Parent entered into a combined $100 million
notional of forward starting swaps to mitigate exposure to interest rate risk in
anticipation of future debt issuance. In October 2008, the Parent entered into a
$50 million notional of forward starting swaps to mitigate exposure to interest
rate risk in anticipation of future debt issuance.




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. In August 2008, PEC entered into a $50 million notional
of forward starting swaps to mitigate exposure to interest rate risk in
anticipation of future debt issuance. In September 2008, PEC entered into a
combined $100 million notional of forward starting swaps to mitigate exposure to
interest rate risk in anticipation of future debt issuance. In October 2008, PEC
entered into a $50 million notional of forward starting swaps to mitigate
exposure to interest rate risk in anticipation of future debt
issuance.




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




43




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 September 30, 2008, and December 31, 2007,
neither we nor the Utilities had any outstanding positions in such
contracts.




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.




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
nine months ended September 30:


Income
      (Loss)Revenues
            
            
            From
      Continuing(in
      millions)
            
            Unaffiliated
            
            
            Intersegment
            
            
            Total
            
            
            Operations
            
            
            AssetsThree Months Ended September 30,
      2008PEC
            
            $
            1,266
            
            
            $
            –
            
            
            $
            1,266
            
            
            $
            200
            
            
            $
            12,492PEF
            
            
            1,428
            
            
            
            –
            
            
            
            1,428
            
            
            
            143
            
            
            
            11,658Corporate
      and Other
            
            
            2
            
            
            
            92
            
            
            
            94
            
            
            
            (35
            )
            
            
            17,426Eliminations
            
            
            –
            
            
            
            (92
            )
            
            
            (92
            )
            
            
            –
            
            
            
            (13,339
            )Totals
            
            $
            2,696
            
            
            $
            –
            
            
            $
            2,696
            
            
            
            308
            
            
            $
            28,237Three Months Ended September 30,
      2007PEC
            
            $
            1,286
            
            
            $
            –
            
            
            $
            1,286
            
            
            $
            203PEF
            
            
            1,456
            
            
            
            –
            
            
            
            1,456
            
            
            
            138Corporate
      and Other
            
            
            8
            
            
            
            99
            
            
            
            107
            
            
            
            (30
            )Eliminations
            
            
            –
            
            
            
            (99
            )
            
            
            (99
            )
            
            
            –Totals
            
            $
            2,750
            
            
            $
            –
            
            
            $
            2,750
            
            
            $
            311





44


Income
      (Loss)Revenues
            
            
            From
      Continuing(in
      millions)
            
            Unaffiliated
            
            
            Intersegment
            
            
            Total
            
            
            Operations
            
            
            AssetsNine Months Ended September 30,
      2008PEC
            
            $
            3,382
            
            
            $
            –
            
            
            $
            3,382
            
            
            $
            426
            
            
            $
            12,492PEF
            
            
            3,618
            
            
            
            –
            
            
            
            3,618
            
            
            
            334
            
            
            
            11,658Corporate
      and Other
            
            
            6
            
            
            
            268
            
            
            
            274
            
            
            
            (103
            )
            
            
            17,426Eliminations
            
            
            –
            
            
            
            (268
            )
            
            
            (268
            )
            
            
            –
            
            
            
            (13,339
            )Totals
            
            $
            7,006
            
            
            $
            –
            
            
            $
            7,006
            
            
            $
            657
            
            
            $
            28,237Nine Months Ended September 30,
      2007PEC
            
            $
            3,340
            
            
            $
            –
            
            
            $
            3,340
            
            
            $
            414PEF
            
            
            3,596
            
            
            
            –
            
            
            
            3,596
            
            
            
            266Corporate
      and Other
            
            
            15
            
            
            
            288
            
            
            
            303
            
            
            
            (82
            )Eliminations
            
            
            –
            
            
            
            (288
            )
            
            
            (288
            )
            
            
            –Totals
            
            $
            6,951
            
            
            $
            –
            
            
            $
            6,951
            
            
            $
            598






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.





The
components of other, net as shown on the accompanying Statements of Income were
as follows:




Progress
      EnergyThree
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Other
      incomeNonregulated
      energy and delivery services income
            
            $
            3
            
            
            $
            2
            
            
            $
            25
            
            
            $
            25DIG
      Issue C20 amortization (see Note 9A)
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            3CVOs
      unrealized gain
            
            
            –
            
            
            
            1
            
            
            
            –
            
            
            
            2Gain
      on sale of property, net
            
            
            –
            
            
            
            3
            
            
            
            –
            
            
            
            1Investment
      gains
            
            
            2
            
            
            
            2
            
            
            
            6
            
            
            
            5Income
      from equity investments
            
            
            1
            
            
            
            1
            
            
            
            1
            
            
            
            2Derivative
      mark-to-market gain
            
            
            –
            
            
            
            –
            
            
            
            4
            
            
            
            –Other
            
            
            3
            
            
            
            3
            
            
            
            9
            
            
            
            10Total
      other income
            
            
            10
            
            
            
            13
            
            
            
            47
            
            
            
            48Other
      expenseNonregulated
      energy and delivery services expenses
            
            
            6
            
            
            
            7
            
            
            
            15
            
            
            
            19Donations
            
            
            3
            
            
            
            6
            
            
            
            14
            
            
            
            16Investment
      losses
            
            
            1
            
            
            
            4
            
            
            
            8
            
            
            
            4Loss
      from equity investments
            
            
            –
            
            
            
            –
            
            
            
            3
            
            
            
            1Derivative
      mark-to-market loss
            
            
            5
            
            
            
            –
            
            
            
            5
            
            
            
            –CVOs
      unrealized loss
            
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            4Other
            
            
            2
            
            
            
            1
            
            
            
            9
            
            
            
            10Total
      other expense
            
            
            17
            
            
            
            18
            
            
            
            56
            
            
            
            54Other,
      net
            
            $
            (7
            )
            
            $
            (5
            )
            
            $
            (9
            )
            
            $
            (6
            )





45




PECThree
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            2008
            
            
            2007
            
            
            2008
            
            
            2007Other
      incomeNonregulated
      energy and delivery services income
            $
            (1
            )
            
            $
            (3
            )
            
            $
            11
            
            
            $
            6DIG
      Issue C20 amortization (see Note 9A)
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            3Investment
      gains
            
            2
            
            
            
            2
            
            
            
            3
            
            
            
            3Income
      from equity investments
            
            1
            
            
            
            1
            
            
            
            1
            
            
            
            3Derivative
      mark-to-market gain
            
            –
            
            
            
            –
            
            
            
            4
            
            
            
            –Other
            
            3
            
            
            
            2
            
            
            
            8
            
            
            
            7Total
      other income
            
            6
            
            
            
            3
            
            
            
            29
            
            
            
            22Other
      expenseNonregulated
      energy and delivery services expenses
            
            3
            
            
            
            3
            
            
            
            6
            
            
            
            6Donations
            
            2
            
            
            
            1
            
            
            
            8
            
            
            
            6Investment
      losses
            
            –
            
            
            
            2
            
            
            
            3
            
            
            
            3Loss
      from equity investments
            
            –
            
            
            
            –
            
            
            
            2
            
            
            
            1Derivative
      mark-to-market loss
            
            5
            
            
            
            –
            
            
            
            5
            
            
            
            –Other
            
            1
            
            
            
            –
            
            
            
            5
            
            
            
            4Total
      other expense
            
            11
            
            
            
            6
            
            
            
            29
            
            
            
            20Other,
      net
            $
            (5
            )
            
            $
            (3
            )
            
            $
            –
            
            
            $
            2




PEFThree
      Months Ended September 30,
            
            
            Nine
      Months Ended September 30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Other
      incomeNonregulated
      energy and delivery services income
            
            $
            5
            
            
            $
            5
            
            
            $
            15
            
            
            $
            19Investment
      gains
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            2Other
            
            
            –
            
            
            
            1
            
            
            
            2
            
            
            
            1Total
      other income
            
            
            5
            
            
            
            6
            
            
            
            18
            
            
            
            22Other
      expenseNonregulated
      energy and delivery services expenses
            
            
            3
            
            
            
            4
            
            
            
            9
            
            
            
            13Donations
            
            
            1
            
            
            
            1
            
            
            
            6
            
            
            
            4Investment
      losses
            
            
            –
            
            
            
            1
            
            
            
            2
            
            
            
            1Loss
      from equity investments
            
            
            –
            
            
            
            –
            
            
            
            1
            
            
            
            1Other
            
            
            1
            
            
            
            –
            
            
            
            1
            
            
            
            3Total
      other expense
            
            
            5
            
            
            
            6
            
            
            
            19
            
            
            
            22Other,
      net
            
            $
            –
            
            
            $
            –
            
            
            $
            (1
            )
            
            $
            –





46


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 potential and pending claims cannot
be predicted. A discussion of sites by legal entity follows.




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




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)
            
            September
      30, 2008
            
            
            December
      31, 2007PECMGP
      and other sites(a)
            
            $
            18
            
            
            $
            16PEFRemediation
      of distribution and substation transformers
            
            
            26
            
            
            
            31MGP
      and other sites
            
            
            15
            
            
            
            17Total
      PEF environmental remediation accruals(b)
            
            
            41
            
            
            
            48Total
      Progress Energy environmental remediation accruals
            
            $
            59
            
            
            $
            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).




47


PEC




In 2006,
the NCUC and the SCPSC authorized PEC to defer and amortize certain
environmental remediation expenses. Remediation expenses not authorized to be
deferred are included in operation and maintenance expense. Including the Ward
Transformer site located in Raleigh, N.C. (Ward) and MGP sites discussed below,
for the three months ended September 30, 2008, PEC accrued approximately $2
million and spent approximately $2 million. For the nine months ended September
30, 2008, PEC accrued approximately $8 million, of which $2 million was
deferred, and spent approximately $6 million. For the three months ended
September 30, 2007, PEC accrued and deferred approximately $1 million and spent
approximately $1 million. For the nine months ended September 30, 2007, PEC
reduced its accrual by approximately $4 million and spent approximately $2
million. These amounts primarily relate to the Ward site.




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




During
the fourth quarter of 2004, the EPA advised PEC that it had been identified as a
PRP at the Ward site. The EPA offered PEC and a number of other PRPs the
opportunity to negotiate the removal action for the Ward site and reimbursement
to the EPA for the EPA’s past expenditures in addressing conditions at the Ward
site. Subsequently, PEC and other PRPs signed a settlement agreement, which
requires the participating PRPs to remediate the Ward site. During 2007, the PRP
agreement was amended to include an additional participating PRP, which reduced
on an interim basis, 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 September 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. On September 12,
2008, PEC filed a complaint seeking contribution for and recovery of costs
incurred in remediating the Ward site, as well as a declaratory judgment that
defendants are jointly and severally liable for response costs at the site. The
complaint names 28 parties that did not sign a tolling agreement with PEC, which
was entered into by over 200 PRPs.  The tolling agreement suspends the
running of the statute of limitations for determination of cost recovery from
PRPs at the Ward site. The litigation has been stayed to allow the parties to
explore private settlements. The outcome of these matters cannot be
predicted.




On
September 30, 2008, the EPA issued a Record of Decision for the operable unit
for stream segments downstream from the Ward site (Ward OU1) and advised 61
parties, including PEC, of their identification as PRPs for Ward OU1 and for the
operable unit for further investigation at the Ward facility and certain
adjacent areas (Ward OU2). The EPA’s estimate for the selected remedy for Ward
OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the
opportunity to negotiate implementation of a response action for Ward OU1 and a
remedial investigation and feasibility study for Ward OU2, as well as
reimbursement to the EPA of approximately $1 million for the EPA’s past
expenditures in addressing conditions at the site. Although a loss is considered
probable, an agreement among PRPs for these matters has not been reached;
consequently, it is not possible at this time to reasonably estimate the total
amount of PEC’s obligation for Ward OU1 and Ward OU2.




PEF




PEF has
received approval from the FPSC for recovery through the ECRC of the majority of
costs associated with the remediation of distribution and substation
transformers. Under agreements with the Florida Department of Environmental
Protection (FDEP), PEF has reviewed 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 nine months ended September 30, 2008, PEF
accrued approximately $3 million and $15 million, respectively, due to the
identification of additional transformer sites and an increase in estimated
remediation costs, and spent approximately $6 million and $20 million,
respectively, related to the remediation of transformers. For the three and nine
months ended September 30, 2007, PEF accrued approximately $4 million and $9
million, respectively, due to an increase in estimated remediation costs and
spent




48




approximately
$5 million and $16 million, respectively, related to the remediation of
transformers. At September 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 months ended September 30, 2008, PEF made no
additional accruals or material expenditures. For the nine months ended
September 30, 2008, PEF made no additional accruals and spent approximately $2
million. For the three and nine months ended September 30, 2007, PEF made no
additional accruals or material expenditures.




B.
            AIR
      AND WATER QUALITY




At
September 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 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 September
30, 2008, cumulative environmental compliance capital expenditures to date with
regard to these environmental laws and regulations were $1.754 billion,
including $1.009 billion at PEC of which $15 million related to in-process CAIR
projects, and $745 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 $1.225 billion, including $902 million at PEC and $323 million at PEF. PEC
completed installation of controls to meet the requirements of the NOx SIP Call
Rule under Section 110 of the Clean Air Act (NOx SIP Call) in 2007.




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. On September 24, 2008, petitions for rehearing were filed by the
EPA, the Utility Air Regulatory Group, the National Mining Association and
several environmental groups. PEC and PEF are members of the Utility Air
Regulatory Group. On October 21, 2008, the Court issued an order directing
petitionersto
address (1) whether any party is seeking to vacate the CAIR, and (2) whether the
court should stay its mandate until EPA promulgates a revised rule. The Court
will not issue its mandate until after it evaluates the responses to this order
and renders a decision on the petitions for rehearing. If it stands, 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 SO2and NOx
emissions in addition to particulate matter emissions. On February 8, 2008,
the D. C. Court of Appeals vacated the delisting determination and the Clean Air
Mercury Rule (CAMR). On September 17, 2008, the Utility Air Regulatory Group
filed a petition for writ of certiorari with the U.S. Supreme Court seeking a
review of the decision that vacated the CAMR. On October 17, 2008, the EPA filed
a similar petition. 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 any review granted by the Supreme Court will affect the state rules;
however, state-specific provisions are likely to remain in effect. The North
Carolina mercury rule contains a requirement that all coal-fired units in the
state install mercury controls by December 31, 2017, and requires compliance
plan applications to be submitted in 2013. We are currently evaluating the
impact of these decisions. The outcome of these matters cannot be
predicted.




The
Utilities are 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 complete
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 and the market prices
for emission allowances have declined. At September 30, 2008, PEC had
approximately $25 million in SO2 emission
allowances, which will
  49
 
 be
utilized to comply with existing Clean Air Act requirements and an immaterial
amount of NOx emission allowances. 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. During the three
months ended September 30, 2008, PEF reduced the value of its annual NOx
allowance inventory by $59 million due to the uncertainty of whether the
allowances will ultimately be used, and reduced the value of its seasonal NOx
allowance inventory by approximately $1 million based on current market prices.
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
retail portion of the costs of these allowances through its ECRC. Accordingly,
PEF recorded a $57 million regulatory asset for the retail portion of its annual
and seasonal NOx allowances. Therefore, there was no material impact to PEF’s
results of operations for the reduction in value of its NOx allowance inventory.
On August 29, 2008, PEF filed for recovery of its CAIR expenses, including NOx
allowance inventory expense, through the ECRC. A hearing on the matter is
scheduled for November 4-6, 2008. At September 30, 2008, PEF had approximately
$6 million in seasonal NOx emission allowance inventory and approximately $14
million in SO2 emission
allowance inventory. 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 SO2 removal
from its larger coal-fired units, including Roxboro No. 4 and Mayo, so as to
avoid the installation of expensive emission controls on its smaller coal-fired
units. In order to address the joint owner's concerns that such a compliance
strategy would result in a disproportionate share of the cost of compliance for
the jointly owned units, 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 September 30, 2008 and December 31, 2007, the amount of the
liability was $15 million and $30 million, respectively, based upon the
respective estimates for the remaining Clean Smokestacks Act compliance costs.
During the three months ended September 30, 2008, PEC made no additional
accruals and spent approximately $5 million that exceeded the joint owner limit.
During the nine months ended September 30, 2008, PEC made no additional accruals
and spent approximately $15 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 September 5,
2008, the NCUC ordered that PEC shall be allowed to include in rate base all
reasonable and prudently incurred environmental compliance costs in excess of
$584 million, including eligible compliance costs in excess of the joint owner’s
share, as the projects are closed to plant in service (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.


50





PROGRESS
ENERGY




Through
September 30, 2008, contracts procured through our subsidiaries have increased
our aggregate purchase obligations for fuel and purchased power by $7.417
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
September 30, 2008, PEC’s fuel and purchased power commitments increased by
$3.495 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 $2.156 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 $487 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.




In July
2008, PEC entered into an amendment to an existing transportation service
agreement with an intrastate pipeline for firm pipeline transportation capacity
to support PEC’s gas supply needs for the period from April 2011 through May
2030. The total additional cost to PEC associated with this amendment is
estimated to be approximately $54 million. The amendment is subject to several
conditions precedent, including state regulatory approval, the completion and
commencement of operation of necessary related intrastate natural 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
September 30, 2008, PEF’s fuel and purchased power commitments increased by
$3.922 billion from $12.566 billion as stated in Note 22A in the 2007 Form
10-K.  As discussed in Note 22A in the 2007 Form 10-K, PEF entered into
certain conditional contracts for gas supply and transportation. Due to the
conditions of these contracts, the associated estimated costs were not included
in our or PEF’s contractual cash obligations table at December 31, 2007.
Additional conditional gas supply and transportation contracts were entered into
during the second quarter of 2008. During 2008, the conditions were
satisfied and several gas supply and transportation contracts totaling $3.255
billion became effective.  These agreements for the supply of natural gas
and associated firm pipeline transportation augment PEF’s gas supply needs for
various periods from September 2008 through January 2032.  The estimated
costs associated with these agreements are approximately $81 million in 2008,
$436 million in 2009, $570 million in 2010, $602 million in 2011, $548 million
in 2012, and $1.018 billion thereafter.  Also, the increase in gas supply
and transportation purchase commitments includes new contracts along with the
impact of price increases on certain existing contracts that are market price
indexed. Coal purchase commitments increased by approximately $804 million; of
this increase, approximately $230 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.




In April
2008, PEF entered into conditional contracts 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 these agreements is estimated to be approximately
$2.176 billion. The contracts are 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 contracts, 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




51




$987
million. 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 September 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
September 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 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
September 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 September 30, 2008 and December 31, 2007, we
have recorded liabilities related to guarantees and indemnifications to third
parties of approximately $66 million and $80 million, respectively. These
amounts include $15 million and $30 million, respectively, for PEC and $8
million for PEF at September 30, 2008 and December 31, 2007. During the three
months ended September 30, 2008, PEC made no additional accruals and spent
approximately $5 million that exceeded the joint owner limit. During the nine
months ended September 30, 2008, PEC made no additional accruals and spent
approximately $15 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. On August 15, 2008, the Department of Justice appealed
the United States Court of Federal Claims ruling to the D.C. Court of Appeals.
In the event that the Utilities recover




52




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. On September 30, 2008, the EPA issued final rules
for limiting radiation exposure at Yucca Mountain, Nev. The EPA retained the
dose limit of 15 millirem per year for the first 10,000 years and established a
dose limit of 100 millirem for annual exposure per year between 10,000 years and
1 million years. On October 10, 2008, the state of Nevada again filed suit with
the D.C. Court of Appeals challenging the EPA standard.




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.




The DOE
submitted the license application for the proposed high-level nuclear waste
repository at Yucca Mountain in June 2008. The NRC formally docketed the license
application in September 2008, which begins the formal licensing phase that is
anticipated to take three to four years. The state of Nevada and other
interested parties are expected to intervene in the licensing
proceedings.




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.




On
October 9, 2008, the NRC proposed revisions to its waste confidence findings
that would remove the provisions stating that the NRC’s confidence in waste
management, underlying the licensing of reactors, is based in part on a
repository being in operation by 2025. Instead, the NRC states that repository
capacity will be available within 50 to 60 years beyond the licensed operation
of all reactors, and that used fuel generated in any reactor can be safely
stored without significant environmental impact for at least 60 years beyond the
licensed operation of the reactor.




With
certain modifications and additional approvals by the NRC, including the
installation of on-site dry cask storage facilities at PEC’s Robinson Nuclear
Plant, 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
previously owned by the Progress Affiliates and an option to purchase additional
interests in the two synthetic fuels facilities, (2) that it is entitled to
damages because the Progress Affiliates prohibited it from procuring purchasers
for the synthetic fuels facilities and (3) a number of tort claims related to
the contracts.






53




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.




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.


54


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.


55





Condensed
      Consolidating Statement of Income
              Three
      Months Ended September 30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
                Energy, Inc.Operating
      revenues
            
            $
            –
            
            
            $
            1,430
            
            
            $
            1,266
            
            
            $
            2,696Operating
      expensesFuel
      used in electric generation
            
            
            –
            
            
            
            521
            
            
            
            348
            
            
            
            869Purchased
      power
            
            
            –
            
            
            
            305
            
            
            
            145
            
            
            
            450Operation
      and maintenance
            
            
            1
            
            
            
            201
            
            
            
            237
            
            
            
            439Depreciation
      and amortization
            
            
            –
            
            
            
            77
            
            
            
            128
            
            
            
            205Taxes
      other than on income
            
            
            –
            
            
            
            88
            
            
            
            53
            
            
            
            141Other
            
            
            –
            
            
            
            2
            
            
            
            (1
            )
            
            
            1Total
      operating expenses
            
            
            1
            
            
            
            1,194
            
            
            
            910
            
            
            
            2,105Operating
      (loss) income
            
            
            (1
            )
            
            
            236
            
            
            
            356
            
            
            
            591Other
      income, net
            
            
            3
            
            
            
            29
            
            
            
            3
            
            
            
            35Interest
      charges, net
            
            
            49
            
            
            
            68
            
            
            
            50
            
            
            
            167(Loss)
      income from continuing operations before income tax,
              equity
      in earnings of consolidated subsidiaries and minority
    interest
            
            
            (47
            )
            
            
            197
            
            
            
            309
            
            
            
            459Income
      tax (benefit) expense
            
            
            (20
            )
            
            
            59
            
            
            
            111
            
            
            
            150Equity
      in earnings of consolidated subsidiaries
            
            
            336
            
            
            
            –
            
            
            
            (336
            )
            
            
            –Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (1
            )
            
            
            –
            
            
            
            (1
            )Income
      (loss) from continuing operations
            
            
            309
            
            
            
            137
            
            
            
            (138
            )
            
            
            308Discontinued
      operations, net of tax
            
            
            –
            
            
            
            (1
            )
            
            
            2
            
            
            
            1Net
      income (loss)
            
            $
            309
            
            
            $
            136
            
            
            $
            (136
            )
            
            $
            309


56




Condensed
      Consolidating Statement of Income
              Three
      Months Ended September 30, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
                Energy, Inc.Operating
      revenues
            
            $
            –
            
            
            $
            1,465
            
            
            $
            1,285
            
            
            $
            2,750Operating
      expensesFuel
      used in electric generation
            
            
            –
            
            
            
            544
            
            
            
            385
            
            
            
            929Purchased
      power
            
            
            –
            
            
            
            281
            
            
            
            109
            
            
            
            390Operation
      and maintenance
            
            
            2
            
            
            
            213
            
            
            
            241
            
            
            
            456Depreciation
      and amortization
            
            
            –
            
            
            
            102
            
            
            
            121
            
            
            
            223Taxes
      other than on income
            
            
            –
            
            
            
            83
            
            
            
            52
            
            
            
            135Other
            
            
            –
            
            
            
            4
            
            
            
            3
            
            
            
            7Total
      operating expenses
            
            
            2
            
            
            
            1,227
            
            
            
            911
            
            
            
            2,140Operating
      (loss) income
            
            
            (2
            )
            
            
            238
            
            
            
            374
            
            
            
            610Other
      income (expense), net
            
            
            10
            
            
            
            13
            
            
            
            (8
            )
            
            
            15Interest
      charges, net
            
            
            52
            
            
            
            53
            
            
            
            49
            
            
            
            154(Loss)
      income from continuing operations before income tax and
              equity
      in earnings of consolidated subsidiaries
            
            
            (44
            )
            
            
            198
            
            
            
            317
            
            
            
            471Income
      tax (benefit) expense
            
            
            (21
            )
            
            
            65
            
            
            
            116
            
            
            
            160Equity
      in earnings of consolidated subsidiaries
            
            
            340
            
            
            
            –
            
            
            
            (340
            )
            
            
            –Income
      (loss) from continuing operations
            
            
            317
            
            
            
            133
            
            
            
            (139
            )
            
            
            311Discontinued
      operations, net of tax
            
            
            2
            
            
            
            6
            
            
            
            –
            
            
            
            8Net
      income (loss)
            
            $
            319
            
            
            $
            139
            
            
            $
            (139
            )
            
            $
            319





57





Condensed
      Consolidating Statement of Income
              Nine
      Months Ended September 30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
                Energy, Inc.Operating
      revenues
            
            $
            –
            
            
            $
            3,624
            
            
            $
            3,382
            
            
            $
            7,006Operating
      expensesFuel
      used in electric generation
            
            
            –
            
            
            
            1,235
            
            
            
            1,027
            
            
            
            2,262Purchased
      power
            
            
            –
            
            
            
            746
            
            
            
            266
            
            
            
            1,012Operation
      and maintenance
            
            
            3
            
            
            
            621
            
            
            
            746
            
            
            
            1,370Depreciation
      and amortization
            
            
            –
            
            
            
            229
            
            
            
            390
            
            
            
            619Taxes
      other than on income
            
            
            –
            
            
            
            235
            
            
            
            152
            
            
            
            387Other
            
            
            –
            
            
            
            –
            
            
            
            (6
            )
            
            
            (6
            )Total
      operating expenses
            
            
            3
            
            
            
            3,066
            
            
            
            2,575
            
            
            
            5,644Operating
      (loss) income
            
            
            (3
            )
            
            
            558
            
            
            
            807
            
            
            
            1,362Other
      income, net
            
            
            7
            
            
            
            68
            
            
            
            20
            
            
            
            95Interest
      charges, net
            
            
            147
            
            
            
            165
            
            
            
            154
            
            
            
            466(Loss)
      income from continuing operations before income tax,
              equity
      in earnings of consolidated subsidiaries and minority
    interest
            
            
            (143
            )
            
            
            461
            
            
            
            673
            
            
            
            991Income
      tax (benefit) expense
            
            
            (60
            )
            
            
            139
            
            
            
            250
            
            
            
            329Equity
      in earnings of consolidated subsidiaries
            
            
            806
            
            
            
            –
            
            
            
            (806
            )
            
            
            –Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (5
            )
            
            
            –
            
            
            
            (5
            )Income
      (loss) from continuing operations
            
            
            723
            
            
            
            317
            
            
            
            (383
            )
            
            
            657Discontinued
      operations, net of tax
            
            
            –
            
            
            
            62
            
            
            
            4
            
            
            
            66Net
      income (loss)
            
            $
            723
            
            
            $
            379
            
            
            $
            (379
            )
            
            $
            723





58





Condensed
      Consolidating Statement of Income
              Nine
      Months Ended September 30, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
                Energy, Inc.Operating
      revenues
            
            $
            –
            
            
            $
            3,611
            
            
            $
            3,340
            
            
            $
            6,951Operating
      expensesFuel
      used in electric generation
            
            
            –
            
            
            
            1,340
            
            
            
            1,041
            
            
            
            2,381Purchased
      power
            
            
            –
            
            
            
            651
            
            
            
            243
            
            
            
            894Operation
      and maintenance
            
            
            9
            
            
            
            586
            
            
            
            742
            
            
            
            1,337Depreciation
      and amortization
            
            
            –
            
            
            
            300
            
            
            
            365
            
            
            
            665Taxes
      other than on income
            
            
            –
            
            
            
            233
            
            
            
            151
            
            
            
            384Other
            
            
            –
            
            
            
            18
            
            
            
            10
            
            
            
            28Total
      operating expenses
            
            
            9
            
            
            
            3,128
            
            
            
            2,552
            
            
            
            5,689Operating
      (loss) income
            
            
            (9
            )
            
            
            483
            
            
            
            788
            
            
            
            1,262Other
      income, net
            
            
            19
            
            
            
            27
            
            
            
            2
            
            
            
            48Interest
      charges, net
            
            
            151
            
            
            
            135
            
            
            
            145
            
            
            
            431(Loss)
      income from continuing operations before income tax,
              equity
      in earnings of consolidated subsidiaries and minority
    interest
            
            
            (141
            )
            
            
            375
            
            
            
            645
            
            
            
            879Income
      tax (benefit) expense
            
            
            (64
            )
            
            
            101
            
            
            
            236
            
            
            
            273Equity
      in earnings of consolidated subsidiaries
            
            
            472
            
            
            
            –
            
            
            
            (472
            )
            
            
            –Minority
      interest in subsidiaries’ income, net of tax
            
            
            –
            
            
            
            (8
            )
            
            
            –
            
            
            
            (8
            )Income
      (loss) from continuing operations
            
            
            395
            
            
            
            266
            
            
            
            (63
            )
            
            
            598Discontinued
      operations, net of tax
            
            
            6
            
            
            
            38
            
            
            
            (241
            )
            
            
            (197
            )Net
      income (loss)
            
            $
            401
            
            
            $
            304
            
            
            $
            (304
            )
            
            $
            401


59





Condensed
      Consolidating Balance Sheet
              September
      30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
                Energy, Inc.ASSETSUtility
      plant, net
            
            $
            –
            
            
            $
            8,619
            
            
            $
            9,296
            
            
            $
            17,915Current
      assetsCash
      and cash equivalents
            
            
            –
            
            
            
            257
            
            
            
            146
            
            
            
            403Notes
      receivable from affiliated companies
            
            
            17
            
            
            
            66
            
            
            
            (83
            )
            
            
            –Prepayments
      and other current assets
            
            
            69
            
            
            
            1,353
            
            
            
            1,324
            
            
            
            2,746Total
      current assets
            
            
            86
            
            
            
            1,676
            
            
            
            1,387
            
            
            
            3,149Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
            
            
            11,927
            
            
            
            –
            
            
            
            (11,927
            )
            
            
            –Goodwill
            
            
            –
            
            
            
            –
            
            
            
            3,655
            
            
            
            3,655Regulatory
      assets
            
            
            –
            
            
            
            578
            
            
            
            769
            
            
            
            1,347Other
      assets and deferred debits
            
            
            155
            
            
            
            1,025
            
            
            
            991
            
            
            
            2,171Total
      deferred debits and other assets
            
            
            12,082
            
            
            
            1,603
            
            
            
            (6,512
            )
            
            
            7,173Total
      assets
            
            $
            12,168
            
            
            $
            11,898
            
            
            $
            4,171
            
            
            $
            28,237CAPITALIZATION
      AND LIABILITIESCommon
      stock equity
            
            $
            8,827
            
            
            $
            3,527
            
            
            $
            (3,527
            )
            
            $
            8,827Preferred
      stock of subsidiaries – not subject to mandatory
redemption
            
            
            –
            
            
            
            34
            
            
            
            59
            
            
            
            93Minority
      interest
            
            
            –
            
            
            
            3
            
            
            
            3
            
            
            
            6Long-term
      debt, affiliate
            
            
            –
            
            
            
            309
            
            
            
            (37
            )
            
            
            272Long-term
      debt, net
            
            
            2,595
            
            
            
            4,182
            
            
            
            3,109
            
            
            
            9,886Total
      capitalization
            
            
            11,422
            
            
            
            8,055
            
            
            
            (393
            )
            
            
            19,084Current
      liabilitiesCurrent
      portion of long-term debt
            
            
            –
            
            
            
            –
            
            
            
            400
            
            
            
            400Short-term
      debt
            
            
            495
            
            
            
            –
            
            
            
            –
            
            
            
            495Notes
      payable to affiliated companies
            
            
            –
            
            
            
            131
            
            
            
            (131
            )
            
            
            –Other
      current liabilities
            
            
            203
            
            
            
            1,226
            
            
            
            743
            
            
            
            2,172Total
      current liabilities
            
            
            698
            
            
            
            1,357
            
            
            
            1,012
            
            
            
            3,067Deferred
      credits and other liabilitiesNoncurrent
      income tax liabilities
            
            
            1
            
            
            
            80
            
            
            
            645
            
            
            
            726Regulatory
      liabilities
            
            
            –
            
            
            
            1,282
            
            
            
            1,175
            
            
            
            2,457Other
      liabilities and deferred credits
            
            
            47
            
            
            
            1,124
            
            
            
            1,732
            
            
            
            2,903Total
      deferred credits and other liabilities
            
            
            48
            
            
            
            2,486
            
            
            
            3,552
            
            
            
            6,086Total
      capitalization and liabilities
            
            $
            12,168
            
            
            $
            11,898
            
            
            $
            4,171
            
            
            $
            28,237





60





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
            
            
            
            255Notes
      receivable from affiliated companies
            
            
            157
            
            
            
            149
            
            
            
            (306
            )
            
            
            –Assets
      to be divested
            
            
            –
            
            
            
            48
            
            
            
            4
            
            
            
            52Prepayments
      and other current assets
            
            
            21
            
            
            
            1,252
            
            
            
            1,249
            
            
            
            2,522Total
      current assets
            
            
            363
            
            
            
            1,492
            
            
            
            974
            
            
            
            2,829Deferred
      debits and other assetsInvestment
      in consolidated subsidiaries
            
            
            10,969
            
            
            
            –
            
            
            
            (10,969
            )
            
            
            –Goodwill
            
            
            –
            
            
            
            1
            
            
            
            3,654
            
            
            
            3,655Regulatory
      assets
            
            
            –
            
            
            
            266
            
            
            
            680
            
            
            
            946Other
      assets and deferred debits
            
            
            149
            
            
            
            1,309
            
            
            
            872
            
            
            
            2,330Total
      deferred debits and other assets
            
            
            11,118
            
            
            
            1,576
            
            
            
            (5,763
            )
            
            
            6,931Total
      assets
            
            $
            11,481
            
            
            $
            10,668
            
            
            $
            4,216
            
            
            $
            26,365CAPITALIZATION
      AND LIABILITIESCommon
      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
            
            
            
            –
            
            
            
            –
            
            
            
            201Notes
      payable to affiliated companies
            
            
            –
            
            
            
            227
            
            
            
            (227
            )
            
            
            –Liabilities
      to be divested
            
            
            –
            
            
            
            8
            
            
            
            –
            
            
            
            8Other
      current liabilities
            
            
            215
            
            
            
            1,237
            
            
            
            764
            
            
            
            2,216Total
      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





61





Condensed
      Consolidating Statement of Cash Flows
              Nine
      Months Ended September 30, 2008(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
              Energy, Inc.Net
      cash (used) provided by operating activities
            
            $
            (138
            )
            
            $
            502
            
            
            $
            995
            
            
            $
            1,359Investing
      activitiesGross
      property additions
            
            
            –
            
            
            
            (1,230
            )
            
            
            (530
            )
            
            
            (1,760
            )Nuclear
      fuel additions
            
            
            –
            
            
            
            (27
            )
            
            
            (131
            )
            
            
            (158
            )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
            
            
            –
            
            
            
            60
            
            
            
            3
            
            
            
            63Proceeds
      from sales of assets to affiliated companies
            
            
            –
            
            
            
            12
            
            
            
            (12
            )
            
            
            –Purchases
      of available-for-sale securities and other investments
            
            
            (6
            )
            
            
            (618
            )
            
            
            (566
            )
            
            
            (1,190
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            –
            
            
            
            622
            
            
            
            532
            
            
            
            1,154Contributions
      to consolidated subsidiaries
            
            
            (99
            )
            
            
            –
            
            
            
            99
            
            
            
            –Changes
      in advances to affiliated companies
            
            
            140
            
            
            
            83
            
            
            
            (223
            )
            
            
            –Other
      investing activities
            
            
            (1
            )
            
            
            9
            
            
            
            (11
            )
            
            
            (3
            )Net
      cash provided (used) by investing activities
            
            
            34
            
            
            
            (1,089
            )
            
            
            (839
            )
            
            
            (1,894
            )Financing
      activitiesIssuance
      of common stock
            
            
            106
            
            
            
            –
            
            
            
            –
            
            
            
            106Dividends
      paid on common stock
            
            
            (481
            )
            
            
            –
            
            
            
            –
            
            
            
            (481
            )Dividends
      paid to parent
            
            
            –
            
            
            
            (3
            )
            
            
            3
            
            
            
            –Payments
      of short-term debt with original maturities greater than 90
      days
            
            
            (176
            )
            
            
            –
            
            
            
            –
            
            
            
            (176
            )Net
      increase in short-term debt
            
            
            470
            
            
            
            –
            
            
            
            –
            
            
            
            470Proceeds
      from issuance of long-term debt, net
            
            
            –
            
            
            
            1,475
            
            
            
            322
            
            
            
            1,797Retirement
      of long-term debt
            
            
            –
            
            
            
            (577
            )
            
            
            (300
            )
            
            
            (877
            )Cash
      distributions to minority interests of consolidated
      subsidiaries
            
            
            –
            
            
            
            (85
            )
            
            
            –
            
            
            
            (85
            )Contributions
      from parent
            
            
            –
            
            
            
            85
            
            
            
            (85
            )
            
            
            –Changes
      in advances from affiliated companies
            
            
            –
            
            
            
            (96
            )
            
            
            96
            
            
            
            –Other
      financing activities
            
            
            –
            
            
            
            2
            
            
            
            (73
            )
            
            
            (71
            )Net
      cash (used) provided by financing activities
            
            
            (81
            )
            
            
            801
            
            
            
            (37
            )
            
            
            683Net
      (decrease) increase in cash and cash equivalents
            
            
            (185
            )
            
            
            214
            
            
            
            119
            
            
            
            148Cash
      and cash equivalents at beginning of period
            
            
            185
            
            
            
            43
            
            
            
            27
            
            
            
            255Cash
      and cash equivalents at end of period
            
            $
            –
            
            
            $
            257
            
            
            $
            146
            
            
            $
            403





62





Condensed
      Consolidating Statement of Cash Flows
              Nine
      Months Ended September 30, 2007(in
      millions)
            
            Parent
            
            
            Subsidiary
      Guarantor
            
            
            Other
            
            
            Progress
                Energy, Inc.Net
      cash provided by operating activities
            
            $
            6
            
            
            $
            356
            
            
            $
            376
            
            
            $
            738Investing
      activitiesGross
      property additions
            
            
            –
            
            
            
            (822
            )
            
            
            (589
            )
            
            
            (1,411
            )Nuclear
      fuel additions
            
            
            –
            
            
            
            (39
            )
            
            
            (159
            )
            
            
            (198
            )Proceeds
      from sales of discontinued operations and other assets, net of cash
      divested
            
            
            –
            
            
            
            37
            
            
            
            621
            
            
            
            658Purchases
      of available-for-sale securities and other investments
            
            
            –
            
            
            
            (457
            )
            
            
            (615
            )
            
            
            (1,072
            )Proceeds
      from sales of available-for-sale securities and other
      investments
            
            
            21
            
            
            
            279
            
            
            
            639
            
            
            
            939Changes
      in advances to affiliated companies
            
            
            (250
            )
            
            
            37
            
            
            
            213
            
            
            
            –Return
      of investment in consolidated subsidiary
            
            
            190
            
            
            
            –
            
            
            
            (190
            )
            
            
            –Other
      investing activities
            
            
            (5
            )
            
            
            12
            
            
            
            9
            
            
            
            16Net
      cash used by investing activities
            
            
            (44
            )
            
            
            (953
            )
            
            
            (71
            )
            
            
            (1,068
            )Financing
      activitiesIssuance
      of common stock
            
            
            134
            
            
            
            –
            
            
            
            –
            
            
            
            134Dividends
      paid on common stock
            
            
            (469
            )
            
            
            –
            
            
            
            –
            
            
            
            (469
            )Dividends
      paid to parent
            
            
            –
            
            
            
            (10
            )
            
            
            10
            
            
            
            –Net
      increase in short-term debt
            
            
            400
            
            
            
            –
            
            
            
            150
            
            
            
            550Proceeds
      from issuance of long-term debt, net
            
            
            –
            
            
            
            742
            
            
            
            –
            
            
            
            742Retirement
      of long-term debt
            
            
            –
            
            
            
            (87
            )
            
            
            (200
            )
            
            
            (287
            )Cash
      distributions to minority interests of consolidated
      subsidiaries
            
            
            –
            
            
            
            (10
            )
            
            
            –
            
            
            
            (10
            )Changes
      in advances from affiliated companies
            
            
            –
            
            
            
            214
            
            
            
            (214
            )
            
            
            –Other
      financing activities
            
            
            –
            
            
            
            49
            
            
            
            (27
            )
            
            
            22Net
      cash provided (used) by financing activities
            
            
            65
            
            
            
            898
            
            
            
            (281
            )
            
            
            682Net
      increase in cash and cash equivalents
            
            
            27
            
            
            
            301
            
            
            
            24
            
            
            
            352Cash
      and cash equivalents at beginning of period
            
            
            153
            
            
            
            40
            
            
            
            72
            
            
            
            265Cash
      and cash equivalents at end of period
            
            $
            180
            
            
            $
            341
            
            
            $
            96
            
            
            $
            617





63


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 nine months ended September 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.




64





OVERVIEW




For the
quarter ended September 30, 2008, our net income was $309 million, or $1.19 per
share, compared to net income of $319 million, or $1.24 per share, for the same
period in 2007. For the quarter ended September 30, 2008, our income from
continuing operations was $308 million compared to $311 million for the same
period in 2007. The decrease in income from continuing operations as compared to
prior year was primarily due to:




·
            unfavorable
      weather at the Utilities;


·
            higher
      interest expense at PEF;


·
            the
      impact of tax levelization recorded because accounting principles
      generally accepted in the United States (GAAP) require companies to apply
      a levelized effective tax rate to interim periods that is consistent with
      the estimated annual effective tax rate;
and


·
            unfavorable
      retail customer growth and usage at
PEF.





Partially
offsetting these items were:




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


·
            increased
      retail base rates at PEF;


·
            higher
      wholesale revenues at PEF; and


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





For the
nine months ended September 30, 2008, our net income was $723 million, or $2.78
per share, compared to net income of $401 million, or $1.57 per share, for the
same period in 2007. For the nine months ended September 30, 2008, our income
from continuing operations was $657 million compared to $598 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;


·
            increased
      retail base rates at PEF;


·
            higher
      wholesale revenues at PEF;


·
            favorable
      retail customer growth and usage at PEC;
and


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





Partially
offsetting these items were:




·
            higher
      interest expense at PEF;


·
            unfavorable
      weather at PEC;


·
            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.





65


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


Three Months
      Ended
                September
      30,
            
            
            Nine
      Months Ended
              September
      30,(in
      millions)
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Business
      SegmentPEC
            
            $
            200
            
            
            $
            203
            
            
            $
            426
            
            
            $
            414PEF
            
            
            143
            
            
            
            138
            
            
            
            334
            
            
            
            266Total
      segment profit
            
            
            343
            
            
            
            341
            
            
            
            760
            
            
            
            680Corporate
      and Other
            
            
            (35
            )
            
            
            (30
            )
            
            
            (103
            )
            
            
            (82
            )Income
      from continuing operations
            
            
            308
            
            
            
            311
            
            
            
            657
            
            
            
            598Discontinued
      operations, net of tax
            
            
            1
            
            
            
            8
            
            
            
            66
            
            
            
            (197
            )Net
      income
            
            $
            309
            
            
            $
            319
            
            
            $
            723
            
            
            $
            401





PROGRESS
ENERGY CAROLINAS




PEC
contributed segment profits of $200 million and $203 million for the three
months ended September 30, 2008 and 2007, respectively. The decrease in profits
for the three months ended September 30, 2008, compared to the same period in
2007, was primarily due to the unfavorable impact of weather, partially offset
by favorable AFUDC and lower purchased power capacity costs due to the
expiration of a power buyback agreement.




PEC
contributed segment profits of $426 million and $414 million for the nine months
ended September 30, 2008 and 2007, respectively. The increase in profits for the
nine months ended September 30, 2008, compared to the same period in 2007, was
primarily due to the favorable impact of retail customer growth and usage, lower
purchased power capacity costs due to the expiration of a power buyback
agreement and favorable AFUDC, partially offset by the unfavorable impact of
weather, higher depreciation and amortization and lower excess generation
revenues.




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 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.




66





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




REVENUES




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


(in
      millions)
            
            Three
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            495
            
            
            $
            (8
            )
            
            
            (1.6
            )
            
            $
            503Commercial
            
            
            331
            
            
            
            6
            
            
            
            1.8
            
            
            
            325Industrial
            
            
            200
            
            
            
            4
            
            
            
            2.0
            
            
            
            196Governmental
            
            
            32
            
            
            
            3
            
            
            
            10.3
            
            
            
            29Total
      retail revenues
            
            
            1,058
            
            
            
            5
            
            
            
            0.5
            
            
            
            1,053Wholesale
            
            
            196
            
            
            
            (12
            )
            
            
            (5.8
            )
            
            
            208Unbilled
            
            
            (16
            )
            
            
            (16
            )
            
            
            –
            
            
            
            –Miscellaneous
            
            
            28
            
            
            
            3
            
            
            
            12.0
            
            
            
            25Total
      electric revenues
            
            
            1,266
            
            
            
            (20
            )
            
            
            (1.6
            )
            
            
            1,286Less:
      Fuel revenues
            
            
            (455
            )
            
            
            (12
            )
            
            
            –
            
            
            
            (443
            )Revenues
      excluding fuel
            
            $
            811
            
            
            $
            (32
            )
            
            
            (3.8
            )
            
            $
            843





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


(in
      millions of kWh)
            
            Three
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            4,929
            
            
            
            (189
            )
            
            
            (3.7
            )
            
            
            5,118Commercial
            
            
            4,079
            
            
            
            (12
            )
            
            
            (0.3
            )
            
            
            4,091Industrial
            
            
            2,879
            
            
            
            (231
            )
            
            
            (7.4
            )
            
            
            3,110Governmental
            
            
            437
            
            
            
            16
            
            
            
            3.8
            
            
            
            421Total
      retail energy sales
            
            
            12,324
            
            
            
            (416
            )
            
            
            (3.3
            )
            
            
            12,740Wholesale
            
            
            3,746
            
            
            
            (438
            )
            
            
            (10.5
            )
            
            
            4,184Unbilled
            
            
            (250
            )
            
            
            (112
            )
            
            
            –
            
            
            
            (138
            )Total
      kWh sales
            
            
            15,820
            
            
            
            (966
            )
            
            
            (5.8
            )
            
            
            16,786





PEC’s
revenues, excluding fuel revenues of $455 million and $443 million for the three
months ended September 30, 2008 and 2007, respectively, decreased $32 million.
The decrease in revenues excluding fuel is primarily due to the $28 million
unfavorable impact of weather and $5 million lower excess generation revenues,
partially offset by the $7 million favorable impact of retail customer growth
and usage. The unfavorable impact of weather was driven by cooling degree days
12 percent lower than 2007. The lower excess generation revenues were primarily
due to unfavorable market dynamics due to higher relative fuel costs. The
favorable impact of retail customer growth and usage was driven by a net 23,000
customer increase in PEC’s average number of customers for the three months
ended September 30, 2008, compared to the same period in 2007, partially offset
by a decrease in the average usage per retail customer.




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
impacted by the decline in general economic conditions as significantly as PEF.
However, through September 30, 2008, PEC has experienced some decline in the
rate of residential and commercial sales growth. In the future, PEC’s customer
usage could be impacted by customer response to energy-efficiency programs and
to increased rates resulting from higher fuel and other recoverable
costs.




Retail
revenues increased for the three months ended September 30, 2008, despite a
decrease in retail 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.




67





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 $493 million for the three months ended September
30, 2008, which represents a $1 million decrease compared to the same period in
2007. Fuel used in electric generation decreased $37 million compared to the
same period in 2007. The decrease was primarily due to a decrease in deferred
fuel expense driven by a $24 million impact from the implementation of the North
Carolina comprehensive energy legislation (See “Other Matters – Regulatory
Environment”) and a $12 million impact related to a decrease in the collection
of prior period costs. Current year purchased power costs were $36 million
higher than the three months ended September 30, 2007, due to increased
economical purchases in 2008. Higher purchased power expenses were partially
offset by the $9 million impact from the expiration of a power buyback agreement
with North Carolina Eastern Municipal Power Agency (Power Agency).




Depreciation and
Amortization




Depreciation
and amortization expense was $124 million for the three months ended September
30, 2008, which represents a $6 million increase compared to the same period in
2007. Depreciation and amortization expense increased primarily due to $10
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 (See Note 4A).




Total Other Income,
net




Total
other income, net of $6 million increased $2 million for the three months ended
September 30, 2008, compared to the same period in 2007, primarily due to $7
million favorable AFUDC equity related to increased Clean Smokestacks Act
compliance and other eligible construction project costs, partially offset by $5
million derivative mark-to-market losses. The derivative mark-to-market losses
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.




Total Interest Charges,
net




Total
interest charges, net of $50 million decreased $6 million for the three months
ended September 30, 2008, compared to the same period in 2007, primarily due to
$2 million lower interest as a result of lower average debt outstanding and $2
million favorable AFUDC debt related to increased Clean Smokestacks Act
compliance and other eligible construction project costs.




Income Tax
Expense




Income
tax expense decreased $11 million for the three months ended September 30, 2008,
as compared to the same period in 2007, primarily due to the $6 million tax
impact of lower pre-tax earnings, the $4 million tax impact of employee
stock-based benefits and the $3 million impact of the increase in AFUDC equity
discussed above, partially offset by the $4 million impact of tax levelization.
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. PEC’s
income tax expense was increased by $3 million for the three months ended
September 30, 2008, in order to maintain an effective tax rate consistent with
the estimated annual rate, compared to a decrease of $1 million for the three
months ended September 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.




68





Nine Months Ended September
30, 2008, Compared to Nine Months Ended September 30, 2007




REVENUES




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


(in
      millions)
            
            Nine
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            1,256
            
            
            $
            2
            
            
            
            0.2
            
            
            $
            1,254Commercial
            
            
            862
            
            
            
            22
            
            
            
            2.6
            
            
            
            840Industrial
            
            
            555
            
            
            
            20
            
            
            
            3.7
            
            
            
            535Governmental
            
            
            78
            
            
            
            5
            
            
            
            6.8
            
            
            
            73Total
      retail revenues
            
            
            2,751
            
            
            
            49
            
            
            
            1.8
            
            
            
            2,702Wholesale
            
            
            566
            
            
            
            6
            
            
            
            1.1
            
            
            
            560Unbilled
            
            
            (10
            )
            
            
            (13
            )
            
            
            –
            
            
            
            3Miscellaneous
            
            
            74
            
            
            
            –
            
            
            
            –
            
            
            
            74Total
      electric revenues
            
            
            3,381
            
            
            
            42
            
            
            
            1.3
            
            
            
            3,339Less:
      Fuel revenues
            
            
            (1,227
            )
            
            
            (61
            )
            
            
            –
            
            
            
            (1,166
            )Revenues
      excluding fuel
            
            $
            2,154
            
            
            $
            (19
            )
            
            
            (0.9
            )
            
            $
            2,173





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


(in
      millions of kWh)
            
            Nine
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            13,192
            
            
            
            (242
            )
            
            
            (1.8
            )
            
            
            13,434Commercial
            
            
            10,741
            
            
            
            59
            
            
            
            0.6
            
            
            
            10,682Industrial
            
            
            8,773
            
            
            
            (144
            )
            
            
            (1.6
            )
            
            
            8,917Governmental
            
            
            1,105
            
            
            
            25
            
            
            
            2.3
            
            
            
            1,080Total
      retail energy sales
            
            
            33,811
            
            
            
            (302
            )
            
            
            (0.9
            )
            
            
            34,113Wholesale
            
            
            10,959
            
            
            
            (347
            )
            
            
            (3.1
            )
            
            
            11,306Unbilled
            
            
            (246
            )
            
            
            (168
            )
            
            
            –
            
            
            
            (78
            )Total
      kWh sales
            
            
            44,524
            
            
            
            (817
            )
            
            
            (1.8
            )
            
            
            45,341





PEC’s
revenues, excluding fuel revenues of $1.227 billion and $1.166 billion for the
nine months ended September 30, 2008 and 2007, respectively, decreased $19
million. The decrease in revenues excluding fuel is primarily due to the $36
million unfavorable impact of weather and $13 million lower excess generation
revenues, partially offset by the $33 million favorable impact of retail
customer growth and usage. The unfavorable impact of weather was driven by
cooling degree days 7 percent lower than 2007. Lower excess generation revenues
were primarily due to unfavorable market dynamics due to higher relative fuel
costs. The favorable impact of retail customer growth and usage was driven by a
net 25,000 customer increase in PEC’s average number of customers for the nine
months ended September 30, 2008, compared to the same period in 2007, and by an
increase in the average usage per retail customer.




As
discussed previously in “Revenues” for the three months ended September 30, 2008
and 2007, PEC has not been impacted by the decline in general economic
conditions as significantly as PEF. However, through September 30, 2008, PEC has
experienced some decline in the rate of residential and commercial sales growth.
In the future, PEC’s customer usage could be impacted by customer response to
energy-efficiency programs and to increased rates resulting from higher fuel and
other recoverable costs.




Retail
and wholesale revenues increased for the nine months ended September 30, 2008,
despite a decrease in retail and wholesale energy sales for the same period
primarily due to the impact of increased fuel revenues as a result of higher
energy costs. Additionally, retail revenues increased for the nine months ended
September 30, 2008, due to the recovery of prior year fuel
costs.


69


EXPENSES




Fuel and Purchased
Power




Fuel and
purchased power expenses were $1.293 billion for the nine months ended September
30, 2008, which represents a $9 million increase compared to the same period in
2007. Current year purchased power costs were $23 million higher than the nine
months ended September 30, 2007 due to increased economical purchases in
2008 of $46 million, partially offset by the $29 million impact from the
expiration of a power buyback agreement with Power Agency. Fuel used in electric
generation decreased $14 million compared to the same period in 2007 primarily
due to a decrease in deferred fuel expense of $31 million, partially offset by
an increase in current year fuel costs of $17 million. Deferred fuel expense
decreased primarily due to a $48 million impact of the implementation of the
North Carolina comprehensive energy legislation (See “Other Matters – Regulatory
Environment”), partially offset by a $10 million increase driven by higher fuel
costs. Current year fuel costs increased primarily due to an increase in fuel
prices, partially offset by a change in the generation mix and lower system
requirements.




Operation and
Maintenance




O&M
expenses were $766 million for the nine months ended September 30, 2008, which
represents a $4 million increase compared to the same period in 2007. O&M
expenses increased primarily due to a $24 million increase in nuclear expenses,
of which $11 million relates to refurbishments, preventative maintenance and
incremental outage expenses at Brunswick Nuclear Plant (Brunswick), and a $7
million increase in estimated environmental remediation expenses (See Note 12A),
partially offset by lower plant outage and maintenance costs of $25 million
(primarily due to one nuclear outage in the current year compared to two in the
prior year).




Depreciation and
Amortization




Depreciation
and amortization expense was $379 million for the nine months ended September
30, 2008, which represents a $26 million increase compared to the same period in
2007. Depreciation and amortization expense increased primarily due to $25
million additional depreciation associated with the accelerated cost-recovery
program for nuclear generating assets (See Note 4A) and the $9 million impact of
depreciable asset base increases, partially offset by $10 million lower Clean
Smokestacks Act amortization (See Note 4A).




Other




Other
operating expenses consisted of gains of $6 million for the nine months ended
September 30, 2008, primarily due to land sales. There were no net gains from
land sales for the same period in 2007.




Total Other Income,
net




Total
other income, net of $28 million increased $3 million for the nine months ended
September 30, 2008, compared to the same period in 2007, primarily due to $12
million favorable AFUDC equity related to increased Clean Smokestacks Act
compliance and other eligible construction project costs, partially offset by $7
million lower interest income resulting from lower temporary investment
balances. We expect AFUDC equity to continue to increase for the remainder of
2008, primarily due to increased spending on eligible construction
projects.




Total Interest Charges,
net




Total
interest charges, net of $156 million decreased $9 million for the nine months
ended September 30, 2008, compared to the same period in 2007, primarily due to
$5 million lower interest as a result of lower average debt outstanding and $4
million favorable AFUDC debt related to increased Clean Smokestacks Act
compliance and other eligible construction project costs.




70


Income Tax
Expense




Income
tax expense increased $8 million for the nine months ended September 30, 2008,
as compared to the same period in 2007, primarily due to the $8 million tax
impact of higher pre-tax earnings, $4 million prior year changes in tax
estimates and the $4 million impact of tax levelization, partially offset by the
$6 million tax impact of employee stock-based benefits and the $5 million impact
of the increase in AFUDC equity discussed above. 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. PEC’s income tax expense was increased
by $2 million for the nine months ended September 30, 2008, in order to maintain
an effective tax rate consistent with the estimated annual rate, compared to a
decrease of $2 million for the nine months ended September 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.




PROGRESS
ENERGY FLORIDA




PEF
contributed segment profits of $143 million and $138 million for the three
months ended September 30, 2008 and 2007, respectively. The increase in profits
for the three months ended September 30, 2008, compared to the same period in
2007, was primarily due to increased retail base rates, favorable AFUDC and
higher wholesale revenues, partially offset by higher interest expense, the
unfavorable impact of weather, the unfavorable impact of retail customer growth
and usage and severance expenses in 2008.




PEF
contributed segment profits of $334 million and $266 million for the nine months
ended September 30, 2008 and 2007, respectively. The increase in profits for the
nine months ended September 30, 2008, compared to the same period in 2007, was
primarily due to favorable AFUDC, increased retail base rates and higher
wholesale revenues, partially offset by higher interest expense and 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 September
30, 2008, Compared to Three Months Ended September 30, 2007




REVENUES




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


(in
      millions)
            
            Three
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            722
            
            
            $
            (52
            )
            
            
            (6.7
            )
            
            $
            774Commercial
            
            
            328
            
            
            
            (8
            )
            
            
            (2.4
            )
            
            
            336Industrial
            
            
            81
            
            
            
            (3
            )
            
            
            (3.6
            )
            
            
            84Governmental
            
            
            81
            
            
            
            (3
            )
            
            
            (3.6
            )
            
            
            84Total
      retail revenues
            
            
            1,212
            
            
            
            (66
            )
            
            
            (5.2
            )
            
            
            1,278Wholesale
            
            
            175
            
            
            
            42
            
            
            
            31.6
            
            
            
            133Unbilled
            
            
            (5
            )
            
            
            (7
            )
            
            
            –
            
            
            
            2Miscellaneous
            
            
            46
            
            
            
            3
            
            
            
            7.0
            
            
            
            43Total
      electric revenues
            
            
            1,428
            
            
            
            (28
            )
            
            
            (1.9
            )
            
            
            1,456Less:
      Fuel and other pass-through revenues
            
            
            (920
            )
            
            
            46
            
            
            
            –
            
            
            
            (966
            )Revenues
      excluding fuel and other pass-through revenues
            
            $
            508
            
            
            $
            18
            
            
            
            3.7
            
            
            $
            490





71


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


(in
      millions of kWh)
            
            Three
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            6,093
            
            
            
            (397
            )
            
            
            (6.1
            )
            
            
            6,490Commercial
            
            
            3,523
            
            
            
            (32
            )
            
            
            (0.9
            )
            
            
            3,555Industrial
            
            
            981
            
            
            
            (27
            )
            
            
            (2.7
            )
            
            
            1,008Governmental
            
            
            901
            
            
            
            (26
            )
            
            
            (2.8
            )
            
            
            927Total
      retail energy sales
            
            
            11,498
            
            
            
            (482
            )
            
            
            (4.0
            )
            
            
            11,980Wholesale
            
            
            1,924
            
            
            
            171
            
            
            
            9.8
            
            
            
            1,753Unbilled
            
            
            (184
            )
            
            
            (162
            )
            
            
            –
            
            
            
            (22
            )Total
      kWh sales
            
            
            13,238
            
            
            
            (473
            )
            
            
            (3.4
            )
            
            
            13,711





PEF’s
revenues, excluding fuel and other pass-through revenues of $920 million and
$966 million for the three months ended September 30, 2008 and 2007,
respectively, increased $18 million. The increase in revenues was primarily due
to base rate increases and increased wholesale revenues, partially offset by the
unfavorable impacts of weather and retail customer growth and usage. The
increase in base rates was $28 million; Hines 4 being placed in service
contributed $16 million in additional revenues and the transfer of Hines 2 cost
recovery from the fuel clause to base rates contributed $12 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
$13 million primarily due to several new and amended contracts. Offsetting these
favorable items were the $16 million unfavorable impact of weather driven by
cooling degree days 8 percent lower than 2007 and the unfavorable retail
customer growth and usage impact of $9 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’s average number of customers for the
three months ended September 30, 2008, compared to the same period in 2007,
decreased a net 2,000 customers. In comparison, PEF’s average number of
customers for the three months ended September 30, 2007, compared to the same
period in 2006, increased a net 22,000 customers. In the future, PEF’s customer
usage could be impacted by customer response to energy-efficiency programs and
to increased rates resulting from higher fuel and other recoverable
costs.




PEF has
secured 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 $826 million for the three months ended September
30, 2008, which represents a $1 million increase compared to the same period in
2007. Purchased power costs were $24 million higher for the three months ended
September 30, 2008, primarily due to increased costs of $14 million in the
current year driven by higher fuel costs and an increase in the recovery of
deferred capacity costs of $9 million. Fuel used in electric generation
decreased $23 million primarily due to a decrease in deferred fuel expense of
$86 million, partially offset by an increase in current year fuel costs of $62
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 fuel prices.




72




With the
higher fuel costs experienced in 2008 and the anticipated high fuel costs for
the remainder of 2008, the Florida Public Service Commission (FPSC) approved
PEF’s petition requesting a mid-course correction to its fuel cost-recovery
factors which was effective August 1, 2008 (See Note 4B).




Operation and
Maintenance




O&M
expenses were $201 million for the three months ended September 30, 2008, which
represents a $12 million decrease when compared to the same period in 2007.
O&M expenses decreased $8 million due to lower employee benefits, $6 million
related to the expiration of a regulatory order spanning August 2007 to August
2008 to replenish storm damage reserves and $4 million lower environmental
cost-recovery clause (ECRC) costs due to a decrease in the current year rates
resulting from prior year over-recovery, partially offset by $6 million
severance expenses in 2008. The severance expenses in 2008 resulted from the
elimination of approximately 300 positions as part of a restructuring of our
distribution operations in response to the ongoing economic downturn in Florida.
The replenishment of storm damage reserves and ECRC expenses are recovered
through cost-recovery clauses and, therefore, have no material impact on
earnings. In the aggregate, O&M expenses recoverable through base rates
decreased approximately $3 million compared to the same period in
2007.




Depreciation and
Amortization




Depreciation
and amortization expense was $77 million for the three months ended September
30, 2008, which represents a $23 million decrease compared to the same period in
2007. Depreciation and amortization expense decreased $21 million due to lower
amortization of unrecovered storm restoration costs and $7 million due to a
write-off in 2007 of leasehold improvements primarily related to vacated office
space, 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.




Total Other Income,
net




Total
other income, net of $30 million increased $17 million for the three months
ended September 30, 2008, compared to the same period in 2007, primarily due to
$13 million favorable AFUDC equity related to eligible construction project
costs and $4 million higher interest income driven by higher temporary
investment balances resulting from a debt issuance. We expect AFUDC equity to
continue to increase primarily due to increased spending on environmental
initiatives and other eligible construction projects.




Total Interest Charges,
net




Total
interest charges, net were $61 million for the three months ended September 30,
2008, which represents a $19 million increase compared to the same period in
2007. Interest charges, net increased $27 million as a result of higher average
debt outstanding, partially offset by $4 million favorable AFUDC debt related to
increased eligible construction project costs.




Income Tax
Expense




Income
tax expense decreased $6 million for the three months ended September 30, 2008,
compared to the same period in 2007, primarily due to the $5 million impact of
the increase in AFUDC equity discussed above. AFUDC equity is excluded from the
calculation of income tax expense.




73





Nine Months Ended September
30, 2008, Compared to Nine Months Ended September 30, 2007




REVENUES




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


(in
      millions)
            
            Nine
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            $
            1,739
            
            
            
            (59
            )
            
            
            (3.3
            )
            
            $
            1,798Commercial
            
            
            852
            
            
            
            (12
            )
            
            
            (1.4
            )
            
            
            864Industrial
            
            
            230
            
            
            
            (6
            )
            
            
            (2.5
            )
            
            
            236Governmental
            
            
            217
            
            
            
            (8
            )
            
            
            (3.6
            )
            
            
            225Total
      retail revenues
            
            
            3,038
            
            
            
            (85
            )
            
            
            (2.7
            )
            
            
            3,123Wholesale
            
            
            420
            
            
            
            106
            
            
            
            33.8
            
            
            
            314Unbilled
            
            
            27
            
            
            
            (2
            )
            
            
            –
            
            
            
            29Miscellaneous
            
            
            133
            
            
            
            3
            
            
            
            2.3
            
            
            
            130Total
      electric revenues
            
            
            3,618
            
            
            
            22
            
            
            
            0.6
            
            
            
            3,596Less:
      Fuel and other pass-through revenues
            
            
            (2,260
            )
            
            
            76
            
            
            
            –
            
            
            
            (2,336
            )Revenues
      excluding fuel and other pass-through revenues
            
            $
            1,358
            
            
            $
            98
            
            
            
            7.8
            
            
            $
            1,260





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


(in
      millions of kWh)
            
            Nine
      Months Ended September 30,Customer
      Class
            
            2008
            
            
            Change
            
            
            %
      Change
            
            
            2007Residential
            
            
            14,854
            
            
            
            (293
            )
            
            
            (1.9
            )
            
            
            15,147Commercial
            
            
            9,252
            
            
            
            127
            
            
            
            1.4
            
            
            
            9,125Industrial
            
            
            2,855
            
            
            
            13
            
            
            
            0.5
            
            
            
            2,842Governmental
            
            
            2,468
            
            
            
            (18
            )
            
            
            (0.7
            )
            
            
            2,486Total
      retail energy sales
            
            
            29,429
            
            
            
            (171
            )
            
            
            (0.6
            )
            
            
            29,600Wholesale
            
            
            5,225
            
            
            
            855
            
            
            
            19.6
            
            
            
            4,370Unbilled
            
            
            751
            
            
            
            (168
            )
            
            
            –
            
            
            
            919Total
      kWh sales
            
            
            35,405
            
            
            
            516
            
            
            
            1.5
            
            
            
            34,889





PEF’s
revenues, excluding fuel and other pass-through revenues of $2.260 billion and
$2.336 billion for the nine months ended September 30, 2008 and 2007,
respectively, increased $98 million. The increase in revenues was primarily due
to base rate increases and increased wholesale revenues, partially offset by
unfavorable retail customer growth and usage. The increase in base rates was $72
million; Hines 4 being placed in service contributed $42 million in additional
revenues and the transfer of Hines 2 cost recovery from the fuel clause to base
rates contributed $30 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 $41 million primarily due to several
new and amended contracts. PEF’s base rate and wholesale revenue favorability
was partially offset by the unfavorable retail customer growth and usage impact
of $22 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 nine months of 2008
than had been experienced in recent periods. PEF’s average number of customers
for the nine months ended September 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 nine months ended September 30, 2007, compared to the same
period in 2006, increased a net 27,000 customers. In the future, PEF’s customer
usage could be impacted by customer response to energy-efficiency programs and
to increased rates resulting from higher fuel and other recoverable
costs.




74


EXPENSES




Fuel and Purchased
Power




Fuel and
purchased power expenses were $1.981 billion for the nine months ended September
30, 2008, which represents a $10 million decrease compared to the same period in
2007. Fuel used in electric generation decreased $105 million compared to the
same period in 2007 due to lower deferred fuel expense of $353 million,
partially offset by increased current year fuel costs of $248 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 increased fuel prices. Purchased power costs were $95 million
higher for the nine months ended September 30, 2008, primarily due to increased
current year purchases of $73 million as a result of higher fuel costs and an
increase in the recovery of deferred capacity costs of $22 million.




As
previously discussed, the FPSC approved PEF’s petition requesting a mid-course
correction to its fuel cost-recovery factors, which was effective August 1, 2008
(See Note 4B).




Operation and
Maintenance




O&M
expenses were $621 million for the nine months ended September 30, 2008, which
represents a $35 million increase when compared to the same period in 2007.
O&M expenses increased $49 million related to replenishment of storm damage
reserves, which began in August 2007 and continued through August 2008 in
accordance with a regulatory order, and $6 million severance expenses in 2008,
partially offset by $11 million lower ECRC costs due to a decrease in the
current year rates resulting from prior year over-recovery and a $9 million
sales and use tax audit adjustment. The severance expenses in 2008 resulted from
the elimination of approximately 300 positions as part of a restructuring of our
distribution operations in response to the ongoing economic downturn in Florida.
The replenishment of storm damage reserves and ECRC expenses are recovered
through cost-recovery clauses and, therefore, have no material impact on
earnings. In the aggregate, O&M expenses recoverable through base rates
decreased $5 million compared to the same period in 2007.




Depreciation and
Amortization




Depreciation
and amortization expense was $229 million for the nine months ended September
30, 2008, which represents a $68 million decrease compared to the same period in
2007. Depreciation and amortization expense decreased $75 million due to lower
amortization of unrecovered storm restoration costs and $7 million due to a
write-off in 2007 of leasehold improvements primarily related to vacated office
space, partially offset by the $15 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 nine months ended September 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 nine months ended September 30, 2008, consists of a gain on a land sale. The
other operating expenses of $12 million for the nine months ended September 30,
2007, resulted from 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 $71 million increased $41 million for the nine months ended
September 30, 2008, compared to the same period in 2007, primarily due to $38
million favorable AFUDC equity related to costs associated with eligible
construction projects. We expect AFUDC equity to continue to increase primarily
due to increased spending on environmental initiatives and other eligible
construction projects.




Total Interest Charges,
net




Total
interest charges, net were $144 million for the nine months ended September 30,
2008, which represents a $26 million increase compared to the same period in
2007. The increase was primarily due to $45 million higher interest as a result
of higher average debt outstanding. Partially offsetting this increase was $11
million favorable AFUDC




75




debt
related to costs associated with eligible construction projects and an $8
million interest benefit resulting from the resolution of tax matters in
2008.




Income Tax
Expense




Income
tax expense increased $26 million for the nine months ended September 30, 2008,
compared to the same period in 2007, primarily due to the $36 million tax impact
of higher pre-tax income compared to the prior year and the $4 million prior
year benefit related to the closure of certain federal tax years and positions,
partially offset by the $15 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 $7 million for the nine months ended
September 30, 2008, compared to a decrease of $3 million for the nine months
ended September 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
                  September
      30,
                
                
                Nine
      Months Ended
                  September
      30,(in
      millions)
                
                2008
                
                
                2007
                
                
                2008
                
                
                2007Other
      interest expense
                
                $
                (54
                )
                
                $
                (57
                )
                
                $
                (165
                )
                
                $
                (149
                )Contingent
      value obligations
                
                
                –
                
                
                
                1
                
                
                
                (2
                )
                
                
                (2
                )Tax
      levelization
                
                
                1
                
                
                
                5
                
                
                
                1
                
                
                
                4Other
      income tax benefit
                
                
                18
                
                
                
                23
                
                
                
                59
                
                
                
                81Other
                
                
                –
                
                
                
                (2
                )
                
                
                4
                
                
                
                (16
                )Corporate
      and Other after-tax expense
                
                $
                (35
                )
                
                $
                (30
                )
                
                $
                (103
                )
                
                $
                (82
                )


Other
interest expense increased $16 million for the nine months ended September 30,
2008, compared to the same period in 2007, 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 to operations that were sold
later in 2007. No interest expense was allocated to discontinued operations for
the three months ended September 30, 2008, and an immaterial amount of interest
expense was allocated to discontinued operations for the nine months ended
September 30, 2008. An immaterial amount and $12 million of interest expense was
allocated to discontinued operations for the three and nine months ended
September 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
September 30, 2008 and 2007, the CVOs had fair values of approximately $36
million and $34 million, respectively, and average unit prices of $0.37 and
$0.35, respectively. We recorded an unrealized gain of $1 million for the three
months ended September 30, 2007, and no adjustment for the three months ended
September 30, 2008, to record the changes in fair value of the CVOs. We recorded
net unrealized losses of $2 million for the nine months ended September 30, 2008
and 2007.




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 and $5 million for the three months
ended September 30, 2008 and 2007, respectively, and $1 million and $4 million
for the nine months ended September 30, 2008 and 2007, respectively, in order to
maintain an effective rate consistent with the estimated




76




annual
rate. Fluctuations in estimated annual earnings and the timing of various
permanent items of 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 $22 million for the nine months ended September 30,
2008, compared to the same period in 2007, primarily due to the $14 million
prior year benefit related to the closure of certain federal tax years and
positions.




Other
decreased $20 million for the nine months ended September 30, 2008, compared to
the same period in 2007, primarily due to $12 million decreased indirect
corporate overhead due to divestitures completed in 2007 and $11 million
decreased legal expenses.




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 nine months ended September 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 for the three months ended September 30,
2007, compared to no earnings for the same period in 2008, and net earnings from
discontinued operations of $21 million and $72 million for the nine months ended
September 30, 2008 and 2007, respectively. The decrease in net earnings from
discontinued operations for the three and nine months ended September 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 nine months ended September 30, 2007, we reversed $1
million and $18 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 loss 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.




CCO’s
operations generated net earnings from discontinued operations of $2 million and
net losses from discontinued operations of $1 million for the three months ended
September 30, 2008 and 2007, respectively, and net losses from discontinued
operations of $1 million and $280 million for the nine months ended September
30, 2008 and 2007, respectively. The decrease in net losses from discontinued
operations for the nine months ended




77




September
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 nine months ended September 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 were $1 million for each of
the three months ended September 30, 2008 and 2007, and $5 million and $9
million for the nine months ended September 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 nine months ended September 30, 2008, we recorded additional
gains of $3 million, net of tax. For the three and nine months ended September
30, 2007, we recorded additional gains of $1 million and $2 million, net of
tax.




LIQUIDITY AND CAPITAL
RESOURCES




OVERVIEW




Our
significant cash requirements arise primarily from the capital-intensive nature
of the Utilities’ operations, including expenditures for environmental
compliance. We rely upon our operating cash flow, substantially all of which is
generated by the Utilities, commercial paper and bank facilities, and our
ability to access the long-term debt and equity capital markets for sources of
liquidity. As discussed under “Future Liquidity and Capital Resources” below,
synthetic fuels tax credits provide an additional source of liquidity as those
credits are realized.




Progress
Energy, Inc. is a holding company and, as such, has no revenue-generating
operations of its own. The Parent’s primary cash needs are its common stock
dividend and interest and principal payments on its $2.6 billion of senior
unsecured debt. The Parent’s ability to meet these needs is dependent on the
earnings and cash flows of the Utilities, the ability of the Utilities and other
subsidiaries to pay dividends or repay funds to the Parent, the Parent’s
commercial paper and bank facilities, and the Parent’s ability to access the
long-term debt and equity capital markets. The Utilities have not paid, and do
not currently expect to pay, dividends to the Parent in 2008. There are a number
of factors that impact the Utilities’ ability to pay dividends to the Parent,
including capital expenditure decisions and the timing of recovery of fuel and
other pass-through costs. Although we cannot predict the level of dividends that
the Utilities may pay to the Parent in the near term, we do not currently expect
changes to the Parent's common stock dividend policy.




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.




78




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 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.




We expect
to fund our 2008 capital expenditures and common stock dividend with cash from
operations, issuance of short-term and long-term debt, proceeds from the first
quarter sale of the remainder of our nonregulated businesses, and periodic
common stock sales from our Investor Plus Stock Purchase Plan and employee
benefit and stock option plans. For the fiscal year 2008, we anticipate
realizing approximately $130 million from the sale of common stock through these
plans. At September 30, 2008, we had $403 million in cash and cash
equivalents.




The
financial market distress of September and October 2008 has made it more
difficult and expensive for companies to raise both short-term and long-term
capital. As shown in the table below, we have a number of financial institutions
that support our combined $2.030 billion revolving credit facilities for the
Parent, PEC and PEF, thereby limiting our dependence on any one individual
institution. The credit facilities serve as back-ups to our commercial paper
programs. At September 30, 2008, we had no outstanding borrowings under our
credit facilities. In November 2008, the Parent borrowed $600 million under its
revolving credit agreement (RCA) as discussed below.




(in
      millions)
            
            Total
      CommitmentCredit
      Provider
            
            Progress
      Energy
            
            
            Parent(a)
            
            
            PEC
            
            
            PEFJPMorgan
      Chase Bank, N.A.
            
            $
            225.0
            
            
            $
            141.0
            
            
            $
            44.0
            
            
            $
            40.0Bank
      of Tokyo-Mitsubishi UFJ, Ltd., New York Branch
            
            
            200.0
            
            
            
            95.0
            
            
            
            45.0
            
            
            
            60.0Barclays
      Bank PLC
            
            
            190.5
            
            
            
            100.0
            
            
            
            20.5
            
            
            
            70.0Bank
      of America, N.A.
            
            
            190.0
            
            
            
            98.0
            
            
            
            22.0
            
            
            
            70.0Citibank,
      N.A.
            
            
            180.0
            
            
            
            111.0
            
            
            
            34.0
            
            
            
            35.0Wachovia
      Bank, N.A.
            
            
            175.5
            
            
            
            53.0
            
            
            
            82.5
            
            
            
            40.0


Royal
      Bank of Scotland plc
            
            
            169.0
            
            
            
            92.0
            
            
            
            77.0
            
            
            
            –The
      Bank of New York Mellon
            
            
            120.0
            
            
            
            35.0
            
            
            
            40.0
            
            
            
            45.0SunTrust
      Bank
            
            
            115.0
            
            
            
            50.0
            
            
            
            20.0
            
            
            
            45.0Morgan
      Stanley Bank
            
            
            100.0
            
            
            
            50.0
            
            
            
            50.0
            
            
            –William
      Street Commitment Corporation
            
            
            100.0
            
            
            
            100.0
            
            
            –
            
            
            –Deutsche
      Bank AG,  New York Branch
            
            
            95.0
            
            
            
            50.0
            
            
            –
            
            
            
            45.0UBS
      Loan Finance LLC
            
            
            80.0
            
            
            
            80.0
            
            
            –
            
            
            –BNP
      Paribas
            
            
            50.0
            
            
            
            50.0
            
            
            –
            
            
            –Branch
      Banking & Trust Co.
            
            
            25.0
            
            
            
            25.0
            
            
            –
            
            
            –First
      Tennessee Bank N.A.
            
            
            15.0
            
            
            –
            
            
            
            15.0
            
            
            –Total
      commitment
            
            $
            2,030.0
            
            
            $
            1,130.0
            
            
            $
            450.0
            
            
            $
            450.0


(a)
            To
      the extent amounts are reserved for commercial paper or letters of credit
      outstanding, they are not available for additional borrowings. At
      September 30, 2008, the Parent had $495 million in commercial paper
      outstanding and $29 million of letters of credit issued, which were
      supported by the RCA.




79


At
September 30, 2008, we had limited mark-to-market exposure to certain financial
institutions under pay-fixed forward starting swaps to hedge cash flow risk with
regard to future financing transactions for both the Parent and PEC as disclosed
in the table below. In the event of default by a counterparty, the exposure in
the transaction is the cost of replacing the agreements at current market
rates.




(dollars
      in millions)
            
            Number
      of Counterparties
            
            
            Net
      Mark-to-Market Asset Position
            
            
            Net
      Mark-to-Market Liability PositionParent
            
            
            3
            
            
            $
            2
            
            
            $
            1PEC
            
            
            3
            
            
            
            2
            
            
            
            1Progress
      Energy total
            
            
            6
            
            
            $
            4
            
            
            $
            2





At
September 30, 2008, PEC and PEF had limited counterparty mark-to-market exposure
for financial commodity hedges (primarily gas and oil hedges) due to spreading
our concentration risk over a number of partners, as disclosed in the table
below. In the event of default by a counterparty, the exposure in the
transaction is the cost of replacing the agreements at current market rates. The
mark-to-market exposure in the table takes into account collateral held for or
paid to counterparties.




(dollars
      in millions)
              
              Financial
      Counterparty Type
            
            Number
      of Counterparties(a)
            
            
            Net
              Mark-to-Market
              Asset
      Position
            
            
            Net
              Mark-to-Market
              Liability
      PositionPECFinancial
      institutions
            
            
            9
            
            
            $
            4
            
            
            $
            26PEFFinancial
      institutions
            
            
            16
            
            
            
            49
            
            
            
            78Energy
      companies
            
            
            3
            
            
            
            1
            
            
            
            32PEF
      total
            
            
            19
            
            
            
            50
            
            
            
            110Progress
      Energy total
            
            
            28
            
            
            $
            54
            
            
            $
            136





(a)
            PEC
      also had positions with two energy companies, which were not
      material.





Our
pension trust funds, nuclear decommissioning trust funds and short-term
investments do not include material investments in the securities of
institutions that have recently been sold, taken over or filed for
bankruptcy.




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 $621
million for the nine months ended September 30, 2008, when compared to the
corresponding period in the prior year. The increase in operating cash flow was
primarily due to the $347 payment made in 2007 to exit the Georgia contracts
(See Note 3B); a $306 million increase from the change in accounts receivable
related to our divested CCO operations and former synthetic fuels businesses; a
$251 million increase from income taxes, net; a $118 million increase from the
change in accounts payable; an $87 million increase related to derivative assets
in 2007 at our divested CCO operations; and $65 million in premiums paid in 2007
for derivative contracts in our synthetic fuels businesses (See Note 9A). These
impacts were partially offset by a $358 million decrease in the recovery of fuel
costs, primarily 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; a $110 million decrease from inventory, primarily
coal, driven by higher prices; and a $108 million decrease in




80




collateral
held associated with derivative contracts for our synthetic fuels businesses.
The primary driver of the change in accounts receivable was the settlement of
$234 million of derivative receivables related to derivative contracts for our
former synthetic fuels businesses (see Note 9A). The increase from income taxes,
net was primarily due to $252 million in income tax payments made in 2007
related to the sale of natural gas drilling and production business (see Note
3D). The primary drivers of the change in accounts payable were the impact of
rising fuel prices at the Utilities and the change in accounts payable related
to our divested CCO operations.




INVESTING
ACTIVITIES




Net cash
used by investing activities increased by $826 million for the nine months ended
September 30, 2008, when compared to the corresponding period in the prior year.
This is due primarily to a $595 million decrease in proceeds from sales of
discontinued operations and other assets, net of cash divested; a $410 million
increase in capital expenditures for utility property additions at PEF,
partially offset by a $69 million decrease in utility property additions
at PEC. These impacts were partially offset by a $97 million decrease in net
purchases of short-term investments included in available-for-sale
securities and other investments and a $40 million decrease in nuclear fuel
additions. At PEF, the increase in utility property additions was primarily due
to a $343 million increase in environmental compliance expenditures and a $109
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 nine months ended September 30, 2008, proceeds from sales of discontinued
operations and other assets of $63 million primarily included proceeds from the
sale of Terminals and Coal Mining (see Notes 3A and 3C). During the nine months
ended September 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 increased $1 million for the nine months ended
September 30, 2008, when compared to the corresponding period in the prior year.
The increase in net cash provided by financing activities was primarily due to
PEF’s $1.475 billion net proceeds and PEC’s $322 million net proceeds from the
issuance of long-term debt in 2008 discussed below, compared to $742 million in
net proceeds in 2007. The increase in proceeds from long-term debt issuances was
offset by a $590 million increase in long-term debt retirements; $176 million in
payments on short-term debt; an $80 million decrease in short-term indebtedness,
and $85 million in cash distributions to owners of minority interests of
consolidated subsidiaries primarily related to the settlement of Ceredo Synfuel
LLC’s (Ceredo) synthetic fuels derivatives contracts (See Note 9A).





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 RCAs 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, the Parent amended its RCA with a syndication of financial
institutions to extend the termination date by one year. The extension was
effective on May 2, 2008. The RCA is now scheduled to expire on May 3,
2012.




81




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 August 14, 2008, PEF redeemed the entire outstanding $450
million principal amount of its Series A Floating Rate Notes due November 14,
2008, at 100 percent of par plus accrued interest. The redemption was funded
with a portion of the proceeds from the June 18, 2008 debt
issuance.




On
November 3, 2008, the Parent borrowed $600 million under its RCA to reduce
rollover risk in the commercial paper markets. We will continue to monitor the
commercial paper and short-term credit markets to determine when to repay the
outstanding balance of the RCA loan, while maintaining an appropriate level of
liquidity.




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
nine months ended September 30, 2008, respectively, we issued approximately 1.5
million shares and 2.5 million shares of common stock resulting in approximately
$64 million and $106 million in proceeds. Included in these amounts were
approximately 1.5 million shares and 2.4 million shares for proceeds of
approximately $63 million and $104 million, respectively, to meet the
requirements of the 401(k) Plan and the Investor Plus Stock Purchase Plan. For
the three and nine months ended September 30, 2007, respectively, we issued
approximately 0.3 million shares and 3.0 million shares of common stock
resulting in approximately $12 million and $134 million in proceeds. Included in
these amounts were approximately 0.2 million shares and 0.7 million shares for
proceeds of approximately $12 million and $35 million, respectively, to meet the
requirements of the 401(k) Plan and the Investor Plus Stock Purchase
Plan.




FUTURE
LIQUIDITY AND CAPITAL RESOURCES




At
September 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”). A portion of 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 September 30,
2008, we have carried forward $803 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.




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.





We expect
to be able to meet our future liquidity needs through cash from operations,
commercial paper issuance, availability under our credit facilities and
long-term financings. To the extent necessary, we may also use periodic 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 rates and
shorter available durations. In the latter half of the first quarter of 2008 and
continuing into the second quarter of 2008, the market improved; however, there
was volatility in commercial interest rates. In September 2008, the financial
markets significantly deteriorated and the short-term credit markets tightened
again, resulting in a further increase in interest rates and shorter available
durations. Prior to the end of the third quarter of 2008, we were able to issue
commercial paper to meet our short-term financing needs




82




with
maturities past the quarter-end, albeit at higher interest rates. In September
2008, the weighted average interest rate for the Parent’s outstanding commercial
paper balance increased 56 basis points to 3.47% compared to August 2008. The
interest rate increase resulted in an immaterial increase in interest expense
for September 2008 compared to August 2008. PEC and PEF did not have any
outstanding commercial paper balances during September 2008. In November 2008,
the Parent borrowed $600 million under its RCA. We will continue to monitor the
commercial paper and short-term credit markets to determine when to repay the
outstanding balance of the RCA loan, while maintaining an appropriate level of
liquidity. If liquidity conditions deteriorate further and negatively impact the
commercial paper market, we will need to evaluate other, potentially more
expensive, options for meeting our short-term liquidity needs, which may include
extending the term of our borrowings under the Parent’s RCA, issuing short-term
floating rate notes, and/or issuing long-term debt.




Progress
Energy and its subsidiaries have approximately $11.053 billion in outstanding
debt. Currently, $860 million of our Utility debt obligations, which consists of
approximately $620 million at PEC and approximately $240 million at PEF, are
tax-exempt auction rate securities insured by bond insurance. Bond insurance
generally allows
companies to issue tax-exempt bonds with the insurance company’s higher credit
rating. Ambac Assurance Corporation (Ambac) insures PEC’s bonds and Syncora
Guarantee Inc., formerly XL Capital Assurance, Inc., (Syncora) insures PEF’s
bonds.





In 2008,
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 (SIFMA) Index or the London Interbank Offered Rate (LIBOR). The
interest rates for PEC’s portfolio of tax-exempt securities reset based on the
SIFMA index. The interest rates for PEF’s portfolio of tax-exempt securities
reset based on one-month LIBOR. The multiple on our auction rate bonds is stable
as long as the bonds are rated A3 or higher by Moody’s Investors Service, Inc.
(Moody’s) or A- or higher by Standard & Poor’s Rating Services (S&P). If
the insurance 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 Syncora in
February 2008 by Moody’s and S&P caused an initial increase in market
volatility and an increase in interest rates. The June 2008 downgrades of
Syncora by Moody’s and S&P to B2 and BBB-, respectively, and Ambac by
Moody’s and S&P to Aa3 and AA, respectively, did not materially impact the
reset rates of the Utilities’ tax-exempt bonds. In October 2008, Syncora was
downgraded again by Moody’s to Caa1. We do not expect this to materially impact
the reset rates of the Utilities’ tax-exempt securities.





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 decreased as the underlying
indices trended down through the middle of September 2008. However, during the
second half of September 2008, the financial markets deteriorated further and
the SIFMA index dramatically increased, thereby causing a significant increase
in the interest rate for many of PEC’s tax-exempt auction rate securities.
One-month LIBOR also increased. The increase in interest rates will increase the
Utilities’ interest expense for 2008. However, since the interest rates for
these bonds reset on either a weekly or monthly basis, while the SIFMA index
resets weekly and LIBOR resets daily, the total impact to 2008 interest expense
cannot be determined at this time. In September 2008, the Utilities’ interest
expense related to tax-exempt bonds increased by an immaterial amount compared
to August 2008 and the September 2008 weighted average interest rate related to
tax-exempt bonds increased 43 basis points to 4.29% compared to August 2008. The
September 2008 weighted average interest rate increase compared to August 2008
for PEC was 50 basis points to 3.93% and 27 basis points to 5.20% for PEF.
Continued volatility in the indices that dictate our interest rate resets and
rating agency downgrades that move our tax-exempt bonds below A2/A- could result
in the continuation of higher interest rate resets. We will continue to monitor
this market and evaluate options to mitigate our exposure to future
volatility.





The
performance of the capital markets affects the values of the assets that are
held in trust to satisfy future obligations under our defined benefit pension
plans. Although there are a number of factors that impact our pension funding
requirements, a decline in the market value of these assets may significantly
increase the future funding requirements of the obligations under our defined
benefit pension plans.




83





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.




At
September 30, 2008, the current portion of our long-term debt was $400 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. Regulatory developments since our 2007 Form 10-K that are
expected to have a material impact on our liquidity are discussed
below.





As
discussed further in Note 4 and in “Other Matters – Regulatory Environment,” the
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. Subsequently, PEC jointly filed a settlement
agreement with CIGFUR, CUCA and the NCUC Public Staff. Under the terms of the
settlement agreement, PEC would collect $203 million of deferred fuel costs
ratably over a three-year period beginning December 1, 2008, compared with a
one-year recovery period proposed in PEC’s original request. Amounts to be
collected in years beginning December 1, 2009 and 2010, will bear interest at a
rate equal to the five-year United States Treasury Note plus 150 basis points.
If the settlement agreement is approved, the increase would take effect on or
about December 1, 2008, and would increase residential electric bills by $8.79
per




84




1,000
kWh, or 9.1 percent. A hearing on the settlement agreement was held on September
16, 2008. The NCUC is expected to make a decision on this settlement agreement
in November 2008. We cannot predict the outcome of this matter.




PEC has
begun implementing a series of DSM and energy-efficiency programs and has
deferred $6 million of implementation and program costs for future recovery. On
October 14, 2008, the NCUC approved PEC’s request for approval of four DSM and
energy-efficiency programs. On April 29, 2008, PEC filed for NCUC approval of a
distribution system demand response (DSDR) program. PEC anticipates that the
DSDR program will require an investment of approximately $260 million over five
years. We cannot predict the outcome of the DSDR program filing or whether
any of the programs will produce the expected operational and economic
results.


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.  A hearing has been scheduled on the 2006 and 2007 coal
purchases for April 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 percent 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 increased by $2.48 per 1,000 kWh, or 2.29
percent. On October 15, 2008, PEF filed a request with the FPSC to seek approval
of a cost adjustment for the under-recovery of fuel costs in 2008 and other
recovery-clause factors. PEF asked the FPSC to approve an increase in
residential electric bills of $27.28 per 1,000 kWh, or 24.7 percent, effective
January 1, 2009. The FPSC
is scheduled to hold hearings on the cost adjustment proposal November 4-6,
2008. We cannot predict the outcome of this matter.





PEF has
received approval from the FPSC for recovery through the ECRC of the majority of
costs associated with the remediation of distribution and substation
transformers, which were estimated to be $26 million at September 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 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.




85




As
discussed further in Note 4 and “Other Matters – Nuclear”, on August 12, 2008,
the FPSC issued the final order granting 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 October 14, 2008, the FPSC voted to
approve the inclusion of preconstruction and
carrying charges of $357 million as well as site selection costs of $38 million
in establishing PEF's 2009 capacity cost-recovery clause factor.




During
2008, PEF filed for recovery of costs incurred to uprate Crystal River Unit No.
3 Nuclear Plant (CR3) under Florida’s comprehensive energy legislation and the
FPSC’s nuclear cost-recovery rule. The current project estimate of fully
loaded costs is $364 million. On August 19, 2008, the FPSC granted PEF’s
petition to amend its request to recover costs for the nuclear uprate project
under the nuclear cost-recovery rule.




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 September 30, 2008,
we have issued $402 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
September 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.




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
September 30, 2008, contracts procured though our subsidiaries have increased
our aggregate purchase obligations for fuel and purchased power by $7.417
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.




86




We have
noncontributory defined benefit retirement plans for substantially all full-time
employees that provide pension benefits. The performance of the capital markets
affects the values of the assets that are held in trust to satisfy future
obligations under our defined benefit pension plans. Although there are a number
of factors that impact our pension funding requirements, a decline in the market
value of these assets may significantly increase the future funding requirements
of the obligations under our defined benefit pension plans.





PEC




Through
September 30, 2008, PEC’s fuel and purchased power commitments increased by
$3.495 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 $2.156 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 $487 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.




In July
2008, PEC entered into an amendment to an existing transportation service
agreement with an intrastate pipeline for firm pipeline transportation capacity
to support PEC’s gas supply needs for the period from April 2011 through May
2030. The total additional cost to PEC associated with this amendment is
estimated to be approximately $54 million. The amendment is subject to several
conditions precedent, including state regulatory approval, the completion and
commencement of operation of necessary related intrastate natural 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
September 30, 2008, PEF’s fuel and purchased power commitments increased by
$3.922 billion from $12.566 billion, as stated in Note 22A in the 2007 Form
10-K. As discussed in Note 22A in the 2007 Form 10-K, PEF entered into certain
conditional contracts for gas supply and transportation. Due to the conditions
of these contracts, the associated estimated costs were not included in our or
PEF’s contractual cash obligations table at December 31, 2007. Additional
conditional gas supply and transportation contracts were entered into during the
second quarter of 2008. During 2008, the conditions were satisfied and several
gas supply and transportation contracts totaling $3.255 billion became
effective. These contracts for the supply of natural gas and associated firm
pipeline transportation augment PEF’s gas supply needs for various periods from
September 2008 through January 2032.  The estimated costs associated with
these agreements are approximately $81 million in 2008, $436 million in 2009,
$570 million in 2010, $602 million in 2011, $548 million in 2012, and $1.018
billion thereafter. Also, the increase in gas supply and transportation purchase
commitments includes new contracts along with the impact of price increases on
certain existing contracts that are market price indexed. Coal purchase
commitments increased by approximately $804 million; of this increase,
approximately $230 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.




In April
2008, PEF entered into conditional contracts 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 these agreements is estimated to be approximately
$2.176 billion. The contracts are 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 contracts, 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 $987 million. Due to the
conditions of these agreements, the estimated costs associated with these
agreements are




87




not
included in the increase in PEF’s fuel and purchased power commitments discussed
above.




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 September 30, 2008, $1.088 billion of tax credits had been used to offset
regular federal income tax liability and $803 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 March 2007. For the three months ended September 30, 2007,
we recorded net pre-tax gains of $74 million related to these contracts,
including $26 million attributable to Ceredo which was attributed to minority
interest for the




88


portion
of the gain subsequent to disposal. For the nine months ended September 30,
2007, we recorded net pre-tax gains of $105 million related to these contracts,
including $36 million attributable to Ceredo, of which $21 million were
attributed to minority interest for the portion of the gain 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 nine months
ended September 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 potentially 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, the SCPSC and the FPSC, respectively. The Utilities are
also subject to regulation by the FERC, the Nuclear Regulatory Commission (NRC)
and other federal and state agencies common to the utility business. As a result
of regulation, many of the fundamental business decisions, as well as the rate
of return the Utilities are permitted to earn, are subject to the approval of
one or more of these governmental agencies.




To our
knowledge, there is currently no enacted or proposed legislation in North
Carolina, South Carolina or Florida that would give retail ratepayers the right
to choose their electricity provider or otherwise restructure or deregulate the
electric industry. We cannot anticipate when, or if, any of these states will
move to increase retail competition in the electric industry.




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




89




During
2007, the North Carolina legislature passed comprehensive energy legislation,
which became law on August 20, 2007. The law includes provisions for REPS,
expansion of the definition of the traditional fuel clause and recovery of the
costs of new DSM and energy-efficiency programs through an annual DSM
clause.




On
February 29, 2008, the NCUC issued an order adopting final rules for
implementing North Carolina’s comprehensive energy legislation. These rules
provide filing requirements associated with the legislation. The order required
PEC to submit its first annual REPS compliance plan as part of its integrated
resource plan, which was filed on September 2, 2008. 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 DSDR 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. On October 14,
2008, the NCUC approved PEC’s request for its EnergyWiseTM program as well as
three other DSM and energy-efficiency programs.





Also on
April 29, 2008, PEC filed for NCUC approval of its DSDR 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 DSDR program has been scheduled by
the NCUC for December 17, 2008.





We cannot
predict the outcome of the DSDR program filing or whether any of the DSM and
energy-efficiency 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 standard, and the FPSC staff has drafted a renewable
portfolio standard (RPS) that would require that 20 percent of electricity
produced in the state come from renewable resources by 2041. The FPSC has not
formally proposed a RPS rule. 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. Additional development and




90




discussion
of the recommendations has occurred through a stakeholder process in 2008.The Energy and Climate
Action Team submitted its final report to the governor on October 15, 2008. The
report’s recommendations encourage the development and implementation of
energy-efficiency and conservation measures, implementation of a climate
registry, consideration of a cap-and-trade approach to reducing the state’s
greenhouse gas emissions and a recommendation to implement a RPS of 20 percent
by 2020. The FDEP’s first workshop on the greenhouse gas cap-and-trade
rulemaking is scheduled for December 11, 2008. The rulemaking is expected to
continue through 2009. 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
producing electricity from swine waste and other plant or animal sources, solar,
hydrogen, biomass and landfill-gas technologies. We are evaluating the
feasibility of producing electricity from these and other 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. In 2007, PEC announced
a two-year moratorium on constructing new coal-fired plants while pursuing
expansion of energy-efficiency and conservation programs. If PEC proceeds with
construction of a new nuclear plant, the new plant would not be online until at
least 2019 (see “Nuclear” below).




As
authorized under the Energy Policy Act of 2005 (EPACT), on October 4, 2007, the
United States Department of Energy (DOE) published final regulations for the
disbursement of up to $13 billion in loan guarantees for clean-energy projects
using innovative technologies. The guarantees, which will cover up to 100
percent of the amount of any loan for no more than 80 percent of the project
cost, are expected to spur development of nuclear, clean-coal and ethanol
projects.




In 2008,
Congress authorized $38.5 billion in loan guarantee authority for innovative
energy projects. Of the total provided, $18.5 billion is set aside for nuclear
power facilities, $2 billion for advanced nuclear facilities for the "front-end"
of the nuclear fuel cycle, $10 billion for renewable and/or energy efficient
systems and manufacturing and distributed energy generation/transmission and
distribution, $6 billion for coal-based power generation and industrial
gasification at retrofitted and new facilities that incorporate carbon capture
and sequestration or other beneficial uses of carbon and $2 billion for advanced
coal gasification.PEF submitted Part I of the Application for Federal Loan
Guarantees for Nuclear Power Facilities on September 29, 2008, for the proposed
Levy nuclear project. PEF was one of 19 applicants that submitted Part I of the
application. Part II of the application is due on December 19, 2008. We cannot
predict if PEF’s application will be approved.




91




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 2019 (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. On October 6, 2008, the NRC docketed, or accepted for
review, the Levy nuclear project 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. 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 issued the final order granting the petition for the Determination of
Need for the proposed nuclear power plants on August 12, 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. On May 29, 2008, the Florida Department of Community Affairs (FDCA) issued
its final determination that the amendments to the Levy County Comprehensive
Plan are in compliance with land use regulations.




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.




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




92




adequate
review of the projects costs recoverable under the FPSC nuclear cost-recovery
rule (see discussion of nuclear cost-recovery rule below).  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. On October
2, 2008, the FPSC staff recommended that PEF recover all prudently incurred
costs under the nuclear cost-recovery rule. On October 14, 2008, the FPSC voted
to approve the inclusion of
preconstruction and carrying charges as well as site selection costs in
establishing PEF's 2009 capacity cost-recovery clause
factor.




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”).




93





ENVIRONMENTAL
MATTERS




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




HAZARDOUS
AND SOLID WASTE MANAGEMENT




The
provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the 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 potential and pending claims cannot be predicted.
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




94




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 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. On September 24, 2008, petitions for rehearing were filed by the EPA,
the Utility Air Regulatory Group, the National Mining Association and several
environmental groups. PEC and PEF are members of the Utility Air Regulatory
Group. On October 21, 2008, the Court issued an order directing petitionersto
address (1) whether any party is seeking to vacate the CAIR, and (2) whether the
court should stay its mandate until EPA promulgates a revised rule. The Court
will not issue its mandate until after it evaluates the responses to this order
and renders a decision on the petitions for rehearing. The outcome of this
matter cannot be predicted.




The
Utilities are 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 complete
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 and the market prices
for emission allowances have declined. At September 30, 2008, PEC had
approximately $25 million in SO2 emission
allowances, which will be utilized to comply with existing Clean Air Act
requirements, and an immaterial amount of NOx emission allowances. In order to
achieve compliance with the requirements of the CAIR pursuant to its Integrated
Clean Air Compliance Plan (discussed further in “Compliance Strategy”), PEF
needed to purchase CAIR seasonal and annual NOx allowances. During the three
months ended September 30, 2008, PEF reduced the value of its annual NOx
allowance inventory by $59 million due to the uncertainty of whether the
allowances will ultimately be used, and




95




reduced
the value of its seasonal NOx allowance inventory by approximately $1 million
based on current market prices. 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 retail portion of the costs of these
allowances through its ECRC. Accordingly, PEF recorded a $57 million regulatory
asset for the retail portion of its annual and seasonal NOx allowances.
Therefore, there was no material impact to PEF’s results of operations for the
reduction in value of its NOx allowance inventory. On August 29, 2008, PEF filed
for recovery of its CAIR expenses, including NOx allowance inventory expense,
through the ECRC. A hearing on the matter is scheduled for November 4-6, 2008.
At September 30, 2008, PEF had approximately $6 million in seasonal NOx emission
allowance inventory and approximately $14 million in SO2 emission
allowance inventory. SO2 emission
allowances will be utilized to comply with existing Clean Air Act
requirements.




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 filed petitions for rehearing by the full court of appeals,
which were denied on May 20, 2008. On September 17, 2008, the
Utility Air Regulatory Group filed a petition for writ of certiorari with the
U.S. Supreme Court with regard to the decision that vacated the CAMR. On October
17, 2008, the EPA filed a similar petition. 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 any review granted by the Supreme Court 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. If it stands, 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. Consequently, 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, the CAVR and mercury regulation. The air quality
controls installed to comply with the requirements of the NOx SIP Call Rule
under Section 110 of the Clean Air Act (NOx SIP Call) and Clean Smokestacks Act
resulted in a reduction of the costs to meet the CAIR requirements for our North
Carolina units at PEC.




96





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 programs by North Carolina and South Carolina 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 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. Amounts presented in the tables exclude AFUDC.
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 estimated costs to comply with the CAVR prior to the July 11,
2008 D.C. Court of Appeals’ decision regarding CAIR 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.




97




Progress
      EnergyAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
            
            Estimated
      Timetable
            
            
            Total
      Estimated Expenditures
            
            
            Cumulative
      Spent through September 30, 2008Clean
      Smokestacks Act
            
            
            2002–2013
            
            
            $
            1,500
      – 1,600
            
            
            $
            986In-process
      CAIR projects(a)
            
            
            2005–2010
            
            
            
            1,200
            
            
            
            760CAVR(b)
            
            
            –2017
            
            
            
            –
            
            
            
            –Mercury
      regulation(c)
            
            
            2006–2017
            
            
            
            –
            
            
            
            8Total
      air quality
            
            
            
            
            
            
            2,700
      – 2,800
            
            
            
            1,754Clean
      Water Act Section 316(b)(d)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air and water quality
            
            
            
            
            
            $
            2,700
      – 2,800
            
            
            $
            1,754




PECAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
            
            Estimated
      Timetable
            
            
            Total
      Estimated Expenditures
            
            
            Cumulative
      Spent through September 30, 2008Clean
      Smokestacks Act
            
            
            2002–2013
            
            
            $
            1,500
      – 1,600
            
            
            $
            986In-process
      CAIR projects(a)
            
            
            2005–2008
            
            
            
            –
            
            
            
            15CAVR(b)
            
            
            –2017
            
            
            
            –
            
            
            
            –Mercury
      regulation(c)
            
            
            2006–2017
            
            
            
            –
            
            
            
            8Total
      air quality
            
            
            
            
            
            
            1,500
      – 1,600
            
            
            
            1,009Clean
      Water Act Section 316(b)(d)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air and water quality
            
            
            
            
            
            $
            1,500
      – 1,600
            
            
            $
            1,009





PEFAir and Water Quality Estimated
      Required Environmental Expenditures  (in
      millions)
            
            Estimated
      Timetable
            
            
            Total
      Estimated Expenditures
            
            
            Cumulative
      Spent through September 30, 2008In-process
      CAIR projects(a)
            
            
            2005–2010
            
            
            $
            1,200
            
            
            $
            745CAVR(b)
            
            
            –2017
            
            
            
            –
            
            
            
            –Mercury
      regulation(c)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air quality
            
            
            
            
            
            
            1,200
            
            
            
            745Clean
      Water Act Section 316(b)(d)
            
            
            
            
            
            
            –
            
            
            
            –Total
      air and water quality
            
            
            
            
            
            $
            1,200
            
            
            $
            745





(a)
            The
      Utilities are continuing construction of 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 Air Interstate
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 first
phase 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.




98





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 had been held in abeyance but was resumed
following the D.C. Court of Appeal’s decision that vacated the CAIR. 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 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
October 16, 2008, the EPA published a revision to the NAAQS for lead to 0.15
micrograms per cubic meter rolling three-month average. The former standard was
1.5 micrograms per cubic meter, calendar quarter average. The 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




99




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 will be generated at
certain affected facilities. Integration of these new wastewater streams into the
existing wastewater treatment processes is currently ongoing and will result in
permitting, construction and treatment requirements imposed on the Utilities now
and into the future.




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.




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




100




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




As
discussed in Note 2, on January 1, 2008, we adopted SFAS No. 157, "Fair Value
Measurements" (SFAS No. 157), for all recurring financial assets and
liabilities. 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). SFAS No. 157 also requires disclosure of the impact on
earnings of fair value measurements based on significant unobservable inputs.
Our financial assets and liabilities are primarily comprised of derivative
financial instruments and marketable debt and equity securities held in our
nuclear decommissioning trusts, substantially all of which are valued using
directly or indirectly observable inputs. In addition, substantially all
unrealized gains and losses on derivatives and all unrealized gains and losses
on nuclear decommissioning trust investments are deferred as regulatory
liabilities or assets consistent with ratemaking treatment. Therefore, the
impact of fair value measurements from recurring financial assets and
liabilities on our or the Utilities’ earnings is not significant.





We will
adopt SFAS No. 157 for all nonrecurring nonfinancial assets and liabilities,
such as reporting units and long-lived asset groups measured at fair value for
impairment purpose, on January 1, 2009. We do not expect the adoption 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.




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




101


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 $57 million for the nine months ended
September 30, 2008, when compared to the corresponding period in the prior year.
The increase in operating cash flow was primarily due to the $74 million
increase from the change in receivables largely driven by the timing of
settlements with affiliated companies; a $50 million increase in cash receipts
from a wholesale customer due to the expiration of a prepayment agreement; and
lower interest payments of $18 million. These impacts were partially offset by a
$53 million decrease from inventory, primarily coal, driven by higher prices and
$39 million in higher income tax payments.





Cash used
by investing activities decreased $40 million for the nine months ended
September 30, 2008, when compared to the corresponding period in the prior year.
The decrease in cash used in investing activities was primarily due to a $69
million decrease in utility property additions, primarily related to lower
environmental compliance expenditures, and a $28 million decrease in nuclear
fuel additions. These impacts were partially offset by a $57 million decrease in
net proceeds from short-term investments included in available-for-sale
securities and other investments. 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 decreased by $5 million for the nine months ended
September 30, 2008, when compared to the corresponding period in the prior year.
The decrease in net cash used by financing activities was primarily due to $322
million in net proceeds from the issuance of long-term debt in 2008 and $108
million in dividends paid to the Parent in 2007, offset by a $100 million
increase in the retirement of long-term debt and decreases in short-term debt
and advances from affiliated companies in 2008. PEC’s 2008 financing activities
are further described under Progress Energy’s MD&A, “Liquidity and Capital
Resources”.




102




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.


OTHER
MATTERS




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




103


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 decreased $372 million for the nine months
ended September 30, 2008, when compared to the corresponding period in the prior
year. The decrease in operating cash flow was primarily due to a $321 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 $51 million increase in inventory
primarily driven by coal price increases, and net refunds of $45 million
received during the prior year for cash collateral previously paid to
counterparties on derivative contracts. These impacts were partially offset by
$42 million related to the extension of PEF’s storm recovery surcharge, which
began in August 2007 and expired in August 2008.




Cash used
by investing activities increased $63 million for the nine months ended
September 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 $410
million increase in capital expenditures for utility property additions,
including a $343 million increase in environmental compliance expenditures and a
$109 million increase in nuclear project expenditures, partially offset by a
$180 million increase in net proceeds from short-term investments included in
available-for-sale securities and other investments and a $149 million decrease
from changes in advances to affiliated companies. 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
provided by financing activities increased $333 million for the nine months
ended September 30, 2008, when compared to the corresponding period in the prior
year. The increase in cash provided by financing activities was primarily due to
PEF’s $1.475 billion in net proceeds from issuance of long-term debt in 2008,
partially offset by $742 million in net proceeds from the issuance of long-term
debt in 2007 and a $445 million increase in long-term debt retirements. PEF’s
2008 financing activities are further described under Progress Energy’s
MD&A, “Liquidity and Capital Resources”.




104




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.




OTHER
MATTERS




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




105


ITEM
3.                      QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK




We are
exposed to various risks related to changes in market conditions. Market risk
represents the potential loss arising from adverse changes in market rates and
prices. We have a risk management committee that includes senior executives from
various business groups. The risk management committee is responsible for
administering risk management policies and monitoring compliance with those
policies by all subsidiaries. Under our risk policy, we may use a variety of
instruments, including swaps, options and forward contracts, to manage exposure
to fluctuations in commodity prices and interest rates. Such instruments contain
credit risk to the extent that the counterparty fails to perform under the
contract. We mitigate such risk by performing annual and interim credit reviews
using, among other things, publicly available credit ratings of such
counterparties (See Note 9). Both PEC and PEF also have limited counterparty
exposure for commodity hedges (primarily gas and oil hedges) due to spreading
our concentration risk over a number of partners.




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 September 30, 2008, has changed from December 31, 2007. The
total notional amount of fixed rate long-term debt at September 30, 2008, was
$9.345 billion, with an average interest rate of 6.17% and fair market value of
$8.8 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 September 30, 2008, was $961 million, with an average interest
rate of 5.45% and fair market value of $961 million. 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 September 30, 2008 and December 31, 2007,
approximately 13 percent of consolidated debt was in floating rate
mode.




Based on
our variable rate long-term debt balances at September 30, 2008, a 100 basis
point change in interest rates would result in an annual interest expense change
of approximately $10 million. Based on our commercial paper balances at
September 30, 2008, a 100 basis point change in interest rates would result in
an annual interest expense change of approximately $5 million.




The
financial market distress of September 2008 resulted in higher interest expense
for floating rate debt, including tax-exempt auction rate securities and
commercial paper. See “Future Liquidity and Capital Resources” in Item 2 for
additional information.




106




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.




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




At
September 30, 2008, the Parent had $150 million notional of pay-fixed forward
starting swaps to hedge cash flow risk with regard to future financing
transactions. The Parent had no open interest rate cash flow hedges at December
31, 2007. At September 30, 2008, PEC had $150 million notional of pay-fixed
forward starting swaps to hedge cash flow risk with regard to future financing
transactions. 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 had no open interest
rate cash flow hedges at September 30, 2008, and December 31, 2007. See "Future
Liquidity and Capital Resources" in Item 2 above for additional
information.


(dollars
      in millions)
            
            Notional
      Amount
            
            
            Pay
            
            Receive
      (a)
            
            Fair
      Value
            
            
            Exposure
      (b)ParentRisk hedged at
      September 30, 2008Anticipated
      10-year debt issue
            
            $
            150
            
            
            
            4.44
            %
            3-month
      LIBOR
            
            $
            1
            
            
            $
            (3
            )PECRisk hedged at
      September 30, 2008Anticipated
      10-year debt issue
            
            $
            150
            
            
            
            4.46
            %
            3-month
      LIBOR
            
            $
            1
            
            
            $
            (3
            )Risk 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% and 4.05% at December 31, 2007 and September 30,
      2008, respectively.


(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. In January 2008,
PEF entered into a $100 million notional 10-year forward starting swap and a
$100 million notional 30-year forward starting swap. In May 2008, PEF entered
into combined




107




$100
million notional 10-year forward starting swaps and $150 million notional
30-year forward starting swaps.  In June 2008, PEF entered into
combined $100 million notional 30-year forward starting swaps. In June 2008, PEF
terminated 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.




In
October 2008, the Parent and PEC each entered into $50 million notional 10-year
forward starting swaps to mitigate exposure to interest rate risk in
anticipation of future debt issuances.




MARKETABLE SECURITIES PRICE
RISK




At
September 30, 2008 and December 31, 2007, the fair value of our nuclear
decommissioning trust funds was $1.210 billion and $1.384 billion, respectively,
including $723 million and $804 million, respectively, for PEC and $487 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.
The trust funds have no material investments in the securities of financial
institutions that were recently sold, taken over or filed for
bankruptcy.




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 September 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 September 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 September 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




108




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. We had a $108 million cash collateral liability related to these
contracts at December 31, 2007, included in other current liabilities 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 September 30, 2007, we recorded net pre-tax gains of
$74 million related to these contracts, including $26 million attributable to
Ceredo, which was attributed to minority interest for the portion of the gain
subsequent to disposal. For the nine months ended September 30, 2007, we
recorded net pre-tax gains of $105 million related to these contracts, including
$36 million attributable to Ceredo, of which $21 million were attributed to
minority interest for the portion of the gain 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.




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 nine months ended September 30, 2008, PEC recorded a net realized gain of $6
million and $12 million, respectively. During each of the three and nine months
ended September 30, 2007, PEC recorded a net realized loss of $6 million. During
the three and nine months ended September 30, 2008, PEF recorded a net realized
gain of $118 million and $237 million, respectively. During the three and nine
months ended September 30, 2007, PEF recorded a net realized loss of $23 million
and $45 million, respectively.




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




At
September 30, 2008, the fair value of PEC’s commodity derivative instruments was
recorded as a $1 million short-term derivative asset position included in
prepayments and other current assets, a $19 million long-term derivative asset
position included in other assets and deferred debits, a $24 million short-term
liability position included in other current liabilities, and a $18 million
long-term derivative liability position included in other liabilities and
deferred credits on the PEC Consolidated Balance Sheet. At December 31, 2007,
the fair value of such instruments was recorded as a $19 million long-term
derivative asset position included in other assets and deferred debits and a $4
million short-term derivative liability position included in other current
liabilities on the PEC Consolidated Balance Sheet. PEC had no cash collateral
position at September 30, 2008 or December 31, 2007.




At
September 30, 2008, the fair value of PEF’s commodity derivative instruments was
recorded as a $59 million short-term derivative asset position included in
current derivative assets, a $90 million long-term derivative asset position
included in derivative assets, a $133 million short-term liability position
included in derivative liabilities, and a $73 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 $14 million cash collateral receivable
included in prepayments and other current assets and a $14 million cash
collateral liability included in other current liabilities at September 30,
2008, on the PEF Balance Sheet, and no cash collateral position at December 31,
2007.




109





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 September 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 nine months ended September 30, 2008 and
2007.




At
September 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.




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).




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.




During
the third quarter of 2008, Progress Energy announced that Peter M Scott, III,
Executive Vice President and Chief Financial Officer of Progress Energy would
retire effective September 1, 2008. Mark F. Mulhern, Senior Vice President -
Finance, was appointed as Chief Financial Officer of Progress Energy and its
subsidiaries upon Mr. Scott’s retirement.







Other
than the above-referenced item, there has been no change in our internal control
over financial reporting during the quarter ended September 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




110




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.




During the third quarter of 2008,
Progress Energy announced that Peter M Scott, III, Executive Vice President and
Chief Financial Officer of Progress Energy and PEC would retire effective
September 1, 2008.Mark F. Mulhern, Senior Vice President
- Finance of Progress Energy was appointed as Chief Financial Officer of
Progress Energy and PEC upon Mr. Scott’s retirement.







Other
than the above-referenced item, there has been no change in PEC’s internal
control over financial reporting during the quarter ended September 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.




During the third quarter of 2008,
Progress Energy announced that Peter M Scott, III, Executive Vice President and
Chief Financial Officer of Progress Energy and PEF would retire effective
September 1, 2008.Mark F. Mulhern, Senior Vice President
- Finance of Progress Energy, was appointed as Chief Financial Officer of
Progress Energy and PEF upon Mr. Scott’s retirement.







Other
than the above-referenced item, there has been no change in PEF’s internal
control over financial reporting during the quarter ended September 30, 2008,
that has materially affected, or is reasonably likely to materially affect, its
internal control over financial reporting.




111








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




ISSUER
PURCHASES OF EQUITY SECURITIES FOR THIRD QUARTER OF 2008







Period
            
            (a)
              Total
      Number of Shares
              (or
      Units) Purchased(1)(2)
            
            
            (b)
              Average
      Price
              Paid
      Per Share(or
      Unit)
            
            
            (c)
              Total
      Number of Shares (or Units) Purchased as
              Part
      of Publicly Announced Plans or Programs(1)
            
            
            (d)
              Maximum
      Number (or Approximate Dollar Value) of Shares (or Units)that
      May Yet Be Purchased Under the Plans or Programs(1)July
      1 – July 31
            
            
            20,763
            
            
            $
            41.19
            
            
            
            N/A
            
            
            
            N/AAugust
      1 –August
      31
            
            
            29,500
            
            
            $
            41.94
            
            
            
            N/A
            
            
            
            N/ASeptember
      1 – September 30
            
            
            101,400
            
            
            $
            43.41
            
            
            
            N/A
            
            
            
            N/ATotal
            
            
            151,663
            
            
            $
            42.18
            
            
            
            N/A
            
            
            
            N/A





(1)
            As
      of September 30, 2008, Progress Energy does not have any publicly
      announced plans or programs to purchase shares of its common
      stock.


(2)
            151,663
      shares of our common stock were purchased in open-market transactions by
      the plan administrator to meet share delivery obligations under the
      Savings Plan for Employees of Florida Progress
  Corporation.


112








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





113





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:
      November 5,
      2008
            (Registrants)By: /s/ Mark F. MulhernMark
      F. MulhernSenior
      Vice President and Chief Financial OfficerBy: /s/ Jeffrey M. StoneJeffrey
      M. StoneChief
      Accounting Officer and ControllerProgress
      Energy, Inc.Chief
      Accounting OfficerCarolina
      Power & Light Company d/b/a Progress Energy Carolinas,
      Inc.Florida
      Power Corporation d/b/a Progress Energy Florida,
  Inc.





114